e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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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, 2005 |
OR |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period
from to |
Commission file number: 0001-338613
REGENCY ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)
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Delaware |
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16-1731691 |
(State or other jurisdiction of
incorporation or organization) |
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(I.R.S. Employer
Identification No.) |
1700 Pacific Avenue, Suite 2900
Dallas, Texas |
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75201 |
(Address of principal executive offices) |
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(Zip Code) |
(214) 750-1771
(Registrants telephone number, including area code)
[None]
(Former name, former address and former fiscal year, if changed
since last report)
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) 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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Nasdaq National Market |
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange Act. Yes
þ No
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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
o No
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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
registrants 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. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2 of the
Exchange Act.
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Large accelerated filer o |
Accelerated filer o |
Non-accelerated filer þ |
Indicate by check mark whether the registrant is a shell company
(as defined in Rule 12b-2 of the Exchange
Act). Yes o No
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As of March 15, 2006, the aggregate market value of the
registrants common stock held by non-affiliates of the
registrant was $322,543,500 based on the closing sale price as
reported on the National Association of Securities Dealers
Automated Quotation System National Market System.
Indicate the number of outstanding units of each of the
registrants classes of units, as of the latest practicable
date.
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Class |
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Outstanding at March 15, 2006 |
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Common Units |
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19,103,896 |
Subordinated Units |
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19,103,896 |
DOCUMENTS INCORPORATED BY REFERENCE
None.
REGENCY ENERGY PARTNERS LP
ANNUAL REPORT on
FORM 10-K
For the year ended December 31, 2005
TABLE OF CONTENTS
PART I
Introductory Statement
References in this report to Regency Energy
Partners, 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 in 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. References to our general partner or
the General Partner refer to Regency GP LP, the
general partner of the Partnership, and to the Managing
GP refer to Regency GP LLC, the general partner of the
General Partner, which effectively manages the business and
affairs of the Partnership. References to
HM Capital refer to HM Capital Partners
LLC. References to HM Capital Investors refer
to Regency Acquisition LP, HMTF Regency L.P., HM Capital
and funds managed by HM Capital, including the Hicks, Muse,
Tate & Furst Equity Fund V, L.P., and certain
co-investors, including some of the directors and officers of
the Managing GP. Regency Acquisition LP is wholly owned by HMTF
Regency L.P., which, in turn, is wholly owned by
HM Capital, funds managed by HM Capital and certain
co-investors.
Forward-Looking Statements
Certain matters discussed in this report, excluding
historical information, as well as some statements by us in
periodic press releases and some oral statements of our
officials during presentations about the Partnership, include
certain 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. These
forward-looking statements are identified as any statement that
does not related strictly to historical or current facts.
Statements using words such as anticipate,
believe, intend, project,
plan, expect, continue,
estimate, goal, forecast,
may, will, or similar expressions help
identify forward-looking statements. Although we and our
Managing GP believe such forward-looking statements are based on
reasonable assumptions and current expectations and projections
about future events, neither we nor our Managing GP can give
assurances that such expectations will prove to be correct.
Forward-looking statements are subject to a variety of risks,
uncertainties and assumptions. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may vary materially from those
anticipated, estimated, projected or expected. When considering
forward-looking statements, please read the section titled
Risk Factors included under Item 1A of this
annual report.
ITEM
1. Business.
Overview
We are a Delaware limited partnership recently formed by
HM Capital Partners LLC (formerly Hicks, Muse,
Tate & Furst Incorporated), or HM Capital, to
capitalize on opportunities in the midstream sector of the
natural gas industry. We are a growth-oriented independent
midstream energy partnership engaged in the gathering,
processing, marketing and transportation of natural gas. We
provide these services through systems located in north
Louisiana, west Texas and the mid-continent region of the United
States, which includes Kansas, Oklahoma, Colorado and the Texas
Panhandle.
We divide our operations into two business segments:
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Gathering and Processing: in which 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 natural gas liquids, or
NGLs, from the raw natural gas and selling or delivering the
pipeline-quality natural gas and NGLs to various markets and
pipeline systems; and |
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Transportation: in which we deliver natural gas from northwest
Louisiana to northeast Louisiana through our
320-mile Regency
Intrastate Pipeline system, which has been significantly
expanded and extended through our Regency Intrastate Enhancement
Project. |
Please refer to Notes 8 and 9 of the consolidated financial
statements for information regarding revenues from external
customers, segment margin, and total assets by segment.
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Gathering and Processing Segment |
We operate our Gathering and Processing segment in three
geographic areas of the United States: north Louisiana, west
Texas and the mid-continent region. Our gathering and processing
assets include five cryogenic processing plants, of which four
are currently active, and approximately 2,950 miles of
related gathering and pipeline infrastructure connected to
approximately 2,650 active wells. In north Louisiana, we
own a large gathering system that is connected to two processing
plants that we own and operate. In west Texas, we own a large
gathering system that is connected to a processing plant that we
own and operate. In the mid-continent region, we own three large
gathering systems, one of which is connected to a processing
plant that we own and operate. Our Gathering and Processing
segment also includes our NGL marketing business through which
we sell the NGLs that are produced by our processing plants for
our own account and for the accounts of our customers.
The following table contains information regarding our gathering
systems and processing plants as of December 31, 2005:
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Throughput | |
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Length | |
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Wells | |
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Compression | |
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Capacity | |
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North Louisiana
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Gathering pipelines |
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600 |
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700 |
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14,500 |
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300 |
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Processing facilities |
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10,000 |
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90 |
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West Texas
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Gathering pipelines |
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750 |
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450 |
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22,000 |
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200 |
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Processing facility |
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20,000 |
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125 |
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Mid-Continent
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Gathering pipelines |
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1,600 |
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1,500 |
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41,500 |
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265 |
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Processing facility |
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3,650 |
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Excludes 80 MMcf/d of throughput capacity available at our
inactive Lakin processing facility. |
Our Transportation segment consists of our Regency Intrastate
Pipeline system, a
320-mile natural gas
pipeline in north Louisiana that transports natural gas
primarily from northwest Louisiana to northeast Louisiana where
it connects to a number of interstate and intrastate pipelines.
Upon completion of our Regency Intrastate Enhancement Project in
December 2005, our Regency Intrastate Pipeline system had a
capacity of 800 MMcf/d with 27,400 horsepower of
compression and a 35 MMcf/d refrigeration plant for
hydrocarbon dewpoint control.
Portions of the Regency Intrastate Pipeline system have
historically operated at full capacity and represented a
significant constraint on the flow of natural gas from producing
fields in north Louisiana to intrastate and interstate markets
in northeast Louisiana. To alleviate the constraint, we
constructed a major expansion and extension of this system,
which we refer to as the Regency Intrastate Enhancement Project.
The project quadrupled the systems capacity from the
capacity that existed prior to the commencement of the project.
The completion of the Regency Intrastate Enhancement Project
enables us to provide transportation services from the three
largest natural gas producing fields in Louisiana.
The Regency Intrastate Enhancement Project was a multi-phase
project designed to relieve bottlenecks on certain sections of
the pipeline and to access new sources of supply and markets. We
began
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planning this project in January 2005 and started construction
in May 2005. We completed the project in December 2005.
The total cost of this project is approximately
$157.0 million, and included the 40 mile expansion of
our existing Regency Intrastate Pipeline system and the addition
of an 80-mile,
30-inch diameter
pipeline extension to the Regency Intrastate Pipeline system
supported by approximately 9,500 horsepower of additional
compression. The project has extended our transportation
services into additional major producing fields in north
Louisiana, connected our system to other pipelines in northeast
Louisiana, and has increased the capacity of the pipeline to
800 MMcf/d.
During the year ended December 31, 2005 (most of which
preceded completion of the Regency Intrastate Enhancement
Project), our Regency Intrastate Pipeline system had average
throughput of 258,000 MMBtu/d.
One of our motivations in constructing the Enhancement Project
was to enable our customers to reach markets offering more
favorable prices by interconnecting with other pipelines in
northeast Louisiana. As of December 31, 2005, the Regency
Intrastate Pipeline system could deliver gas to two
250 MMcf/d pipeline interconnects. Since then, three
additional interconnects have been completed: two
250 MMcf/d pipeline interconnects and a 500 MMcf/d
pipeline interconnect.
Through March 28, 2006, we have signed definitive
agreements for 466,000 MMBtu/d of firm transportation and
404,000 MMBtu/d of interruptible transportation on the Regency
Intrastate Pipeline system. We are engaged in discussions with
other parties interested in utilizing the remaining firm system
transportation capacity.
Business Strategies
Our management team is dedicated to increasing the amount of
cash available for distribution to each outstanding unit. We
intend to achieve this by pursuing organic growth projects that
yield attractive returns and by capitalizing on accretive
acquisition opportunities.
Our specific strategies include:
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Implementing cost-effective organic growth opportunities.
We intend to build natural gas gathering assets, processing
facilities and transportation lines that enhance our existing
systems and our ability to aggregate supply and to access
premium markets for that supply. We will emphasize projects that
increase volume throughput and are expected to generate
attractive returns, such as our Regency Intrastate Enhancement
Project and our project to provide gathering facilities for a
long-term exploration and development program under an existing
letter of intent with a producer in the Mid-Continent area. We
are also evaluating, but have not yet made any decision to
pursue, other organic growth projects. The projects under
consideration include: |
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Expansion of our Regency Intrastate Pipeline west of Haughton to
relieve capacity constraints; |
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extensions of the pipeline east into other fields beyond
Winnsboro; |
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construction and installation of a refrigeration plant at
Longwood or Sibley or both; |
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construction of additional compression at our Mainline
Compressor Station; |
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construction of a storage facility in proximity to the Regency
Intrastate Pipeline in conjunction with a third party; and |
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initiation and construction of step out expansion projects for
our Waha gathering system. |
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Continuing to enhance profitability of our existing
assets. We intend to increase the profitability of our
existing asset base by identifying new business opportunities,
adding new volumes of natural gas supplies, undertaking
additional initiatives to enhance utilization and continuing to
reduce costs. As an example, until recently, the NGLs produced
by our processing plants were sold to third parties as mixed
NGLs. In September 2005, we began delivering the mixed NGLs
produced by our |
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processing plants to operators of fractionation facilities for
fractionation for our account. We then sell the individual
components, such as ethane, propane and isobutane, directly to
marketing companies, refineries and other wholesalers. We
believe this marketing function will allow us to earn additional
margins from the sale of the NGLs that otherwise would have been
earned by the fractionator. |
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Pursuing accretive acquisitions of complementary assets.
We intend to pursue strategic acquisitions of midstream assets
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 that there will be additional acquisition opportunities
as a result of the ongoing divestiture of midstream assets by
large industry participants. |
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Continuing to reduce our exposure to commodity price
risk. Because of the volatility of natural gas and NGL
prices, we attempt to operate our business in a manner that
allows us to mitigate the impact of fluctuations in commodity
prices and to generate stable cash flows. We manage this
commodity price exposure through an integrated strategy that
includes management of our contract portfolio, matching sales
prices of commodities with purchases, optimization of our
portfolio by monitoring basis and other price differentials in
our areas of operations, and the use of derivative contracts. We
have reduced and intend to continue to reduce, when the
opportunity arises, our commodity price exposure by replacing
keep-whole contracts with fee based or
percentage-of-proceeds
gas processing contracts. We have executed swap contracts
settled against ethane, propane, butane and natural gasoline
market prices, supplemented with crude oil put options.
(Historically, changes in the prices of heavy NGLs, such as
natural gasoline, have generally correlated with changes in the
price of crude oil.) As a result, we have hedged approximately
95% of our expected exposure to NGL prices in 2006,
approximately 75% in 2007 and approximately 50% in 2008. We
continually monitor our hedging and contract portfolio and
expect to continue to adjust our hedge position as conditions
warrant. |
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Improving our credit ratings. We are committed to
improving our credit ratings. The current credit ratings on our
debt under our credit facilities are B+ by Standard &
Poors and B1 by Moodys. The additional revenue and
cash flow resulting from the completed Regency Intrastate
Enhancement Project will significantly improve our credit
statistics that are considered by the rating agencies. |
We intend to finance our growth projects through a combination
of funds available under our credit facility, commercial bank
borrowings and the issuance of debt and equity securities. Given
our policy of distributing available cash, we may not be able to
finance such growth through the application of internal cash
flow.
Competitive
Strengths
We believe that we are well positioned to execute our strategies
and to compete in the natural gas gathering, processing,
marketing and transportation businesses based on the following
competitive strengths:
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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 Delaware and Devonian basins of west Texas and the Hugoton
and Anadarko basins in the mid-continent area. 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. Currently, these areas are 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. |
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Our recently completed Regency Intrastate Enhancement Project
will provide us with the opportunity to increase significantly
our fee-based transportation throughput and cash flow. Prior
to the completion of the Regency Intrastate Enhancement Project,
a portion of the Regency Intrastate Pipeline system was at full
capacity and was not able to capitalize on the current
significant constraint on the flow of natural gas from prolific
producing fields in north Louisiana to intrastate and interstate
markets in northeast Louisiana. As a result of this bottleneck
in the pipeline, we had not been able to increase significantly
the throughput on the pipeline despite an increase in drilling
and production in the area. Our Regency Intrastate Enhancement
Project has substantially increased the pipelines capacity
by alleviating the bottleneck and extending the pipeline to
additional markets in northeast Louisiana. We expect this
expansion project will provide us with significant additional
transportation throughput volumes and stable, fee-based cash
flow. |
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We have the financial flexibility to pursue growth
opportunities. The borrowing limit under our revolving
credit facility is $160 million. At December 31, 2005
we had borrowed $50 million against this facility. This
revolving credit facility provides us with the liquidity and
financing flexibility we will need to execute our business
strategy. We remain committed to maintaining a balanced capital
structure which will afford us the financial flexibility to fund
expansion projects and other attractive investment opportunities. |
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We have an experienced, knowledgeable management team with a
proven track record of performance. Our management team has
a proven track record of enhancing value through the investment
in and the acquisition, exploitation and integration of energy
assets. Our senior management has an average of over
20 years of industry related experience. Our teams
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. Members of our senior
management team have a substantial economic interest in us. |
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We are affiliated with HM Capital a leading private equity
investment firm headquartered in Dallas, Texas. Our affiliation
with HM Capital provides us with significant benefits. We
expect that our relationship with HM Capital will provide us
with several significant benefits, including access to a
significant pool of operational, transactional and financial
professionals, multiple sources of capital and increased
exposure to acquisition opportunities. HM Capital is a
leading sector focused private equity firm and is currently
managing and investing a $1.6 billion fund. Since the
firms founding in 1989, HM Capital has completed more than
150 transactions in its core sectors for a total transaction
value in excess of $26 billion. |
Industry
Overview
General. Raw natural gas produced from the wellhead is
gathered and delivered to a processing plant located near the
production, where it is treated and dehydrated and then
processed through cryogenic or other processing facilities.
Natural gas processing involves the separation of raw natural
gas into pipeline quality natural gas, principally methane, and
mixed NGLs. It also 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 end users. Mixed NGLs that are produced
by processing raw natural gas are typically transported via NGL
pipelines or by truck to a fractionator, which separates the NGL
into its components, such as ethane, propane, normal butane,
isobutane and natural gasoline. NGLs are then sold to end users.
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The following diagram depicts our role in the process of
gathering, processing, marketing and transporting
natural gas.
Overview of U.S. market. 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. The midstream natural gas industry in North America
includes approximately 574 processing plants that process
approximately 47 Bcf of natural gas per day and produce
approximately 77 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 continues to be a critical component of energy
consumption in the United States. According to the Energy
Information Administration, or EIA, total annual domestic
consumption of natural gas is expected to increase from
approximately 22.2 trillion cubic feet, or Tcf, in 2005 to
approximately 25.9 Tcf in 2015, representing an average
annual growth rate of approximately 1.7%. 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 19.8 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 and treating. The process of raw natural gas
gathering begins with the drilling of wells into gas bearing
rock formations. Once a well has been completed, the well is
connected to a gathering system. 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 five
large gathering systems.
