UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
10-K
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þ
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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For
the fiscal year ended December 31, 2007
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OR
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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
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Commission file number: 000-51757
REGENCY
ENERGY PARTNERS LP
(Exact
name of registrant as specified in its charter)
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Delaware
(State
or other jurisdiction of
incorporation
or organization)
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16-1731691
(I.R.S.
Employer
Identification
No.)
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1700
Pacific Avenue, Suite 2900 Dallas, Texas
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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)
(Former name, former address and
former fiscal year, if changed since last report): None
Securities
registered pursuant to Section 12(b) of the Act:
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Title
of Each Class
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Name
of Each Exchange on Which Registered
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Common
Units of Limited Partner Interests
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The
Nasdaq Stock Market LLC
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Securities registered pursuant to Section
12(g) of the
Act: None
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Indicate
by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes þ No o
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Indicate
by check mark if the registrant is not required to file reports pursuant
to Section 13 or Section 15(d) of the Exchange
Act. Yes o No þ
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Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90
days. Yes þ No o
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Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. þ
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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
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Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes o No þ
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As of
June 30, 2007, the aggregate market value of the registrant’s common stock held
by non-affiliates of the registrant was $1,004,269,000 based on the closing
sale price as reported on the NASDAQ Stock Market LLC.
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Indicate
the number of outstanding units of each of the registrant’s classes of
units, as of the latest practicable
date.
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Class
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Outstanding
at February 7, 2008
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Common
Units
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40,704,020
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Subordinated
Units
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19,103,896
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Class
D Common Units
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7,276,506
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Class
E Common Units
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4,701,034
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DOCUMENTS
INCORPORATED BY REFERENCE
None
REGENCY
ENERGY PARTNERS LP
ANNUAL
REPORT ON FORM 10-K
FOR
THE YEAR ENDED DECEMBER 31, 2007
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Page
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Introductory
Statement
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1
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Cautionary
Statement about Forward-Looking Statements
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2
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Item
1
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3
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Item
1A
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29
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Item
1B
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29
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Item
2
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29
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Item
3
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29
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Item
4
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29
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Item
5
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29
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Item
6
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31
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Item
7
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34
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Item
7A
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47
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Item
8
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48
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Item
9
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48
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Item
9A
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48
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Item
9B
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49
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Item
10
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49
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Item
11
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54
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Item
12
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64
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Item
13
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66
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Item
14
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67
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Item
15
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68
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Introductory
Statement
References
in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when
used in an historical context, refer to Regency Energy Partners LP, or the
Partnership, and to Regency Gas Services LLC, all the outstanding member
interests of which were contributed to the Partnership on February 3, 2006, and
its subsidiaries. When used in the present tense or prospectively, these
terms refer to the Partnership and its subsidiaries. We use the
following definitions in this annual report on Form 10-K:
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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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BP
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BP
America Production Co., a wholly-owned subsidiary of BP
plc.
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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, Ltd.
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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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| CFTC | Commodities Futures Trading Commission | |
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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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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 Regency 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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| ICA | Interstate Commerce Act | |
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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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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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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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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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§
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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;
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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.
Other
factors that could cause our actual results to differ from our projected results
are discussed in Item 1A of this annual report.
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.
PART
I
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. We were formed in 2005.
We divide
our operations into three business segments:
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§
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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;
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§
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Transportation: We
deliver natural gas from northwest Louisiana to more favorable markets in
northeast Louisiana through our 320-mile Regency Intrastate Pipeline
system; and
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§
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Contract
Compression: On January 15, 2008, we acquired CDM, which
provides customers with turn-key natural gas compression
services.
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All of
our midstream assets are located in well-established areas of natural gas
production that are characterized by long-lived, predictable reserves.
These areas are generally experiencing increased levels of natural gas
exploration, development and production activities as a result of strong demand
for natural gas, attractive recent discoveries, infill drilling opportunities
and the implementation of new exploration and production
techniques.
BUSINESS STRATEGIES. Our management
team is dedicated to increasing the amount of cash available for distribution to
each outstanding unit while maintaining a strong balance sheet. We
intend to achieve this by executing the following strategies:
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§
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Implementing cost-effective
organic growth opportunities. We intend to build natural
gas gathering assets, processing facilities, field compression, and
transportation lines that will enhance our existing systems, further our
ability to aggregate supply, and enable us to access premium markets for
that supply. Where applicable, we will seek to coordinate each
expansion with the needs of significant producers in the area to mitigate
speculative risk associated with securing through-put
volumes.
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§
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Maximizing the profitability
of our existing assets. We intend to increase the
profitability of our existing asset base by actively controlling and
reducing operating costs, identifying new business opportunities, scaling
our operations by adding new volumes of natural gas supplies, and
undertaking additional initiatives to enhance
efficiency.
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§
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Continuing to reduce our
exposure to commodity price risk. We operate our
business in a manner designed to allow us to generate stable cash flows
while mitigating the impact of fluctuations in commodity
prices.
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§
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Utilizing our relationship
with GE EFS to facilitate acquisitions from third
parties. We intend to pursue strategic acquisitions of
midstream assets from third parties in or near our current areas of
operation that offer the opportunity for operational efficiencies and the
potential for increased utilization and expansion of those
assets. We also intend to pursue opportunities in new regions
with significant natural gas reserves and high levels of drilling
activity. We believe our relationship with GE EFS will provide
increased access to such
opportunities.
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§
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Pursuing strategic
acquisitions of midstream assets from GE EFS. GE EFS’s
energy asset base is considerably larger than our own and includes
midstream assets that we believe are strategically aligned with our
existing operations or provide attractive operations in new regions.
GE EFS does not have any obligation to sell assets to us. On
January 8, 2008, however, we acquired FrontStreet, which owns a gas
gathering system located in Kansas and Oklahoma, from affiliates of
GECC.
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§
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Improving our credit
ratings. We are committed to achieving an investment grade
rating on our debt. Our current credit ratings are BB- and
Ba3.
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COMPETITIVE STRENGTHS. We believe that
we are well positioned to execute our business strategies and to compete in the
natural gas gathering, processing, compression, marketing, and transportation
businesses based on the following competitive strengths:
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§
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Our acquisition strategy and
growth opportunities will benefit from our affiliation with GE
EFS. As indicated above, we believe our
affiliation with GE EFS enhances our ability to consummate accretive
acquisitions and capitalize on market
opportunities.
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§
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We have the financial
flexibility and adequate access to capital to pursue acquisition and
organic growth opportunities. We remain committed to
maintaining a capital structure that will afford us the financial strength
to fund expansion projects and other attractive investment
opportunities. We believe our relationship with GE increases
our access to capital and enables us to pursue strategic opportunities
that we might otherwise be unable to pursue. In addition, we
have sufficient liquidity under our credit facility to fund our near term
growth capital requirements.
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§
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We have a significant market
presence in major natural gas supply areas. We have a
significant market presence in each of our operating areas, which are
located in some of the largest and most prolific gas-producing regions of
the United States: the Louisiana-Mississippi-Alabama Salt basin in north
Louisiana, the Permian basin of west Texas, the Hugoton and Anadarko
basins in the mid-continent area in Kansas and Oklahoma, the Barnett Shale
basin in north Texas, the East Texas basin and Edwards,
Olmos and Wilcox trends in south Texas. Our geographical
diversity reduces our reliance on any particular region, basin
or gathering system. Each of these producing regions is
well-established with generally long-lived, predictable reserves, and our
assets are strategically located in each of the regions. These
areas are experiencing high levels of natural gas exploration, development
and production activities as a result of strong demand for natural gas,
attractive recent discoveries, infill drilling opportunities and the
implementation of new exploration and production
techniques.
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§
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We have a modern and efficient contract compressor fleet. Our highly
standardized compressor fleet provides us with significant operational
efficiencies and flexibility. At December 31, 2007, 73 percent
of the total available horsepower in our contract compression segment was
purchased new since December 31, 2003. We believe the young age
and overall composition of our compressor fleet will result in fewer
mechanical failures, lower fuel usage (a direct cost savings for our
customers), and reduced environmental emissions. In addition,
in developing and maintaining our standardized fleet, we have acquired
increased technical proficiency in predictive and preventive maintenance
and overhaul operations on our equipment, which helps us to achieve our
mechanical availability commitments. We guarantee our customers
98 percent mechanical availability of our compression units for land
installations and 96 percent mechanical availability for over-water
installations.
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§
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Our large horsepower contract
compression installations have long-term commitments and
provide
stable, fee-based cash
flows. The large horsepower applications on which we
focus in our contract compression business segment generally result in
long-term installations with our customers, which we believe improves the
stability of our cash flows. Our contracts generally have
initial terms ranging from one to five years. We charge our
customers either a fixed monthly fee for our compression services,
regardless of the volume of natural gas we compress in that month,
or a fee based on the volume of natural gas compressed per
month.
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§
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Our Regency Intrastate
Pipeline System provides us with significant fee-based transportation
through-put volumes and cash flow. The Regency
Intrastate Pipeline System allows us to capitalize on the flow of natural
gas from producing fields in north Louisiana to intrastate and interstate
markets in northeast Louisiana. These transportation
through-put volumes have limited commodity price exposure and provide us
with a stable, fee-based cash flow.
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§
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We have an experienced,
knowledgeable management team with a proven track
record. Our senior management team has an average of
over 20 years of industry related experience. Our team’s
extensive experience and contacts within the midstream industry provide a
strong foundation and focus for managing and enhancing our operations, for
accessing strategic acquisition opportunities and for constructing new
assets. Additionally, members of our management team have a
substantial economic interest in us through an indirect 8.2 percent
economic interest in the General Partner and a 1.6 percent limited partner
interest.
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RECENT
DEVELOPMENTS
Acquisition of Nexus. On February 22, 2008,
we entered into an Agreement and Plan of Merger (the “Nexus Merger Agreement”)
with Nexus Gas Partners, LLC, a Delaware limited liability company (“Nexus
Member”), and Nexus Gas Holdings, LLC, a Delaware limited liability company
(“Nexus”) (“Nexus Acquisition”). The aggregate consideration to be
paid is $85,000,000 in cash, subject to adjustment pursuant to customary closing
adjustments. Nexus is
a midstream provider of natural gas gathering, dehydration and compression
services for producers in DeSoto Parish, La., and Shelby County, Texas. The
Nexus gathering system consists of 80 miles of low- and high-pressure gathering
pipelines and is currently gathering more than 110 MMCF per day from
approximately 500 wells. In addition, upon consummation of the
Nexus Acquisition, we will acquire 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 that would enable the Nexus gathering system to be
integrated into our north Louisiana asset base (the “Sonat
Acquisition”). The Sonat Acquisition is subject to abandonment
approval by the FERC and other customary closing conditions. Upon the
closing of the Sonat Acquisition, we will pay Sonat $28,000,000, and, if the
closing occurs on or prior to March 1, 2010, on certain terms and conditions as
provided in the Merger Agreement, we will make an additional payment of
$25,000,000 to the Nexus Member.
In
connection with the closing of the Merger, $8,500,000 will be deposited with an
escrow agent to secure certain indemnification obligations of Member under the
Merger Agreement. The escrow will remain in place for one year after
the closing of the Merger, and the balance of the escrow upon termination of the
escrow (net of any pending claims) will be released to Member.
The Nexus
Acquisition is subject to approval under the Hart-Scott-Rodino Antitrust
Improvements Act and other customary closing conditions. The closing is expected
to occur in late first quarter or early second quarter 2008. We
anticipate funding the Merger consideration through borrowings under the
existing revolving credit facility.
Acquisition of
CDM. On January 15, 2008, we acquired CDM for
$695,314,000. The total purchase price, subject to customary
post-closing adjustments, paid 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 $216,869,000, (2) the payment of an aggregate
of $161,945,000 in cash to the CDM Partners, and (3) the assumption of
$316,500,000 in CDM’s debt obligations. Of those Class D common units
issued, 4,197,303 Class D common units were deposited with an escrow agent
pursuant to an escrow agreement. CDM provides 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. CDM’s 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 field
wide needs. CDM is responsible for the installation and ongoing
operation, service, and repair of compressors, which we modify as necessary to
adapt to our customers’ changing operating conditions. The CDM
acquisition provides the Partnership with stable, fee based cash flows, a source
of long-term organic growth projects, and provides synergies with the
Partnership’s existing operations. CDM’s experienced management
team, retained by us to operate our contract compression segment, has
demonstrated an ability to deliver strong organic growth since its
inception. CDM’s contract compression services will be reported as a
separate business segment from the date of acquisition forward and will comprise
the entire business segment.
Amendments to the Fourth Amended and
Restated Revolving Credit Facility. We have amended our credit
agreement three times (September 28, 2007, January 15, 2008, and February 13,
2008) to increase commitments under our revolving credit facility to
$900,000,000. The availability for letters of credit is
$100,000,000. We also have 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 fourth amended and restated credit agreement, or
the credit facility, have been met. These amendments were executed to
primarily provide funding for organic growth projects and
acquisitions.
Acquisition of
FrontStreet. On January 7, 2008, the Partnership acquired all
the outstanding equity (the “FrontStreet Acquisition”) of FrontStreet from ASC
(an affiliate of GECC) and EnergyOne for $146,766,000. 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, which were valued at $135,014,000 and
(2) the payment of $11,752,000 in cash to EnergyOne. FrontStreet owns
a gas gathering system located in Kansas and Oklahoma, which is operated by a
third party. FrontStreet’s gas gathering system has 63,500 horsepower
and 1,875 miles of pipeline extending over nine counties in Kansas and
Oklahoma. The FrontStreet acquisition provides the Partnership with
stable, fee based cash flows and is expected to be immediately accretive to our
unitholders.
Equity Offering. On July 26,
2007, we closed an underwritten public offering of 10,000,000 common units for
$32.05 per unit and, on July 31, 2007, the underwriters exercised their option
to purchase 1,500,000 additional common units. We received net proceeds of
$353,832,000 from these offerings. We used a portion of these
proceeds to repay amounts outstanding under the term ($50,000,000) and revolving
credit facility ($178,930,000). With the remaining proceeds and
additional borrowings under the revolving credit facility, the Partnership
repurchased $192,500,000, or 35 percent, of its outstanding senior notes which
required us to pay an early redemption penalty of $16,122,000 in August
2007.
GE EFS acquisition of HM
Capital’s interests in us and resulting
change in
control. On June 18, 2007,
Regency GP Acquirer LP, an indirect subsidiary of GECC, acquired 91.3 percent of
both the member interest in the General Partner and the outstanding limited
partner interests in the General Partner from an affiliate of HM Capital
Partners. Concurrently, Regency LP Acquirer LP, another indirect
subsidiary of GECC, acquired 17,763,809 of the outstanding subordinated units,
exclusive of 1,222,717 subordinated units which were owned directly or
indirectly by certain members of the Partnership’s management
team. As a part of this acquisition, affiliates of HM Capital
Partners entered into an agreement not to sell or otherwise distribute 4,692,471
of the Partnership’s common units retained by it for a period of 180
days. In addition, a separate affiliate of HM Capital Partners
entered into an agreement not to sell or otherwise distribute 3,406,099 of the
Partnership’s common units retained by it for a period of one year.
GE Energy
Financial Services is a unit of GECC which is an indirect wholly owned
subsidiary of GE. For simplicity, we refer to Regency GP Acquirer LP,
Regency LP Acquirer LP and GE Energy Financial Services collectively as “GE
EFS.” Concurrent with the Partnership's issuance of common units in July
and August 2007, GE EFS and certain members of the Partnership’s management made
a capital contribution aggregating to $7,735,000 to maintain the General
Partner’s two percent interest in the Partnership.
Concurrent
with the GE EFS acquisition of HM Capital's interest in us, eight members of the
Partnership’s senior management, together with two independent directors,
entered into an agreement to sell an aggregate of 1,344,551 subordinated units
for a total consideration of $25,544,000 or $24.00 per unit. Additionally,
GE EFS entered into a subscription agreement with four officers and certain
other management of the Partnership whereby these individuals acquired an 8.2
percent indirect economic interest in the General Partner.
The
Partnership was not required to record any adjustments to reflect GE EFS’s
acquisition of the HM Capital Partners’ interest in the Partnership or the
related transactions (together, referred to as “GE EFS
Acquisition”).
INDUSTRY
OVERVIEW
General. The midstream
natural gas industry is the link between exploration and production of raw
natural gas and the delivery of its components to end-use markets. It
consists of natural gas gathering, compression, dehydration, processing and
treating, fractionation, marketing and transportation. Raw natural
gas produced from the wellhead is gathered and delivered to a processing plant
located near the production, where it is treated, dehydrated, and/or processed.
Natural gas processing involves the separation of raw natural gas into
pipeline quality natural gas, principally methane, and mixed NGLs. Natural
gas treating entails the removal of impurities, such as water, sulfur compounds,
carbon dioxide and nitrogen. Pipeline-quality natural gas is delivered by
interstate and intrastate pipelines to markets. Mixed NGLs are typically
transported via NGL pipelines or by truck to a fractionator, which separates the
NGLs into their components, such as ethane, propane, butane, isobutane and
natural gasoline. The NGL components are then sold to end
users.
The
following diagram depicts our role in the process of gathering, processing,
compression, marketing and transporting natural gas.
Overview of U.S. market. According to the
EIA, the midstream natural gas industry in the United States includes
approximately 530 processing plants that process approximately 40 Bcf of natural
gas per day and produce approximately 73 million gallons per day of NGLs.
The midstream industry is generally characterized by regional competition
based on the proximity of gathering systems and processing plants to natural gas
wells. Natural gas remains a critical component of energy consumption in
the United States. According to the EIA, total annual domestic consumption
of natural gas is expected to increase from 21.8 Tcf in 2006 to 24.3 Tcf in
2016, representing an average annual growth rate of 1.1 percent, with a
slight decrease in consumption through the year 2030. During the five years
ended December 31, 2005, the United States has on average consumed approximately
22.4 Tcf per year, while total marketed domestic production averaged
approximately 18.9 Tcf per year during the same period. The industrial and
electricity generation sectors currently account for the largest usage of
natural gas in the United States.
Gathering. A gathering
system typically consists of a network of small diameter pipelines and, if
necessary, a compression system which together collect natural gas from points
near producing wells and transport it to larger pipelines for further
transportation. We own and operate large gathering systems in five
geographic regions of the United States.
Compression. Gathering
systems are operated at design pressures that seek to maximize the total
through-put volumes from all connected wells. Since wells produce at
progressively lower field pressures as they age, the raw natural gas must be
compressed to deliver the remaining production against a higher pressure that
exists in the connected gathering system. Natural gas compression is a
mechanical process in which a volume of gas at a lower pressure is boosted,
or compressed, to a desired higher pressure, allowing gas that no longer
naturally flows into a higher pressure downstream pipeline to be brought to
market. Field compression is typically used to lower the entry pressure,
while maintaining or increasing the exit pressure of a gathering system to allow
it to operate at a lower receipt pressure and provide sufficient pressure to
deliver gas into a higher pressure downstream pipeline. We operate
more than 700,000 horsepower of compression in Texas, Louisiana, Oklahoma,
Kansas and Arkansas.
Amine
treating. The amine treating process involves a continuous
circulation of a liquid chemical called amine that physically contacts with the
natural gas. Amine has a chemical affinity for hydrogen sulfide and
carbon dioxide that allows it to absorb these impurities from the
gas. After mixing, gas and amine are separated, and the impurities
are removed from the amine by heating. The treating plants are sized
by the amine circulation capacity in terms of gallons per minute. We
own and operate natural gas processing and/or treating plants in five geographic
regions.
Processing. Natural
gas processing involves the separation of natural gas into pipeline quality
natural gas and a mixed NGL stream. The principal component of
natural gas is methane, but most natural gas also contains varying amounts of
heavier hydrocarbon components, or NGLs. Natural gas is described as
lean or rich depending on its content of NGLs. Most natural gas
produced by a well is not suitable for long-haul pipeline transportation or
commercial use because it contains NGLs and impurities. Natural gas
processing not only removes unwanted NGLs that would interfere with pipeline
transportation or use of the natural gas, but also extracts hydrocarbon liquids
that can have higher value as NGLs. Removal and separation of
individual hydrocarbons by processing is possible because of differences in
weight, boiling point, vapor pressure and other physical
characteristics. We own and operate natural gas processing and/or
treating plants in five geographic regions.
Fractionation. NGL
fractionation facilities separate mixed NGL streams into discrete NGL products:
ethane, propane, normal butane, isobutane and natural gasoline. Ethane is
primarily used in the petrochemical industry as feedstock for ethylene, one of
the basic building blocks for a wide range of plastics and other chemical
products. Propane is used both as a petrochemical feedstock in the
production of propylene and as a heating fuel, an engine fuel and an industrial
fuel. Normal butane is used as a petrochemical feedstock in the production
of butadiene (a key ingredient in synthetic rubber) and as a blend stock for
motor gasoline. Isobutane is typically fractionated from mixed butane (a
stream of normal butane and isobutane in solution), principally for use in
enhancing the octane content of motor gasoline. Natural gasoline, a
mixture of pentanes and heavier hydrocarbons, is used primarily as motor
gasoline blend stock or petrochemical feedstock. We do not own or operate
any NGL fractionation facilities.
Marketing. Natural gas
marketing involves the sale of the pipeline-quality natural gas either produced
by processing plants or purchased from gathering systems or other pipelines.
We perform a limited natural gas marketing function for our account and
for the accounts of our customers.
Transportation. Natural
gas transportation consists of moving pipeline-quality natural gas from
gathering systems, processing plants and other
pipelines and delivering it to wholesalers, utilities and other pipelines.
We own and operate the Regency Intrastate Pipeline system, an intrastate
natural gas pipeline system located in north Louisiana. We also own a
10-mile interstate pipeline that extends from Harrison County, Texas to Caddo
Parish, Louisiana.
GATHERING
AND PROCESSING OPERATIONS
General. We operate significant
gathering and processing assets in five geographic regions of the United States:
north Louisiana, the mid-continent, and east, south, and west Texas. We
contract with producers to gather raw natural gas from individual wells or
central delivery points, which may have multiple wells behind them, located near
our processing plants or gathering systems. Following the execution of a
contract, we connect wells and central delivery points to our gathering lines
through which the raw natural gas flows to a processing plant, treating facility
or directly to interstate or intrastate gas transportation pipelines. At
our processing plants, we remove any impurities in the raw natural gas stream
and extract the NGLs. Our gathering and processing operations are located
in areas that have experienced significant levels of drilling activity,
providing us with opportunities to access newly developed natural gas
supplies.
All raw
natural gas flowing through our gathering and processing facilities is supplied
under gathering and processing contracts having terms ranging from
month-to-month to the life of the oil and gas lease. For a description of
our contracts, please read “—Our Contracts” and “Item 7— Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Our
Operations.”
The
pipeline-quality natural gas remaining after separation of NGLs through
processing is either returned to the producer or sold, for our own account or
for the account of the producer, at the tailgates of our processing plants for
delivery through interstate or intrastate gas transportation
pipelines.
The
following table sets forth information regarding our gathering systems and
processing plants as of December 31, 2007.
|
Region
|
Pipeline
Length (Miles)
|
Plants
|
Compression
(Horsepower)
|
Through-put
Volume Capacity (MMcf/d)
|
||||||||||||
|
North
Louisiana
|
600 | 4 | 39,100 | 790 | ||||||||||||
|
East
Texas
|
371 | 1 | 25,665 | 215 | ||||||||||||
|
South
Texas
|
623 | 2 | 27,828 | 555 | ||||||||||||
|
West
Texas
|
750 | 1 | 47,000 | 325 | ||||||||||||
|
Mid-Continent
|
3,470 | 1 | 105,630 | 437 | ||||||||||||
|
Total
|
5,814 | 9 | 245,223 | 2,322 | ||||||||||||
The
following map depicts the geographic areas of our operations.
North
Louisiana
Region. Our north Louisiana
region includes:
|
§
|
the
Dubach and Lisbon processing
plants;
|
|
§
|
the
Dubach/Calhoun/Lisbon gathering system, which is a large integrated
natural gas gathering and processing system located primarily in four
parishes of north Louisiana; and
|
|
§
|
the
Elm Grove and Dubberly refrigeration
plants.
|
This
system is located in active drilling areas in north
Louisiana. Through our Dubach/Calhoun/Lisbon gathering system and its
interconnections with our Regency Intrastate Pipeline system in north Louisiana
described in “—Transportation Operations,” we offer producers wellhead-to-market
services, including natural gas gathering, compression, processing, marketing
and transportation.
Natural Gas Supply. The
natural gas supply for our north Louisiana gathering systems is derived
primarily from natural gas wells located in Claiborne, Union, Lincoln and
Ouachita Parishes in north Louisiana. This area has experienced
significant levels of drilling activity, providing us with opportunities to
access newly developed natural gas supplies. Natural gas production in
this area has increased as a result of the additional drilling, which includes
deeper reservoirs in the Cotton Valley and Hosston trends.
Dubach/Lisbon/Calhoun Gathering
System. The Dubach/Lisbon/Calhoun gathering system consists of
600 miles of natural gas gathering pipelines ranging in size from two
inches to 10 inches in diameter. The system gathers raw natural gas
from producers and delivers it to either the Dubach or Lisbon processing plant
for processing. The remainder of the raw natural gas is lean natural gas,
which does not require processing and is delivered directly to interstate
pipelines and our Regency Intrastate Pipeline system.
Dubach and Lisbon Processing Plants. The Dubach processing
plant is a cryogenic natural gas processing plant that processes raw natural gas
gathered on the Dubach and Calhoun gathering systems. The Lisbon plant is
a cryogenic natural gas processing plant that processes raw natural gas gathered
on the Lisbon gathering system. These plants were acquired by us
in 2003, were originally constructed in 1980 and were reassembled on their
present locations in 1994 and 1996, respectively.
Elm Grove and Dubberly Refrigeration
Plants. The Elm Grove and Dubberly refrigeration plants process raw
natural gas located in Bossier and Webster parishes in northeastern Louisiana.
Elm Grove was placed into service in May 2006 and Dubberly was placed into
service in December 2006.
East
Texas
Region. Our east Texas
gathering assets gather, compress, and dehydrate natural gas. Natural
gas produced in this region contains high levels of hydrogen sulfide. Our
east Texas region includes:
|
§
|
the
Eustace Gathering System, a large integrated natural gas gathering and
processing system located in Rains, Wood, Van Zandt and Henderson
Counties; and
|
|
§
|
the
Como Gathering System, a smaller integrated natural gas gathering and
processing system located in Franklin, Wood, Hopkins and
Rains Counties.
|
Both the
Eustace and Como gathering systems deliver natural gas to into the Eustace
processing plant that is equipped with a sulfur removal unit.
Natural Gas Supply. The
natural gas supply for our east Texas gathering systems is derived primarily
from natural gas wells located in a mature basin that generally have long lives
and predictable gas flow rates.
Eustace Processing Plant. The
Eustace processing plant is a cryogenic natural gas processing plant that was
constructed in its current location in 1981. It includes an amine
treating unit, a cryogenic NGL recovery unit, a nitrogen rejection unit, and a
liquid sulfur recovery unit. This plant removes hydrogen sulfide, carbon
dioxide and nitrogen from the natural gas stream, recovers NGLs and condensate,
delivers pipeline quality gas at the plant outlet and produces
sulfur.
South
Texas
Region. The south Texas gathering assets gather,
compress, and dehydrate natural gas. Some of the natural gas produced
in this region can have significant hydrogen sulfide and carbon dioxide
content. These systems are connected to processing and treating
facilities that include an acid gas reinjection well. Our south
Texas region primarily includes the following natural gas gathering
systems:
|
§
|
the
LaSalle Gathering System, a large natural gas gathering system located in
LaSalle and Webb counties. Gas from this system is processed by
a third party.
|
|
§
|
the
Pueblo Gathering System, a large integrated natural gas gathering,
treating, and processing system located in Karnes and Atascosa
counties. Gas from this system is treated and processed at our
Fashing Plant. We have plans to connect this system to our
Tilden treating plant during 2008;
|
|
§
|
the
Tilden Gathering System, a large integrated natural gas gathering and
treating system located in McMullen, Atascosa, Frio and LaSalle Counties
in south Texas and flows into the Tilden treating plant;
and
|
|
§
|
the
Palafox Gathering System, a small gathering system located in Dimmitt and
Webb counties, Texas. The natural gas gathered by this system is
delivered to a third party for
processing.
|
Natural Gas Supply. The
natural gas supply for our south Texas gathering systems is derived primarily
from natural gas wells located in a mature basin that generally have long lives
and predictable gas flow rates.
Tilden Treating Plant. The Tilden
Treating Plant is a natural gas treating plant constructed on its current
location in 1981. It includes inlet compression, a 60 MMcf/d amine
treating unit, a 55 MMcf/d amine treating unit and a 40 ton (per day) liquid
sulfur recovery unit. An additional 55 MMcf/d amine treating unit is
currently inactive. This plant removes hydrogen sulfide from the natural
gas stream, which in this region often contains a high concentration of hydrogen
sulfide, recovers condensate, delivers pipeline quality gas at the plant outlet
and reinjects acid gas.
West
Texas
Region. The
system covers four Texas counties surrounding the Waha Hub, one of Texas’ major
natural gas market areas. Through our Waha gathering system, we offer
producers wellhead to market services. As a result of the proximity
of this system to the Waha Hub, the Waha gathering system has a variety of
market outlets for the natural gas that we gather and process, including several
major interstate and intrastate pipelines serving California, the mid-continent
region of the United States and Texas natural gas markets. Our west
Texas region includes the Waha gathering system and the Waha processing
plant.
Natural Gas Supply. The
natural gas supply for the Waha gathering system is derived primarily from
natural gas wells located in four counties in west Texas near the Waha Hub.
Natural gas exploration and production drilling in this area has primarily
targeted productive zones in the Permian Delaware basin and Devonian basin.
These basins are mature basins with wells that generally have long lives
and predictable flow rates.
Waha Gathering
System. The Waha gathering system consists of 750 miles of natural
gas gathering pipelines ranging in size from three inches in diameter to
24 inches in diameter. We offer producers four different levels of
natural gas compression on the Waha gathering system, as compared to the two
levels typically offered in the industry. By offering multiple levels of
compression, our gathering system is often more cost-effective for our
producers, since the producer is typically not required to pay for a level of
compression that is higher than the level it requires.
Waha Processing
Plant. The Waha processing plant is a cryogenic natural gas
processing plant that processes raw natural gas gathered on the Waha gathering
system. This plant was constructed in 1965, and, due to recent upgrades to
state of the art cryogenic processing capabilities, it is a highly efficient
natural gas processing plant. The Waha processing plant also includes an
amine treating facility which removes carbon dioxide and hydrogen sulfide from
raw natural gas gathered in our Waha gathering system before moving the natural
gas to the processing plant. The acid gas is reinjected.
Mid-Continent
Region. Our mid-continent region includes natural gas
gathering systems located primarily in Kansas and Oklahoma. Our
mid-continent gathering assets are extensive systems that gather, compress and
dehydrate low-pressure gas from approximately 1,500 wells. These systems
are geographically concentrated, with each central facility located within 90
miles of the others. We operate our mid-continent gathering systems at low
pressures to increase the total through-put volumes from the connected wells.
Wellhead pressures are therefore adequate to access the gathering lines
without the cost of wellhead compression. In addition, we process natural
gas from the Mocane-Laverne gathering system at our Mocane processing
plant.
Natural Gas Supply. Our
mid-continent systems are located in two of the largest and most prolific
natural gas producing regions in the United States, including the
Hugoton Basin in southwest Kansas and the Anadarko Basin in western
Oklahoma. These mature basins have continued to provide generally
long-lived, predictable reserves. Recent increases in production in these
areas have been driven primarily by continued infill drilling, compression
enhancements, and advanced well bore completion technology. In addition,
the application of 3-D seismic technology in these areas has yielded
better-defined reservoirs for continuing development of these
basins.
Hugoton Gathering
System. On January 7, 2008, the Partnership completed its
acquisition of FrontStreet which owns the Hugoton gathering system, consisting
of five compressor stations with over 63,500 horsepower and 1,875 miles of
pipeline extending over nine counties in Kansas and Oklahoma. This
system is operated by a third party.
Lakin Gathering System. The
Lakin gathering system is located in southwestern Kansas. It consists of
850 miles of natural gas gathering pipelines ranging in size from two
inches to 20 inches in diameter. Substantially all of the raw natural
gas gathered by the Lakin gathering system is delivered to a third party’s
processing plant.
Mocane-Laverne Gathering
System. The Mocane-Laverne gathering system is located in Beaver and
Harper counties in the Oklahoma panhandle and Meade County in southwestern
Kansas. It consists of 500 miles of natural gas gathering pipelines
ranging in size from two inches to 24 inches in diameter. The system
gathers raw natural gas from producers and delivers it for processing to the
Mocane processing plant.
Greenwood Gathering System. The
Greenwood gathering system is primarily located in Morton and
Stanton Counties in southwestern Kansas. It consists of 250
miles of natural gas gathering pipelines ranging in size from four inches to 20
inches in diameter. The raw natural gas gathered by this system is
delivered to a third party’s processing plant. We pay the third party a
fee to process the gas for our account.
Mocane Processing
Plant. The Mocane processing plant is a cryogenic natural gas
processing plant that processes raw natural gas gathered on the Mocane-Laverne
gathering system. This plant was constructed in 1975 and acquired by us in
2003.
Other. We also own the
Lakin processing plant, a cryogenic processing plant with nitrogen rejection and
helium recovery capabilities. This plant, which is currently idle, has a
capacity of 80 MMcf/d. The plant was constructed in 1995 and was acquired
by us in 2003. We are currently evaluating opportunities to utilize the
Lakin processing plant, which may include connecting a new source of supply to
the plant or moving the plant to another area.
TRANSPORTATION
OPERATIONS
Regency Intrastate
Pipeline. We own and operate a 320-mile intrastate natural gas
pipeline system, known as the Regency Intrastate Pipeline system, in north
Louisiana extending from Caddo Parish to Franklin Parish in northern Louisiana.
This system, with pipeline ranging from 12 to 30 inches in diameter,
includes total system capacity of 910 MMcf/d, 28,375 horsepower of compression
and our Haughton Plant, a 35 MMcf/d refrigeration plant. Natural gas
generally flows from west to east on the pipeline from wellhead connections or
connections with other gathering systems. The Regency Intrastate Pipeline
system transports natural gas produced from the Vernon field, the Elm Grove
field and the Sligo field, which are three of the four largest natural gas
producing fields in Louisiana. Our transportation operations are located in
areas that have experienced significant levels of drilling activity providing us
with opportunities to access newly developed natural gas supplies.
Gulf States Transmission. Our interstate
pipeline consists of 10 miles of 12 and 20 inch diameter pipeline that extends
from Harrison County, Texas to Caddo Parish, Louisiana. The pipeline has a
FERC certificated capacity of 150 MMcf/d.
On
February 6, 2008, one of the interstate pipelines, Columbia Gulf, which our RIGS
pipeline interconnects with, lost approximately 68,000 horsepower of compression
due to a tornado. We have not experienced a material impact to our
operations or results of operations. We continue to monitor this
situation and will modify our operations if necessary.
CONTRACT
COMPRESSION OPERATIONS
The
natural gas contract compression services we provide, subsequent to our
acquisition of CDM, include designing, sourcing, owning, insuring, installing,
operating, servicing, repairing, and maintaining compressors and related
equipment for which we guarantee our customers 98 percent mechanical
availability for land installations and 96 percent mechanical availability for
over-water installations. We 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. We
believe that we improve the stability of our cash flow by focusing on field-wide
compression applications because such applications generally involve long-term
installations of multiple large horsepower compression units. Our
contract compression operations are primarily located in Texas, Louisiana, and
Arkansas.
The
following table set forth certain information regarding CDM’s revenue generating
natural gas compressor horsepower as of December 31, 2007.
|
Percentage
of
|
|||||||
|
Horsepower
|
Total
Revenue
|
Revenue
Generating
|
Number
of
|
||||
|
Range
|
Generating
Horsepower
|
Horsepower
|
Units
|
||||
|
0-499
|
41,958
|
7%
|
252
|
||||
|
500-999
|
61,609
|
11%
|
99
|
||||
|
1,000+
|
464,660
|
82%
|
307
|
||||
|
568,227
|
100%
|
658
|
OUR
CONTRACTS
Gathering and
Processing Contracts. We
contract with producers to gather raw natural gas from individual wells or
central delivery points located near our gathering systems and processing
plants. Following the execution of a contract with the producer, we
connect the producer’s wells or central delivery points to our gathering lines
through which the natural gas is delivered to a processing plant owned and
operated by us or a third party for a fee. We obtain supplies of raw
natural gas for our gathering and processing facilities under contracts having
terms ranging from month-to-month to life of the lease. We categorize our
processing contracts in increasing order of commodity price risk as fee-based,
percentage-of-proceeds, or keep-whole contracts. For a description of our
fee-based arrangements, percent-of-proceeds arrangements, and keep-whole
arrangements, please read “Item 7— Management’s discussion and analysis of
financial condition and results of operations — Our
Operations.” During the year ended December 31, 2007, purchases
from KCS Resources, Inc. were 16 percent of the volumes underlying the cost
of gas and liquids on our consolidated statement of operations.
For the
above described contracts, the margin by product and percentage were as follows
for the year ended December 31, 2007.
|
Margin
by Product
|
Percent
|
|||
|
Net
Fee
|
43 | % | ||
|
NGL
|
37 | |||
|
Gas
|
10 | |||
|
Condensate
|
8 | |||
|
Helium
and Sulfur
|
2 | |||
|
Total
|
100 | % | ||
Transportation
Contracts.
Fee Transportation
Contracts. We provide natural gas transportation services on the
Regency Intrastate Pipeline pursuant to contracts with natural gas shippers.
These contracts are all fee-based. Generally, our transportation
services are of two types: firm transportation and interruptible transportation.
When we agree to provide firm transportation service, we become obligated
to transport natural gas nominated by the shipper up to the maximum daily
quantity specified in the contract. In exchange for that obligation on our
part, the shipper pays a specified reservation charge, whether or not the
capacity is utilized by the shipper, and in some cases the shipper also pays a
commodity charge with respect to quantities actually shipped. When we
agree to provide interruptible transportation service, we become obligated to
transport natural gas nominated and actually delivered by the shipper only to
the extent that we have available capacity. The shipper pays no
reservation charge for this service but pays a commodity charge for quantities
actually shipped. We provide our transportation services under the terms
of our contracts and under an operating statement that we have filed and
maintain with the FERC with respect to transportation authorized under Section
311 of the NGPA.