Raw natural gas has a varied composition depending on the field,
the formation and the reservoir from which it is produced. Raw
natural gas produced in some areas may contain hydrogen sulfide,
carbon dioxide, nitrogen and other impurities. Treating plants,
such as the one that we own and operate at our Waha facility,
remove these impurities before the natural gas is introduced to
the processing plant. Our Waha facility utilizes an amine
treating process, which involves a continuous circulation of a
liquid chemical called amine that physically contacts the raw
natural gas. The amine reacts with carbon dioxide and hydrogen
sulfide, removing them from the gas stream prior to further
processing.
Compression. Gathering systems are operated at design
pressures that will maximize the total throughput 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 in the ground
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.
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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
downstream pipeline.
Processing. Raw natural gas produced at the wellhead is
often unsuitable for long-haul pipeline transportation or
commercial use and must be processed to remove the heavier
hydrocarbon components and contaminants. The principal
components of raw natural gas are methane and ethane, but most
raw natural gas also contains varying amounts of NGLs (such as
ethane, propane, normal butane, isobutane, and natural gasoline)
and impurities, such as water, sulfur compounds, carbon dioxide,
or nitrogen. Natural gas in commercial distribution systems is
composed almost entirely of methane and ethane, with moisture
and other impurities reduced to very low concentrations. Raw
natural gas is processed not only to remove unwanted impurities
that would interfere with pipeline transportation or use of raw
natural gas, but also to separate from the gas those hydrocarbon
liquids that have higher financial value as NGLs. We own and
operate four cryogenic natural gas processing plants. The
cryogenic process utilizes heat exchangers and a turbo-expander
to cool the gas and condense the NGLs. The NGLs are then
separated from the gaseous components.
Fractionation. NGL fractionation facilities separate
mixed NGL streams into discrete NGL products: ethane, propane,
normal butane, isobutane and natural gasoline. We do not own or
operate any NGL fractionation facilities. We ship the NGLs that
we produce to a fractionator. 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.
Marketing. Natural gas and NGL marketing involves the
sale of the pipeline-quality gas and NGLs that are either
produced by processing plants or purchased from gathering
systems or other pipelines. In the fall of 2005, we began
marketing NGLs 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. Our intrastate
natural gas pipeline system includes a refrigeration processing
plant that is utilized to reduce the hydrocarbon dewpoint of
natural gas in order to meet downstream market pipeline-quality
specifications.
Gathering
and Processing Operations
We contract with producers to gather raw natural gas from
individual wells or central delivery points located near our
processing plants or gathering systems. In general, once we have
executed a contract, we connect wells and central delivery
points to our gathering lines through which the raw natural gas
is delivered 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, process the gas and extract
the NGLs.
We continuously seek new sources of raw natural gas supply to
increase throughput volume on our systems and through our
plants. We connected 44 new wells in 2004 and 117 new
wells during 2005, including connections of central delivery
points which may have multiple wells behind them.
All raw natural gas flowing through our gathering and processing
facilities is supplied under gathering and processing contracts
having fixed terms ranging from
month-to-month to
20 years. Alternatively, we
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have some contracts that span the life of the oil and gas lease.
For a description of our contracts, please read Our
Contracts and Managements 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.
Until recently, the NGLs produced by our processing plants were
sold to third parties as mixed NGLs. In September 2005, we began
delivering the mixed NGLs produced by our processing plants to
operators of fractionation facilities for fractionation for our
account. We then sell the individual components, such as ethane,
propane and butane, directly to marketing companies, refineries
and other wholesalers. We believe this marketing function will
allow us to earn additional margins from the sale of the NGLs
that otherwise would have been earned by the fractionator.
Our natural gas gathering and processing assets consist
primarily of five large natural gas gathering systems and four
active cryogenic gas processing plants which are located in
north Louisiana, West Texas and the
mid-continent region of
the United States. The following table contains certain
information regarding these gathering systems and processing
plants as of and for the year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput | |
|
|
Length | |
|
Wells | |
|
Compression | |
|
Capacity | |
Asset |
|
(Miles) | |
|
Connected | |
|
(Horsepower) | |
|
(MMcf/d) | |
|
|
| |
|
| |
|
| |
|
| |
North Louisiana
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dubach/Calhoun/Lisbon Gathering System
|
|
|
600 |
|
|
|
700 |
|
|
|
14,500 |
|
|
|
300 |
|
|
Dubach Processing Plant
|
|
|
|
|
|
|
|
|
|
|
7,000 |
|
|
|
50 |
|
|
Lisbon Processing Plant
|
|
|
|
|
|
|
|
|
|
|
3,000 |
|
|
|
40 |
|
West Texas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waha Gathering System
|
|
|
750 |
|
|
|
450 |
|
|
|
22,000 |
|
|
|
200 |
|
|
Waha Processing Plant
|
|
|
|
|
|
|
|
|
|
|
20,000 |
|
|
|
125 |
|
Mid-Continent
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hugoton Gathering System
|
|
|
850 |
|
|
|
900 |
|
|
|
28,000 |
|
|
|
120 |
|
|
Mocane-Laverne Gathering System
|
|
|
500 |
|
|
|
350 |
|
|
|
4,000 |
|
|
|
100 |
|
|
Greenwood Gathering System
|
|
|
250 |
|
|
|
250 |
|
|
|
9,500 |
|
|
|
45 |
|
|
Mocane Processing Plant
|
|
|
|
|
|
|
|
|
|
|
3,650 |
|
|
|
50 |
|
8
Our north Louisiana system includes the Dubach and Lisbon
processing plants and 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 includes over 600 miles of gathering
pipelines.
The following is a map of our north Louisiana gathering and
processing system.
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 the following four parishes in north
Louisiana: Claiborne, Union, Lincoln and Ouachita. Our operating
areas have 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.
During the year ended December 31, 2005, we connected
62 wells to our north Louisiana gathering system.
Devon Energy Corporation and XTO Energy Inc. represented
approximately 21% and 13%, respectively, of our natural gas
supply in this region for the year ended December 31, 2005.
Dubach/ Lisbon/ Calhoun Gathering System. The Dubach/
Lisbon/ Calhoun gathering system consists of over 600 miles
of natural gas gathering pipelines ranging in size from two
inches in diameter to ten inches in diameter. The system gathers
raw natural gas from producers and delivers approximately 85% of
the raw natural gas to either the Dubach or Lisbon processing
plants 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.
9
Dubach Processing Plant. The Dubach processing plant is a
cryogenic natural gas processing plant that processes raw
natural gas gathered on the Dubach and Calhoun gathering systems
and natural gas transported on the Regency Intrastate Pipeline
system. This plant, which was acquired by us in 2003, was
originally constructed in 1980 and was subsequently reassembled
in its present location in 1994.
Lisbon Processing Plant. The Lisbon processing plant is a
cryogenic natural gas processing plant that processes raw
natural gas gathered on the Lisbon gathering system. This plant,
which was acquired by us in 2003, was constructed in 1980 and
was subsequently reassembled in its present location in 1996.
Markets. There are numerous market outlets for the raw
natural gas that we gather and the NGLs that we produce on our
north Louisiana systems. The Dubach/ Lisbon/ Calhoun gathering
system is directly connected to several interstate natural gas
pipelines, including Texas Gas Transmission, Mississippi River
Transmission and Texas Eastern Transmission, and to our Regency
Intrastate Pipeline system. Our access to numerous markets,
including interstate pipelines in northeast Louisiana and to
several power plants located on our system, provides us with the
flexibility to sell our natural gas supply into markets with the
most attractive pricing.
The NGLs extracted from the raw natural gas at our processing
plants are transported by a
37-mile Regency NGL
pipeline to a third-party pipeline that delivers the NGLs to
Mont Belvieu, Texas for fractionation by third parties.
Our primary purchasers of pipeline-quality gas on the north
Louisiana gathering system are Atmos Energy Marketing, LLC, Duke
Energy Field Services and Sequent, which represented
approximately 64%, 11% and 10%, respectively, of the
revenues from such sales for the year ended December 31,
2005. All of the NGL sales from the north Louisiana processing
plants were made to Koch Hydrocarbon, LP, which
provided fractionation services during this period.
The following is a map of our Waha gathering and processing
system.
10
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.
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 and around 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
and steady flow rates.
This area is experiencing increasing levels of oil and natural
gas drilling activity as a result of strong demand for natural
gas and recent discoveries. In addition, several independent
exploration and production companies are pursuing more
aggressive drilling programs than the major oil companies that
currently are the primary producers in the area. Several of
these independent exploration and production companies are
developing unexploited reserves within our area of operations
through new well completions and infill drilling, along with
workovers and re-completions of existing wells. Additionally,
there have been recent large oil and natural gas discoveries in
this region by Chesapeake Energy Corporation and Anadarko
Petroleum Company. We believe that our significant presence and
modern and efficient asset base provides us with competitive
advantages in capturing new supplies of natural gas in the
region. Many of these areas of increased drilling require little
to no pipeline or meter expense as producers are connecting to
existing facilities.
During the year ended December 31, 2005, we connected to
24 wells to our Waha gathering system.
Duke Energy Field Services and ExxonMobil Corporation
represented approximately 25% and 14%, respectively, of our
natural gas supply in this region for the year ended
December 31, 2005.
Waha Gathering System. The Waha gathering system consists
of approximately 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 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 raw natural gas processing plant. The Waha processing
plant also includes an amine treating facility. The treating
facility uses an amine treating process to remove carbon dioxide
and hydrogen sulfide from raw natural gas that is gathered in
our Waha gathering system before the natural gas is introduced
to the processing plant.
Markets. The Waha gathering system has a variety of
market outlets for the natural gas that we gather. The
pipeline-quality gas from our gathering and processing
operations can be delivered into the Waha Hub, which includes
connections to several major interstate and intrastate pipelines
serving California, the mid-continent and Texas natural gas
markets, including Oasis Pipeline, Enterprise Texas Pipeline,
Atmos Pipeline, ONEOK Westex and El Paso Natural Gas
Pipeline. The NGLs extracted from the raw natural gas at the
Waha processing plant are transported to ExxonMobils NGL
pipeline, which delivers the NGLs to facilities in Mont Belvieu,
Texas for fractionation by third parties.
Our primary purchasers of pipeline-quality gas on the west Texas
gathering system are Energy Transfer Partners, Tenaska Marketing
Ventures, and BP Energy Company, which represented
approximately 40%, 25% and 15%, respectively, of the revenues
from such sales for the year ended December 31,
11
2005. All of the NGL sales from the Waha processing plant were
made to ExxonMobil Corporation, which fractionated the NGLs from
these plants during this period.
Our mid-continent systems include the following natural gas
gathering systems primarily in Kansas and Oklahoma:
|
|
|
|
|
the Hugoton gathering system, which is a large integrated
natural gas gathering and processing system located in
southwestern Kansas and includes approximately 850 miles of
gathering pipeline; |
|
|
|
the Mocane-Laverne gathering system, which is a large integrated
natural gas gathering and processing system located primarily in
the Oklahoma Panhandle and includes approximately 500 miles
of gathering pipelines and the Mocane cryogenic processing
plant; and |
|
|
|
the Greenwood gathering system, which is a large natural gas
gathering system located primarily in southwestern Kansas and
includes approximately 250 miles of gathering pipelines. |
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
throughput 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.
The following is a map of our mid-continent gathering and
processing systems.
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 and
the Texas panhandle. 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
12
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.
During the year ended December 31, 2005, we connected
31 wells to our mid-continent gathering systems.
Occidental Petroleum Corporation and Penn Virginia Corporation
provided approximately 21% and 10%, respectively, of our natural
gas supply in this region for the year ended December 31,
2005.
Hugoton Gathering System. The Hugoton gathering system is
located in southwestern Kansas. It consists of approximately
850 miles of natural gas gathering pipelines ranging in
size from two inches in diameter to 20 inches in diameter.
Substantially all of the raw natural gas gathered by the Hugoton
gathering system is delivered to a third partys processing
plant. We pay the third party a fee to process the gas for our
account.
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 approximately 500 miles of natural gas
gathering pipelines ranging in size from two inches in diameter
to 24 inches in diameter. The system gathers raw natural
gas from producers and delivers it for processing to the Mocane
processing plant.
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.
Greenwood Gathering System. The Greenwood gathering
system is located in Morton and Stanton Counties in southwestern
Kansas and Baca County in southeastern Colorado. It consists of
approximately 250 miles of natural gas gathering pipelines
ranging in size from four inches in diameter to 20 inches
in diameter. The raw natural gas gathered by this system is
delivered to a third partys processing plant. We pay the
third party a fee to process the gas for our account.
Markets. The pipeline-quality gas from our gathering and
processing operations in the mid-continent area is delivered
primarily into Panhandle Eastern Pipeline to serve markets in
the mid-continent and upper Midwest. This gas can also be sold
into the ANR Pipeline via the North Kiowa system or via the CIG
Pipeline or can be pooled through BPs Jayhawk processing
plant and Pioneer Natural Resources Santanta processing
plant.
The NGLs extracted from the raw natural gas at our gathering and
processing plants are transported by a third party NGL pipeline
that delivers the NGLs to the Conway Hub in Kansas for
fractionation by a third party.
Our primary purchasers of pipeline-quality gas on the
mid-continent gathering systems are Seminole Energy Services,
LLC, BP Energy Company, and Cinergy Marketing and Trading, LP,
which represented 37%, 29% and 21%, respectively, of the
revenues from such sales for the year ended December 31,
2005. All of the NGL sales from the mid-continent processing
plants were made to Koch Hydrocarbon, LP, which fractionated
these NGLs during this period.
We also own the Lakin processing plant, which is a cryogenic
processing plant with nitrogen rejection and helium recovery
capabilities. This plant has a capacity of 80,000 Mcf/d.
The plant was constructed in 1995 and was acquired by us in
2003. Through July 31, 2005, the Lakin processing plant
processed raw natural gas received from the Hugoton gathering
system. As part of our previously planned strategy, we suspended
operations at the Lakin processing plant (subject to
intermittent resumption) as of August 1, 2005. Suspending
the operations of the plant allowed us to renegotiate certain
unfavorable keep-whole processing contracts covering gas
processed at the plant and replace them with fee-based contracts
and to avoid charges for transporting natural gas from the
Hugoton gathering system through a third party pipeline out of
the tailgate of the Lakin plant. All of the gas from the Hugoton
gathering system is now
13
processed at a third party processing plant for our account for
a fee. 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
General. We own and operate a
320-mile intrastate
natural gas pipeline system, known as the Regency Intrastate
Pipeline system, in north Louisiana extending from northwest
Louisiana to northeast Louisiana. This system includes 27,400
horsepower of compression and a 35 MMcf/d refrigeration
plant for hydrocarbon dewpoint control. The following map
presents the location of the Regency Intrastate Pipeline system,
including the Regency Intrastate Enhancement Project described
below:
The following table contains certain information regarding the
Regency Intrastate Pipeline system prior to the commencement of
construction and following the completion of the Regency
Intrastate Enhancement Project:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput | |
|
|
|
|
Length | |
|
Compression | |
|
Capacity | |
|
Market | |
Asset |
|
(Miles) | |
|
(Horsepower) | |
|
(MMcf/d) | |
|
Outlets | |
|
|
| |
|
| |
|
| |
|
| |
Regency Intrastate Pipeline System
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-Enhancement Project
|
|
|
200 |
|
|
|
17,900 |
|
|
|
200 |
|
|
|
6 |
|
|
Post-Enhancement Project
|
|
|
320 |
|
|
|
27,400 |
|
|
|
800 |
|
|
|
11 |
|
Haughton Refrigeration Processing Plant
|
|
|
|
|
|
|
|
|
|
|
35 |
|
|
|
|
|
During the years ended December 31, 2005 and 2004, the
Regency Intrastate Pipeline system had average throughput of
258,194 MMBtu/d and 189,640 MMBtu/d, respectively.
Natural gas generally flows from west to east on the pipeline
from wellhead connections or connections with other gathering
systems.
14
Prior to the completion of our Regency Intrastate Enhancement
Project, our Regency Intrastate Pipeline system consisted of the
following components:
the Elm Grove System, a
31-mile,
12-inch diameter
pipeline placed in operation in 1974 that extends from
Southwestern Electric Power Companys Arsenal Hill Power
Plant in Caddo Parrish eastward to the Elm Grove natural gas
field in Bossier Parish;
the North Louisiana
Pipeline, a 23-mile,
12-inch diameter
pipeline and a 25-mile,
16-inch diameter
pipeline placed in service in 1989 that extends from the tie-in
point with the Elm Grove System to an interconnection with a
pipeline owned by Southern Natural Gas Company in Bienville
Parish;
the Metco Pipeline, a
19-mile,
20-inch diameter
pipeline placed in operation in 1990 that extends from the
interconnect point with the pipeline owned by Gulf States
Transmission Corporation to the western end of the Elm Grove
System interconnect;
the Ruston System, a
12-mile, six-inch
diameter pipeline, a six-mile,
12-inch diameter
pipeline and a
0.5-mile, four-inch
diameter pipeline located in Jackson and Lincoln Parishes in
northeast Louisiana and interconnects with pipelines owned by
Southern Natural Gas Co. and Duke Energy Field Services;
the Panda Pipeline, a
20-mile,
20-inch diameter
pipeline and an
11-mile,
24-inch diameter
pipeline placed in operation in 2002 that extends from the
eastern portion of the North Louisiana Pipeline to an interstate
pipeline that transports natural gas exclusively to a power
generation plant; and
the Dubach Extension, an
eight-mile, 12-inch
diameter pipeline that was constructed as part of our
Enhancement Project and is described in further detail below.
Our Regency Intrastate Pipeline system includes a natural gas
refrigeration conditioning plant. At the plant, we condition
natural gas to remove NGLs to ensure that it meets
pipeline-quality specifications so that it can be transported on
our intrastate pipeline. The NGLs extracted from the raw natural
gas at our refrigeration conditioning plant are sold to a third
party at the tailgate of the plant.
Our primary purchasers of pipeline-quality gas on the Regency
Intrastate Pipeline system are Alabama Gas Corporation,
Southwestern Power and Electric Company and Louis Dreyfus
Energy, which represented approximately 66%, 9% and 9%,
respectively, of the external revenues from such sales for the
year ended December 31, 2005.
Enhancement Project. Portions of the Regency Intrastate
Pipeline system have historically operated at full capacity and
represented a significant constraint on the flow of natural gas
from producing fields in north Louisiana to intrastate and
interstate markets in northeast Louisiana. As a result, in 2005,
we undertook to construct and completed a major expansion and
extension of this system, which we refer to as the Regency
Intrastate Enhancement Project. The project quadrupled the
systems capacity from the capacity that existed prior to
the commencement of the project.
The Regency Intrastate Enhancement Project was a multi-phase
project designed to relieve bottlenecks on certain sections of
the pipeline and to extend the pipeline in order to access new
sources of supply and markets. We began planning this project in
January 2005 and started construction in May 2005. We completed
the project in December 2005.
The total cost of this project is approximately
$157.0 million. On July 1, 2005, we completed the
Dubach extension, which consists of an eight mile,
12-inch diameter
pipeline and connection to the Panda Pipeline to our Dubach
processing plant located on our north Louisiana gathering
system. The Dubach extension provides the Regency Intrastate
Pipeline system with direct access to four interstate pipelines
that are directly connected to the Dubach processing plant.
As of October 1, 2005, we had completed construction of the
second phase of this project, a
40-mile,
24-inch diameter system
loop along a portion of our existing pipeline. This additional
pipeline increased the capacity of the Regency Intrastate
Pipeline system by 100 MMcf/d.
15
In December 2005, we completed construction of the final phase
of this project, which includes an
80-mile,
30-inch diameter
pipeline extension to the Regency Intrastate Pipeline system
providing transportation services from several major producing
fields in north Louisiana to markets in northeast Louisiana.
This Winnsboro extension extends from the eastern terminus of
the North Louisiana Pipeline to a point near Winnsboro,
Louisiana.
In order to facilitate the enhancement of the system, we also
added approximately 9,500 horsepower of compression.
As a result of the completion of the Regency Intrastate
Enhancement Project, we are able to transport natural gas
produced from the Vernon field, the Elm Grove field and the
Sligo field, which are the three largest natural gas producing
fields in Louisiana.
New Transportation Contracts. Through March 28,
2006, we have signed definitive agreements for 466,000 MMBtu/d
of firm transportation and 404,000 MMBtu/d of interruptible
transportation on the Regency Intrastate Pipeline system. We are
engaged in discussions with other parties interested in
utilizing the remaining firm system transportation capacity.
Funding of Project Costs. In July 2005, we amended our
credit facilities to provide for $170 million in additional
borrowing capacity, consisting of $60 million in additional
term loans and $110 million in additional revolving loans.
We used these amounts, together with an additional
$15 million equity contribution from funds managed by HM
Capital Partners and other investors, including directors and
members of management (collectively, the HM Capital Investors)
to complete the Regency Intrastate Enhancement Project. For
information regarding the terms of the amended and restated
credit facilities, please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Capital Requirements.
Interstate Pipeline Specifications. The markets to which
the shippers on our Regency Intrastate Pipeline ship natural gas
include interstate pipelines. These interstate pipelines
establish specifications for the natural gas that they are
willing to accept, which include such matters as hydrocarbon
dewpoint, temperature and impurities including water, sulphur,
carbon dioxide and hydrogen sulphide. 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, that pipeline may refuse to
accept all or a part of the natural gas scheduled for delivery
to it.
In certain cases, the mix of natural gas that we transport for
shippers on our Regency Intrastate Pipeline does not meet the
dewpoint specification of one of our interconnected interstate
pipelines. In October 2005, we began construction of a
refrigeration plant at Elm Grove to remove hydrocarbons and
allow the natural gas to meet these dewpoint specifications. We
expect the plant to be completed by the end of April 2006.
An interstate pipeline curtailed shipments through its existing
interconnect with our pipeline in late November 2005. We and our
shippers have thus far been able to find alternative markets for
all the curtailed gas. If for some reason we are unable to do so
during the period prior to completion of the Elm Grove
refrigeration plant, we may be required to shut-in
non-conforming gas delivered to us for transportation. We
estimate that a reduction of approximately 25,000 MMBtu/d
would substantially restore the total mix of transported gas to
these dewpoint specifications.
Also, lean or processed gas that we transport or are scheduled
to transport may be mixed with gas that does not meet dewpoint
specifications, which lowers the overall dewpoint of the natural
gas stream and allows us to avoid having to
shut-in any gas.
As a result of the introduction of a significant quantity of
lean gas into the system following the completion of the Regency
Intrastate Enhancement Project, the interstate pipeline has
suspended its curtailments.
16
Other Assets
Gulf States Transmission, our small interstate pipeline,
consists of approximately 10 miles of
20-inch pipeline that
extends from Harrison County, Texas to Caddo Parish, Louisiana.
The pipeline has a Federal Energy Regulatory Commission
(FERC) certificated capacity of 150 MMcf/d.
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. Once we have executed a contract with the
producer, we connect the producers wells and central
delivery points to our gathering lines through which the natural
gas is delivered to a processing plant (whether 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
twenty years or 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. Additionally, it is common for a
percentage-of-proceeds
or keep-whole contract to have a fee component in addition to
its commodity-sensitive component. For a description of our
fee-based arrangements,
percent-of-proceeds
arrangements, and keep-whole arrangements, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Our
Operations.
At December 31, 2005, the mixture of our gathering and
processing contracts by category and by geographic region is set
forth in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nature of Contract | |
|
|
(Measured by 2005 volumes) | |
|
|
| |
|
|
Keep-Whole | |
|
POP | |
|
Fee-Based | |
Geographic Region |
|
| |
|
| |
|
| |
North Louisiana(1)
|
|
|
29.3 |
% |
|
|
57.9 |
% |
|
|
12.8 |
% |
West Texas
|
|
|
18.0 |
% |
|
|
44.5 |
% |
|
|
37.5 |
% |
Mid-Continent
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31.3 |
% |
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46.8 |
% |
|
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21.9 |
% |
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Total Gathering and Processing
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26.1 |
% |
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48.5 |
% |
|
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25.4 |
% |
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|
Note (1) |
approximately 24% of 29% reported keep-whole exposure in north
Louisiana is attributable to a package of bypassable gas
controlled by us. We only process this gas when economically
beneficial. |
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.
Our obligation to provide firm transportation service means that
we are 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. Our obligation to provide interruptible
transportation service means that we are only obligated to
transport natural gas nominated by the shipper 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 our transportation
services under the terms of our contracts and under an operating
statement that we have filed and maintain with FERC with respect
to transportation authorized under section 311 of the
Natural Gas Policy Act.
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 at which 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.
17
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.
Competition
The natural gas gathering, processing, 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:
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North Louisiana: CenterPoint Energy Gas Marketing Company; Gulf
South Pipeline L.P.; PanEnergy Louisiana Intrastate, LLC
(Pelico). |
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West Texas: Sid Richardson Energy Services Co. |
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Mid-Continent: Duke Energy Field Service, L.P.; ONEOK Energy
Marketing and Trading, L.P.; Penn Virginia Corporation. |
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. Many
of our competitors have substantially greater resources, both in
capital and in access to shippers supplies of natural gas
than we do. Competition in natural gas transportation is
characterized by price of transportation, the nature of the
markets accessible from a transportation pipeline and nature of
service.
Risk Management
To manage commodity price risk, we have implemented a risk
management program under which we seek to match sales prices of
commodities (especially natural gas) with purchases under our
contracts; manage our portfolio of contracts to reduce commodity
price risk; optimize our portfolio by active monitoring of
basis, swing, and fractionation spread exposure; and hedge a
portion of our exposure to commodity prices (specifically NGLs).
To the extent that we purchase or commit contractually to
purchase natural gas that we gather and process, we are exposed
to commodity price changes 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 when recovery of ethane as an NGL is
uneconomical.
As a consequence of our processing contract portfolio, we derive
a portion of our earnings from a long position in NGL products,
resulting from the purchase of natural gas for our account or
from the payment of processing charges in kind, that are exposed
to commodity price fluctuations. Shortly after the acquisition
of our company by HM Capital, we implemented a policy of hedging
this commodity price risk by purchasing a series of contracts
relating to swaps of individual NGL products and crude oil puts.
Our hedging position and needs to supplement or modify our
position are closely monitored by the Risk Management Committee
of our Managing General Partner. Please read Item 7
Managements Discussion and Analysis of Financial
Condition and Results of Operations Quantitative and
Qualitative Disclosures about Market Risk for information
regarding the status of these contracts and the accounting
treatment to be accorded to them. As a matter of policy we do
not acquire forward contracts or derivative products for the
purpose of speculating on price changes.
18
Regulation
Intrastate Pipeline Regulation. To the extent that our
Regency Intrastate Pipeline system transports natural gas in
interstate commerce, the rates, terms and conditions of that
transportation service are subject to the jurisdiction of FERC,
under Section 311 of the Natural Gas Policy Act of 1978, or
NGPA, which regulates, among other things, the provision of
transportation services by an intrastate natural gas pipeline on
behalf of an interstate natural gas pipeline. 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 FERC are
generally analogous to the cost-based rates that FERC deems
just and reasonable for interstate pipelines under
the Natural Gas Act, or NGA. Certain aspects of FERC rate
regulation under the NGA are discussed under the section below
entitled Regulation Interstate
Pipeline Regulation. Additionally, the terms and
conditions of service set forth in the intrastate
pipelines Statement of Operating Conditions are subject to
FERC approval.
FERC Pipeline Regulation. Regency Intrastate Gas LLC, or
RIGS, is one of our subsidiaries which transports interstate gas
in Louisiana under Section 311 (a) (2) of the
NGPA for many of its shippers. FERC approves Section 311
(a)(2) transportation rates for our intrastate pipeline (as for
others) typically on a cost of service basis. FERC requires most
of these pipelines, including RIGS, to file triennial rate
petitions either justifying its existing rates or requesting new
rates. RIGS most recent Section 311 maximum rates
were established by a FERC order dated September 26, 2005,
and were set for firm transportation at $0.15 per MMBtu/d
reservation charge, with a $0.05 MMBtu commodity charge,
and for interruptible transportation at $0.20 per MMBtu/d.
RIGS is obligated to file its next Section 311 rate case no
later than May 1, 2008.
Under Section 311, intrastate pipelines providing
transportation service under NGPA Section 311 may avoid
jurisdiction that would otherwise apply under the Natural Gas
Act of 1938, or NGA.
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 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 |
could result in an alteration of our jurisdictional status or
the imposition of administrative, civil and criminal penalties,
or both.
Our Regency Intrastate Pipeline system in north Louisiana is
subject to regulation by various agencies of the State of
Louisiana. Louisianas 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. Historically, apart from pipeline safety,
it has not acted to exercise this jurisdiction respecting
gathering 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.
Interstate Pipeline Regulation. FERC also has broad
regulatory authority over the business and operations of
interstate natural gas pipelines, such as the Gulf States
Transmission Corporation pipeline. Under the Natural Gas Act,
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. Gulf
States Transmission holds a FERC-approved tariff setting forth
cost-based rates, terms and
19
conditions for services to shippers wishing to take interstate
transportation service. FERCs 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; and |
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information posting requirements. |
FERC regulation and policy determine whether and to what extent
an interstate pipelines costs are eligible for inclusion
in that pipelines
cost-of-service for
purposes of establishing the pipelines maximum just
and reasonable rates for service. Under new FERC rate
policy, pipelines are permitted to include, as part of their
cost-of-service, a full
income tax allowance for all entities owning the public utility
asset, provided that such entities or individuals are subject to
an actual or potential tax liability to be paid on income
derived from the public utility asset. FERCs income tax
allowance policy is, however, currently being challenged, and
may be subject to change in the future. As a consequence, we
cannot provide any assurance that we will be able to continue to
include an income tax allowance in the
cost-of-service used to
set Gulf States Transmission Corporations maximum just and
reasonable rates. Additionally, whether and to what extent an
intrastate pipeline company providing service under NGPA
Section 311 is allowed to include an analogous income tax
allowance in its
cost-of-service for
ratemaking purposes is currently unclear and is, in any event,
likewise subject to change in the future.
Gathering Pipeline Regulation. Section I (b) of
the NGA exempts natural gas gathering facilities from the
jurisdiction of FERC under the NGA. We own a number of natural
gas pipelines that we believe meet the traditional tests FERC
has used to establish a pipelines status as a gatherer not
subject to FERC jurisdiction. The distinction between
FERC-regulated transmission services and federally unregulated
gathering services is the subject of substantial, on-going
litigation, so the classification and regulation of our
gathering facilities are subject to change based on future
determinations by FERC, the courts or Congress.
State regulation of gathering facilities generally includes
various safety, environmental and, in some circumstances,
nondiscriminatory take requirements and in some instances
complaint-based rate regulation. We are subject to state ratable
take and common purchaser statues. 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 statues are designed to prohibit discrimination in favor
of one producer over another or one source of supply over
another. These statues 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
both the state and the federal levels now that FERC has taken a
less stringent approach to regulation of the gas gathering
activities of interstate pipeline transmission companies and a
number of such companies have transferred gathering facilities
to unregulated affiliates. For example, the Texas Railroad
Commission, or TRRC, has approved
20
changes to its regulations governing transportation and
gathering services performed by intrastate pipelines and
gatherers, which 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.
Sales of Natural Gas. 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, including interstate natural gas pipelines and
natural gas storage facilities. 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.
Oil Price Controls and Transportation Rates. Sales of
crude oil, condensate and NGLs are not currently regulated.
Prices of these products are set by the market rather than by
regulation. Effective as of January 1, 1995, FERC
implemented regulations establishing an indexing system for
transportation rates for oil, NGLs and other products that
allowed for an increase in the cost of transporting oil to the
purchaser. The implementation of these regulations has not had a
material adverse effect on our results of 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 relating to the
release of hazardous substances or wastes into the environment.
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 the
environmental laws.
Any failure to comply with applicable environmental laws and
regulations, including those relating to obtaining required
governmental approvals, may result in the assessment of
administrative, civil or criminal penalties, requirements to
perform investigatory or remedial activities and the issuance of
injunctions or construction bans or delays. 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 consolidated results of
operations or financial condition.
Under an omnibus agreement, Regency Acquisition LP agreed to
indemnify us in an aggregate amount not to exceed
$8.6 million generally for three years after
February 3, 2006 for certain environmental noncompliance
and remediation liabilities associated with the assets
transferred to us and
21
occurring or existing before that date. For a discussion of the
omnibus agreement, please read Item 13 Certain
Relationships and Related Party Transactions Omnibus
Agreement.