Merchant Transportation
Contracts. We perform a
limited merchant function on our Regency Intrastate Pipeline system. We
purchase natural gas from producers or gas marketers at receipt points on our
system at a price adjusted to reflect our transportation fee and transport that
gas to delivery points on our system where we sell the natural gas at market
price. We regard the total segment margin with respect to those purchases
and sales as the economic equivalent of a fee for our transportation
service.
These
contracts are frequently settled in terms of an index price for both purchases
and sales. In order to minimize commodity price risk, we attempt to match
sales with purchases at the same index price on the date of
settlement.
Contract
Compression Contracts. We generally enter into
a new contract with respect to each distinct application for which we will
provide contract compression services. Our compression contracts
typically have an initial term between one and five years, after which the
contract continues on a month-to-month basis. Our customers pay
either a fixed monthly fee, or a fee based on the volume of natural gas actually
compressed. We are not responsible for acts of force majeure and our
customers are generally required to pay our monthly fee for fixed fee contracts,
or a minimum fee for throughput contracts, even during periods of limited or
disrupted production. We are generally responsible for the costs and
expenses associated with operation and maintenance of our compression equipment,
such as providing necessary lubricants, although certain fees and expenses are
the responsibility of the customer under the terms of their
contracts. For example, all fuel gas is provided by our customers
without cost to us, and in many cases customers are required to provide all
water and electricity. We are also reimbursed by our customers for
certain ancillary expenses such as trucking, crane and installation labor costs,
depending on the terms agreed to in a particular contract.
COMPETITION
Gathering and Processing. The natural gas
gathering, processing, contract compression, marketing, and transportation
businesses are highly competitive. We face strong competition in each
region in acquiring new gas supplies. Our competitors in acquiring new gas
supplies and in processing new natural gas supplies include major integrated oil
companies, major interstate and intrastate pipelines and other natural gas
gatherers that gather, process and market natural gas. Competition for
natural gas supplies is primarily based on the reputation, efficiency and
reliability of the gatherer and the pricing arrangements offered by the
gatherer.
Many of
our competitors have capital resources and control supplies of natural gas
substantially greater than ours. Our major competitors in each region
include:
|
§
|
North
Louisiana: CenterPoint Energy Gas Marketing Company;
PanEnergy Louisiana Intrastate, LLC
(Pelico)
|
|
§
|
East Texas: Enbridge
Energy Partners LP
|
|
§
|
South
Texas: Enterprise Products Partners LP, Duke Energy Field
Services, L.P
|
|
§
|
West
Texas: Southern Union Gas Services, Enterprise Products
Partners LP
|
|
§
|
Mid-Continent: Duke
Energy Field Services, L.P.; ONEOK Energy Marketing and Trading, L.P.;
Penn Virginia Corporation
|
Transportation. Competition
in natural gas transportation is characterized by price of transportation, the
nature of the markets accessible from a transportation pipeline and the type of
service provided. In transporting natural gas across north Louisiana,
we face major competition from CenterPoint Energy Gas Marketing Company, Gulf
South Pipeline, L.P., and Texas Gas Transmission, LLC.
Contract Compression. The
natural gas contract compression services business is highly competitive.
We face competition from large national and multinational companies with
greater financial resources and, on a regional basis, from numerous smaller
companies. Our main competitors in the natural gas contract compression
business, based on horsepower, are Hanover Compressor Company, Universal
Compression Holdings, Inc. (or Exterran Holdings, Inc. following its merger with
Hanover Compressor Company), Universal Compression Partners, L.P., Compressor
Systems, Inc., USA Compression and J-W Operating Company.
We
believe that the superior mechanical availability of our standardized compressor
fleet is the primary basis on which we compete and a significant distinguishing
factor from our competition. All of our competitors attempt to compete on
the basis of price. We believe our pricing has proven competitive because
of the superior mechanical availability we deliver, the quality of our
compression units, as well as the technical expertise we provide to our
customers. We believe our focus on addressing customers’ more complex
natural gas compression needs related primarily to field-wide compression
applications differentiates us from many of our competitors who target smaller
horsepower projects related to individual wellhead applications.
RISK
MANAGEMENT
To manage
commodity price risk, we have implemented a risk management program under which
we seek to
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match
sales prices of commodities (especially natural gas) with purchases under
our contracts;
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manage
our portfolio of contracts to reduce commodity price
risk;
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optimize
our portfolio by active monitoring of basis, swing, and fractionation
spread exposure; and
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hedge
a portion of our exposure to commodity
prices.
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As a
consequence of our gathering and processing contract portfolio, we derive a
portion of our earnings from a long position in NGLs, natural gas and
condensate, resulting from the purchase of natural gas for our account or from
the payment of processing charges in kind. This long position is
exposed to commodity price fluctuations in both the natural gas and NGL markets.
Operationally, we mitigate this price risk by generally purchasing natural
gas and NGLs at prices derived from published indices, rather than at a
contractually fixed price and by marketing natural gas and natural gas liquids
under similar pricing mechanisms. In addition, we optimize the operations
of our processing facilities on a daily basis, for example by rejecting ethane
in processing when recovery of ethane as an NGL is uneconomical. We also
hedge this commodity price risk by purchasing a series of swap contracts for
individual NGLs. Our hedging position and needs to supplement or
modify our position are closely monitored by the Risk Management Committee of
the Board of Directors. Please read “Item 7A-Quantitative and
Qualitative Disclosures About Market Risk” for information regarding the status
of these contracts. As a matter of policy we do not acquire forward
contracts or derivative products for the purpose of speculating on price
changes.
Our
contract compression business does not have direct exposure to natural gas
commodity price risk because we do not take title to the natural gas we compress
and because the natural gas we use as fuel for our compressors is supplied by
our customers without cost to us. Our indirect exposure to short-term
volatility in natural gas and crude oil commodity prices is mitigated because
natural gas and crude oil production, rather than exploration, is the primary
demand driver for our contract compression services, and because our focus on
field-wide applications reduces our dependence on individual well
economics.
REGULATION
Industry
Regulation
Intrastate Natural Gas Pipeline
Regulation. Pursuant to Section 311 of the NGPAS, RIGS transports
interstate natural gas in Louisiana for many of its shippers. To the
extent that our Regency Intrastate Pipeline system transports natural gas in
interstate service, its rates, terms and conditions of service are subject to
the jurisdiction of the FERC. Under Section 311, rates charged for
transportation must be fair and equitable, and amounts collected in excess of
“fair and equitable” rates are subject to refund with interest. NGPA
Section 311 rates deemed fair and equitable by the FERC are generally
analogous to the cost-based rates that the FERC deems “just and reasonable” for
interstate pipelines under the NGA. RIGS is required to file triennial
rate petitions either justifying its existing rates or requesting new
rates. RIGS’ most recent FERC-approved Section 311 maximum rates were
established in 2005 effective from May 1, 2005 to May 1, 2008. These
rates were set for firm transportation at $0.15 per MMBtu reservation charge,
with a $0.05 MMBtu daily commodity charge, and for interruptible
transportation at $0.20 per MMBtu. RIGS is obligated to file its next
Section 311 rate case no later than May 1, 2008. Any failure on our
part:
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to
observe the service limitations applicable to transportation service under
Section 311,
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to
comply with the rates approved by the FERC for Section 311
service,
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to
comply with the terms and conditions of service established in our
FERC-approved Statement of Operating Conditions,
or
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to
comply with applicable FERC regulations, the NGPA or certain state laws
and regulations
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could
result in an alteration of our jurisdictional status or the imposition of
administrative, civil and criminal penalties, or both.
RIGS is
also subject to regulation by various agencies of the State of
Louisiana. Louisiana’s Pipeline Operations Section of the Department
of Natural Resources’ Office of Conservation is generally responsible for
regulating intrastate pipelines and gathering facilities in Louisiana and has
authority to review and authorize natural gas transportation transactions and
the construction, acquisition, abandonment and interconnection of physical
facilities. Louisiana also has agencies that regulate transportation
rates, service terms and conditions and contract pricing to ensure their
reasonableness and to ensure that the intrastate pipeline companies that they
regulate do not discriminate among similarly situated customers. The
distinction between FERC-regulated transmission facilities and intrastate
facilities has been the subject of litigation, so the classification and
regulation of RIGS as an intrastate pipeline may be subject to change based on
future determinations by the FERC, the courts or the U.S. Congress.
FERC has
adopted new market-monitoring and annual reporting regulations applicable to
many intrastate pipelines. These regulations are intended to increase
the transparency of wholesale energy markets, to protect the integrity of such
markets, and to improve FERC’s ability to assess market forces and detect market
manipulation. Although these regulations are not final, the
monitoring and annual reporting mandated by these regulations could require
intrastate pipelines to incur increased costs and administrative
burdens. FERC has also proposed to require both interstate and
certain major non-interstate pipelines to post, on a daily basis, capacity,
scheduled flow information and actual flow information, which regulations could
subject us to further costs and administrative burdens.
Interstate Natural Gas Pipeline Regulation. The
FERC also has broad regulatory authority over the business and operations of
interstate natural gas pipelines, such as the pipeline owned by our subsidiary,
GSTC. Under the NGA, rates charged for interstate natural gas transmission
must be just and reasonable, and amounts collected in excess of just and
reasonable rates are subject to refund with interest. GSTC holds a
FERC-approved tariff setting forth cost-based rates, terms and conditions for
services to shippers wishing to take interstate transportation
service. The FERC’s authority extends to:
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rates
and charges for natural gas transportation and related
services;
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certification
and construction of new facilities;
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extension
or abandonment of services and
facilities;
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maintenance
of accounts and records;
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relationships
between the pipeline and its energy
affiliates;
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terms
and conditions of service;
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depreciation
and amortization policies;
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accounting
rates for ratemaking purposes;
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acquisition
and disposition of facilities;
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initiation
and discontinuation of services;
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market
manipulation in connection with interstate sales, purchases, or
transportation of natural gas and
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information
posting requirements.
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Any
failure on our part to comply with the laws and regulations governing interstate
transmission service could result in the imposition of administrative, civil and
criminal penalties.
Gathering Pipeline
Regulation. Section 1(b) of the NGA exempts natural gas
gathering facilities from the jurisdiction of the FERC under the NGA. We
own a number of natural gas pipelines that we believe meet the traditional tests
that the FERC has used to establish a pipeline’s status as a gatherer not
subject to FERC jurisdiction. The distinction between FERC-regulated
transmission facilities and federally unregulated gathering facilities is the
subject of substantial, on-going litigation, so the classification and
regulation of one or more of our gathering systems may be subject to change
based on future determinations by the FERC, the courts or the U.S.
Congress.
State
regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory take requirements
and, in other instances, complaint-based rate regulation. We are subject
to state ratable take and common purchaser statutes. The ratable take
statutes generally require gatherers to take, without undue discrimination,
natural gas production that may be tendered to the gatherer for handling.
Similarly, common purchaser statutes generally require gatherers that
purchase gas to purchase without undue discrimination as to source of supply or
producer. These statutes are designed to prohibit discrimination in favor
of one producer over another or one source of supply over another. These
statutes have the effect of restricting our right as an owner of gathering
facilities to decide with whom we contract to purchase or gather natural
gas.
Natural
gas gathering may receive greater regulatory scrutiny at the state level now
that the FERC has allowed a number of interstate pipeline transmission companies
to transfer formerly jurisdictional assets to gathering companies. For
example, in 2006, the TRRC approved changes to its regulations governing
transportation and gathering services performed by intrastate pipelines that
prohibit such entities from unduly discriminating in favor of their
affiliates.
In
addition, many of the producing states have adopted some form of complaint-based
regulation that generally allows natural gas producers and shippers to file
complaints with state regulators in an effort to resolve grievances relating to
natural gas gathering access and rate discrimination. Our gathering
operations could be adversely affected should they be subject in the future to
the application of state or federal regulation of rates and services. Our
gathering operations also may be subject to safety and operational regulations
relating to the design, installation, testing, construction, operation,
replacement and management of gathering facilities. Additional rules and
legislation pertaining to these matters may be considered or adopted from time
to time. We cannot predict what effect, if any, such changes might have on
our operations, but the industry could be required to incur additional capital
expenditures and increased costs depending on future legislative and regulatory
changes.
Regulation of NGL and Crude Oil
Transportation. We have a pipeline in Louisiana that
transports NGLs in interstate commerce pursuant to a FERC-approved
tariff. Under the ICA, the Energy Policy Act of 1992, and rules and
orders promulgated thereunder, the FERC regulates the tariff rates for
interstate NGL transportation and imposes reporting and a number of other
requirements. Our NGL transportation tariff is required to be just
and reasonable and not unduly discriminatory or confer any undue
preference. FERC has established an indexing system for
transportation rates for oil, NGLs and other products that allows for an
annual inflation-based increase in the cost of transporting these liquids to the
shipper. The implementation of these regulations has not had a
material adverse effect on our results of operations. Any failure on
our part to comply with the laws and regulations governing interstate
transmission of NGLs could result in the imposition of administrative, civil and
criminal penalties. We also have a Texas common carrier pipeline that
provides intrastate transportation of crude oil subject to a local tariff
approved by and on file with the TRRC. This pipeline is subject to a
number of TRRC regulatory requirements governing rates and terms and conditions
of service.
Sales of Natural
Gas. Our ability to sell gas in interstate markets is subject to
FERC authority and its rules prohibiting natural gas market
manipulation. The price at which we buy and sell natural gas
currently is not subject to federal regulation and, for the most part, is not
subject to state regulation. The prices at which we sell natural gas are
affected by many competitive factors, including the availability, terms and cost
of pipeline transportation. As noted above, the price and terms of access
to pipeline transportation are subject to extensive federal and state
regulation. FERC is continually proposing and implementing new rules and
regulations affecting interstate transportation. These
initiatives also may affect the intrastate transportation of natural gas under
certain circumstances. The stated purpose of many of these regulatory
changes is to promote competition among the various sectors of the natural gas
industry. We do not believe that we will be affected by any such FERC
action in a manner materially differently than other natural gas companies with
whom we compete.
Sales of Liquids. Sales of crude oil,
natural gas, condensate and NGLs are not currently regulated. Prices of
these products are set by the market rather than by regulation.
Anti-Market Manipulation
Requirements. Under the Energy Policy Act of 2005, FERC
possesses regulatory oversight over natural gas markets, including the purchase,
sale and transportation activities of non-interstate pipelines and other natural
gas market participants. The CFTC also holds authority to monitor
certain segments of the physical and futures energy commodities market pursuant
to the Commodity Exchange Act. With regard to our physical purchases
and sales of natural gas, NGLs and crude oil, our gathering or transportation of
these energy commodities, and any related hedging activities that we undertake,
we are required to observe these anti-market manipulation laws and related
regulations enforced by FERC and/or the CFTC. These agencies hold
substantial enforcement authority, including the ability to assess civil
penalties of up to $1,000,000 per day per violation, to order disgorgement of
profits and to recommend criminal penalties. Should we violate the
anti-market manipulation laws and regulations, we could also be subject to
related third party damage claims by, among others, sellers, royalty owners and
taxing authorities.
Anti-terrorism
Regulations. We may be subject to future anti-terrorism
requirements of the DHS. The DHS has issued its National
Infrastructure Protection Plan calling for broadened efforts to “reduce
vulnerability, deter threats, and minimize the consequences of attacks and other
incidents” as they relate to pipelines, processing facilities and other
infrastructure. The precise parameters of DHS regulations and any related
sector-specific requirements are not currently known, and there can be no
guarantee that any final anti-terrorism rules that might be applicable to our
facilities will not impose costs and administrative burdens on our operations.
Environmental
Matters
General. Our operation
of processing plants, pipelines and associated facilities, including
compression, in connection with the gathering and processing of natural gas and
the transportation of NGLs is subject to stringent and complex federal, state
and local laws and regulations, including those governing, among other things,
air emissions, wastewater discharges, the use, management and disposal of
hazardous and nonhazardous materials and wastes, and the cleanup of
contamination. Noncompliance with such laws and regulations, or incidents
resulting in environmental releases, could cause us to incur substantial costs,
penalties, fines and other criminal sanctions, third party claims for personal
injury or property damage, investments to retrofit or upgrade our facilities and
programs, or curtailment of operations. As with the industry
generally, compliance with existing and anticipated environmental laws and
regulations increases our overall costs of doing business, including our cost of
planning, constructing and operating our plants, pipelines and other
facilities. Included in our construction and operation costs are capital
cost items necessary to maintain or upgrade our equipment and facilities to
remain in compliance with environmental laws and regulations.
We have
implemented procedures to ensure that all governmental environmental approvals
for both existing operations and those under construction are updated as
circumstances require. We believe that our operations and facilities are
in substantial compliance with applicable environmental laws and regulations and
that the cost of compliance with such laws and regulations will not have a
material adverse effect on our business, results of operations and financial
condition.
Under an
omnibus agreement, Regency Acquisition LP, the entity that formerly owned our
General Partner, agreed to indemnify us in an aggregate amount not to exceed
$8,600,000, generally for three years after February 3, 2006, for certain
environmental noncompliance and remediation liabilities associated with the
assets transferred to us and occurring or existing before that date. For a
discussion of the omnibus agreement, please read “Item 13 — Certain
Relationships and Related Transactions, and Director Independence — Omnibus
Agreement.”
Hazardous Substances and Waste Materials. To a
large extent, the environmental laws and regulations affecting our operations
relate to the release of hazardous substances and waste materials into soils,
groundwater and surface water and include measures to control contamination of
the environment. These laws and regulations generally regulate the
generation, storage, treatment, transportation and disposal of hazardous
substances and waste materials and may require investigatory and remedial
actions at sites where such material has been released or disposed. For
example, CERCLA, also known as the “Superfund” law, and comparable state laws,
impose liability without regard to fault or the legality of the original conduct
on certain classes of persons that contributed to a release of a “hazardous
substance” into the environment. These persons include the owner and
operator of the site where a release occurred and companies that disposed or
arranged for the disposal of the hazardous substance that has been released into
the environment. Under CERCLA, these persons may be subject to joint and
several liability, without regard to fault, for, among other things, the costs
of investigating and remediating the hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of certain health studies. CERCLA and comparable state law also
authorize the federal EPA, its state counterparts, and, in some instances,
third parties to take actions in response to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. It is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by hazardous substances or other pollutants released into the
environment. Although “petroleum” as well as natural gas and NGLs are
excluded from CERCLA’s definition of a “hazardous substance,” in the course of
our ordinary operations we generate wastes that may fall within that definition,
and certain state law analogs to CERCLA, including the Texas Solid Waste
Disposal Act, do not contain a similar exclusion for petroleum. We may be
responsible under CERCLA or state laws for all or part of the costs required to
clean up sites at which such substances or wastes have been disposed. We
have not received any notification that we may be potentially responsible for
cleanup costs under CERCLA or comparable state laws.