Hazardous Substances and Waste. To a large extent, the
environmental laws and regulations affecting our operations
relate to the release of hazardous substances or solid waste
into soils, groundwater and surface water and include measures
to control pollution of the environment. These laws and
regulations generally regulate the generation, storage,
treatment, transportation and disposal of solid and hazardous
wastes and may require investigatory and corrective actions of
facilities where such waste may have been released or disposed.
For example, the Comprehensive Environmental Response,
Compensation and Liability Act, or 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 hazardous substance into the
environment. These persons include the owner or operator of the
site where a release occurred and companies that disposed or
arranged for the disposal of the hazardous substances that have
been released into the environment. Under CERCLA, these persons
may be subject to joint and several strict liability for the
costs of cleaning up the hazardous substances that have been
released into the environment, for damages to natural resources
and for the costs of certain health studies. CERCLA also
authorizes the Environmental Protection Agency, or EPA, 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 CERCLAs definition of a hazardous
substance, in the course of our ordinary operations we
generate wastes that may fall within that definition. We may be
responsible under CERCLA for all or part of the costs required
to clean up sites at which such wastes have been disposed. We
have not received any notification that we may be potentially
responsible for cleanup costs under CERCLA or analogous state
laws.
We also generate both hazardous and nonhazardous solid wastes
that are subject to requirements of the federal Resource
Conservation and Recovery Act, or RCRA and comparable state
statutes. From time to time, the EPA has considered the adoption
of stricter 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 because our operations generate minimal quantities
of hazardous wastes. 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. Changes in applicable regulations
may result in an increase in our capital expenditures or plant
operating expenses.
We currently own or lease properties 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 other
solid wastes have been disposed of or released on or under
various properties during the operating history of those
facilities that are now owned or leased by us. Notwithstanding
the possibility that these dispositions of wastes may have
occurred during the ownership of these assets by others, these
properties and wastes may be subject to CERCLA, RCRA and
analogous 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
property contamination (including groundwater contamination) or
to perform remedial operations to prevent the migration of
contamination.
It is this possibility that led the management of Regency Gas
Services to negotiate for the inclusion of environmental
indemnity provisions in the agreement under which it agreed to
acquire assets from El Paso Field Services LP and its
affiliates in 2003. Those provisions included an indemnity of
Regency Gas Services by the El Paso sellers against a
variety of environmental claims for a period of five years up to
an aggregate of $84 million. They also included an escrow
of $9 million relating to claims, including environmental
claims, under the El Paso agreement.
22
Regency Gas Services has submitted a claim against the
El Paso sellers for a variety of environmental defects at
these assets, and the El Paso sellers have agreed to
maintain $5.4 million in the escrow account to pay any
claim amounts 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.
A Phase I environmental study was performed on our west
Texas assets by an environmental consultant engaged by us in
connection with our investigation of those assets prior to our
purchase of them in 2004. The study indicated that 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 in the first quarter of 2004, management of
Regency Gas Services obtained an insurance policy against
specified risks of environmental claims up to $10 million.
The premiums on the insurance policy were prepaid for a period
of 10 years or until February 2014. This policy covers
third party claims for
on-site and off-site
cleanup costs and personal injury/property damage arising from
pre-February 2004 contamination or incidents, with a
$100,000 per claim deductible.
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 expected to produce air emissions or result in the
increase of existing air emissions, obtain and strictly comply
with air permits containing various emissions and operational
limitations, or utilize specific emission control technologies
to limit emissions. Our failure to comply with these
requirements could subject us to monetary penalties,
injunctions, conditions or restrictions on operations, and
potentially criminal enforcement actions. 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 practice 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.
ODEQ Notice of Violation. In March 2005, the Oklahoma
Department of Environmental Quality, or ODEQ, sent us a notice
of violation, alleging that we are operating the Mocane
processing plant in Beaver County, Oklahoma in violation of the
National Emission Standard for Hazardous Air Pollutants from Oil
and Natural Gas Production Facilities, or NESHAP, and the
requirements to apply for and obtain a federal operating permit
(Title V permit). After seeking and obtaining advice from
the Environmental Protection Agency, the ODEQ issued an order
requiring us to apply for a Title V permit with respect to
emissions from the Mocane processing plant by April 2006. No
fine or penalty was imposed by the ODEQ. While we believe that
the basis for the allegations identified in the notice of
violation is inapplicable to the Mocane processing plant, we
intend to comply with the order. Resolution of this matter will
not have any materially adverse effect on our consolidated
results of operations.
TCEQ Notice of Enforcement. In November 2004, the Texas
Commission on Environmental Quality, or TCEQ, sent a Notice of
Enforcement, or NOE, to us relating to the operation of the Waha
processing plant in 2001 before it was acquired by us. We
settled this NOE with the TCEQ in November 2005.
Absent the physical or operational changes at the Waha
processing plant that allegedly occasioned the NOE, the air
emissions at the plant would have been limited, based on the
plants grandfathered status under the relevant
federal statutory standards, only by historical amounts until
2007. In anticipation of the expiration of that status and
regardless of the outcome of the NOE, we submitted to the TCEQ
in early February 2005 an application for a state air permit for
emissions from the Waha plant predicated on the
23
construction of an acid gas reinjection well and, after
completion of the well and facilities, the reinjection of the
emitted gases. That permit has been issued and requires
completion of construction of the well and facilities by the end
of February 2007. We estimate the capital expenditure relating
to the well and facilities at $6.0 million.
Clean Water Act. The Federal Water Pollution Control Act
of 1972, as renamed and amended as the Clean Water Act, and
similar 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
National Pollutant Discharge Elimination System, or NPDES, or
state permit, or both, must be obtained to discharge pollutants
into state and federal waters. The Clean Water Act and analogous
state laws assess administrative, civil and criminal penalties
for discharges of unauthorized pollutants into the water and
impose substantial liability for the costs of removing spills
from such waters. In addition, the Clean Water Act and analogous
state laws require that individual permits or coverage under
general permits be obtained by covered 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 consolidated results of operation
or financial position.
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 Occupational Safety and Health Act, referred
to as 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, record
keeping 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 U.S. Department of
Transportation under the Hazardous Liquid Pipeline Safety Act,
or 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
make certain reports and provide information as required by the
Secretary of Transportation. We believe our liquids pipelines
are in substantial compliance with applicable HLPSA requirements.
Our intrastate pipeline facilities are subject to regulation by
the U.S. Department of Transportation, or the DOT, under
the Natural Gas Pipeline Safety Act of 1968, as amended, or the
NGPSA, pursuant to which the DOT has established requirements
relating to the design, installation, testing, construction,
operation, replacement and management of pipeline facilities.
The NGPSA covers natural gas, crude oil, carbon dioxide, NGL and
petroleum products pipelines and requires any entity that owns
or operates pipeline facilities to comply with the regulations
under the NGPSA, to permit access to and allow copying of
records and to make certain reports and provide information as
required by the Secretary of Transportation. We believe that our
pipeline operations are in substantial compliance with
applicable NGPSA requirements; however, we cannot predict the
effect of any new or amended laws and regulations or
reinterpretation of existing laws and regulations on our future
compliance with the NGPSA.
Louisiana administers federal pipeline safety standards under
the NGPSA. The Louisiana Office of Conservation, Pipeline
Division, monitors Louisiana intrastate pipeline operators to
ensure safety and compliance with regulations. Among other
things, the Louisiana Office of Conservation conducts pipeline
inspections and accident investigations, and it oversees
compliance and enforcement, safety programs, and
24
record maintenance and reporting. The rural gathering
exemption under the NGPSA currently exempts our gathering
facilities from jurisdiction under that statute. The rural
gathering exemption, however, may be restricted in the
future, and that exemption does not apply to our intrastate
natural gas pipeline facilities. With respect to recent pipeline
accidents in other parts of the country, Congress and the DOT
have passed or are considering heightened pipeline safety
requirements.
Employees
Our Managing GP or its affiliates employ approximately 153
employees, of whom 103 are field operating employees and 50 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 Managing GP or any of its affiliates is a party. Our
Managing GP believes that it has good relations with its
employees.
Legal Proceedings
We are not a party to any material litigation. See, however, the
discussion of the TCEQ NOE and the ODEQ NOV under
Environmental Matters TCEQ Notice
of Enforcement and Environmental
Matters ODEQ Notice of Violation. Our
operations 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.
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.
Available Information
Regency Energy Partners LP 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 SECs 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.
ITEM 1A. Risk
Factors.
Limited partner interests are inherently different from
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged in a similar business. You should
consider carefully the following risk factors together with all
of the other information included in this report in evaluating
an investment in our common units.
If any of the following risks were actually to occur, our
business, financial condition, results of operations or cash
flows could be materially adversely affected. In that case, we
might not be able to pay the minimum quarterly distribution on
our common units, the trading price of our common units could
decline and you could lose all or part of your investment.
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Risks Related to Our Business
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We may not have sufficient cash from operations to enable
us to pay the minimum 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 the minimum quarterly distribution. 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. |
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, including capital expenditures incurred in
connection with our enhancement projects; |
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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. |
You should be aware that the amount of cash we have available
for distribution depends primarily on our cash flow and not
solely on profitability, which is 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.
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If we do not receive the revenues we anticipate from the
Regency Intrastate Enhancement Project, our cash flow and our
ability to make cash distributions to you may be adversely
affected. |
Our ability to pay the minimum quarterly distributions for 2006
assumes, among other things, the generation of revenues
contemplated by the gas transportation contracts relating to our
Regency Intrastate Enhancement Project.
Our ability to pay the minimum quarterly distributions for 2006
also assumes the generation of the revenues contemplated by the
contracts that we have entered into with our customers relating
to the transportation of gas on our Regency Intrastate Pipeline.
If any of the following were to occur, our forecast of these
revenues would be adversely affected:
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we are unable to perform the requisite transportation services
for any reason, |
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in the case of interruptible
transportation services, our customers fail to utilize our
services in whole or in part, or |
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our customers fail to pay for our services for any reason,
including financial distress. |
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While substantial amounts of the incremental capacity
resulting from the completion of the Regency Intrastate
Enhancement Project has been contracted, if we are unable to
utilize the remaining incremental transportation capacity, our
business and our operating results could be adversely
affected. |
We have agreed to provide natural gas transportation services to
natural gas producers in the area upon completion of the Regency
Intrastate Enhancement Project, which increased our capacity on
the Regency Intrastate Pipeline from 200 MMcf/d to
800 MMcf/d. We have signed definitive agreements for
466,000 MMbtu/d of firm transportation and for
404,000 MMbtu/d of interruptible transportation. We are
currently transporting approximately 450,000 MMbtu/d under
these existing contracts. We are engaged in discussions with
various shippers interested in contracting for portions of the
uncommitted capacity on the system for firm transportation of
natural gas volumes. If we are unable to commit the remaining
uncommitted capacity on the system to firm gas transportation
contracts and the parties to existing interruptible
transportation contracts fail to utilize the capacity, our
business and our operating results could be adversely affected.
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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 transportation pipeline systems are connected
to or 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 throughput 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 include: the level of successful drilling activity
near these 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.
Currently, natural gas prices are high in relation to historical
prices. For example, the twelve-month average of NYMEX daily
settlement price of natural gas increased from $6.18 per
MMBtu as of December 31, 2004 to $9.35 per MMBtu as of
February 28, 2006. 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, throughput 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, financial condition and ability
to make cash distributions to you.
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We depend on certain key producers and other customers for
a significant portion of our supply of natural gas. The loss of,
or reduction in volumes from, 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. Our three
largest suppliers of natural gas by volume for the year ended
December 31, 2005, Oxy USA Inc., Duke Energy Field Services
LLC and ExxonMobil Corporation accounted for approximately 24%
of our total natural gas supply. These contracts have terms that
are either month-to-month or year-to-year. 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
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these producers and other customers, as a result of competition
or otherwise, could have a material adverse effect on our
business, results of operations, financial condition and our
ability to make cash distributions to you.
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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 cash flow and our
ability to make cash distributions to you. |
In accordance with industry practice, 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 is 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, financial condition and our
ability to make cash distributions to you.
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Natural gas, NGLs and other commodity prices are volatile,
and a reduction in these prices could adversely affect our cash
flow and our ability to make distributions to you. |
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 NYMEX daily settlement price for natural gas for the prompt
month contract in 2004 ranged from a high of $8.75 per
MMBtu to a low of $4.57 per MMBtu. In 2005, the same index
ranged from a high of $15.38 per MMBtu to a low of
$5.79 per MMBtu. The NYMEX daily settlement price for crude
oil for the prompt month contract in 2004 ranged from a high of
$56.37 per barrel to a low of $32.49 per barrel. In
2005, the same index ranged from a high of $69.91 per
barrel to a low of $42.16 per barrel. 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 fluctuate 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. |
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 or NGL
products 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
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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. For a detailed discussion of these arrangements, please
read Item 1 Business Our Contracts.
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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 deliver 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.
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Our results of operations and cash flow may be adversely
affected by risks associated with our hedging activities and our
hedging activities may limit potential gains. |
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 and other commodity prices in
recent years, in December 2004, we initiated a plan to hedge a
significant percentage of our total segment margin for the years
2005 to 2007. Under this plan, we executed swap contracts
settled against ethane, propane, butane and natural gasoline
market prices, supplemented with crude oil put options.
(Historically, changes in the prices of heavy NGLs, such as
natural gasoline, have generally correlated with changes in the
price of crude oil.) As a result, we have hedged approximately
95% of our expected exposure to NGL prices in 2006,
approximately 75% in 2007 and approximately 50% in 2008. 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. Our hedging
transactions are intended to reduce our exposure to downward
movements in NGL prices. In exchange for this reduction in
exposure, however, these transactions limit our potential gains
if NGL prices rise over the price established by the hedging
arrangements. In addition, 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.
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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 our cash available for
distribution. |
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.
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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 its completion
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
results of operations and our ability to make cash distributions
to you.
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.
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If we do not make acquisitions on economically acceptable
terms, our future growth may be limited. |
Our ability to grow depends in part on our ability to make
acquisitions that result in an increase in the cash per unit
generated from operations. Factors affecting our ability to do
so include our abilities:
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To identify businesses
engaged in managing, operating or owning gathering, compression,
processing and pipeline assets for acquisitions and joint
ventures; |
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to obtain required financing
for acquisitions and joint ventures; |
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to outbid competitors for
acquisition prospects; |
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to analyze acquisition and
joint venture prospects successfully from both an operational
and financial viewpoint; |
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to consummate acquisitions
and joint ventures; |
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to integrate acquired
businesses and assets with our existing operations and to
subject them to our operating and financial systems and
controls; and |
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to hire, train and retain
qualified personnel to manage and operate our expanded business. |
In addition, even though we expect an acquisition to be
accretive, it may not be.
Any acquisition involves potential risks, including among others
the following:
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Mistaken assumptions
regarding revenues and costs, including synergies; |
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the assumption of unknown
liabilities; |
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limitations on rights to
indemnity from sellers; |
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the diversion of
managements attention from other business concerns; |
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unforeseen difficulties in
operating in new geographic areas; and |
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customer or key employee
losses at the acquired business. |
Our capitalization and results of operations may change
significantly if we consummate any acquisitions, and you will
not have the opportunity to evaluate the economic, financial or
other relevant information that we will consider in determining
to make those acquisitions.
Our acquisition strategy is based, in part, on our expectation
of ongoing divestitures of midstream assets by large industry
participants. A material decrease in such divestitures would
limit our opportunities for future acquisitions and could
adversely affect our operations and cash flows available for
distribution to our unitholders.
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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, 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.
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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 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. All of these competitive pressures could have a
material adverse effect on our business, results of operations,
financial condition and ability to make cash distributions to
you.
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Restrictions in our credit facility limit our ability to
make distributions to you and our ability to capitalize on
acquisitions and other business opportunities. |
Our bank credit facility prohibits us from making cash
distributions during an event of default or if the payment of a
distribution would cause an event of default. Our credit
facility, as amended, allows us to make distributions as long as
we are in compliance with the covenants in this agreement. In
addition, it contains various covenants limiting our ability to
incur indebtedness, to grant liens, and to engage in
transactions with affiliates, as well as others requiring us to
maintain certain financial ratios and tests. Our payment of
principal and interest on the debt will reduce the cash
available for distribution on our units, as will our obligation
to repay this debt upon the occurrence of specified events
involving a change of control of our general partner. Any
subsequent refinancing of our current debt or any new
indebtedness could have similar or greater restrictions. Please
read Managements Discussion and Analysis of
Financial Condition and Results of Operations
Capital Requirements.
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We have a significant amount of debt that may limit our
ability to grow. |
Our total outstanding long-term indebtedness under our credit
facility was approximately $371.4 million at March 24,
2006. Our leverage and various limitations in our credit
facility and our lack of an investment grade rating may reduce
our ability to incur additional debt, engage in some
transactions, and capitalize on acquisition or other business
opportunities. Any subsequent refinancing of our current debt or
any new indebtedness could have similar or greater restrictions.
Please read Item 7 Managements Discussion and
Analysis of Financial Condition and Results of
Operation Capital Requirements and
Liquidity and Capital Resources.
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Increases in interest rates, which have recently
experienced record lows, could adversely impact our unit price
and our ability to issue additional equity, make acquisitions,
reduce debt or for other purposes. |
The credit markets recently have experienced
50-year record lows in
interest rates. If the overall economy strengthens, it is likely
that monetary policy will tighten further, resulting in higher
interest rates to counter possible inflation. We expect our
quarterly interest payments in 2006 to range between $6.1 and
$6.5 million. An increase of 100 basis points in the
LIBOR rate would increase this quarterly payment by
approximately $0.4 million. Additionally, 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-
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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, make acquisitions, reduce debt or
for other purposes.
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If third-party pipelines interconnected to our processing
plants become unavailable to transport NGLs, our cash flow and
cash available for distribution 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. For example:
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all of the NGLs produced at
our north Louisiana system are transported to Mont Belvieu on
the Black Lake Pipeline, which is owned by BP Energy Company and
Duke Energy Field Services; |
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all of the NGLs produced at
the Waha processing plant are transported to Mont Belvieu by use
of Louis Dreyfus pipeline and ExxonMobil
Corporations NGL pipeline; and |
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all of the NGLs produced at
our mid-continent processing plants are transported to the
Conway Hub in Kansas by ONEOK Hydrocarbon Southwest
L.L.C.s NGL pipeline. |
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 out of
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. For example,
Hurricane Rita disrupted the operations of NGL pipelines and
fractionators in the Houston, Texas area. As a result of these
disruptions, we were forced temporarily to curtail producers in
the west Texas region for approximately four days and to operate
our north Louisiana processing assets in a reduced recovery mode
for six days.
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We are exposed to the credit risks of our key customers,
and any material nonpayment or nonperformance by our key
customers could reduce our ability to make distributions to our
unitholders. |
We are subject to risks of loss resulting from nonpayment or
nonperformance by our customers. For example, in January 2005,
one of our customers filed for Chapter 11 reorganization
under U.S. bankruptcy law although that customer has since
emerged from bankruptcy court protection. Any material
nonpayment or nonperformance by this customer or 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.
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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 |
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other hazards, including
those associated with high-sulfur content, or sour 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.
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Due to our lack of asset diversification, adverse
developments in our midstream operations would reduce our
ability to make distributions to our unitholders. |
We rely exclusively on the revenues generated from our midstream
energy business, and as a result, our financial condition
depends upon prices of, and continued demand for, natural gas
and NGLs. Due to our lack of diversification in asset type, an
adverse development in this business would have a significantly
greater impact on our financial condition and results of
operations than if we maintained more diverse assets.
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Failure of the gas that we ship on our Regency Intrastate
Pipeline to meet the specifications of interconnecting
interstate pipelines could result in curtailments by the
interstate pipelines. |
The markets to which the shippers on our Regency Intrastate
Pipeline 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,
that pipeline 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 throughput volumes or revenues. Please see
Item 1 Business Transportation
Operations Interstate Pipeline Specifications.
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Terrorist attacks, the threat of terrorist attacks,
continued 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 threat of
future terrorist attacks, on the energy transportation industry
in general, and on us in particular, is not known at this time.
Uncertainty surrounding continued 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.
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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
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contracts or leases or otherwise, could have a material adverse
effect on our business, results of operations and financial
condition and our ability to make cash distributions to you.
In addition, the construction of additions to our existing
gathering 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 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.
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A successful challenge to the rates we charge on Regency
Intrastate Pipeline may reduce the amount of cash we
generate. |
To the extent our Regency Intrastate Pipeline transports natural
gas in interstate commerce, the rates, terms and conditions of
that transportation service are subject to regulation by the
Federal Energy Regulatory Commission, or FERC, pursuant to
Section 311 of the Natural Gas Policy Act of 1978, or NGPA,
which regulates, among other things, the provision of
transportation services by an intrastate natural gas pipeline on
behalf of an interstate natural gas pipeline. Under
Section 311, rates charged for transportation must be fair
and equitable, and the FERC is required to approve the terms and
conditions of the service. Rates established pursuant to
Section 311 are generally analogous to the cost based rates
FERC deems just and reasonable for interstate
pipelines under the Natural Gas Act or NGA. FERC may therefore
apply its NGA policies to determine costs that can be included
in cost of service used to establish Section 311 rates.
These rate policies include the new FERC policy on income tax
allowance that permits interstate pipelines to include, as part
of the cost of service, a full income tax allowance for all
entities owning the utility asset provided such entities or
individuals are subject to an actual or potential tax liability.
If the Section 311 rates presently approved for Regency
through May 2008 are successfully challenged in a complaint or
after such date the FERC disallows the inclusion of costs in the
cost of service, changes its regulations or policies, or
establishes more onerous terms and conditions applicable to
Section 311 service, this may adversely affect our
business. Any reduction in our rates could have an adverse
effect on our business, results of operations, financial
condition and ability to pay distributions to you.
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A change in the 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
Natural Gas Act of 1938, or NGA, but FERC regulation still
affects these businesses and the markets for products derived
from these businesses. FERCs 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. We
cannot assure you, however, that FERC will continue this
approach as it considers 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 the courts and of policy discussions at
FERC, so, in such circumstances, the classification and
regulation of some of our gathering facilities or our intrastate
transportation pipeline may be subject to change based on future
determinations by FERC, and the courts or Congress. Such a
change could result in increased regulation by FERC.
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
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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. Please read Item 1
Business Regulation.
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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. These
include, for example, (1) the federal Clean Air Act and
comparable state laws and regulations that impose obligations
related to air emissions, (2) the federal Resource
Conservation and Recovery Act, or RCRA, and comparable state
laws that impose requirements for the discharge of waste from
our facilities and (3) the Comprehensive Environmental,
Response Compensation and Liability Act of 1980, or CERCLA, also
known as Superfund, and comparable state laws that
regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated
by us or locations to which we have sent waste for disposal.
For example, in November 2005, we settled with the Texas
Commission on Environmental Quality, or TCEQ, a notice of
enforcement relating to the operation of the Waha processing
plant in 2001 before it was acquired by us. In connection with
this settlement, we agreed to construct an acid reinjection
well, in which we will reinject emitted gases from the plant at
a cost of $6.0 million. Please read Item 1
Business Regulation.
Failure to comply with these laws and regulations or newly
adopted laws or regulations may trigger a variety of
administrative, civil and criminal enforcement measures,
including the assessment of monetary penalties, the imposition
of remedial requirements, and the issuance of orders enjoining
future operations. Certain environmental statutes, including the
Clean Air Act, RCRA, CERCLA and the federal Water Pollution
Control Act of 1972, also known as the Clean Water Act, and
analogous state laws and regulations, impose strict, joint and
several liability for costs required to clean up and restore
sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of
hazardous substances or other waste products into the
environment.
There is inherent risk of the incurrence of environmental costs
and liabilities in our business due to the necessity of handling
of natural gas and other petroleum products, 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. Please read Item 1
Business Environmental Matters and
Item 7 Managements Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations Other Matters
Environmental.
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If we fail to develop or maintain an effective system of
internal controls, we may not be able to report our financial
results accurately or prevent fraud. |
We became subject to the public reporting requirements of the
Securities Exchange Act of 1934 on February 3, 2006. We
produce our consolidated financial statements in accordance with
the requirements of GAAP, but we do not become subject to
certain of the internal controls standards applicable to most
companies with publicly traded securities until after 2007. We
may not currently meet all those standards. Effective internal
controls are necessary for us to provide reliable financial
reports to prevent fraud and to
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operate successfully as a publicly traded partnership. Our
efforts to develop and maintain our internal controls may not be
successful, and we may be unable to maintain adequate controls
over our financial processes and reporting in the future,
including compliance with the obligations under Section 404
of the Sarbanes-Oxley Act of 2002, which we refer to as
Section 404. For example, Section 404 will require us,
among other things, annually to review and report on, and our
independent registered public accounting firm to attest to, our
internal control over financial reporting. We must comply with
Section 404 for our fiscal year ending December 31,
2007. Any failure to develop or maintain effective controls or
difficulties encountered in their implementation or other
effective improvement of our internal controls could harm our
operating results or cause us to fail to meet our reporting
obligations. Given the difficulties inherent in the design and
operation of internal controls over financial reporting, we can
provide no assurance as to our conclusions, or those of our
independent registered public accounting firm, regarding the
effectiveness of our internal controls. Ineffective internal
controls subject us to regulatory scrutiny and a loss of
confidence in our reported financial information, which could
have an adverse effect on our business and would likely have a
negative effect on the trading price of our common units. See
Item 9A Controls and Procedures.
Risks Inherent in an Investment in Us
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The HM Capital Investors own a 60.3% limited partner
interest in us and control our general partner, which has sole
responsibility for conducting our business and managing our
operations. Our general partner has conflicts of interest and
limited fiduciary duties, which may permit it to favor its own
interests to your detriment. |
The HM Capital Investors own a 60.3% limited partner
interest in us and control our general partner. 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 (who together own an economic interest in
our general partner of 8.4%) have a fiduciary duty to manage our
general partner in a manner beneficial to its owners, the
HM Capital Investors. Conflicts of interest may arise
between the HM Capital Investors and their affiliates,
including our general partner, on the one hand, and us and our
unitholders, 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 the interests of our
unitholders. These conflicts include, among others, the
following situations:
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neither our partnership
agreement nor any other agreement requires the HM Capital
Investors or their affiliates 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 the HM Capital Investors, in resolving
conflicts of interest; |
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the HM Capital
Investors and their affiliates may engage in competition with us; |
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our general partner has
limited its liability and reduced its fiduciary duties, and has
also restricted the remedies available to our unitholders for
actions that, without the limitations, might constitute breaches
of fiduciary duty; |
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our general partner
determines the amount and timing of asset purchases and sales,
capital expenditures, borrowings, issuance of additional
partnership securities, and reserves, each of which can affect
the amount of cash that is distributed to unitholders; |
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our general partner
determines the amount and timing of any capital expenditures and
whether a capital expenditure is a maintenance capital
expenditure, which reduces operating surplus, or growth capital
expenditure, which does not, which determination can affect the
amount of cash that is distributed to our unitholders and the
ability of the subordinated units to convert to common units; |
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our general partner
determines which costs incurred by it and its affiliates are
reimbursable by us; |
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our partnership agreement
does not restrict our general partner from causing us to pay it
or its affiliates 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; |
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our general partner may
exercise its limited right to call and purchase common units if
it and its affiliates own more than 80% of the common units; |
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our general partner controls
the enforcement of obligations owed to us by our general partner
and its affiliates; and |
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our general partner decides
whether to retain separate counsel, accountants, or others to
perform services for us. |
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The HM Capital Investors and their affiliates may compete
directly with us. |
The HM Capital Investors and their affiliates are not prohibited
from owning assets or engaging in businesses that compete
directly or independently with us. In addition, the HM Capital
Investors or their affiliates 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.
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Our reimbursement of our general partners expenses
will reduce our cash available for distribution
to you. |
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. Please read
Item 13. Certain Relationships and Related Party
Transactions. The reimbursement of expenses of our general
partner and its affiliates could adversely affect our ability to
pay cash distributions to you.
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Our partnership agreement limits our general
partners 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 |
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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. |
By purchasing a common unit, a common unitholder will become
bound by the provisions in the partnership agreement, including
the provisions discussed above.
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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
managements decisions regarding our business. Unitholders
did not elect our general partner or its board of directors and
will 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 were
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.
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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. The vote of the holders of at least
662/3
% of all outstanding units voting together as a single
class is required to remove the general partner. Our general
partner and its affiliates own 60.3% 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 our general partner and its affiliates 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.
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Our partnership agreement restricts the voting rights of
those unitholders owning 20% 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% 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 management.
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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 Regency GP LLC
with their own choices and to control the decisions taken by the
board of directors and officers.
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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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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% 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. Our
general partner and its affiliates now own approximately 20.7%
of the common units. At the end of the subordination period,
assuming no additional issuances of common units, our general
partner and its affiliates will own approximately 60.3% of the
common units.
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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 states 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
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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.
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We will incur increased costs as a result of being a
public company. |
We have no significant history operating as a public company. As
a public company, we incur significant legal, accounting and
other expenses that we did not incur as a private company. In
addition, the Sarbanes-Oxley Act of 2002, as well as rules
subsequently implemented by the SEC and the stock exchanges and
markets, have required changes in corporate governance practices
of public companies. We expect these rules and regulations to
increase our legal and financial compliance costs and to make
activities more time-consuming and costly. For example, as a
result of becoming a public company, we are required to have
three independent directors, create additional board committees
and adopt policies regarding internal controls and disclosure
controls and procedures, including the preparation of reports on
internal controls over financial reporting. In addition, we will
incur additional costs associated with our public company
reporting requirements. We are currently evaluating and
monitoring developments with respect to these rules, and we
estimate the amount of additional costs we may incur will be
$2.5 million annually.
Tax Risks to Common Unitholders
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Our tax treatment depends on our status as a partnership
for federal income tax purposes, as well as our not being
subject to entity-level taxation by individual states. If the
Internal Revenue Service, or IRS, treats us as a corporation or
we become subject to entity-level taxation for state tax
purposes, it would substantially reduce the amount of cash
available for distribution to you. |
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We did not request,
and do not plan to request, a ruling from the IRS on this or any
other tax matter affecting us.
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% and
would likely pay state 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, our treatment 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 our common 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. In addition, because of widespread
state budget deficits, several states are evaluating ways to
subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of
taxation. If any of these states were to impose a tax on us, the
cash available for distribution to you would be reduced. The
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 levels will be adjusted to reflect the
impact of that law on us.
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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.
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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.
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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.
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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.
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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
benefits available to you. It also could affect the timing of
these tax benefits 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.
41
|
|
|
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, and Colorado. 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 franchise
tax (which is based in part on net income) 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.
ITEM 1B. Unresolved
Staff Comments. This item is not applicable to the
registrant.
ITEM 2. Properties.
Substantially all of our pipelines, which are located in Texas,
Louisiana, Oklahoma, Kansas and, to a minor extent, Colorado,
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. Title to
substantially all our assets is subject to a first priority lien
and security interest in favor of the lending banks under our
credit facilities. 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.
Office Facilities
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. We also maintain
small regional offices located on leased premises in Shreveport,
Louisiana; Tulsa, Oklahoma; and Midland and San Antonio,
Texas. 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.
ITEM 3. Legal
Proceedings.
The operations of our operating partnership, Regency Gas
Services LP or RGS, and its subsidiaries 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 RGS nor any of its subsidiaries is,
however, currently a party to any material legal proceedings. In
addition, there are no material legal or governmental
proceedings currently pending or, to our knowledge, threatened
against RGS or any of its subsidiaries under any of the various
environmental protection statutes to which it is subject. See,
however, the discussion of the TCEQ NOE and the ODEQ NOV under
Item 1 Business Environmental
Matters TCEQ Notice of Enforcement and
Item 1 Business Environmental
Matters ODEQ Notice of Violation.
42
There are no material legal or governmental proceedings
currently pending or, to our knowledge, threatened against the
Partnership or any of its subsidiaries.
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.
ITEM 4. Submission
of Matters to a Vote of Security Holders.
None.