We also
generate both hazardous and nonhazardous wastes that are subject to requirements
of the federal RCRA, and comparable state statutes. From time to
time, the EPA has considered the adoption of stricter handling, storage, and
disposal standards for nonhazardous wastes, including crude oil and natural gas
wastes. We are not currently required to comply with a substantial portion
of the RCRA requirements at many of our facilities because the minimal
quantities of hazardous wastes generated there make us subject to less stringent
management standards. It is possible, however, that some wastes generated
by us that are currently classified as nonhazardous may in the future be
designated as “hazardous wastes,” resulting in the wastes being subject to more
rigorous and costly disposal requirements, or that the full complement of RCRA
standards could be applied to facilities that generate lesser amounts of
hazardous waste. Changes in applicable regulations may result in a
material increase in our capital expenditures or plant operating and maintenance
expense.
We
currently own or lease sites that have been used over the years by prior owners
and by us for natural gas gathering, processing and transportation. Solid waste
disposal practices within the midstream gas industry have improved over the
years with the passage and implementation of various environmental laws and
regulations. Nevertheless, some hydrocarbons and wastes have been disposed
of or released on or under various sites during the operating history of those
facilities that are now owned or leased by us.
Notwithstanding
the possibility that these dispositions may have occurred during the ownership
of these assets by others, these sites may be subject to CERCLA, RCRA and
comparable state laws. Under these laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or contamination (including soil and groundwater
contamination) or to prevent the migration of contamination.
Assets Acquired from El Paso. Under the agreement
pursuant to which our operating partnership acquired assets from El Paso Field
Services LP and its affiliates in 2003, we are indemnified for certain
environmental matters. Those provisions include an indemnity by the El Paso
sellers against a variety of environmental claims for a period of five years up
to an aggregate of $84,000,000. The agreement also included an escrow of
$9,000,000 relating to claims, including environmental claims. In response
to our submission of a claim to the El Paso sellers for a variety of
environmental defects at these assets, the El Paso sellers have agreed to
maintain $5,400,000 in the escrow account to pay any claims for environmental
matters ultimately deemed to be covered by their indemnity. This amount
represents the upper end of the estimated remediation cost calculated by Regency
based on the results of its investigations of these assets.
Since the
time of this agreement, a Final Site Investigation Report has been prepared.
Based on this additional investigation, environmental issues exist with
respect to four facilities, including the two subject to accepted claims and two
of our processing plants. The estimated remediation costs associated with the
processing plants aggregate $2,750,000. We believe that any of our
obligations to remediate the properties is subject to the indemnity under the El
Paso PSA, and we intend to reinstate the claims for indemnification for these
plant sites.
In
January 2008, the Board of Directors of the General Partner and 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 at that site. All sites for which the
Partnership made environmental claims against El Paso are either addressed in
the settlement or have already been resolved. The Partnership will
release all but $1,500,000 from the escrow fund maintained to secure El Paso’s
obligations. This amount will be further reduced per a specified
schedule as El Paso completes its cleanups and the remainder will be released
upon completion.
West Texas Assets. A Phase I
environmental study was performed on our west Texas assets in connection with
our investigation of those assets prior to our purchase of them 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. We believe that the likelihood that we will be liable for any
significant potential remediation liabilities identified in the study is
remote. At the time of the negotiation of the agreement to acquire the west
Texas assets, management of RGS obtained an insurance policy against specified
risks of environmental claims (other than those items known to exist). 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.
Air Emissions. Our
operations are subject to the federal Clean Air Act and comparable state laws
and regulations. These laws and regulations regulate emissions of air
pollutants from various industrial sources, including our processing plants, and
also impose various monitoring and reporting requirements. Such laws and
regulations may require that we obtain pre-approval for the construction or
modification of certain projects or facilities, such as our processing plants
and compression facilities, expected to produce air emissions or to result in
the increase of existing air emissions, that we obtain and strictly comply with
air permits containing various emissions and operational limitations, or that we
utilize specific emission control technologies to limit emissions. We will
be required to incur certain capital expenditures in the future for air
pollution control equipment in connection with obtaining and maintaining
operating permits and approvals for air emissions. In addition, our
processing plants, pipelines and compression facilities are becoming subject to
increasingly stringent regulations, including regulations that require the
installation of control technology or the implementation of work practices to
control hazardous air pollutants. Moreover, the Clean Air Act requires an
operating permit for major sources of emissions and this requirement applies to
some of our facilities. We believe that our operations are in substantial
compliance with the federal Clean Air Act and comparable state
laws.
Clean Water Act. The
Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean
Water Act, and comparable state laws impose restrictions and strict controls
regarding the discharge of pollutants, including natural gas liquid-related
wastes, into waters of the United States. Pursuant to the Clean Water Act
and similar state laws, a NPDES, or state permit, or both, must be obtained
to discharge pollutants into federal and state waters. The Clean Water Act
and comparable state laws and their respective regulations provide for
administrative, civil and criminal penalties for discharges of unauthorized
pollutants into the water and also provide for penalties and liability for the
costs of removing spills from such waters. In addition, the Clean Water
Act and comparable state laws require that individual permits or coverage under
general permits be obtained by subject facilities for discharges of storm water
runoff. We believe that we are in substantial compliance with Clean Water
Act permitting requirements as well as the conditions imposed thereunder, and
that our continued compliance with such existing permit conditions will not have
a material adverse effect on our business, financial condition, or results of
operations.
Endangered Species
Act. The Endangered Species Act restricts activities that may affect
endangered or threatened species or their habitat. While we have no reason
to believe that we operate in any area that is currently designated as a habitat
for endangered or threatened species, the discovery of previously unidentified
endangered species could cause us to incur additional costs or to become subject
to operating restrictions or bans in the affected areas.
Employee Health and
Safety. We are subject to the requirements of the federal OSHA,
and comparable state laws that regulate the protection of the health and safety
of workers. In addition, the OSHA hazard communication standard requires
that information be maintained about hazardous materials used or produced in
operations and that this information be provided to employees, state and local
government authorities and citizens. We believe that our operations are in
substantial compliance with the OSHA requirements, including general industry
standards, recordkeeping requirements, and monitoring of occupational exposure
to regulated substances.
Safety
Regulations. Those pipelines through which we transport mixed NGLs
(exclusively to other NGL pipelines) are subject to regulation by the DOT,
under the HLPSA, relating to the design, installation, testing,
construction, operation, replacement and management of pipeline facilities.
The HLPSA requires any entity that owns or operates liquids pipelines to
comply with the regulations under the HLPSA, to permit access to and allow
copying of records and to submit certain reports and provide other information
as required by the Secretary of Transportation. We believe our liquids
pipelines are in substantial compliance with applicable HLPSA
requirements.
Our
interstate, intrastate and certain of our gathering pipelines are also are
subject to regulation by the DOT under the NGPSA, which covers natural gas,
crude oil, carbon dioxide, NGLs and petroleum products pipelines, and under the
Pipeline Safety Improvement Act of 2002, as amended. Pursuant to
these authorities, the DOT has established a series of rules which require
pipeline operators to develop and implement “integrity management programs” for
natural gas pipelines located in areas where the consequences of potential
pipeline accidents pose the greatest risk to people and their
property. Similar rules are also in place for operators of hazardous
liquid pipelines. The DOT’s integrity management rules establish
requirements relating to the design, installation, testing, construction,
operation, inspection, replacement and management of pipeline facilities.
We believe that our pipeline operations are in substantial compliance with
applicable NGPSA requirements.
The
states administer federal pipeline safety standards under the NGPSA and have the
authority to conduct pipeline inspections, to investigate accidents, and to
oversee compliance and enforcement, safety programs, and record maintenance and
reporting. Congress, the DOT and individual states may pass additional
pipeline safety requirements, but such requirements, if adopted, would not be
expected to affect us disproportionately relative to other companies in our
industry. We believe, based on current information, that any costs that we
may incur relating to environmental matters will not adversely affect us.
We cannot be certain, however, that identification of presently
unidentified conditions, more vigorous enforcement by regulatory agencies,
enactment of more stringent laws and regulations, or other unanticipated events
will not arise in the future and give rise to material environmental liabilities
that could have a material adverse effect on our business, financial condition
or results of operations.
TCEQ Notice of
Enforcement. On February 15, 2008, the Texas Commission on
Environmental Quality, or TCEQ, sent us a notice of enforcement, or NOE,
relating to the air emissions at our Tilden processing plant. The NOE
relates to 15 alleged violations occurring during the period from March 2006
through July 2007 of the emissions event reporting and recordkeeping
requirements of the TCEQs rules. Specifically, it is alleged that one
of our subsidiaries failed to report, using the TCEQ’s electronic data base for
emissions events, 15 emissions events within 24 hours of the incident, as
required. 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, indeed, the subsidiary paid the emission fines in
connection with all the incidents. Using that procedure, all except
one were timely. The TCEQ has, prior to our subsidiary acquiring the
Tilden facility, established its electronic data base for emissions events, but
the subsidiary did not report using that electronic facility. It is
the failure to report each incident timely using the electronic reporting
procedure that is the subject of the NOE. Representatives of the
Partnership are scheduled to meet with the staff of the TCEQ in the near future
regarding the NOE. Management of the General Partner does not
expect the NOE to have a material adverse effect on its results of operations or
financial condition.
EMPLOYEES
As of
December 31, 2007, our General Partner employs 317 employees, of whom 182
are field operating employees and 135 are mid-and senior-level management and
staff. None of these employees is represented by a labor union and there
are no outstanding collective bargaining agreements to which our General Partner
is a party. Our General Partner believes that it has good relations with
its employees. With our CDM acquisition, we now employ 609
employees.
AVAILABLE
INFORMATION
The
Partnership files annual and quarterly financial reports, as well as interim
updates of a material nature to investors with the Securities and Exchange
Commission. You may read and copy any of these materials at the SEC’s
Public Reference Room at 100 F. Street, NE, Room 1580, Washington,
DC 20549. Information on the operation of the Public Reference Room
is available by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC
maintains an Internet site that contains reports, proxy and information
statements, and other information regarding issuers that file electronically
with the SEC. The address of that site is http://www.sec.gov
..
The
Partnership makes its SEC filings available to the public, free of charge and as
soon as practicable after they are filed with the SEC, through its Internet site
located at
http://www.regencyenergy.com . Our annual reports are filed on Form
10-K, our quarterly reports are filed on Form 10-Q, and current-event reports
are filed on Form 8-K; we also file amendments to reports filed or furnished
pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of
1934. References to our website addressed in this report are provided as a
convenience and do not constitute, or should be viewed as, an incorporation by
reference of the information contained on, or available through, the
website. Therefore, such information should not be considered part of this
report.
RISKS
RELATED TO OUR BUSINESS
We
may not have sufficient cash from operations to enable us to pay our current
quarterly distribution following the establishment of cash reserves and payment
of fees and expenses, including reimbursement of fees and expenses of our
general partner.
We may
not have sufficient available cash from operating surplus each quarter to pay
our MQD. The amount of cash we can distribute on our units depends
principally on the amount of cash we generate from our operations, which will
fluctuate from quarter to quarter based on, among other things:
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the
fees we charge and the margins we realize for our services and
sales;
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the
prices of, level of production of, and demand for natural gas and
NGLs;
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the
volumes of natural gas we gather, process and
transport;
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the
level of our operating costs, including reimbursement of fees and expenses
of our general partner; and
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prevailing
economic conditions.
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In
addition, the actual amount of cash we will have available for distribution will
depend on other factors, some of which are beyond our control,
including:
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our
debt service requirements;
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fluctuations
in our working capital needs;
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our
ability to borrow funds and access capital
markets;
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restrictions
contained in our debt agreements;
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the
level of capital expenditures we
make;
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the
cost of acquisitions, if any; and
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the
amount of cash reserves established by our general
partner.
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You
should be aware that the amount of cash we have available for distribution
depends primarily upon our cash flow and not solely on profitability, which will
be affected by non-cash items. As a result, we may make cash
distributions during periods when we record losses for financial accounting
purposes and may not make cash distributions during periods when we record net
earnings for financial accounting purposes.
We
may be unable to integrate successfully the operations of future
acquisitions with our operations and we may not realize all the anticipated
benefits of the past and any future acquisitions.
Integration
of acquisitions with our business and operations is a complex, time consuming,
and costly process. Failure to integrate acquisitions successfully with
our business and operations in a timely manner may have a material adverse
effect on our business, financial condition, and results of operations. We
cannot assure you that we will achieve the desired profitability from past or
future acquisitions. In addition, failure to assimilate future
acquisitions successfully could adversely affect our financial condition and
results of operations. Our acquisitions involve numerous risks,
including:
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operating
a significantly larger combined organization and adding
operations;
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difficulties
in the assimilation of the assets and operations of the acquired
businesses, especially if the assets acquired are in a new business
segment or geographic area, such as the assets acquired in the CDM
acquisition;
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the
risk that natural gas reserves expected to support the acquired assets may
not be of the anticipated magnitude or may not be developed as
anticipated;
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the
loss of significant producers or markets or key employees from the
acquired businesses;
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the
diversion of management’s attention from other business
concerns;
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the
failure to realize expected profitability, growth or synergies and cost
savings;
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coordinating
geographically disparate organizations, systems, and facilities;
and
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coordinating
or consolidating corporate and administrative
functions.
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Further,
unexpected costs and challenges may arise whenever businesses with different
operations or management are combined, and we may experience unanticipated
delays in realizing the benefits of an acquisition. If we consummate any
future acquisition, our capitalization and results of operation may change
significantly, and you may not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in evaluating
future acquisitions.
Because
of the natural decline in production from existing wells, our success depends on
our ability to obtain new supplies of natural gas, which involves factors beyond
our control. Any decrease in supplies of natural gas in our areas of
operation could adversely affect our business and operating
results.
Our
gathering and processing and transportation pipeline systems are dependent on
the level of production from natural gas wells that supply our systems and from
which production will naturally decline over time. As a result, our cash
flows associated with these wells will also decline over time. In order to
maintain or increase through-put volume levels on our gathering and
transportation pipeline systems and the asset utilization rates at our natural
gas processing plants, we must continually obtain new supplies. The
primary factors affecting our ability to obtain new supplies of natural gas and
attract new customers to our assets are: the level of successful drilling
activity near our systems and our ability to compete with other gathering and
processing companies for volumes from successful new wells.
The level
of natural gas drilling activity is dependent on economic and business factors
beyond our control. The primary factor that impacts drilling decisions is
natural gas prices. A sustained decline in natural gas prices could result
in a decrease in exploration and development activities in the fields served by
our gathering and processing facilities and pipeline transportation systems,
which would lead to reduced utilization of these assets. Other factors
that impact production decisions include producers’ capital budget limitations,
the ability of producers to obtain necessary drilling and other governmental
permits and regulatory changes. Because of these factors, even if
additional natural gas reserves were discovered in areas served by our assets,
producers may choose not to develop
those reserves. If we were not able to obtain new supplies of natural gas
to replace the natural decline in volumes from existing wells due to reductions
in drilling activity or competition, through-put volumes on our pipelines and
the utilization rates of our processing facilities would decline, which could
have a material adverse effect on our business, results of operations and
financial condition.
Our
natural gas contract compression operations significantly depend upon the
continued demand for and production of natural gas and crude oil. Demand
may be affected by, among other factors, natural gas prices, crude oil prices,
weather, demand for energy, and availability of alternative energy sources.
Any prolonged, substantial reduction in the demand for natural gas or
crude oil would, in all likelihood, depress the level of production activity and
result in a decline in the demand for our contract compression services and
products. Lower natural gas prices or crude oil prices over the long-term
could result in a decline in the production of natural gas or crude oil,
respectively, resulting in reduced demand for our natural gas contract
compression services. Additionally, production from natural gas sources such as
longer-lived tight sands, shales and coalbeds constitute an increasing
percentage of our compression services business. Such sources are
generally less economically feasible to produce in lower natural gas price
environments, and a reduction in demand for natural gas or natural gas lift for
crude oil may cause such sources of natural gas to be uneconomic to drill and
produce, which could in turn negatively impact the demand for our
services.
We
depend on certain key producers and other customers for a significant portion of
our supply of natural gas and contract compression revenue. The loss of,
or reduction in, any of these key producers or customers could adversely affect
our business and operating results.
We rely
on a limited number of producers and other customers for a significant portion
of our natural gas supplies and our contracts for compression
services. These contracts have terms that range from month-to-month
to life of lease. As these contracts expire, we will have to negotiate
extensions or renewals or replace the contracts with those of other suppliers.
We may be unable to obtain new or renewed contracts on favorable terms, if
at all. The loss of all or even a portion of the volumes of natural gas
supplied by these producers and other customers, as a result of competition or
otherwise, could have a material adverse effect on our business, results of
operations, and financial condition. For example, purchases from KCS
Resources, Inc. made up 16 percent of the volumes underlying the cost of gas and
liquids on our consolidated statement of operations during the year ended
December 31, 2007.
Our
contract compression segment depends on particular suppliers and is
vulnerable to product shortages and price increases, which could have a negative
impact on our results of operations.
The
principal manufacturers of components for our natural gas compression equipment
include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel
Corporation for compressors and frames. Our reliance on these suppliers
involves several risks, including price increases and a potential inability to
obtain an adequate supply of required components in a timely manner. We
also rely primarily on two vendors, Spitzer Corp. and Standard Equipment Corp.,
to package and assemble our compression units. We do not have long-term
contracts with these suppliers or packagers, and a partial or complete loss of
certain of these sources could have a negative impact on our results of
operations and could damage our customer relationships. In addition, since
we expect any increase in component prices for compression equipment or
packaging costs will be passed on to us, a significant increase in their pricing
could have a negative impact on our results of operations.
In
accordance with industry practice, we do not obtain independent evaluations of
natural gas reserves dedicated to our gathering systems. Accordingly,
volumes of natural gas gathered on our gathering systems in the future could be
less than we anticipate, which could adversely affect our business and operating
results.
We do not
obtain independent evaluations of natural gas reserves connected to our
gathering systems due to the unwillingness of producers to provide reserve
information as well as the cost of such evaluations. Accordingly, we do
not have estimates of total reserves dedicated to our systems or the anticipated
lives of such reserves. If the total reserves or estimated lives of the
reserves connected to our gathering systems are less than we anticipate and we
are unable to secure additional sources of natural gas, then the volumes of
natural gas gathered on our gathering systems in the future could be less than
we anticipate. A decline in the volumes of natural gas gathered on our
gathering systems could have an adverse effect on our business, results of
operations, and financial condition.
Natural
gas, NGLs and other commodity prices are volatile, and a reduction in these
prices could adversely affect our cash flow and operating results.
We are
subject to risks due to frequent and often substantial fluctuations in commodity
prices. NGL prices generally fluctuate on a basis that correlates to
fluctuations in crude oil prices. In the past, the prices of natural gas
and crude oil have been extremely volatile, and we expect this volatility to
continue. The markets and prices for natural gas and NGLs depend upon
factors beyond our control. These factors include demand for oil, natural
gas and NGLs, which fluctuates with changes in market and economic conditions
and other factors, including:
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the
impact of weather on the demand for oil and natural
gas;
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the
level of domestic oil and natural gas
production;
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the
availability of imported oil and natural
gas;
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actions
taken by foreign oil and gas producing
nations;
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the
availability of local, intrastate and interstate transportation
systems;
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the
availability and marketing of competitive
fuels;
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the
impact of energy conservation efforts;
and
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the
extent of governmental regulation and
taxation.