PART II
|
|
ITEM 5. |
Market for the Registrants Common Equity, Related
Unitholder Matters and Issuer Purchases of Equity Securities. |
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 the NASDAQ
National Market under the symbol RGNC. The following
table sets forth, for the periods indicated, the high and low
closing sales prices per common unit, as reported on the NASDAQ
National Market. The quarterly cash distribution to be declared
and paid with respect to the common units for the quarter ending
March 31, 2006 will be declared and paid on or before
May 15, 2006. As a consequence, no quarterly cash
distribution has yet been declared or paid with respect to the
common units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Range | |
|
|
|
|
| |
|
Cash | |
Period |
|
High | |
|
Low | |
|
Distribution | |
|
|
| |
|
| |
|
| |
Fiscal Year 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter (through March 15, 2006)*
|
|
$ |
21.29 |
|
|
$ |
19.47 |
|
|
|
** |
|
|
|
* |
Trading in common units on the NASDAQ National Market commenced
on February 3, 2006. |
|
|
** |
The initial quarterly cash distribution is not due to be
declared and paid until May 15, 2006. |
As of March 15, 2006, the number of holders of record of
the common units was 1. The holder of record is Cede &
Co., the nominee for Depository Trust Company.
We will distribute to our unitholders, on a quarterly basis, all
of our available cash in the manner described below. Available
cash generally means, for any quarter ending prior to
liquidation, 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% 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 our partnership agreement.
Under the quarterly incentive distribution provisions, our
general partner is
43
entitled, without duplication, to 15% of amounts we distribute
in excess of $0.4025 per unit, 25% of the amounts we distribute
in excess of $0.4375 per unit and 50% of amounts we distribute
in excess of $0.5250 per unit after each unitholder has received
a total of $0.5250 per unit. We have not paid the general
partner any incentive distributions in 2005.
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. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Third Amended and Restated Credit
Agreement.
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%
general partner interest in us for $20 and (ii) to Regency
Acquisition LLC its 98% 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
March 8, 2006, we closed the sale of an additional
1,400,000 common units at a price of $20 per unit as the
underwriters exercised their over allotment option in part. The
net proceeds from the sale were used by us to redeem an
equivalent number of common units held by Regency Acquisition LP
for the benefit of the HM Capital Investors. The common and
subordinated units were distributed by Regency Acquisition LP to
its parent partnership which then further distributed an
aggregate of 457,871 common units and 2,212,279 subordinated
units to two directors and seven officers of the Managing GP
upon their exchange of certain equity interests in that
partnership. 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 securities within the past three
years.
Use of Proceeds
In connection with the offering and sale by us of 13,750,000
common units on February 3, 2006 pursuant to our initial
public offering of securities, we received net proceeds of
approximately $257.0 million, after deducting underwriting
discounts, fees and commissions but before paying estimated
offering expenses. Approximately $48.0 million of the net
proceeds was used to replenish our working capital as described
below. We used the aggregate net proceeds of this offering:
|
|
|
|
|
To replenish all, or approximately $48.0 million, of the
working capital, or 18.7% of the net proceeds,
$37.0 million of which was used to repay working capital
borrowings under the revolving portion of our second amended and
restated credit facility, that was distributed to the
HM Capital Investors by RGS, immediately prior to
consummation of the offering and the related formation
transactions; |
|
|
|
to distribute approximately $195.5 million, or 76.1% of net
proceeds, to the HM Capital Investors for reimbursement of
capital expenditures comprising most of the initial investment
by the HM Capital Investors in Regency Gas Services LLC; |
|
|
|
to pay $9.0 million, or 3.5% of net proceeds, to an
affiliate of HM Capital as consideration for the termination of
ten-year financial advisory and monitoring and oversight
agreements between the affiliate of HM Capital and us; and |
|
|
|
to pay approximately $4.5 million, or 1.8% of net proceeds,
of expenses associated with the offering and related formation
transactions. |
The HM Capital Investors realized approximately
$243.5 million as a result of distributions made by us in
connection with the offering, including the $48.0 million
of working capital distributed to them
44
immediately prior to the consummation of the offering. This
represented approximately 94.7% of the net proceeds from the
offering. In addition, an affiliate of HM Capital received
$9.0 million in connection with the termination of the
financial advisory and monitoring and oversight agreements with
us.
Borrowings being repaid under the revolving portion of our
second amended and restated credit facility were incurred
temporarily to finance working capital. Those borrowings under
the revolving portion of our second amended and restated credit
facility bore interest at the annual rate of 8.5% and would
otherwise have matured on June 1, 2010. Affiliates of UBS
Securities LLC, Wachovia Capital Markets, LLC and KeyBanc
Capital Markets, a Division of McDonald Investments Inc., are
lenders under our second amended and restated credit facility.
In early March, the underwriters of our initial public offering
exercised in part their option to purchase additional common
units pursuant to the underwriting agreement by purchasing
1,400,000 common units for $28.0 million
($26.2 million net to the Partnership). On March 8,
2006, we closed the sale of the additional 1,400,000 common
units at a price of $20 per unit as the underwriters
exercised their over allotment option in part. The net proceeds
from the sale were used by us to redeem an equivalent number of
common units held by Regency Acquisition LP for the benefit of
the HM Capital Investors.
Equity Compensation Plan Information as of December 31,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
| |
|
|
| |
|
|
|
|
(a) |
|
|
(b) |
|
|
(c) |
|
|
|
|
| |
|
|
| |
|
|
| |
|
|
|
|
|
|
|
|
|
|
Number of securities |
|
|
|
|
|
|
|
|
|
|
remaining available for |
|
|
|
|
|
|
|
Weighted-average |
|
|
future issuance under |
|
|
|
|
Number of securities to be |
|
|
exercise price of |
|
|
equity compensation |
|
|
|
|
issued upon exercise of |
|
|
outstanding |
|
|
plans (excluding |
|
|
|
|
outstanding options, |
|
|
options, warrants |
|
|
securities reported in |
|
Plan Category |
|
|
warrants and rights |
|
|
and rights |
|
|
column (a)) |
|
|
|
|
| |
|
|
| |
|
|
| |
|
Equity compensation plans approved by security holders
|
|
|
|
0 |
|
|
|
|
n/a |
|
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not approved by security holders
|
|
|
|
0 |
|
|
|
|
n/a |
|
|
|
|
2,865,584 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
0 |
|
|
|
|
n/a |
|
|
|
|
2,865,584 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45
ITEM
6. Selected Financial Data
The following table shows selected financial data of our
predecessors, Regency Gas Services LLC (Predecessor) and Regency
LLC Predecessor. Our results of operations for the periods
presented below may not be comparable, either from period to
period or going forward, for the following reasons:
|
|
|
|
|
Regency LLC Predecessor was formed on April 2, 2003 and
commenced operations on June 2, 2003 with the acquisition
of certain natural gas gathering, processing and transportation
assets from subsidiaries of El Paso Corporation. As a
result, we do not have any financial results for periods prior
to April 2, 2003 and our results of operations for the
period ended December 31, 2003 includes only seven months
of financial results. |
|
|
|
On March 1, 2004, Regency LLC Predecessor acquired certain
natural gas gathering and processing assets from Duke Energy
Field Services, LP. As a result, our historical financial
results for the periods prior to March 1, 2004 do not
include the financial results from the operation of these assets. |
|
|
|
In connection with the acquisition of Regency Gas Services LLC
by the HM Capital Investors on December 1, 2004, the
purchase price was pushed-down to the financial
statements of Regency Gas Services LLC. As a result of this
push-down accounting, the book basis of our assets
was increased to reflect the purchase price, which had the
effect of increasing our depreciation and amortization expense.
Also, the increased amount of debt we incurred in connection
with the acquisition increased our interest expense subsequent
to December 1, 2004. |
|
|
|
After our acquisition by the HM Capital Investors, we
initiated a risk management program comprised of commodity swaps
and crude oil puts that we accounted for using
mark-to-market
accounting from December 2004 through June 2005. Under mark-to
market accounting, changes in the fair value of these
instruments are recorded in earnings. On July 1, 2005 we
implemented hedge accounting for our derivative financial
instruments that qualified, in accordance with Statement of
Financial Accounting Standards No. 133, Accounting
for Derivative Instruments and Hedging Activities. Changes
in the fair value of these qualifying instruments, to the extent
they are effective, are recorded in Other Comprehensive Income. |
|
|
|
In response to transmission capacity constraints in north
Louisiana, we significantly expanded and extended our pipeline
assets in this region, increasing our capacity to
800 MMcf/d from 200 MMcf/d and increasing the length
of the pipeline to 320 miles from 200 miles. The total
cost of the project, which was completed in December 2005, is
approximately $157.0 million. |
We refer to Regency Gas Services LLC as Regency LLC
Predecessor for periods prior to the acquisition by the
HM Capital Investors.
The selected financial data for the year ended December 31,
2005 and the period from acquisition date (December 1,
2004) to December 31, 2004 are derived from the audited
financial statements of the Predecessor. The selected financial
data for the period from January 1, 2004 to
November 30, 2004 and the period from inception
(April 2, 2003) to December 31, 2003 are derived from
the audited financial statements of Regency LLC Predecessor.
46
The following table includes the non-GAAP financial measures
EBITDA and total segment margin. We define EBITDA as net income
plus interest expense, provision for income taxes and
depreciation and amortization expense. We define total segment
margin as total revenue, including service fees, less cost of
gas and liquids and other cost of sales. For a reconciliation of
EBITDA and total segment margin to their most directly
comparable financial measures calculated and presented in
accordance with GAAP (accounting principles generally accepted
in the United States), please read Non-GAAP
Financial Measures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency Gas Services LLC | |
|
|
Regency LLC Predecessor | |
|
|
| |
|
|
| |
|
|
|
|
Period from | |
|
|
|
|
|
|
|
Acquisition | |
|
|
|
|
|
|
|
Date | |
|
|
Period from | |
|
Period from | |
|
|
|
|
(December 1, | |
|
|
January 1, | |
|
Inception | |
|
|
Year Ended | |
|
2004) to | |
|
|
2004 to | |
|
(April 2, 2003) to | |
|
|
December 31, | |
|
December 31, | |
|
|
November 30, | |
|
December 31, | |
|
|
2005 | |
|
2004 | |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
| |
|
| |
|
|
($ in thousands) | |
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue (1)
|
|
$ |
692,603 |
|
|
$ |
47,841 |
|
|
|
$ |
432,321 |
|
|
$ |
186,533 |
|
|
Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of sales
|
|
|
620,751 |
|
|
|
40,986 |
|
|
|
|
362,762 |
|
|
|
163,461 |
|
|
|
Operating expenses
|
|
|
21,812 |
|
|
|
1,819 |
|
|
|
|
17,786 |
|
|
|
7,012 |
|
|
|
General and administrative
|
|
|
14,412 |
|
|
|
638 |
|
|
|
|
6,571 |
|
|
|
2,651 |
|
|
|
Transaction expenses
|
|
|
|
|
|
|
|
|
|
|
|
7,003 |
|
|
|
724 |
|
|
|
Depreciation and amortization
|
|
|
22,010 |
|
|
|
1,613 |
|
|
|
|
10,129 |
|
|
|
4,324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
678,985 |
|
|
|
45,056 |
|
|
|
|
404,251 |
|
|
|
178,172 |
|
|
Operating income
|
|
|
13,618 |
|
|
|
2,785 |
|
|
|
|
28,070 |
|
|
|
8,361 |
|
|
Other income and deductions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(17,432 |
) |
|
|
(1,335 |
) |
|
|
|
(5,097 |
) |
|
|
(2,392 |
) |
|
|
Loss on debt refinancing
|
|
|
(8,480 |
) |
|
|
|
|
|
|
|
(3,022 |
) |
|
|
|
|
|
|
Other income and deductions, net
|
|
|
338 |
|
|
|
14 |
|
|
|
|
186 |
|
|
|
205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income and deductions
|
|
|
(25,574 |
) |
|
|
(1,321 |
) |
|
|
|
(7,933 |
) |
|
|
(2,187 |
) |
|
Net (loss) income from continuing operations
|
|
|
(11,956 |
) |
|
|
1,464 |
|
|
|
|
20,137 |
|
|
|
6,174 |
|
|
Discontinued operations
|
|
|
732 |
|
|
|
|
|
|
|
|
(121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$ |
(11,224 |
) |
|
$ |
1,464 |
|
|
|
$ |
20,016 |
|
|
$ |
6,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$ |
480,583 |
|
|
$ |
328,348 |
|
|
|
|
|
|
|
$ |
118,986 |
|
|
Total assets
|
|
|
654,324 |
|
|
|
486,489 |
|
|
|
|
|
|
|
|
164,330 |
|
|
Long-term debt
|
|
|
358,350 |
|
|
|
250,000 |
|
|
|
|
|
|
|
|
66,600 |
|
|
Member interest
|
|
|
169,778 |
|
|
|
176,964 |
|
|
|
|
|
|
|
|
59,856 |
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$ |
31,021 |
|
|
$ |
(4,930 |
) |
|
|
$ |
32,401 |
|
|
$ |
6,494 |
|
|
|
Investing activities
|
|
|
(150,195 |
) |
|
|
(129,947 |
) |
|
|
|
(84,721 |
) |
|
|
(123,165 |
) |
|
|
Financing activities
|
|
|
119,571 |
|
|
|
132,515 |
|
|
|
|
56,380 |
|
|
|
118,245 |
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment margin(1)
|
|
$ |
71,852 |
|
|
$ |
6,855 |
|
|
|
$ |
69,559 |
|
|
$ |
23,072 |
|
|
EBITDA(1)
|
|
|
28,218 |
|
|
|
4,412 |
|
|
|
|
35,242 |
|
|
|
12,890 |
|
|
Maintenance capital expenditures
|
|
|
7,817 |
|
|
|
358 |
|
|
|
|
5,548 |
|
|
|
1,633 |
|
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment margin(1)
|
|
$ |
56,179 |
|
|
$ |
6,247 |
|
|
|
$ |
61,347 |
|
|
$ |
18,805 |
|
|
|
|
|
Segment operating expenses
|
|
|
19,883 |
|
|
|
1,655 |
|
|
|
|
16,230 |
|
|
|
6,131 |
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas throughput (thousand MMBtu/d)
|
|
|
308 |
|
|
|
315 |
|
|
|
|
303 |
|
|
|
211 |
|
|
|
|
|
NGL gross production (Bbls/d)
|
|
|
14,312 |
|
|
|
15,675 |
|
|
|
|
14,487 |
|
|
|
9,434 |
|
|
|
Transportation Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment margin
|
|
$ |
15,672 |
|
|
$ |
608 |
|
|
|
$ |
8,212 |
|
|
$ |
4,268 |
|
|
|
|
|
Segment operating expenses
|
|
|
1,929 |
|
|
|
164 |
|
|
|
|
1,556 |
|
|
|
881 |
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput (thousand MMBtu/d)
|
|
|
258 |
|
|
|
162 |
|
|
|
|
192 |
|
|
|
212 |
|
(1) Includes $0.3 million of unrealized gains on
hedging transactions for the one month ended December 31,
2004, $9.5 million of unrealized losses on hedging
transactions and $2.0 million of put option expiration for
the year ended December 31, 2005.
47
Non-GAAP Financial Measures
We include in this
Form 10-K 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 is the starting point in determining cash available for
distribution, which is an important measure for a publicly
traded master limited partnership. Cash available for
distribution will be fully addressed in the first quarter 2006
report on
Form 10-Q.
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 in measuring 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. Management analyzes these other elements
separately. 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 and other cost of
sales. 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 segment margin is an important
measure because it is directly related to our volumes and
commodity price changes. Operating expenses are 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 operating 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 operating expenses
from total revenues in calculating segment margin because we
separately evaluate commodity volume and price changes in
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.