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Our
natural gas gathering and processing businesses operate under two types of
contractual arrangements that expose our cash flows to increases and decreases
in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole
arrangements. Under percentage-of-proceeds arrangements, we generally
purchase natural gas from producers and retain an agreed percentage of the
proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality
gas and NGLs resulting from our processing activities. Under keep-whole
arrangements, we receive the NGLs removed from the natural gas during our
processing operations as the fee for providing our services in exchange for
replacing the thermal content removed as NGLs with a like thermal content in
pipeline-quality gas or its cash equivalent. Under these types of
arrangements our revenues and our cash flows increase or decrease as the prices
of natural gas and NGLs fluctuate. The relationship between natural gas
prices and NGL prices may also affect our profitability. When natural gas
prices are low relative to NGL prices, it is more profitable for us to process
natural gas under keep-whole arrangements. When natural gas prices are
high relative to NGL prices, it is less profitable for us and our customers to
process natural gas both because of the higher value of natural gas and of the
increased cost (principally that of natural gas as a feedstock and a fuel) of
separating the mixed NGLs from the natural gas. As a result, we may
experience periods in which higher natural gas prices relative to NGL prices
reduce our processing margins or reduce the volume of natural gas processed at
some of our plants.
In
our gathering and processing operations, we purchase raw natural gas containing
significant quantities of NGLs, process the raw natural gas and sell the
processed gas and NGLs. If we are unsuccessful in balancing the purchase
of raw natural gas with its component NGLs and our sales of pipeline quality gas
and NGLs, our exposure to commodity price risks will increase.
We
purchase from producers and other customers a substantial amount of the natural
gas that flows through our natural gas gathering and processing systems and our
transportation pipeline for resale to third parties, including natural gas
marketers and utilities. We may not be successful in balancing our
purchases and sales. In addition, a producer could fail to deliver
promised volumes or could deliver volumes in excess of contracted volumes, a
purchaser could purchase less than contracted volumes, or the natural gas price
differential between the regions in which we operate could vary unexpectedly.
Any of these actions could cause our purchases and sales not to be
balanced. If our purchases and sales are not balanced, we will face increased
exposure to commodity price risks and could have increased volatility in our
operating results.
Our
results of operations and cash flow may be adversely affected by risks
associated with our hedging activities.
In
performing our functions in the Gathering and Processing segment, we are a
seller of NGLs and are exposed to commodity price risk associated with downward
movements in NGL prices. As a result of the volatility of NGL prices, we
have executed swap contracts settled against ethane, propane, normal butane,
natural gasoline and west Texas intermediate crude market prices. We
continually monitor our hedging and contract portfolio and expect to continue to
adjust our hedge position as conditions warrant. Also, we may seek to
limit our exposure to changes in interest rates by using financial derivative
instruments and other hedging mechanisms from time to time. For more
information about our risk management activities, please read “Item 7A —
Quantitative and Qualitative Disclosures about Market Risk.”
Even
though our management monitors our hedging activities, these activities can
result in substantial losses. Such losses could occur under various
circumstances, including any circumstance in which a counterparty does not
perform its obligations under the applicable hedging arrangement, the hedging
arrangement is imperfect, or our hedging policies and procedures are not
followed or do not work as planned.
To
the extent that we intend to grow internally through construction of new, or
modification of existing, facilities, we may not be able to manage that growth
effectively, which could decrease our cash flow and adversely affect our results
of operations.
A
principal focus of our strategy is to continue to grow by expanding our business
both internally and through acquisitions. Our ability to grow internally
will depend on a number of factors, some of which will be beyond our control.
In general, the construction of additions or modifications to our existing
systems, and the construction of new midstream assets involve numerous
regulatory, environmental, political and legal uncertainties beyond our control.
Any project that we undertake may not be completed on schedule, at
budgeted cost or at all. Construction may occur over an extended period, and we
are not likely to receive a material increase in revenues related to such
project until it is completed. Moreover, our revenues may not increase
immediately upon the completion of construction because the anticipated growth
in gas production that the project was intended to capture does not materialize,
our estimates of the growth in production prove inaccurate or for other reasons.
For any of these reasons, newly constructed or modified midstream
facilities may not generate our expected investment return and that, in turn,
could adversely affect our cash flows and results of operations.
In
addition, our ability to undertake to grow in this fashion will depend on our
ability to finance the construction or modification project and on our ability
to hire, train, and retain qualified personnel to manage and operate these
facilities when completed.
Because
we distribute all of our available cash to our unitholders, our future growth
may be limited.
Since we
will distribute all of our available cash to our unitholders, subject to the
limitations on restricted payments contained in the indenture governing our
senior notes and our credit facility, we will depend on financing provided by
commercial banks and other lenders and the issuance of debt and equity
securities to finance any significant internal organic growth or
acquisitions. If we are unable to obtain adequate financing from
these sources, our ability to grow will be limited.
Our
industry is highly competitive, and increased competitive pressure could
adversely affect our business and operating results.
We
compete with similar enterprises in each of our areas of operations. Some
of our competitors are large oil, natural gas and petrochemical companies that
have greater financial resources and access to supplies of natural gas than we
do. In addition, our customers who are significant producers or consumers
of NGLs may develop their own processing facilities in lieu of using ours.
Similarly, competitors may establish new connections with pipeline systems
that would create additional competition for services that we provide to our
customers. Our ability to renew or replace existing contracts with our
customers at rates sufficient to maintain current revenues and cash flows could
be adversely affected by the activities of our competitors.
The
natural gas contract compression business is highly competitive, and there are
low barriers to entry for individual projects. In addition, some of our
competitors are large national and multinational companies that have greater
financial and other resources than we do. Our ability to renew or replace
existing contracts with our customers at rates sufficient to maintain current
revenue and cash flows could be adversely affected by the activities of our
competitors and our customers. If our competitors substantially increase
the resources they devote to the development and marketing of competitive
services or substantially decrease the prices at which they offer their
services, we may be unable to compete effectively. Some of these
competitors may expand or construct newer or more powerful compressor fleets
that would create additional competition for us. In addition, our
customers that are significant producers of natural gas and crude oil may
purchase and operate their own compressor fleets in lieu of using our natural
gas contract compression services.
All of
these competitive pressures could have a material adverse effect on our
business, results of operations, and financial condition.
If
third-party pipelines interconnected to our processing plants become unavailable
to transport NGLs, our cash flow and results of operations could be adversely
affected.
We depend
upon third party pipelines that provide delivery options to and from our
processing plants for the benefit of our customers. If any of these
pipelines become unavailable to transport the NGLs produced at our related
processing plants, we would be required to find alternative means to transport
the NGLs from our processing plants, which could increase our costs, reduce
the revenues we might obtain from the sale of NGLs, or reduce our ability to
process natural gas at these plants.
We
are exposed to the credit risks of our key customers, and any material
nonpayment or nonperformance by our key customers could adversely affect our
cash flow and results of operations.
We are
subject to risks of loss resulting from nonpayment or nonperformance by our
customers. Any material nonpayment or nonperformance by our key customers
could reduce our ability to make distributions to our unitholders.
Furthermore, some of our customers may be highly leveraged and subject to
their own operating and regulatory risks, which increases the risk that they may
default on their obligations to us.
Our
business involves many hazards and operational risks, some of which may not be
fully covered by insurance. If a significant accident or event occurs that
is not fully insured, our operations and financial results could be adversely
affected.
Our
operations are subject to the many hazards inherent in the gathering, processing
and transportation of natural gas and NGLs, including:
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damage
to our gathering and processing facilities, pipelines, related equipment
and surrounding properties caused by tornadoes, floods, fires and other
natural disasters and acts of
terrorism;
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inadvertent
damage from construction and farm
equipment;
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leaks
of natural gas, NGLs and other hydrocarbons or losses of natural gas or
NGLs as a result of the malfunction of pipelines, measurement equipment or
facilities at receipt or delivery
points;
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fires
and explosions;
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weather
related hazards, such as hurricanes and extensive rains which could delay
the construction of assets and extreme cold which can cause freezing of
pipelines, limiting throughput; and
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other
hazards, including those associated with high-sulfur content, or sour gas,
such as an accidental discharge of hydrogen sulfide gas, that could also
result in personal injury and loss of life, pollution and suspension of
operations.
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These
risks could result in substantial losses due to personal injury or loss of life,
severe damage to and destruction of property and equipment and pollution or
other environmental damage and may result in curtailment or suspension of our
related operations. A natural disaster or other hazard affecting the areas
in which we operate could have a material adverse effect on our operations.
We are not insured against all environmental events that might occur.
If a significant accident or event occurs that is not insured or fully
insured, it could adversely affect our operations and financial
condition.
Failure
of the gas that we ship on our pipelines to meet the specifications of
interconnecting interstate pipelines could result in curtailments by the
interstate pipelines.
The
markets to which the shippers on our pipelines ship natural gas include
interstate pipelines. These interstate pipelines establish specifications
for the natural gas that they are willing to accept, which include requirements
such as hydrocarbon dewpoint, temperature, and foreign content including water,
sulfur, carbon dioxide, and hydrogen sulfide. These specifications vary by
interstate pipeline. If the total mix of natural gas shipped by the
shippers on our pipeline fails to meet the specifications of a particular
interstate pipeline, it may refuse to accept all or a part of the natural gas
scheduled for delivery to it. In those circumstances, we may be required
to find alternative markets for that gas or to shut-in the producers of the
non-conforming gas, potentially reducing our through-put volumes or
revenues.
We
may incur significant costs and liabilities as a result of pipeline integrity
management program testing and any related pipeline repair, or preventative or
remedial measures.
The
DOT has adopted regulations requiring pipeline operators to develop
integrity management programs for transportation pipelines and certain gathering
lines located where a leak or rupture could do the most harm in “high
consequence areas.” The regulations require operators
to:
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perform
ongoing assessments of pipeline
integrity;
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identify
and characterize applicable threats to pipeline segments that could impact
a high consequence area;
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improve
data collection, integration and
analysis;
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repair
and remediate the pipeline as necessary;
and
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implement
preventive and mitigating actions.
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We
currently estimate that we will incur costs of $1,200,000 between 2008 and 2010
to implement pipeline integrity management program testing along certain
segments of our pipeline, as required by existing DOT regulations. This
estimate does not include the costs, if any, for repair, remediation,
preventative or mitigating actions that may be determined to be necessary as a
result of the testing program, which could be substantial.
We
do not own all of the land on which our pipelines and facilities have been
constructed, and we are therefore subject to the possibility of increased costs
or the inability to retain necessary land use.
We obtain
the rights to construct and operate our pipelines on land owned by third parties
and governmental agencies for specified periods of time. Many of these
rights-of-way are perpetual in duration; others have terms ranging from five to
ten years. Many are subject to rights of reversion in the case of
non-utilization for periods ranging from one to three years. In addition,
some of our processing facilities are located on leased premises. Our loss
of these rights, through our inability to renew right-of-way contracts or leases
or otherwise, could have a material adverse effect on our business, results of
operations and financial condition.
In
addition, the construction of additions to our existing gathering and
transportation assets may require us to obtain new rights-of-way prior to
constructing new pipelines. We may be unable to obtain such rights-of-way
to connect new natural gas supplies to our existing gathering lines or to
capitalize on other attractive expansion opportunities. If the cost of
obtaining new rights-of-way increases, then our cash flows and growth
opportunities could be adversely affected.
Our
interstate gas transportation operations, including Section 311 service
performed by its intrastate pipelines, are subject to FERC regulation; failure
to comply with applicable regulation, future changes in regulations or policies,
or the establishment of more onerous terms and conditions applicable to
interstate or Section 311 natural gas transportation service could adversely
affect our business.
FERC has
broad regulatory authority over the business and operations of interstate
natural gas pipelines, such as the pipeline owned by our subsidiary,
GSTC. Under the NGA, rates charged for interstate natural gas
transmission must be just and reasonable, and amounts collected in excess of
just and reasonable rates are subject to refund with interest. GSTC
holds a FERC-approved tariff setting forth cost-based rates, terms and
conditions for services to shippers wishing to take interstate transportation
service. In addition, FERC regulates the rates, terms and conditions
of service with respect to Section 311 transportation service provided by
RIGS. Any failure on our part to comply with applicable FERC
administered statutes, rules, regulations and orders could, in the case of RIGS,
result in an alteration of our jurisdictional status, or could result in the
imposition of administrative, civil and criminal penalties, or
both. In addition, FERC has authority to alter its rules, regulations
and policies to comply with its statutory authority. We cannot give
any assurance regarding the likely future regulations under which RIGS or GSTC
will operate its interstate transportation business or the effect such
regulation could have on our business, results of operations, or ability to make
distributions.
As
a limited partnership entity, we may be disadvantaged in calculating its
cost-of-service for rate-making purposes.
Under
current policy applied under the NGA, the FERC permits interstate gas pipelines
to include, in the cost-of-service used as the basis for calculating the
pipeline’s regulated rates, a tax allowance reflecting the actual or potential
income tax liability on public utility income attributable to all partnership or
limited liability company interests, if the ultimate owner of the interest has
an actual or potential income tax liability on such income. Whether a
pipeline’s owners have such actual or potential income tax liability will be
reviewed by the FERC on a case-by-case basis. In connection with its
upcoming Section 311 rate case required to be initiated on or before May 1, RIGS
may be required to demonstrate the extent to which inclusion of an income tax
allowance in Regency’s cost-of-service is permitted under the current income tax
allowance policy. Although FERC’s policy is generally favorable for
pipelines that are organized as, or owned by, tax-pass-through entities,
application of the policy in individual rate cases still entails rate risk due
to the case-by-case review requirement. The specific terms and application
of that policy remain subject to future refinement or change by FERC and the
courts. Moreover, we cannot guarantee that this policy will not be altered
in the future.
In
addition, on July 19, 2007, FERC issued a proposed policy statement regarding
the composition of proxy groups for determining the appropriate returns on
equity for interstate natural gas and oil pipelines. The proposed
policy statement would permit the inclusion of master limited partnerships
(MLPs) in the proxy group for purposes of calculating returns on equity under
the discounted cash flow analysis, a change from its prior view that MLPs had
not been shown to be appropriate for such inclusion. Specifically,
FERC proposes that MLPs may be included in the proxy group provided that the
discounted cash flow analysis recognizes as distributions only the pipeline’s
reported earnings and not other sources of cash flow subject to
distribution. According to the proposed policy statement, under the
discounted cash flow analysis, the return on equity is calculated by adding the
dividend or distribution yield (dividends divided by share/unit price) to the
projected future growth rate of dividends or distributions (weighted one-third
for long-term growth of the economy as a whole and two-thirds short term growth
as determined by analysts’ five-year forecasts for the pipeline). The
determination of which MLPs should be included will be made on a case-by-case
basis, after a review of whether an MLPs earnings have been stable over a
multi-year period. FERC proposes to apply the final policy statement
to all natural gas rate cases that have not completed the hearing phase as of
the date FERC issues the final policy statement. Comments on the
proposed policy statement were filed by numerous parties, and on January 8,
2008, FERC held a technical conference to discuss the proposed
policy. FERC’s proposed policy statement is subject to change based
on filed comments and the technical conference. Therefore, we cannot
predict the scope or outcome of the final policy statement. If the
hearing phase of the Section 311 rate case RIGS is required to file by May 1,
2008, has not been completed as of the date FERC issues its final policy
statement, and FERC determines to apply the policy statement to Section 311
transportation rates, application of the statement might affect RIGS ability to
achieve a reasonable level of equity return in its Section 311 rate
proceeding.
A
change in the jurisdictional characterization of some of our assets by federal,
state or local regulatory agencies or a change in policy by those agencies may
result in increased regulation of our assets, which may cause our revenues to
decline and operating expenses to increase.
Our
natural gas gathering and intrastate transportation operations are generally
exempt from FERC regulation under the NGA, but FERC regulation still affects
these businesses and the markets for products derived from these businesses.
FERC’s policies and practices, including, for example, its policies on
open access transportation, ratemaking, capacity release, and market center
promotion, indirectly affect intrastate markets. In recent years, FERC has
pursued pro-competitive regulatory policies. However, with the passage of
the Energy Policy Act of 2005, the FERC has sought to expand its oversight of
natural gas purchasers, gatherers and intrastate pipelines by developing new
market monitoring and market transparency rules. FERC recently issued
a notice of proposed rulemaking that would require posting of available
capacity, scheduled capacity and actual flows on non-interstate pipelines,
including gathering companies and intrastate pipelines. We cannot
predict the outcome of this proposed rulemaking or how the FERC will approach
future matters such as pipeline rates and rules and policies that may affect
rights of access to natural gas transportation capacity. In addition,
the distinction between FERC-regulated transmission service and federally
unregulated gathering services is the subject of regular litigation at FERC and
in the courts and of policy discussions at FERC. In such
circumstances, the classification and regulation of some of our gathering or our
intrastate transportation pipelines may be subject to change based on future
determinations by FERC, the courts, or Congress. Such a change could
result in increased regulation by FERC, which could adversely affect our
business.
Other
state and local regulations also affect our business. Our gathering lines
are subject to ratable take and common purchaser statutes in states in which we
operate. Ratable take statutes generally require gatherers to take,
without undue discrimination, oil or natural gas production that may be tendered
to the gatherer for handling. Similarly, common purchaser statutes
generally require gatherers to purchase without undue discrimination as to
source of supply or producer. These statutes restrict our right as an
owner of gathering facilities to decide with whom we contract to purchase or
transport natural gas. Federal law leaves any economic regulation of
natural gas gathering to the states. States in which we operate have
adopted complaint-based regulation of oil and natural gas gathering activities,
which allows oil and natural gas producers and shippers to file complaints with
state regulators in an effort to resolve grievances relating to oil and natural
gas gathering access and rate discrimination.
We
may incur significant costs and liabilities in the future resulting from a
failure to comply with new or existing environmental regulations or an
accidental release of hazardous substances into the environment.
Our
operations are subject to stringent and complex federal, state and local
environmental laws and regulations governing, among other things, air emissions,
wastewater discharges, the use, management and disposal of hazardous and
nonhazardous materials and wastes, and the cleanup of contamination.
Noncompliance with such laws and regulations, or incidents resulting in
environmental releases,
could cause us to incur substantial costs, penalties, fines and other criminal
sanctions, third party claims for personal injury or property damage,
investments to retrofit or upgrade our facilities and programs, or curtailment
of operations. Certain environmental statutes, including CERCLA and
comparable state laws, impose strict, joint and several liability for costs
required to clean up and restore sites where hazardous substances have been
disposed or otherwise released.
There is
inherent risk of the incurrence of environmental costs and liabilities in our
business due to the necessity of handling natural gas and NGLs, air emissions
related to our operations, and historical industry operations and waste disposal
practices. For example, an accidental release from one of our pipelines or
processing facilities could subject us to substantial liabilities arising from
environmental cleanup and restoration costs, claims made by neighboring
landowners and other third parties for personal injury and property damage, and
fines or penalties for related violations of environmental laws or
regulations. Moreover, the possibility exists that stricter laws,
regulations or enforcement policies could significantly increase our compliance
costs and the cost of any remediation that may become necessary. We may
not be able to recover these costs from insurance. We cannot be
certain that identification of presently unidentified conditions, more
vigorous enforcement by regulatory agencies, enactment of more stringent laws
and regulations, or other unanticipated events will not arise in the future and
give rise to material environmental liabilities that could have a material
adverse effect on our business, financial condition or results of
operations.
Our
leverage may limit our ability to borrow additional funds, make distributions,
comply with the terms of our indebtedness or capitalize on business
opportunities.
Our
leverage is significant in relation to our partners’ capital. Our debt to
capital ratio, calculated as total debt divided by the sum of total debt and
partners’ capital, as of December 31, 2007 was 51 percent. We will be
prohibited from making cash distributions during an event of default under any
of our indebtedness, and, in the case of the indenture under which our senior
notes were issues, the failure to maintain a prescribed ratio of consolidated
cash flows (as defined in the indenture) to interest expense.. Various
limitations in our credit facility, as well as the indenture for our senior
notes, may reduce our ability to incur additional debt, to engage in some
transactions and to capitalize on business opportunities. Any subsequent
refinancing of our current indebtedness or any new indebtedness could have
similar or greater restrictions.
Our
leverage may adversely affect our ability to fund future working capital,
capital expenditures and other general partnership requirements, future
acquisition, construction or development activities, or otherwise realize fully
the value of our assets and opportunities because of the need to dedicate a
substantial portion of our cash flow from operations to payments on our
indebtedness or to comply with any restrictive terms of our indebtedness.
Our leverage may also make our results of operations more susceptible to
adverse economic and industry conditions by limiting our flexibility in planning
for, or reacting to, changes in our business and the industry in which we
operate and may place us at a competitive disadvantage as compared to our
competitors that have less debt.
Increases
in interest rates could adversely impact our unit price and our ability to issue
additional equity, in order to make acquisitions, to reduce debt, or for other
purposes.
The
interest rate on our senior notes is fixed and the loans outstanding under our
credit facility bear interest at a floating rate. Interest rates on
future credit facilities and debt offerings could be higher than current levels,
causing our financing costs to increase accordingly. As with other
yield-oriented securities, the market price for our units will be affected by
the level of our cash distributions and implied distribution yield. The
distribution yield is often used by investors to compare and rank yield-oriented
securities for investment decision-making purposes. Therefore, changes in
interest rates, either positive or negative, may affect the yield requirements
of investors who invest in our units, and a rising interest rate environment
could have an adverse effect on our unit price and our ability to issue
additional equity in order to make acquisitions, to reduce debt or for
other purposes.
We
may not have the ability to raise funds necessary to finance any change of
control offer required under our senior notes.
If a
change of control (as defined in the indenture) occurs, we will be required to
offer to purchase our outstanding senior notes at 101 percent of their principal
amount plus accrued and unpaid interest. If a purchase offer obligation
arises under the indenture governing the senior notes, a change of control could
also have occurred under the senior secured credit facilities, which could
result in the acceleration of the indebtedness outstanding thereunder. Any
of our future debt agreements may contain similar restrictions and provisions.
If a purchase offer were required under the indenture for our debt, we may
not have sufficient funds to pay the purchase price of all debt that we are
required to purchase or repay.
Our
ability to manage and grow our business effectively may be adversely affected if
our General Partner loses key management or operational
personnel.
We depend
on the continuing efforts of our executive officers. The departure of any
of our executive officers could have a significant negative effect on our
business, operating results, financial condition, and on our ability to compete
effectively in the marketplace. Additionally, the General Partner’s
employees operate our business. Our General Partner’s ability to
hire, train, and retain qualified personnel will continue to be important and
will become more challenging as we grow and if energy industry market conditions
continue to be positive. When general industry conditions are good, the
competition for experienced operational and field technicians increases as other
energy and manufacturing companies’ needs for the same personnel increases.
Our ability to grow and perhaps even to continue our current level of
service to our current customers will be adversely impacted if our General
Partner is unable
to successfully hire, train and retain these important
personnel.
Terrorist
attacks, the threat of terrorist attacks, hostilities in the Middle East, or
other sustained military campaigns may adversely impact our results of
operations.
The
long-term impact of terrorist attacks, such as the attacks that occurred on
September 11, 2001, and the magnitude of the threat of future terrorist attacks
on the energy transportation industry in general and on us in particular are not
known at this time. Uncertainty surrounding hostilities in the Middle
East or other sustained military campaigns may affect our operations in
unpredictable ways, including disruptions of natural gas supplies and markets
for natural gas and NGLs and the possibility that infrastructure facilities
could be direct targets of, or indirect casualties of, an act of
terror.
Changes
in the insurance markets attributable to terrorist attacks may make certain
types of insurance more difficult for us to obtain. Moreover, the
insurance that may be available to us may be significantly more expensive than
our existing insurance coverage. Instability in the financial markets
as a result of terrorism or war could also affect our ability to raise
capital.
RISKS
RELATED TO OUR STRUCTURE
GE
EFS controls our general partner, which has sole responsibility for conducting
our business and managing our operations.
Although
our General Partner has a fiduciary duty to manage us in a manner beneficial to
us and our unitholders, the directors and officers of our General Partner have a
fiduciary duty to manage our General Partner in a manner beneficial to its
owner, GE EFS. Conflicts of interest may arise between GE EFS, including
our General Partner, on the one hand, and us, on the other hand. In
resolving these conflicts of interest, our General Partner may favor its own
interests and the interests of its affiliates over our interests. These
conflicts include, among others, the following situations:
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neither
our partnership agreement nor any other agreement requires GE EFS or
affiliates of GECC to pursue a business strategy that favors
us;
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our
General Partner is allowed to take into account the interests of parties
other than us, such as GE EFS, in resolving conflicts of
interest;
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our
General Partner determines the amount and timing of asset purchases and
sales, capital expenditures, borrowings and repayments of debt, issuance
of additional partnership securities, and cash reserves, each of which can
affect the amount of cash available for
distribution;
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our
General Partner determines which costs incurred are reimbursable by
us;
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our
partnership agreement does not restrict our General Partner from causing
us to pay for any services rendered to us or entering into additional
contractual arrangements with any of these entities on our
behalf;
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our
General Partner intends to limit its liability regarding our contractual
and other obligations; and
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our
General Partner controls the enforcement of obligations owed to us by our
General Partner.
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GE
EFS and affiliates of GECC may compete directly with us.
GE
EFS and
affiliates of GECC are not prohibited from owning assets or
engaging in businesses that compete directly or independently with
us. GE EFS and affiliates of GECC currently own various
midstream assets and conduct midstream businesses that may potentially compete
with us. In addition, GE EFS and affiliates of GECC may acquire,
construct or dispose of any additional midstream or other assets in the future,
without any obligation to offer us the opportunity to purchase or construct or
dispose of those assets.
Our
reimbursement of our general partner’s expenses will reduce our cash available
for distribution to common unitholders.
Prior to
making any distribution on the common units, we will reimburse our General
Partner and its affiliates for all expenses they incur on our behalf.
These expenses will include all costs incurred by our General Partner and
its affiliates in managing and operating us, including costs for rendering
corporate staff and support services to us. The reimbursement of
expenses incurred by our General Partner and its affiliates could adversely
affect our ability to pay cash distributions to you.
Our
partnership agreement limits our General Partner’s fiduciary duties to our
unitholders and restricts the remedies available to unitholders for actions
taken by our General Partner that might otherwise constitute breaches of
fiduciary duty.
Our
partnership agreement contains provisions that reduce the standards to which our
General Partner would otherwise be held by state fiduciary duty
law. For example, our partnership agreement:
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permits our General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;
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provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
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provides that our General Partner is entitled to make other decisions in "good faith" if it believes that the decision is in our best interests;
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provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of our General Partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our General Partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
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provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
Any
common unitholder is bound by the provisions in the partnership agreement,
including the provisions discussed above.
Unitholders
have limited voting rights and are not entitled to elect our general partner or
its directors.
Unlike
the holders of common stock in a corporation, unitholders have only limited
voting rights on matters affecting our business and, therefore, limited ability
to influence management’s decisions regarding our business. Unitholders do not
elect our General Partner or its board of directors and have no right to elect
our General Partner or its board of directors on an annual or other continuing
basis. The board of directors of our General Partner is chosen by the
members of our General Partner. Furthermore, if the unitholders are
dissatisfied with the performance of our General Partner, they will have little
ability to remove our General Partner. As a result of these limitations,
the price at which the common units will trade could be diminished because of
the absence or reduction of a takeover premium in the trading
price.
Even
if unitholders are dissatisfied, they cannot remove our general partner without
its consent.
The
unitholders are currently unable to remove the General Partner without its
consent because the General Partner and its affiliates own sufficient units to
be able to prevent its removal. A vote of the holders of at least
66 2/3 percent of all outstanding units voting together as a single
class is required to remove the General Partner. As of February 7, 2008,
our General Partner owns 31.2 percent of the total of our common and
subordinated units. Moreover, if our General Partner is removed without
cause during the subordination period and units held by GE EFS are not voted in
favor of that removal, all remaining subordinated units will automatically
convert into common units and any existing arrearages on the common units will
be extinguished. A removal of the General Partner under these
circumstances would adversely affect the common units by prematurely eliminating
their distribution and liquidation preference over the subordinated units, which
would otherwise have continued until we had met certain distribution and
performance tests.
Our
partnership agreement restricts the voting rights of those unitholders owning 20
percent or more of our common units.
Unitholders’
voting rights are further restricted by the partnership agreement provision
providing that any units held by a person that owns 20 percent or more of any
class of units then outstanding, other than our General Partner, its affiliates,
their transferees, and persons who acquired such units with the prior approval
of our General Partner, cannot vote on any matter. Our partnership
agreement also contains provisions limiting the ability of unitholders to
call meetings or to acquire information about our operations, as well as other
provisions limiting the unitholders’ ability to influence the manner or
direction of our management.
Control
of our general partner may be transferred to a third party without unitholder
consent.
Our
General Partner may transfer its general partner interest to a third party in a
merger or in a sale of all or substantially all of its assets without the
consent of the unitholders. Furthermore, our partnership agreement does
not restrict the ability of the partners of our general partner from
transferring their ownership in our General Partner to a third party. The
new partners of our General Partner would then be in a position to replace the
board of directors and officers of our General Partner with their own choices
and to control the decisions taken by the board of directors and
officers.
We
may issue an unlimited number of additional units without your approval, which
would dilute your existing ownership interest.
Our
General Partner, without the approval of our unitholders, may cause us to issue
an unlimited number of additional common units. The issuance by us of
additional common units or other equity securities of equal or senior rank will
have the following effects:
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our
unitholders’ proportionate ownership interest in us will
decrease;
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the
amount of cash available for distribution on each unit may
decrease;
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because
a lower percentage of total outstanding units will be subordinated units,
the risk that a shortfall in the payment of the minimum quarterly
distribution will be borne by our common unitholders will
increase;
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the
relative voting strength of each previously outstanding unit may be
diminished; and
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the
market price of the common units may
decline.
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Certain
of our investors may sell units in the public market, which could reduce the
market price of our outstanding common units.
Pursuant
to agreements with investors in private placements or acquisitions, we have
filed registration statements on Form S-3 registering
sales by selling unitholders of an aggregate of 11,881,000
of our common units, and have outstanding obligations to file
registration statements with respect to 11,978,000
common units, including the 7,276,506 common units to be issued upon
conversion of Class D units we issued to the sellers in the CDM acquisition and
the 4,701,034 common units to be issued upon conversion of Class E units we
issued to the sellers in the FrontStreet acquisition.
Substantially
all of the common units so registered remain unsold pursuant to these
registration statements. If investors holding these units were to
dispose of a substantial portion of these units in the public market, whether in
a single transaction or series of transactions, it could temporarily reduce the
market price of our outstanding common units. In addition, these
sales, or the possibility that these sales may occur, could make it more
difficult for us to sell our common units in the future.
Our
general partner has a limited call right that may require you to sell your units
at an undesirable time or price.
If at any
time our General Partner and its affiliates own more than 80 percent of the
common units, our General Partner will have the right, but not the obligation
(which it may assign to any of its affiliates or to us) to acquire all, but not
less than all, of the common units held by unaffiliated persons at a price not
less than their then-current market price. As a result, you may be
required to sell your common units at an undesirable time or price and may not
receive any return on your investment. You may also incur a tax liability
upon a sale of your units. As of February 7, 2008, our General Partner
owns 31.2 percent of the total of our common and subordinated
units.
Your
liability may not be limited if a court finds that unitholder action constitutes
control of our business.
A general
partner of a partnership generally has unlimited liability for the obligations
of the partnership, except for those contractual obligations of the partnership
that are expressly made without recourse to the general partner. Our partnership
is organized under Delaware law and we conduct business in a number of other
states. The limitations on the liability of holders of limited partner
interests for the obligations of a limited partnership have not been clearly
established in some of the other states in which we do business. In most
states, a limited partner is only liable if he participates in the “control” of
the business of the partnership. These statutes generally do not define
control, but do permit limited partners to engage in certain activities,
including, among other actions, taking any action with respect to the
dissolution of the partnership, the sale, exchange, lease or mortgage of any
asset of the partnership, the admission or removal of the general
partner and the amendment of the partnership agreement. You could, however,
be liable for any and all of our obligations as if you were a general partner
if:
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a
court or government agency determined that we were conducting business in
a state but had not complied with that particular state’s partnership
statute; or
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your
right to act with other unitholders to take other actions under our
partnership agreement is found to constitute “control” of our
business.
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Unitholders
may have liability to repay distributions that were wrongfully distributed to
them.
Under
certain circumstances, unitholders may have to repay amounts wrongfully returned
or distributed to them. Under Section 17-607 of the Delaware Revised
Uniform Limited Partnership Act, we may not make a distribution to you if the
distribution would cause our liabilities to exceed the fair value of our assets.
Delaware law provides that for a period of three years from the date of
the distribution, limited partners who received an impermissible distribution
and who knew at the time of the distribution that it violated Delaware law will
be liable to the limited partnership for the distribution amount.
Substituted limited partners are liable for the obligations of the
assignor to make required contributions to the partnership other than
contribution obligations that are unknown to the substituted limited partner at
the time it became a limited partner and that could not be ascertained from the
partnership agreement. Liabilities to partners on account of their partnership
interest and liabilities that are non-recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted.
TAX
RISKS RELATING TO OUR COMMON UNITS
Our
tax treatment depends on our status as a partnership for federal income tax
purposes, as well as our not being subject to a material amount of entity-level
taxation by individual states or local entities. If the IRS treats us as a
corporation or we become subject to a material amount of entity-level taxation
for state or local tax purposes, it would substantially reduce the amount of
cash available for payment for distributions on our common units.
Under
Section 7704 of the Internal Revenue Code, a publicly traded partnership will be
taxed as a corporation unless it satisfies a “qualifying income” exception that
allows it to be treated as a partnership for U.S. federal income tax
purposes. We believe that we meet the “qualifying income” exception and
currently expect to meet such exception for the foreseeable future. If the
IRS were to disagree and if we were treated as a corporation for federal income
tax purposes, we would pay federal income tax on our income at the corporate tax
rate, which is currently a maximum of 35 percent, and would likely pay
state and local income tax at varying rates. Distributions to you would
generally be taxed again as corporate distributions, and no income, gains,
losses or deductions would flow through to you. Because a tax would
be imposed upon us as a corporation, our cash available for distribution to you
would be substantially reduced. Therefore, treatment of us as a
corporation would result in a material reduction in the anticipated cash flow
and after-tax return to the unitholders, likely causing a substantial reduction
in the value of the units.
Current
law may change so as to cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to entity-level taxation. At
the federal level, legislation has been proposed that would eliminate
partnership tax treatment for certain publicly traded partnerships. Although
such legislation would not apply to us as currently proposed, it could be
amended prior to enactment in a manner that does apply to us. We are
unable to predict whether any of these changes or other proposals will
ultimately be enacted. Any such changes could negatively impact the
value of an investment in our common units. At the state level,
because of widespread state budget deficits and other reasons, several states
are evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation. For
example, we are required to pay a Texas margin tax. Imposition of
such a tax on us by Texas, and, if applicable, by any other state, will reduce
our cash available for distribution to you.
Our
partnership agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation for federal, state
or local income tax purposes, the minimum quarterly distribution amount and the
target distribution amounts may be reduced to reflect the impact of that
law on us.
A
successful IRS contest of the federal income tax positions we take may adversely
affect the market for our common units, and the cost of any IRS contest will
reduce our cash available for distribution to you.
We did
not request a ruling from the IRS with respect to our treatment as a partnership
for federal income tax purposes or any other matter affecting us. The IRS
may adopt positions that differ from the positions we take. It may be
necessary to resort to administrative or court proceedings to sustain some or
all of the positions we take. A court may not agree with all of the
positions we take. Any contest with the IRS may materially and adversely
impact the market for our common units and the price at which they trade.
In addition, our costs of any contest with the IRS will be borne
indirectly by our unitholders and our general partner because the costs will
reduce our cash available for distribution.
You
may be required to pay taxes on income from us even if you do not receive any
cash distributions from us.
Because
our unitholders will be treated as partners to whom we will allocate taxable
income that could be different in amount than the cash we distribute, you will
be required to pay any federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income even if you receive no cash
distributions from us. You may not receive cash distributions from us
equal to your share of our taxable income or even equal to the tax liability
that results from that income.
Tax
gain or loss on disposition of common units could be more or less than
expected.
If you
sell your common units, you will recognize a gain or loss equal to the
difference between the amount realized and your tax basis in those common
units. Prior distributions to you in excess of the total net taxable
income you were allocated for a common unit, which decreased your tax basis in
that common unit, will, in effect, become taxable income to you if the common
unit is sold at a price greater than your tax basis in that common unit, even if
the price is less than your original cost. A substantial portion
of the amount realized, whether or not representing gain, may be ordinary
income. In addition, if you sell your units, you may incur a tax
liability in excess of the amount of cash you receive from the
sale.
Tax-exempt
entities and foreign persons face unique tax issues from owning common units
that may result in adverse tax consequences to them.
Investment
in common units by tax-exempt entities, such as individual retirement accounts
(known as IRAs), other retirement plans and non-U.S. persons raises issues
unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable
to them. Distributions to non-U.S. persons will be reduced by
withholding taxes at the highest applicable effective tax rate, and non-U.S.
persons will be required to file United States federal tax returns and pay tax
on their share of our taxable income. If you are a tax-exempt entity
or a regulated investment company, you should consult your tax advisor before
investing in our common units.
We
will treat each purchaser of our common units as having the same tax benefits
without regard to the actual common units purchased. The IRS may challenge
this treatment, which could adversely affect the value of the common
units.
Because
we cannot match transferors and transferees of common units and because of other
reasons, we will take depreciation and amortization positions that may not
conform to all aspects of existing Treasury regulations. A successful
IRS challenge to those positions could adversely affect the amount of tax
deductions available to you. It also could affect the timing of these
tax deductions or the amount of gain from the sale of common units and could
have a negative impact on the value of our common units or result in audit
adjustments to your tax returns.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first day of each month, instead of on the basis of the date a particular unit
is transferred. The IRS may challenge this treatment, which could change
the allocation of items of income, gain, loss and deduction among our
unitholders.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first day of each month, instead of on the basis of the date a particular unit
is transferred. The use of this proration method may not be permitted
under existing Treasury Regulations, and, accordingly, our counsel is unable to
opine as to the validity of this method. If the IRS were to challenge this
method or new Treasury Regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among our
unitholders.
A
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of those units. If so, he would no
longer be treated for tax purposes as a partner with respect to those units
during the period of the loan and may recognize gain or loss from the
disposition.