48
The following table presents a reconciliation of EBITDA and
total segment margin to the most directly comparable GAAP
financial measures, net income and net cash flows provided by
(used in) operating activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency Gas Services LLC | |
|
|
Regency LLC Predecessor | |
|
|
| |
|
|
| |
|
|
|
|
Period from | |
|
|
|
|
|
|
|
Acquisition | |
|
|
|
|
|
|
|
Date | |
|
|
Period from | |
|
Period from | |
|
|
|
|
(December 1, | |
|
|
January 1, | |
|
Inception | |
|
|
Year Ended | |
|
2004) to | |
|
|
2004 to | |
|
(April 2, 2003) to | |
|
|
December 31, | |
|
December 31, | |
|
|
November 30, | |
|
December 31, | |
|
|
2005 | |
|
2004 | |
|
|
2004 | |
|
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
|
|
$ |
31,021 |
|
|
$ |
(4,930 |
) |
|
|
$ |
32,401 |
|
|
$ |
6,494 |
|
|
Add (deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
(23,092 |
) |
|
|
(1,745 |
) |
|
|
|
(10,461 |
) |
|
|
(4,658 |
) |
|
|
Loss on debt refinancing
|
|
|
(8,480 |
) |
|
|
|
|
|
|
|
(3,022 |
) |
|
|
|
|
|
|
Risk management portfolio value changes
|
|
|
(11,191 |
) |
|
|
322 |
|
|
|
|
|
|
|
|
|
|
|
|
Gain on the sale of Regency Gas Treating LP assets
|
|
|
626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on the sale of NGL line pack
|
|
|
628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
29,567 |
|
|
|
(2,583 |
) |
|
|
|
20,408 |
|
|
|
31,390 |
|
|
|
Advances to affiliates
|
|
|
|
|
|
|
|
|
|
|
|
(576 |
) |
|
|
576 |
|
|
|
Other current assets
|
|
|
1,237 |
|
|
|
2,430 |
|
|
|
|
1,169 |
|
|
|
1,070 |
|
|
|
Accounts payable and accrued liabilities
|
|
|
(32,722 |
) |
|
|
155 |
|
|
|
|
(18,122 |
) |
|
|
(26,880 |
) |
|
|
Accrued taxes payable
|
|
|
(806 |
) |
|
|
921 |
|
|
|
|
(1,475 |
) |
|
|
(906 |
) |
|
|
Interest payable
|
|
|
(67 |
) |
|
|
541 |
|
|
|
|
(398 |
) |
|
|
(143 |
) |
|
|
Distributions payable
|
|
|
|
|
|
|
|
|
|
|
|
69 |
|
|
|
(68 |
) |
|
|
Other current liabilities
|
|
|
(1,208 |
) |
|
|
(293 |
) |
|
|
|
(173 |
) |
|
|
(706 |
) |
|
|
Other assets
|
|
|
3,263 |
|
|
|
6,646 |
|
|
|
|
196 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$ |
(11,224 |
) |
|
$ |
1,464 |
|
|
|
$ |
20,016 |
|
|
$ |
6,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
17,432 |
|
|
|
1,335 |
|
|
|
|
5,097 |
|
|
|
2,392 |
|
|
|
Depreciation and amortization
|
|
|
22,010 |
|
|
|
1,613 |
|
|
|
|
10,129 |
|
|
|
4,324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(1)
|
|
$ |
28,218 |
|
|
$ |
4,412 |
|
|
|
$ |
35,242 |
|
|
$ |
12,890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of total segment margin to net
(loss) income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$ |
(11,224 |
) |
|
$ |
1,464 |
|
|
|
$ |
20,016 |
|
|
$ |
6,174 |
|
|
Add (deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
21,812 |
|
|
|
1,819 |
|
|
|
|
17,786 |
|
|
|
7,012 |
|
|
|
General and administrative
|
|
|
14,412 |
|
|
|
638 |
|
|
|
|
6,571 |
|
|
|
2,651 |
|
|
|
Transaction expenses
|
|
|
|
|
|
|
|
|
|
|
|
7,003 |
|
|
|
724 |
|
|
|
Depreciation and amortization
|
|
|
22,010 |
|
|
|
1,613 |
|
|
|
|
10,129 |
|
|
|
4,324 |
|
|
|
Interest expense, net
|
|
|
17,432 |
|
|
|
1,335 |
|
|
|
|
5,097 |
|
|
|
2,392 |
|
|
|
Loss on debt refinancing
|
|
|
8,480 |
|
|
|
|
|
|
|
|
3,022 |
|
|
|
|
|
|
|
Other income and deductions, net
|
|
|
(338 |
) |
|
|
(14 |
) |
|
|
|
(186 |
) |
|
|
(205 |
) |
|
|
Discontinued operations
|
|
|
(732 |
) |
|
|
|
|
|
|
|
121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment margin(1)
|
|
$ |
71,852 |
|
|
$ |
6,855 |
|
|
|
$ |
69,559 |
|
|
$ |
23,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes $0.3 million of unrealized gains on
hedging transactions for the one month ended December 31,
2004, $9.5 million of unrealized losses on hedging
transactions and $2.0 million of put option expiration for
the year ended December 31, 2005.
49
|
|
ITEM 7. |
Managements Discussion and Analysis of Financial
Condition and Results of Operation |
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 Delaware limited partnership formed to capitalize on
opportunities in the midstream sector of the natural gas
industry. We own and operate five major natural gas gathering
systems and four active processing plants in north Louisiana,
west Texas and the mid-continent region of the United States,
which includes Kansas, Oklahoma, Colorado, and the Texas
Panhandle. We are engaged in gathering, processing, marketing
and transporting natural gas and natural gas liquids, or NGLs.
We connect natural gas wells of producers to our gathering
systems through which we transport the natural gas to processing
plants operated by us or by third parties. The processing plants
separate NGLs from the natural gas. We then sell and deliver the
natural gas and NGLs to a variety of markets.
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 factors affecting our profitability and review
these measurements on a monthly basis for consistency and trend
analysis. These measures include volumes, segment margin and
operating 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
impacted by (1) the level of workovers or recompletions of
existing connected wells and successful drilling activity in
areas currently dedicated to our pipelines, (2) our ability
to compete for volumes from successful new wells in other areas
and (3) our ability to obtain natural gas that has been
released from other commitments. We routinely monitor producer
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 to pursue 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, which also include
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 natural gas. Our contract portfolio impacts our
segment margin. See Our Operations for a
discussion of our contract portfolio.
We calculate our Transportation segment margin as revenue minus
the cost of natural gas that we purchase and transport. Revenue
primarily includes sales of pipeline-quality natural gas and
fees for the transportation of pipeline-quality natural gas.
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.
Operating Expenses. Operating expenses are a separate
measure that we use to evaluate operating performance of field
operations. Direct labor, insurance, property taxes, repair and
maintenance, utilities and contract services comprise the most
significant portion of our operating expenses. These expenses
are largely independent of the volumes through our systems but
fluctuate depending on the activities performed during a
specific period. We do not deduct operating expenses from total
revenues in calculating segment margin because we separately
evaluate commodity volume and price changes in segment margin.
50
EBITDA. We define EBITDA as net income plus interest
expense, provision for income taxes and depreciation and
amortization expense. EBITDA is used as a supplemental measure
by our management and by external users of our financial
statements such as investors, commercial banks, research
analysts and others, to assess:
|
|
|
|
|
financial performance of our assets without regard to financing
methods, capital structure or historical cost basis; |
|
|
|
the ability of our assets to generate cash sufficient to pay
interest costs, support our indebtedness and make cash
distributions to our unitholders and general partners; |
|
|
|
our operating performance and return on capital as compared to
those of other companies in the midstream energy sector, without
regard to financing or capital structure; and |
|
|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities. |
EBITDA should not be considered an alternative to net income,
operating income, cash flows from operating activities or any
other measure of financial performance presented in accordance
with GAAP. EBITDA is the starting point in determining cash
available for distribution, which is an important measure for a
publicly traded master limited partnership. Cash available for
distribution will be fully addressed in the first quarter 2006
report on
Form 10-Q.
Our Operations
We manage our business and analyze and report our results of
operations through two business segments:
|
|
|
|
|
Gathering and Processing in which 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 the NGLs and
selling or delivering the pipeline-quality natural gas and NGLs
to various markets and pipeline systems; and |
|
|
|
Transportation in which we deliver natural gas from northwest
Louisiana to northeast Louisiana through our
320-mile Regency
Intrastate Pipeline system, which has been significantly
expanded and extended through our Regency Intrastate Enhancement
Project. Our Transportation Segment includes certain marketing
activities related to our transportation pipelines that are
conducted by a separate subsidiary. |
Gathering and Processing Segment
Results of operations from our Gathering and Processing segment
are determined primarily by the volumes of natural gas 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, which we define as total revenues,
including service fees, less the cost of natural gas and liquids
and other cost of sales. 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 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.
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
51
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.
|
|
|
|
|
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. For the year ended
December 31, 2005, these arrangements accounted for about
25% of our natural gas volumes for this segment. |
|
|
|
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). For the year ended
December 31, 2005, these arrangements accounted for about
49% of our natural gas volumes for this segment. |
|
|
|
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 in unfavorable
price environments. For the year ended December 31, 2005,
these arrangements accounted for approximately 26% of our
natural gas volumes for this segment. |
An important aspect of our contract portfolio management
strategy is to decrease our keep-whole contract risk exposure.
Immediately following the acquisition of our mid-continent
assets in 2003, we terminated our
month-to-month
keep-whole arrangements and replaced them with fee-based or
percentage-of-proceeds
agreements or variations thereof. In addition, we seek to
replace our longer term keep-whole arrangements as they expire
or whenever the opportunity presents itself. At the time of the
acquisition of our mid-continent assets, approximately 71% of
our natural gas volumes associated with those assets was subject
to keep-whole arrangements. As of December 31, 2005, we had
reduced that number to approximately 22% in the mid-continent
region.
As part of our previously planned strategy, on August 1,
2005, we suspended operations at our Lakin natural gas
processing plant, reserving the right to operate it
intermittently. The natural gas that would
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have been processed at the Lakin plant is now processed at a
third party processing plant for our account for a fee.
Suspending the operations of the plant allowed us to renegotiate
and replace certain unfavorable keep-whole processing
arrangements covering natural gas processed at the plant with
fee-based contracts. Additionally, by suspending the Lakin
plant, we are able to avoid charges for transporting natural gas
through a third party pipeline out of the tailgate of the plant.
We expect to realize a net benefit to our cash flows and
earnings from these changes in addition to a reduced risk
portfolio. We are actively seeking to use the 80 MMcf/d of
newly available processing capacity at the Lakin plant by
attempting to contract for additional supply to the plant or by
moving the plant to a new location.
In our Gathering and Processing segment, we are a seller of NGLs
and are exposed to commodity price risk associated with
movements in NGL prices. NGL prices have experienced volatility
in recent years in response to changes in the supply and demand
for NGLs and market uncertainty. In response to this volatility,
we have, since the acquisition of Regency Gas Services LLC by HM
Capital Investors, executed swap contracts settled against
ethane, propane, butane and natural gasoline market prices,
supplemented with crude oil put options (historically, changes
in the prices of heavy NGLs, such as natural gasoline, have
generally correlated with changes in the price of crude oil). As
a result, we have hedged approximately 95% of our expected
exposure to NGL prices in 2006, approximately 75% in 2007 and
approximately 50% in 2008. We continually monitor our hedging
and contract portfolio and expect to continue to adjust our
hedge position as conditions warrant.
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 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.
Until recently, the NGLs produced by our processing plants were
sold to third parties as mixed NGLs. In September 2005, we began
delivering the mixed NGLs produced by our processing plants to
operators of fractionation facilities for fractionation for our
account. We then sell the individual components, such as ethane,
propane and isobutane, directly to marketing companies,
refineries and other wholesalers. We believe this marketing
function will allow us to earn additional margins from the sale
of the NGLs that otherwise would have been earned by the
fractionator.
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 our 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 the outlet. In the latter case, we generally
purchase pipeline-quality natural gas at a pipeline inlet price
adjusted to reflect our transportation fee and we sell that
natural gas at the pipeline outlet. The differential in the
purchase price and the sale price contributes to our segment
margin. 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. To
the extent a sustained decline in commodity prices resulted 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:
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Firm Transportation. Our obligation to provide firm
transportation service means that we are 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. |
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Interruptible Transportation. Our obligation to provide
interruptible transportation service means that we are only
obligated to transport natural gas nominated by the shipper 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 our transportation services under the terms of our
contracts and under an operating statement that we have filed
and maintain with FERC with respect to transportation authorized
under section 311 of the Natural Gas Policy Act of 1978, or
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.
Enhancement Project. Portions of the Regency Intrastate
Pipeline system have historically operated at full capacity and
represented a significant constraint on the flow of natural gas
from producing fields in north Louisiana to intrastate and
interstate markets in northeast Louisiana. In response, we have
completed a major expansion and extension of this system, which
we refer to as the Regency Intrastate Enhancement Project. This
project quadrupled the systems capacity from the capacity
that existed prior to the commencement of the project.
The Regency Intrastate Enhancement Project was a multi-phase
project designed to relieve bottlenecks on certain sections of
the pipeline and to access new sources of supply and markets. We
began planning this project in January 2005 and started
construction in May 2005. We completed the project in December
2005. This project included the expansion of our existing
Regency Intrastate Pipeline system and the addition of an
80-mile,
30-inch diameter
pipeline extension to the Regency Intrastate Pipeline system
supported by approximately 9,500 horsepower of additional
compression. The project has extended our transportation
services into additional major producing fields in north
Louisiana, connected our system to additional pipelines in
northeast Louisiana and has increased the capacity of the
pipeline to 800 MMcf/d.
The total cost of this project is approximately
$157.0 million. Our original estimate for this project was
approximately $140.0 million. The excess of cost over our
estimate includes $2.5 million of costs that we dispute and
otherwise consists primarily of insufficient estimates of
materials, right of way and legal expenditures, sales taxes and
capitalized interest.
One of our motivations to enhance this pipeline was to enable
our customers to reach markets offering more favorable prices by
developing interconnects with other pipelines. As of
December 31, 2005, the Regency Intrastate Pipeline system
could deliver gas to two 250 MMcf/d interconnects. Since
then, three additional interconnects have been completed: two
250 MMcf/d interconnections and a 500 MMcf/d
interconnection.
The completion of the Regency Intrastate Enhancement Project
enables us to provide transportation services from the three
largest natural gas producing fields in Louisiana. Prior to the
completion of the final phase of the project in December 2005,
we were transporting approximately 265 MMcf/d under
existing contracts. Through March 28, 2006, we have signed
definitive agreements for 466,000 MMBtu/d of firm
transportation on the Regency Intrastate Pipeline system and
404,000 MMBtu/d of interruptible transportation. We are
engaged in discussions with other parties interested in
utilizing the remaining firm system transportation capacity.
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General Trends and Outlook
We expect our business to continue to be affected by the
following key trends. Our expectations are based on assumptions
made by us and information currently available to us. To the
extent our underlying assumptions about or interpretations of
available information prove to be incorrect, our actual results
may vary materially from our expected results.
Natural Gas Supply, Demand and Outlook. Natural gas
continues to be a critical component of energy consumption in
the United States. According to the Energy Information
Administration, or EIA, total annual domestic consumption of
natural gas is expected to increase from approximately 22.2
trillion cubic feet, or Tcf, in 2005 to approximately 25.9 Tcf
in 2015, representing an average annual growth rate of
approximately 1.7%. During the five years ending
December 31, 2005, the United States has on average
consumed approximately 22.4 Tcf per year, while total
marketed domestic production averaged approximately
19.8 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.
We believe that current natural gas prices and the existing
strong demand for natural gas will continue to result in
relatively high levels of natural gas-related drilling in the
United States as producers seek to increase their level of
natural gas production. Although the natural gas reserves in the
United States have increased overall in recent years, a
corresponding increase in production has not been realized. We
believe that this lack of increased production is attributable
to insufficient pipeline infrastructure, the continued depletion
of existing wells and a tight labor and equipment market. We
believe that an increase in United States natural gas
production, additional sources of supply such as liquid natural
gas, and imports of natural gas will be required for the natural
gas industry to meet the expected increased demand for natural
gas in the United States.
All of the areas in which we operate are experiencing
significant drilling activity. Although we anticipate continued
high levels of exploration and production activities in all of
these areas, fluctuations in energy prices can affect production
rates over time and levels of investment by third parties in
exploration for and development of new natural gas reserves. We
have no control over the level of natural gas exploration and
development activity in the areas of our operations.
Gathering and Processing Segment Margins. For the year
ended December 31, 2005, our overall portfolio of
processing contracts reflected a net short position in natural
gas of approximately 7,400 MMBtu/d (meaning that we were a
net buyer of natural gas) and a net long position in NGLs of
approximately 4,900 Bbls/d (meaning that we were a net
seller of NGLs). As a result, during this period our segment
margins were positively impacted to the extent the price of NGLs
increased in relation to the price of natural gas and were
adversely impacted to the extent the price of NGLs declined in
relation to the price of natural gas. We refer to the price of
NGLs in relation to the price of natural gas as the
fractionation spread. Our contract portfolio performed well in
response to favorable fractionation spreads during 2005.