Because a
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of the loaned units, he may no longer
be treated for tax purposes as a partner with respect to those units during the
period of the loan to the short seller and the unitholder may recognize
gain or loss from such disposition. Moreover, during the period of the
loan to the short seller, any of our income, gain, loss or deduction with
respect to those units may not be reportable by the unitholder and any cash
distributions received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a loan to a short
seller are urged to modify any applicable brokerage account agreements to
prohibit their brokers from borrowing their units.
We
have adopted certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between the general partner and the
unitholders. The IRS may challenge this treatment, which could
adversely affect the value of the common units.
When we
issue additional units or engage in certain other transactions, we determine the
fair market value of our assets and allocate any unrealized gain or loss
attributable to our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating the
value of our assets. In that case, there may be a shift of income,
gain, loss and deduction between certain unitholders and the general partner,
which may be unfavorable to such unitholders. Moreover, under our
current valuation methods, subsequent purchasers of common units may have a
greater portion of their Internal Revenue Code Section 743(b) adjustment
allocated to our intangible assets and a lesser portion allocated to our
tangible assets. The IRS may challenge our valuation methods, or our
allocation of the Section 743(b) adjustment attributable to our tangible and
intangible assets, and allocations of income, gain, loss and deduction between
the general partner and certain of our unitholders.
A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our
unitholders. It also could affect the amount of gain from our
unitholders’ sale of common units and could have a negative impact on the value
of the common units or result in audit adjustments to our unitholders’ tax
returns without the benefit of additional deductions.
The
sale or exchange of 50 percent or more of our capital and profits interests
during any twelve-month period will result in the termination of our partnership
for federal income tax purposes.
We will
be considered to have terminated for federal income tax purposes if there is a
sale or exchange of 50 percent or more of the total interests in our capital and
profits within a twelve-month period. Pursuant to the GE EFS
Acquisition, GE EFS acquired (i) a 37.3 percent limited partner interest in us,
(ii) the 2 percent general partner interest in us, and (iii) the right to
receive the incentive distributions associated with the general partner
interest. We believe, and will take the position, that the GE EFS
Acquisition, together with all other common units sold within the prior
twelve-month period, represented a sale or exchange of 50 percent or more of the
total interest in our capital and profits interests. This
termination, among other things, resulted in the closing of our taxable year for
all unitholders on June 18, 2007. Such a closing of the books
resulted in a significant deferral of depreciation deductions allowable in
computing our taxable income. Although our termination likely caused
our unitholders to realize an increased amount of taxable income as a percentage
of the cash distributed to them in 2007, we anticipate that the ratio of taxable
income to distributions for future years will return to levels commensurate with
our prior tax periods. However, any future termination of our
partnership could have similar consequences. Additionally, in the
case of a unitholder reporting on a taxable year other than a fiscal year ending
December 31, the closing of our taxable year may result in more than twelve
months of our taxable income or loss being includable in his taxable income for
the year of termination. The position that there was a partnership
termination does not affect our classification as a partnership for federal
income tax purposes; however, we are treated as a new partnership for tax
purposes. If treated as a new partnership, we must make new tax
elections and could be subject to penalties if we are unable to prevail
that a termination occurred.
You
may be subject to state and local taxes and tax return filing
requirements.
In
addition to federal income taxes, you will likely be subject to other taxes,
including state and local taxes, unincorporated business taxes and estate,
inheritance or intangible taxes that are imposed by the various jurisdictions in
which we do business or own property, even if you do not live in any of those
jurisdictions. You will likely be required to file state and local income
tax returns and pay state and local income taxes in some or all of these
jurisdictions. Further, you may be subject to penalties for failure to comply
with those
requirements. We own assets and do business in Texas, Oklahoma, Kansas,
Louisiana, West Virginia and Arkansas. Each of these states, other than
Texas, currently imposes a personal income tax as well as an income tax on
corporations and other entities. Texas imposes a margin tax
on corporations and limited liability companies. As we make
acquisitions or expand our business, we may own assets or do business in
additional states that impose a personal income tax. It is your responsibility
to file all United States federal, foreign, state and local tax returns required
as a result of being a unitholder.
None.
Item 2. Properties
Substantially
all of our pipelines, which are located in Texas, Louisiana, Oklahoma,
and Kansas are constructed on rights-of-way granted by the apparent record
owners of the property. Lands over which pipeline rights-of-way have been
obtained may be subject to prior liens that have not been subordinated to the
right-of-way grants. We have obtained, where necessary, easement
agreements from public authorities and railroad companies to cross over or
under, or to lay facilities in or along, watercourses, county roads, municipal
streets, railroad properties and state highways, as applicable. In some cases,
properties on which our pipelines were built were purchased in fee.
We
believe that we have satisfactory title to all our assets. Record title to
some of our assets may continue to be held by prior owners until we have made
the appropriate filings in the jurisdictions in which such assets are located.
Obligations under our credit facility are secured by substantially all of
our assets and are guaranteed, except for those owned by one of our
subsidiaries, by the Partnership and each such
subsidiary. Title to our assets may also be subject to
other encumbrances. We believe that none of such encumbrances should
materially detract from the value of our properties or our interest in those
properties or should materially interfere with our use of them in the operation
of our business.
Our
executive offices occupy one entire floor in an office building at 1700 Pacific
Avenue, Dallas, Texas, under a lease that expires at the end of October 2008.
Currently, we are evaluating our executive office space needs. We
also maintain small regional offices located on leased premises in Shreveport,
Louisiana; and Midland, Houston, and San Antonio, Texas. We lease the
San Antonio office space from BBE, a related party. While we may require
additional office space as our business expands, we believe that our existing
facilities are adequate to meet our needs for the immediate future, and that
additional facilities will be available on commercially reasonable terms as
needed.
For
additional information regarding our properties, please read “Item 1 —
Business”.
We are
subject to a variety of risks and disputes normally incident to our business.
As a result, we may, at any given time, be a defendant in various legal
proceedings and litigation arising in the ordinary course of business.
Neither the Partnership nor any of its subsidiaries, including RGS, is,
however, currently a party to any pending or, to our knowledge, threatened
material legal or governmental proceedings, including proceedings under any of
the various environmental protection statutes to which it is
subject.
We
maintain insurance policies with insurers in amounts and with coverage and
deductibles that we, with the advice of our insurance advisors and brokers,
believe are reasonable and prudent. We cannot, however, assure you that
this insurance will be adequate to protect us from all material expenses related
to potential future claims for personal and property damage or that these levels
of insurance will be available in the future at economical prices.
None.
Part
II
Market
Price of and Distributions on the Common Units and Related Unitholder
Matters
Our common units were first offered and sold to the public on
February 3, 2006. Our common units are listed on NASDAQ under the symbol
“RGNC.” As of February 13, 2008, the number of holders of record of
common units was 51, including Cede & Co., as nominee for Depository Trust
Company, which held of record 29,296,713 common units. Additionally,
there were 35 unitholders of record of our subordinated units, one unitholder of
record for our Class D common units and one unitholder of record for our Class E
common units. There is no established public trading market for our
subordinated units, our Class D common units or our Class E common
units. Currently, our common units are listed on the Nasdaq Global
Select Market. The following table sets forth, for the periods indicated,
the high and low quarterly sales prices per common unit, as reported on NASDAQ,
and the cash distributions declared per common unit.
|
Cash
Distributions
|
||||||||||||
|
Price
Ranges
|
Declared
|
|||||||||||
|
High
|
Low
|
(per
unit)
|
||||||||||
|
2006
|
||||||||||||
|
First
Quarter (1)
|
$ | 22.10 | $ | 19.47 | $ | 0.2217 | ||||||
|
Second
Quarter
|
23.00 | 21.30 | 0.3500 | |||||||||
|
Third
Quarter (2)
|
24.52 | 22.24 | 0.3700 | |||||||||
|
Fourth
Quarter (2)
|
27.20 | 24.75 | 0.3700 | |||||||||
|
2007
|
||||||||||||
|
First
Quarter
|
28.40 | 26.11 | 0.3800 | |||||||||
|
Second
Quarter
|
33.18 | 24.97 | 0.3800 | |||||||||
|
Third
Quarter
|
34.32 | 29.15 | 0.3900 | |||||||||
|
Fourth
Quarter
|
33.37 | 28.46 | 0.4000 | |||||||||
|
2008
|
||||||||||||
|
First
Quarter (through February 21, 2008)
|
32.60 | 29.71 | (3 | ) | ||||||||
|
(1)
The distribution for the quarter ended March 31, 2006 reflects a pro rata
portion of our $0.35 per unit minimum quarterly
distribution,
|
||||||||||||
|
covering
the period from the February 3, 2006 closing of our initial public
offering through March 31, 2006.
|
||||||||||||
|
(2)
Excludes the Class B and Class C common units which were not entitled to
any distributions until after they were converted into
common
|
||||||||||||
|
units.
The Class B Units and the Class C Units converted into common units on a
one-for-one basis on February 15, 2007 and February 8,
|
||||||||||||
|
2007,
respectively, and as such, are entitled to future cash distributions from
the dates of conversion, respectively.
|
||||||||||||
|
(3)
The cash distribution for the first quarter of 2008 will be determined in
April 2008.
|
||||||||||||
Cash Distribution Policy
We
distribute to our unitholders, on a quarterly basis, all of our available cash
in the manner described below. During the subordination period (as defined
in our partnership agreement), the common units will have the right to receive
distributions of available cash from operating surplus in an amount equal to the
minimum quarterly distribution, or MQD, of $0.35 per quarter, plus any
arrearages in the payment of the MQD on the common units from prior quarters,
before any distributions of available cash may be made on the subordinated
units. If we do not have sufficient cash to pay our distributions as well
as satisfy our other operational and financial obligations, our General Partner
has the ability to reduce or eliminate the distribution paid on our common units
and subordinated units so that we may satisfy such obligations, including
payments on our debt instruments. Holders of our Class D common units
and our Class E common units are not entitled to participate in
distributions.
Available
cash generally means, for any quarter ending prior to liquidation of the
Partnership, all cash on hand at the end of that quarter less the amount of cash
reserves that are necessary or appropriate in the reasonable discretion of the
General Partner to:
|
§
|
provide
for the proper conduct of our
business;
|
|
§
|
comply
with applicable law or any partnership debt instrument or other agreement;
or
|
|
§
|
provide
funds for distributions to unitholders and the general partner in respect
of any one or more of the next four
quarters.
|
In
addition to distributions on its 2 percent General Partner interest, our General
Partner is entitled to receive incentive distributions if the amount we
distribute with respect to any quarter exceeds levels specified in the following
table.
|
Total
|
||||||
|
Quarterly
|
Marginal
Percentage
|
|||||
|
Distribution
|
Interest
in Distributions
|
|||||
|
Target
|
General
|
|||||
|
Amount
|
Unitholders
|
Partner
|
||||
|
Minimum
Quarterly Distribution
|
$0.35
|
98
|
% |
2
|
% | |
|
First
Target Distribution
|
up
to $0.4025
|
98
|
2
|
|||
|
Second
Target Distribution
|
above
$0.4025 up to $0.4375
|
85
|
15
|
|||
|
Third
Target Distribution
|
above
$0.4375 up to $0.5250
|
75
|
25
|
|||
|
Thereafter
|
above
$0.5250
|
50
|
50
|
|||
Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” for further discussion regarding the restrictions on distributions.
Recent
Sales of Unregistered Securities
On
September 8, 2005, in connection with our formation we issued (i) to our general
partner, Regency GP LP, its 2 percent general partner interest in us for $20 and
(ii) to Regency Acquisition LLC its 98 percent limited partner interest in us
for $980. As an integral part of the reorganization of RGS in connection
with our initial public offering, we issued (i) 5,353,896 common units and
19,103,896 subordinated units to Regency Acquisition LP, successor to Regency
Acquisition LLC, in exchange for certain equity interests in RGS and its general
partner and (ii) incentive distribution rights (which represent the right to
receive increasing percentages of quarterly distributions in excess of specified
amounts) to our general partner in exchange for certain member
interests.
On August
15, 2006, in connection with the TexStar acquisition, we issued 5,173,189 of
Class B common units to HMTF Gas Partners as partial consideration for the
TexStar acquisition. The Class B common units had the same terms and
conditions as our common units, except that the Class B common units were
not entitled to participate in distributions by the Partnership. The
Class B common units were converted into common units without the payment of
further consideration on a one-for-one basis on February 15, 2007. The
registrant claims exemption from the registration provisions of the Securities
Act of 1933 under section 4(2) thereof for these issuances.
On
September 21, 2006, we entered into a Class C Unit Purchase Agreement
with certain purchasers, pursuant to which the purchasers purchased from us
2,857,143 Class C common units representing limited partner interests in the
Partnership at a price of $21 per unit. The Class C common units had
the same terms and conditions as the Partnership’s common units, except that the
Class C common units were not entitled to participate in distributions by
the Partnership. The Class C common units were converted into common
units without the payment of further consideration on a one-for-one basis on
February 8, 2007. The registrant claims exemption from the registration
provisions of the Securities Act of 1933 under section 4(2) thereof for these
issuances.
On April
2, 2007, in connection with the Pueblo Acquisition, we issued 751,597 common
units to Bear Cub Investments, LLC and the members of that company as partial
consideration for the Pueblo Acquisition. The registrant claims
exemption from the registration provisions of the Securities Act of 1933 under
section 4(2) thereof for these issuances.
On
January 7, 2008, we issued 4,701,034 of Class E common units as partial
consideration for the contribution of ASC’s 95 percent ownership interest in
FrontStreet. The Class E common units had the same terms and
conditions as our common units, except that the Class E common units were not
entitled to participate in distributions by the Partnership. The
Class E common units may be converted into an equivalent number of common units
anytime from and after February 15, 2008. The registrant claims
exemption from the registration provisions of the Securities Act of 1933 under
section 4(2) thereof for these issuances.
On
January 15, 2008, we issued 7,276,506 of Class D common units to CDM OLP GP,
LLC, the sole general partner of CDM, and CDMR Holdings, LLC, the sole limited
partner of CDM, as partial consideration for the CDM Acquisition. The
Class D common units have the same terms and conditions as our common units,
except that the Class D common units are not entitled to participate in
distributions by the Partnership until converted to 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 registrant claims exemption from the
registration provisions of the Securities Act of 1933 under section 4(2) thereof
for these issuances.
There
have been no other sales of unregistered equity securities during the last three
years.
The
historical financial information presented below for the Partnership and our
predecessors, Regency LLC Predecessor and Regency Gas Services LP (formerly
Regency Gas Services LLC), was derived from our audited consolidated financial
statements as of December 31, 2007, 2006, 2005, and 2004 and for the years ended
December 31, 2007, 2006, and 2005, the one-month period ended December 31, 2004,
the eleven-month period ended November 30, 2004, and the period from inception
(April 2, 2003) to December 31, 2003. See “Item 7 — Management’s
Discussions and Analysis of Financial Condition and Results of Operations
— History of the Partnership and its Predecessor” for a discussion of why
our results may not be comparable, either from period to period or going
forward.
We refer
to Regency Gas Services LLC as “Regency LLC Predecessor” for periods prior to
its acquisition by the HM Capital Investors.
|
Regency
Energy Partners LP
|
Regency
LLC Predecessor
|
|||||||||||||||||||||||
|
Period
from
|
Period
from
|
|||||||||||||||||||||||
|
Acquisition
|
Period
from
|
Inception
|
||||||||||||||||||||||
|
Year
Ended
|
Year
Ended
|
Year
Ended
|
(December 1,
2004) to
|
January 1,
2004 to
|
(April 2,
2003) to
|
|||||||||||||||||||
|
December
31, 2007
|
December
31, 2006
|
December
31, 2005
|
December
31, 2004
|
November
30, 2004
|
December
31, 2003
|
|||||||||||||||||||
|
(in
thousands except per unit data)
|
||||||||||||||||||||||||
|
Statement
of Operations Data:
|
||||||||||||||||||||||||
|
Total
revenue
|
$ | 1,168,054 | $ | 896,865 | $ | 709,401 | $ | 47,857 | $ | 432,321 | $ | 186,533 | ||||||||||||
|
Total
operating expense
|
1,114,843 | 857,005 | 695,366 | 45,112 | 404,251 | 178,172 | ||||||||||||||||||
|
Operating
income
|
53,211 | 39,860 | 14,035 | 2,745 | 28,070 | 8,361 | ||||||||||||||||||
|
Other
income and deductions
|
||||||||||||||||||||||||
|
Interest
expense, net
|
(52,016 | ) | (37,182 | ) | (17,880 | ) | (1,335 | ) | (5,097 | ) | (2,392 | ) | ||||||||||||
|
Loss
on debt refinancing
|
(21,200 | ) | (10,761 | ) | (8,480 | ) | - | (3,022 | ) | - | ||||||||||||||
|
Other
income and deductions, net
|
1,308 | 839 | 733 | 64 | 186 | 205 | ||||||||||||||||||
|
Net
income (loss) from continuing operations
|
(18,697 | ) | (7,244 | ) | (11,592 | ) | 1,474 | 20,137 | 6,174 | |||||||||||||||
|
Discontinued
operations
|
- | - | 732 | - | (121 | ) | - | |||||||||||||||||
|
Income
tax expense
|
931 | - | - | - | - | - | ||||||||||||||||||
|
Net
income (loss)
|
$ | (19,628 | ) | $ | (7,244 | ) | $ | (10,860 | ) | $ | 1,474 | $ | 20,016 | $ | 6,174 | |||||||||
|
Less:
|
||||||||||||||||||||||||
|
Net
income through January 31, 2006
|
- | 1,564 | ||||||||||||||||||||||
|
Net
loss for partners
|
$ | (19,628 | ) | $ | (8,808 | ) | ||||||||||||||||||
|
General
partner interest
|
(393 | ) | (176 | ) | ||||||||||||||||||||
|
Beneficial
conversion feature for Class C common units
|
1,385 | 3,587 | ||||||||||||||||||||||
|
Limited
partner interest
|
$ | (20,620 | ) | $ | (12,219 | ) | ||||||||||||||||||
|
Basic
and diluted net loss per common and subordinated unit (1)
|
$ | (0.40 | ) | $ | (0.30 | ) | ||||||||||||||||||
|
Cash
distributions declared per common and subordinated unit
|
1.52 | 0.9417 | ||||||||||||||||||||||
|
Basic
and diluted net loss per Class B common unit (1)
|
- | (0.17 | ) | |||||||||||||||||||||
|
Cash
distributions declared per Class B common unit
|
- | - | ||||||||||||||||||||||
|
Income
per Class C common unit due to beneficial conversion feature
(1)
|
0.48 | 1.26 | ||||||||||||||||||||||
|
Cash
distributions declared per Class C common unit
|
- | - | ||||||||||||||||||||||
|
Balance
Sheet Data (at period end):
|
||||||||||||||||||||||||
|
Property,
plant and equipment, net
|
$ | 818,054 | $ | 734,034 | $ | 609,157 | $ | 328,784 | $ | 118,986 | ||||||||||||||
|
Total
assets
|
1,173,877 | 1,013,085 | 806,740 | 492,170 | 164,330 | |||||||||||||||||||
|
Long-term
debt (long-term portion only)
|
481,500 | 664,700 | 428,250 | 248,000 | 55,387 | |||||||||||||||||||
|
Net
equity
|
470,331 | 212,657 | 230,962 | 181,936 | 59,856 | |||||||||||||||||||
|
Cash
Flow Data:
|
||||||||||||||||||||||||
|
Net
cash flows provided by (used in):
|
||||||||||||||||||||||||
|
Operating
activities
|
$ | 74,413 | $ | 44,156 | $ | 37,340 | $ | (4,311 | ) | $ | 32,401 | $ | 6,494 | |||||||||||
|
Investing
activities
|
(151,451 | ) | (223,650 | ) | (279,963 | ) | (130,478 | ) | (84,721 | ) | (123,165 | ) | ||||||||||||
|
Financing
activities
|
95,721 | 184,947 | 242,949 | 132,515 | 56,380 | 118,245 | ||||||||||||||||||
|
Other
Financial Data:
|
||||||||||||||||||||||||
|
Total
segment margin (2)
|
$ | 191,909 | $ | 156,419 | $ | 76,536 | $ | 6,870 | $ | 69,559 | $ | 23,072 | ||||||||||||
|
EBITDA
(2)
|
85,058 | 69,592 | 30,191 | 4,470 | 35,242 | 12,890 | ||||||||||||||||||
|
Maintenance
capital expenditures
|
7,734 | 16,433 | 9,158 | 358 | 5,548 | 1,633 | ||||||||||||||||||
|
Segment
Financial and Operating Data:
|
||||||||||||||||||||||||
|
Gathering
and Processing Segment:
|
||||||||||||||||||||||||
|
Financial
data:
|
||||||||||||||||||||||||
|
Segment
margin
|
$ | 132,577 | $ | 111,372 | $ | 60,864 | $ | 6,262 | $ | 61,347 | $ | 18,805 | ||||||||||||
|
Operating
expenses
|
40,970 | 35,008 | 22,362 | 1,655 | 16,230 | 6,131 | ||||||||||||||||||
|
Operating
data:
|
||||||||||||||||||||||||
|
Natural
gas throughput (MMbtu/d)
|
745,020 | 529,467 | 345,398 | 314,812 | 303,345 | 211,474 | ||||||||||||||||||
|
NGL
gross production (Bbls/d)
|
21,803 | 18,587 | 14,883 | 16,321 | 14,487 | 9,434 | ||||||||||||||||||
|
Transportation
Segment:
|
||||||||||||||||||||||||
|
Financial
data:
|
||||||||||||||||||||||||
|
Segment
margin
|
$ | 59,332 | $ | 45,047 | $ | 15,672 | $ | 608 | $ | 8,212 | $ | 4,267 | ||||||||||||
|
Operating
expenses
|
4,504 | 4,488 | 1,929 | 164 | 1,556 | 881 | ||||||||||||||||||
|
Operating
data:
|
||||||||||||||||||||||||
|
Throughput
(MMbtu/d)
|
751,761 | 587,098 | 258,194 | 161,584 | 192,236 | 211,569 | ||||||||||||||||||
(1) The
year ended December 31, 2006 amounts have been corrected for an error made in
the calculation of loss per unit resulting from the issuance of Class C common
units at a discount.
(2) See "-- Non-GAAP Financial Measures" for a reconciliation to its
most directly comparable GAAP measure.
Non-GAAP
Financial Measures
We
include the following non-GAAP financial measures: EBITDA and total segment
margin. We provide reconciliations of these non-GAAP financial measures to
their most directly comparable financial measures as calculated and presented in
accordance with GAAP.
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 Partner;
|
|
§
|
our
operating performance and return on capital as compared to those of other
companies in the midstream energy sector, without regard to financing
methods 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 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
does not include interest expense, income taxes or depreciation and amortization
expense. Because we have borrowed money to finance our operations, interest
expense is a necessary element of our costs and our ability to generate cash
available for distribution. Because we use capital assets, depreciation
and amortization are also necessary elements of our costs. Therefore, any
measures that exclude these elements have material limitations. To
compensate for these limitations, we believe that it is important to consider
both net earnings determined under GAAP, as well as EBITDA, to evaluate our
performance.
We define
total segment margin as total revenues, including service fees, less cost of gas
and liquids. Total segment margin is included as a supplemental disclosure
because it is a primary performance measure used by our management as it
represents the results of product sales, service fee revenues and product
purchases, a key component of our operations. We believe total segment
margin is an important measure because it is directly related to our volumes and
commodity price changes. Operation and maintenance expense is a
separate measure used by management to evaluate operating performance of field
operations. Direct labor, insurance, property taxes, repair and
maintenance, utilities and contract services comprise the most significant
portion of our operation and maintenance expenses. These expenses are
largely independent of the volumes we transport or process and fluctuate
depending on the activities performed during a specific period. We do not
deduct operation and maintenance expenses from total revenues in calculating
total segment margin because we separately evaluate commodity volume and price
changes in total segment margin. As an indicator of our operating
performance, total segment margin should not be considered an alternative to, or
more meaningful than, net income as determined in accordance with GAAP.
Our total segment margin may not be comparable to a similarly titled
measure of another company because other entities may not calculate total
segment margin in the same manner.
|
Regency
Energy Partners LP
|
Regency
LLC Predecessor
|
|||||||||||||||||||||||
|
Period
from
|
Period
from
|
|||||||||||||||||||||||
|
Acquisition
Date
|
Period
from
|
Inception
|
||||||||||||||||||||||
|
Year
Ended
|
Year
Ended
|
Year
Ended
|
(December
1, 2004)
|
January
1, 2004 to
|
(April
2, 2003) to
|
|||||||||||||||||||
|
December
31, 2007
|
December
31, 2006
|
December
31, 2005
|
to
December 31, 2004
|
November
30, 2004
|
December
31, 2003
|
|||||||||||||||||||
|
(in
thousands)
|
||||||||||||||||||||||||
|
Reconciliation
of "EBITDA" to net cash flows provided by (used in) operating activities
and to net (loss) income
|
||||||||||||||||||||||||
|
Net
cash flows provided by (used in) operating activities
|
$ | 74,413 | $ | 44,156 | $ | 37,340 | $ | (4,311 | ) | $ | 32,401 | $ | 6,494 | |||||||||||
|
Add
(deduct):
|
||||||||||||||||||||||||
|
Depreciation
and amortization
|
(53,734 | ) | (39,287 | ) | (24,286 | ) | (1,793 | ) | (10,461 | ) | (4,658 | ) | ||||||||||||
|
Write-off
of debt issuance costs
|
(5,078 | ) | (10,761 | ) | (8,480 | ) | - | (3,022 | ) | - | ||||||||||||||
|
Equity
income
|
43 | 532 | 312 | 56 | - | - | ||||||||||||||||||
|
Risk
management portfolio value changes
|
(14,667 | ) | 2,262 | (11,191 | ) | 322 | - | - | ||||||||||||||||
|
Loss
(gain) on assets sales
|
(1,522 | ) | - | 1,254 | - | - | - | |||||||||||||||||
|
Unit
based compensation expenses
|
(15,534 | ) | (2,906 | ) | - | - | - | - | ||||||||||||||||
|
Accrued
revenues and accounts receivable
|
30,608 | 5,506 | 43,012 | (2,568 | ) | 19,832 | 31,966 | |||||||||||||||||
|
Other
current assets
|
1,293 | (104 | ) | 2,644 | 2,456 | 1,169 | 1,070 | |||||||||||||||||
|
Accounts
payable, accrued cost of gas and liquids and accrued
liabilities
|
(36,319 | ) | 1,359 | (52,651 | ) | (548 | ) | (18,122 | ) | (26,880 | ) | |||||||||||||
|
Accrued
taxes payable
|
(835 | ) | (492 | ) | (806 | ) | 921 | (1,475 | ) | (906 | ) | |||||||||||||
|
Other
current liabilities
|
984 | (3,148 | ) | (1,269 | ) | 242 | (502 | ) | (917 | ) | ||||||||||||||
|
Proceeds
from early termination of interest rate swap
|
- | (4,940 | ) | - | - | - | - | |||||||||||||||||
|
Amount
of swap termination proceeds reclassified into earnings
|
1,078 | 3,862 | - | - | - | - | ||||||||||||||||||
|
Other
assets and liabilities
|
(358 | ) | (3,283 | ) | 3,261 | 6,697 | 196 | 5 | ||||||||||||||||
|
Net
(loss) income
|
$ | (19,628 | ) | $ | (7,244 | ) | $ | (10,860 | ) | $ | 1,474 | $ | 20,016 | $ | 6,174 | |||||||||
|
Add:
|
||||||||||||||||||||||||
|
Interest
expense, net
|
52,016 | 37,182 | 17,880 | 1,335 | 5,097 | 2,392 | ||||||||||||||||||
|
Depreciation
and amortization
|
51,739 | 39,654 | 23,171 | 1,661 | 10,129 | 4,324 | ||||||||||||||||||
| Income tax expense | 931 | - | - | - | - | - | ||||||||||||||||||
|
EBITDA
|
$ | 85,058 | $ | 69,592 | $ | 30,191 | $ | 4,470 | $ | 35,242 | $ | 12,890 | ||||||||||||
|
Reconciliation
of "total segment margin" to net (loss) income
|
||||||||||||||||||||||||
|
Net
(loss) income
|
$ | (19,628 | ) | $ | (7,244 | ) | $ | (10,860 | ) | $ | 1,474 | $ | 20,016 | $ | 6,174 | |||||||||
|
Add
(deduct):
|
||||||||||||||||||||||||
|
Operation
and maintenance
|
45,474 | 39,496 | 24,291 | 1,819 | 17,786 | 7,012 | ||||||||||||||||||
|
General
and administrative
|
39,543 | 22,826 | 15,039 | 645 | 6,571 | 2,651 | ||||||||||||||||||
|
Loss
on assets sales, net
|
1,522 | - | - | - | - | - | ||||||||||||||||||
|
Management
services termination fee
|
- | 12,542 | - | - | - | - | ||||||||||||||||||
|
Transaction
expenses
|
420 | 2,041 | - | - | 7,003 | 724 | ||||||||||||||||||
|
Depreciation
and amortization
|
51,739 | 39,654 | 23,171 | 1,661 | 10,129 | 4,324 | ||||||||||||||||||
|
Interest
expense, net
|
52,016 | 37,182 | 17,880 | 1,335 | 5,097 | 2,392 | ||||||||||||||||||
|
Loss
on debt refinancing
|
21,200 | 10,761 | 8,480 | - | 3,022 | - | ||||||||||||||||||
|
Other
income and deductions, net
|
(1,308 | ) | (839 | ) | (733 | ) | (64 | ) | (186 | ) | (205 | ) | ||||||||||||
|
Discontinued
operations
|
- | - | (732 | ) | - | 121 | - | |||||||||||||||||
|
Income
tax expense
|
931 | - | - | - | - | - | ||||||||||||||||||
|
Total
segment margin
|
$ | 191,909 | $ | 156,419 | $ | 76,536 | $ | 6,870 | $ | 69,559 | $ | 23,072 | ||||||||||||
The
following discussion analyzes our financial condition and results of operations.
You should read the following discussion of our financial condition and
results of operations in conjunction with our historical consolidated financial
statements and 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, Oklahoma, and Colorado.
OUR OPERATIONS. Prior to the
acquisition of CDM in January 2008, we managed our business and analyzed and
reported our results of operations through two 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; and
|
|
§
|
Transportation: We
deliver natural gas from northwest Louisiana to more favorable markets in
northeast Louisiana through our 320-mile Regency Intrastate Pipeline
system.
|
On
January 15, 2008, we acquired CDM, which now comprises our contract compression
segment. Our contract compression segment provides 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.
Through
December 31, 2007, all of our revenue is derived from, and all of our assets and
operations are part of our gathering and processing segment and our
transportation segment. As such the following discussion of our financial
condition and results of operation does not reflect our contract compression
segment.
Gathering and
processing segment. Results
of operations from our Gathering and Processing segment are determined primarily
by the volumes of natural gas that we gather and process, our current contract
portfolio, and natural gas and NGL prices. We measure the performance of
this segment primarily by the segment margin it generates. We gather and
process natural gas pursuant to a variety of arrangements generally categorized
as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole”
arrangements. Under fee-based arrangements, we earn fixed cash fees for
the services that we render. Under the latter two types of arrangements,
we generally purchase raw natural gas and sell processed natural gas and NGLs.
We regard the segment margin generated by our sales of natural gas and
NGLs under percent-of-proceeds and keep-whole arrangements as comparable to the
revenues generated by fixed fee arrangements. The following is a
summary of our most common contractual arrangements:
|
§
|
Fee-Based
Arrangements. Under these arrangements, we generally are
paid a fixed cash fee for performing the gathering and processing
service. This fee is directly related to the volume of natural
gas that flows through our systems and is not directly dependent on
commodity prices. A sustained decline in commodity prices,
however, could result in a decline in volumes and, thus, a decrease in our
fee revenues. These arrangements provide stable cash flows, but
minimal, if any, upside in higher commodity price
environments.
|
|
§
|
Percent-of-Proceeds
Arrangements. Under these arrangements, we generally
gather raw natural gas from producers at the wellhead, transport it
through our gathering system, process it and sell the processed gas and
NGLs at prices based on published index prices. In this type of
arrangement, we retain the sales proceeds less amounts remitted to
producers and the retained sales proceeds constitute our
margin. These arrangements provide upside in high commodity
price environments, but result in lower margins in low commodity price
environments. Under these arrangements, our margins typically cannot be
negative. We regard the margin from this type of arrangement as
an important analytical measure of these arrangements. The
price paid to producers is based on an agreed percentage of one of the
following: (1) the actual sale proceeds; (2) the proceeds based on an
index price; or (3) the proceeds from the sale of processed gas or NGLs or
both. Under this type of arrangement, our margin correlates
directly with the prices of natural gas and NGLs (although there is often
a fee-based component to these contracts in addition to the commodity
sensitive component).
|
|
§
|
Keep-Whole
Arrangements. Under these arrangements, we process raw
natural gas to extract NGLs and pay to the producer the full thermal
equivalent volume of raw natural gas received from the producer in
processed gas or its cash equivalent. We are generally entitled
to retain the processed NGLs and to sell them for our
account. Accordingly, our margin is a function of the
difference between the value of the NGLs produced and the cost of the
processed gas used to replace the thermal equivalent value of those
NGLs. The profitability of these arrangements is subject not
only to the commodity price risk of natural gas and NGLs, but also to the
price of natural gas relative to NGL prices. These arrangements
can provide large profit margins in favorable commodity price
environments, but also can be subject to losses if the cost of natural gas
exceeds the value of its thermal equivalent of NGLs. Many of
our keep-whole contracts include provisions that reduce our commodity
price exposure, including (1) provisions that require the keep-whole
contract to convert to a fee-based arrangement if the NGLs have a lower
value than their thermal equivalent in natural gas, (2) embedded discounts
to the applicable natural gas index price under which we may reimburse the
producer an amount in cash for the thermal equivalent volume of raw
natural gas acquired from the producer, (3) fixed cash fees for ancillary
services, such as gathering, treating, and compression, or (4) the ability
to bypass processing in unfavorable price
environments.
|
Percent-of-proceeds
and keep-whole arrangements involve commodity price risk to us because our
segment margin is based in part on natural gas and NGL prices. We
seek to minimize our exposure to fluctuations in commodity prices in several
ways, including managing our contract portfolio. In managing our
contract portfolio, we classify our gathering and processing contracts according
to the nature of commodity risk implicit in the settlement structure of those
contracts. For example, we seek to replace our longer term keep-whole
arrangements as they expire or whenever the opportunity presents
itself.
Another
way we minimize our exposure to commodity price fluctuations is by executing
swap contracts settled against ethane, propane, butane, natural gasoline, crude
oil, and natural gas market prices. We continually monitor our
hedging and contract portfolio and expect to continue to adjust our hedge
position as conditions warrant.
Transportation
segment. Results
of operations from our Transportation segment are determined primarily by the
volumes of natural gas transported on our Regency Intrastate Pipeline system and
the level of fees charged to our customers or the margins received from purchases
and sales of natural gas. We generate revenues and segment margins for our
Transportation segment principally under fee-based transportation contracts or
through the purchase of natural gas at one of the inlets to the pipeline and the
sale of natural gas at an outlet. The margin we earn from our
transportation activities is directly related to the volume of natural gas that
flows through our system and is not directly dependent on commodity
prices. If a sustained decline in commodity prices should result in a
decline in volumes, our revenues from these arrangements would be
reduced.
Generally,
we provide to shippers two types of fee-based transportation services under our
transportation contracts:
|
§
|
Firm Transportation. When
we agree to provide firm transportation service, we become obligated to
transport natural gas nominated by the shipper up to the maximum daily
quantity specified in the contract. In exchange for that
obligation on our part, the shipper pays a specified reservation charge,
whether or not it utilizes the capacity. In most cases, the shipper also
pays a commodity charge with respect to quantities actually transported by
us.
|
|
§
|
Interruptible
Transportation. When we agree to provide interruptible
transportation service, we become obligated to transport natural gas
nominated by the shipper only to the extent that we have available
capacity. For this service the shipper pays no reservation
charge but pays a commodity charge for quantities actually
shipped.
|
We
provide transportation services under the terms of our contracts and under an
operating statement that we have filed and maintain with the FERC with respect
to transportation authorized under section 311 of the NGPA.
In
addition, we perform a limited merchant function on our Regency Intrastate
Pipeline system. This merchant function is conducted by a separate
subsidiary. We purchase natural gas from a producer or gas marketer at a
receipt point on our system at a price adjusted to reflect our transportation
fee and transport that gas to a delivery point on our system at which we sell
the natural gas at market price. We regard the segment margin with respect
to those purchases and sales as the economic equivalent of a fee for our
transportation service. These contracts are frequently settled in terms of
an index price for both purchases and sales. In order to minimize
commodity price risk, we attempt to match sales with purchases at the index
price on the date of settlement.
We sell
natural gas on intrastate and interstate pipelines to marketing affiliates of
natural gas pipelines, marketing affiliates of integrated oil companies and
utilities. We typically sell natural gas under pricing terms related to a
market index. To the extent possible, we match the pricing and timing of
our supply portfolio to our sales portfolio in order to lock in our margin and
reduce our overall commodity price exposure. To the extent our natural gas
position is not balanced, we will be exposed to the commodity price risk
associated with the price of natural gas.
HOW WE EVALUATE OUR
OPERATIONS. Our management
uses a variety of financial and operational measurements to analyze our
performance. We view these measures as important tools for evaluating the
success of our operations and review these measurements on a monthly basis for
consistency and trend analysis. These measures include volumes, segment
margin and operating and maintenance expenses on a segment basis and EBITDA on a
company-wide basis.
Volumes. We must
continually obtain new supplies of natural gas to maintain or increase
throughput volumes on our gathering and processing systems. Our ability to
maintain existing supplies of natural gas and obtain new supplies is affected by
(1) the level of workovers or recompletions of existing connected wells and
successful drilling activity in areas currently dedicated to our gathering and
processing systems, (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 activity 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.
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.
Total Segment
Margin. Segment margin
from Gathering and Processing, together with segment margin from Transportation,
comprise total segment margin. We use total segment margin as a measure of
performance. See “Item 6 Selected Financial Data — Non-GAAP Financial
Measures” for a reconciliation of this non-GAAP financial measure, total segment
margin, to its most directly comparable GAAP measures, net cash flows provided
by (used in) operating activities and net income (loss).