In keeping with our strategy of reducing commodity price
exposure, we have adjusted our contract portfolio through
renegotiation of certain keep-whole contracts, including three
large keep-whole contracts that were converted to fee contracts
in August 2005, resulting in a shift of our overall natural gas
position to a slightly long position going forward, while
retaining a long physical NGL position. We believe that this
adjusted portfolio effectively hedges our overall exposure to
volatility in fractionation spreads. Our profitability is now
positively impacted if natural gas or NGLs prices increase and
negatively impacted if natural gas or NGLs prices decrease. The
prices of natural gas and NGLs are volatile and beyond our
control.
Impact of Interest Rates and Inflation. The credit
markets recently have experienced
50-year record lows in
interest rates. If the overall economy continues to strengthen,
we believe that it is likely that monetary policy will tighten
further, resulting in higher interest rates to counter possible
inflation. Interest rates on future credit facilities and debt
offerings could be higher than current levels, causing our
financing costs to increase accordingly. Although increased
financing costs could limit our ability to raise funds in
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the capital markets, we expect in this regard to remain
competitive with respect to acquisitions and capital projects
since our competitors would face similar circumstances.
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations in 2003, 2004 or 2005. It may in the future, however,
increase the cost to acquire or replace property, plant and
equipment and may increase the costs of labor and supplies. Our
operating revenues and costs are influenced to a greater extent
by price changes in natural gas and NGLs. To the extent
permitted by competition, regulation and our existing
agreements, we have and will continue to pass along increased
costs to our customers in the form of higher fees.
Formation, Acquisition and Asset Disposal History and
Financial Statement Presentation
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Our Formation of Regency Energy Partners LP and Our
Initial Public Offering |
We are a Delaware limited partnership formed in September 2005
to own and operate Regency Gas Services LLC. Prior to the
completion of our initial public offering, Regency Gas Services
LLC was owned by the HM Capital Investors. Prior to the closing
of our initial public offering on February 3, 2006, Regency
Gas Services LLC was converted into a limited partnership named
Regency Gas Services LP, and was contributed to us by Regency
Acquisition LP, a limited partnership indirectly owned by the HM
Capital Investors, in exchange for 5,353,896 common units,
19,103,896 subordinated units, the incentive distribution
rights, a continuation of its 2% general partner interest in us,
and a right to receive $195.5 million of cash proceeds from
our initial public offering. The cash proceeds constituted a
reimbursement of a corresponding amount of capital expenditures
comprising most of the initial investment by the HM Capital
Investors in Regency Gas Services LLC. In addition,
approximately $48.0 million in cash and accounts receivable
were distributed by Regency Gas Services LLC to Regency
Acquisition LP and then to the HM Capital Investors immediately
prior to the contribution of Regency Gas Services LLC to us.
These current assets were replenished with proceeds from the
offering.
On March 8, 2006, we closed the sale of an additional
1,400,000 common units at a price of $20 per unit as the
underwriters exercised their over allotment option in
part. The net proceeds from the sale were used by us to redeem
an equivalent number of common units held by Regency Acquisition
LP for the benefit of the HM Capital Investors.
We paid $9.0 million of the proceeds from our initial
public offering to terminate our ten-year financial advisory,
monitoring and oversight agreements with an affiliate of HM
Capital. In the first quarter of 2006 we will expense these
costs.
The HM Capital Investors Acquisition of Regency Gas
Services LLC
On December 1, 2004, the HM Capital Investors acquired all
of the outstanding equity interests in Regency Gas Services LLC
from its previous owners. The HM Capital Investors accounted for
this acquisition as a purchase, and purchase accounting
adjustments, including goodwill and other intangible assets,
have been pushed down and are reflected in the
financial statements of Regency Gas Services LLC for the period
subsequent to December 1, 2004. In our consolidated
financial statements, Regency Gas Services LLC is designated as
Predecessor for periods ended subsequent to
December 1, 2004 and the Regency LLC
Predecessor periods ended before December 1, 2004.
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Formation of Regency Gas Services LLC |
Regency Gas Services LLC was organized on April 2, 2003 by
a private equity fund for the purpose of acquiring, managing and
operating natural gas gathering, processing and transportation
assets. Regency Gas Services LLC had no operating history prior
to the acquisition of the assets from affiliates of El Paso
Energy Corporation and Duke Energy Field Services, L.P.
discussed below.
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Acquisition of El Paso Assets |
In June 2003, Regency Gas Services LLC acquired certain natural
gas gathering, processing and transportation assets from
subsidiaries of El Paso Corporation for approximately
$119.5 million. The assets acquired consisted of gathering,
processing and transportation assets located in north Louisiana
and gathering and processing assets located in the mid-continent
region of the United States and represent substantially all of
our existing north Louisiana and mid-continent assets. At the
time of the acquisition, the acquired gathering and
transportation systems had an average expected remaining useful
life of approximately 20 years and the processing plants
had an average expected remaining useful life of approximately
15 years.
Prior to our acquisition of these assets, these assets were
operated as components of El Pasos much larger
midstream operations. Immediately following our acquisition of
these assets, we changed the manner in which these assets were
operated. In that regard, we initiated, and continue to
implement, a strategy to reshape the revenue structure of the
acquired assets to expand revenues, increase margins and
decrease exposure to market volatility.
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Acquisition of Duke Energy Field Services Assets |
In March 2004, Regency Gas Services LLC acquired certain natural
gas gathering and processing assets from Duke Energy Field
Services, LP for approximately $67.3 million, including
transactional costs. The assets acquired consisted of gathering
and processing assets located in west Texas and represent
substantially all of our existing west Texas assets.
Prior to our acquisition of these assets, these assets were
operated as components of Duke Energy Field Services much
larger midstream operations. As with the assets acquired from
El Paso, immediately following our acquisition of these
assets, we implemented significant operational changes designed
to expand revenues, increase margins and limit exposure to
market volatility. We promptly changed the manner in which
pipeline-quality natural gas was marketed from these assets by
extending contract terms.
Others
In April 2004, we completed the purchase of gas processing
interests located in Louisiana and Texas from Cardinal Gas
Services LLC (Cardinal) for $3.5 million in cash. In May
2005, we sold all of the assets acquired from Cardinal, together
with certain related assets, for $6.0 million. After the
allocation of $0.9 million of goodwill, the resulting gain
was $0.6 million. We have treated these operations as a
discontinued operation.
Items Impacting Comparability of Our Financial
Results
Our historical results of operations for the periods presented
may not be comparable, either from period to period or going
forward, for the reasons described below:
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Regency LLC Predecessor commenced operations in June 2003 with
the acquisition of the El Paso assets. As a result, we do
not have any material financial results for periods prior to
June 2003 and our results of operations for the period ended
December 31, 2003 includes only seven months of financial
results. |
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Regency LLC Predecessor acquired the Duke Energy Field Services
assets in March 2004. As a result, our financial results for
periods prior to March 2004 do not include the financial results
of the Duke Energy Field Services assets. |
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In connection with the acquisition of Regency Gas Services LLC
by the HM Capital Investors on December 1, 2004, the
purchase price was pushed-down to the financial
statements of Regency Gas Services LLC. As a result of this
push-down accounting, the book basis of our assets
was increased to reflect the purchase price, which had the
effect of increasing our depreciation and amortization |
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expense. Also, the increased level of debt incurred in
connection with the acquisition increased our interest expense
subsequent to December 1, 2004. |
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We anticipate incurring approximately $2.5 million of
additional general and administrative costs, including costs
relating to operating as a separate publicly held entity, such
as costs associated with annual and quarterly reporting, tax
return and Schedule K-1 preparation and distribution,
Sarbanes-Oxley compliance costs, independent auditor fees,
investor relation expenses, registrar and transfer agent fees. |
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In December 2004 we undertook a hedging program as required by
our credit facilities. Effective July 1, 2005 we designated
certain commodity and interest rate swap instruments for hedge
accounting treatment in accordance with SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities. For the periods from December 1, 2004
through June 30, 2005 unrealized and realized gains and
losses on the commodity swaps were recorded in
unrealized/realized gain (loss) from risk management activities
in our statements of operations. For the six months ended
June 30, 2005 unrealized gains and losses on the interest
rate swap were recorded in interest expense, net. Effective
July 1, 2005, to the extent the hedges are effective, any
unrealized gains or losses on these instruments were recorded in
other comprehensive income (loss) during the lives of the
instruments, which we believe will lead to financial results
that are not comparable for the affected periods. |
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We completed a major enhancement of our Regency Intrastate
Pipeline system and the pipeline, as expanded and extended,
began operations on December 28, 2005. As of March 30,
2006 we were transporting approximately 450,000 MMBtu/d of
natural gas. |
Critical Accounting Policies and Estimates
Conformity with accounting principles generally accepted in the
United States requires management to make estimates and
assumptions that affect the amounts reported in the financial
statements and notes. Although these estimates are based on
managements best available knowledge of current and
expected future events, actual results could be different from
those estimates. We believe that the following are the more
critical judgment areas in the application of our accounting
policies that currently affect our financial condition and
results of operations.
Revenue and Cost of Sales Recognition. We record revenue
and cost of sales on the gross basis for those transactions
where we act as the principal and take title to gas that is
purchased for resale. When our customers pay us a fee for
providing a service such as gathering or transportation we
record the fees separately in revenues.
Prior to March 2006, we recorded the monthly results of
operations using actual results which included settling most of
our volumes with producers, shippers and customers around the
25th of the month following the production month. This
process resulted in a delay in reporting results. To conform to
industry practice, we are implementing a closing process in
March 2006 that eliminates the reporting lag. Prior to the
settlement date, we will record actual operating data as
available, such as actual operating and maintenance and other
expenses. For total segment margin, we will estimate settlements
using actual pricing and nominated volumes. In the subsequent
production month, we will reconcile the estimates to the actual
results and record the difference which is not expected to be
material. The new process expedites financial reporting and
conforms to industry practice.
Risk Management Activities. In order to protect ourselves
from commodity and interest rate risk, we pursue hedging
activities to minimize those risks. These hedging activities
rely upon forecasts of our expected operations and financial
structure over the next four years. If our operations or
financial structure are significantly different from these
forecasts, we could be subject to adverse financial results as a
result of these hedging activities. We mitigate this potential
exposure by retaining an operational cushion between our
forecasted transactions and the level of hedging activity
executed. For example, we recently executed commodity price
swaps on approximately 50% of our expected net NGL exposure in
2008.
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From the inception of our hedging program in December 2004
through June 30, 2005, we used
mark-to-market
accounting for our commodity and interest rate swaps as well as
for crude oil puts. For the one month ending December 31,
2004, the amount of net realized and unrealized gains was
$0.3 million. For the year ended December 31, 2005, we
incurred $22.2 million of realized and unrealized net
losses, $13.0 million of which was realized and
$9.2 million of which was unrealized. The unrealized loss
of $9.2 million is comprised of $9.5 million of net
losses related to commodity hedges that are reflected in
operating revenues and $0.3 million of net gains related to
interest rate hedges that are reflected in interest expense,
net. We record realized gains and losses on hedge instruments
monthly based upon the cash settlements and the expiration of
option premiums. The settlement amounts vary due to the
volatility in the commodity market prices throughout each month.
We also record unrealized gains and losses monthly based upon
the future value of the hedges through their expiration dates.
The expiration dates vary but are currently no later than
December 2008. We monitor and review hedging positions
regularly. Effective July 1, 2005, we elected to use hedge
accounting for the swap contracts. We believe that the
prospective application of cash flow hedge accounting for the
swap transactions will mitigate the volatility in our earnings.
Purchase Accounting. On December 1, 2004, we were
acquired by the HM Capital Investors. We made various
assumptions in determining the fair values of acquired assets
and liabilities. In order to allocate the purchase price to the
business units, we developed fair value models with the
assistance of outside consultants. These fair value models
applied discounted cash flow approaches to expected future
operating results, considering expected growth rates,
development opportunities, and future pricing assumptions. An
economic value was determined for each business unit. The total
economic value was equal to the purchase price. We then
determined the fair value of the fixed assets based on estimates
of replacement costs. We identified intangible assets related to
licenses and permits, and renegotiated customer contracts and
assigned a fair value of $18.5 million. We made assumptions
regarding the period of time it would take to replace these
permits. We assigned value using a lost profits model over that
period of time necessary to replace the permits. The customer
contracts were valued using a discounted cash flow model. We
determined liabilities assumed based on their expected future
cash outflows. We recorded goodwill of $58.5 million as the
excess of the cost of each business unit over the sum of amounts
assigned to the tangible assets, financial assets, and
separately recognized intangible assets acquired less
liabilities assumed of the business unit.
Depreciation Expense and Cost Capitalization Policies.
Our assets consist primarily of natural gas gathering pipelines,
processing plants, and transmission pipeline. We capitalize all
construction-related direct labor and material costs, as well as
indirect construction costs. Indirect construction costs include
general engineering and the costs of funds used in construction.
Capitalized interest represents the cost of funds used to
finance the construction of new facilities. We capitalized
$2.6 million of interest related to the Regency Intrastate
Enhancement Project. These costs are then expensed over the life
of the constructed asset through the recording of depreciation
expense. Under certain contractual circumstances our gathering
and transmission system includes natural gas or NGL line pack,
which is a non-depreciable asset.
As discussed in the Notes to the Consolidated Financial
Statements, depreciation of our assets is generally computed
using the straight-line method over the estimated useful life of
the assets. The costs of renewals and betterments that extend
the useful life of property, plant and equipment are also
capitalized. Certain assets such as land, NGL line pack and
natural gas line pack are non-depreciable. The costs of repairs,
replacements and maintenance projects are expensed as incurred.
The computation of depreciation expense requires judgment
regarding the estimated useful lives and salvage value of
assets. As circumstances warrant, depreciation estimates are
reviewed to determine if any changes are needed. Such changes
could involve an increase or decrease in estimated useful lives
or salvage values which would impact future depreciation expense.
Environmental Remediation. Current accounting guidelines
require us to recognize a liability and expense associated with
environmental remediation if (i) government agencies
mandate such activities or
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one of our properties were added to the Comprehensive
Environmental Response, Compensation and Liability Act, or
CERCLA, database, (ii) the existence of a liability is
probable and (iii) the amount can be reasonably estimated.
To date, we have not recorded any liability for remediation
expenses and we do not believe that any significant liability
currently exists. If governmental regulations change, we could
be required to incur remediation costs that might have a
material impact on our profitability.
We account for our asset retirement obligations in accordance
with Statement of Financial Standards (SFAS) No. 143,
Accounting for Asset Retirement Obligations and
FIN 47 Accounting for Conditional Asset Retirement
Obligations. These accounting standards require us to
recognize on the balance sheet the net present value of any
legally binding obligation to remove or remediate the physical
assets that we retire from service, as well as any similar
obligations for which the timing and/or method of settlement are
conditional on a future event that may or may not be within our
control. While we are obligated under contractual agreements to
remove certain facilities upon their retirement, we are unable
to reasonably determine the fair value of any asset retirement
obligations as of December 31, 2005 and 2004 because the
settlement dates, or ranges thereof, were indeterminable and
could range up to ninety-six years, and the undiscounted amounts
are immaterial. An asset retirement obligation will be recorded
in the periods wherein we can reasonably determine the
settlement dates.
Equity Based Compensation. In December 2005, the
compensation committee of the board of directors of our Managing
GP approved a long-term incentive plan, or LTIP, for
our employees, directors and consultants. On February 3,
2006 awards were granted in connection with the consummation of
our initial public offering. The initial grant included a total
of 262,500 restricted common units and 599,300 common
unit options with grant-date fair values of $20 per unit
and $1.15 per option. In the aggregate, these awards
represent 861,800 potential common units. The options were
valued with the Black-Scholes Option Pricing Model under the
following assumptions: 15% volatility in the unit price, a ten
year term, a strike price equal to the initial public offering
price of $20 per unit, a distribution yield of 7%, and an
average exercise of the options of four years after vesting is
complete. The assumption that participants will, on average,
exercise their options four years from the vesting date is based
on the average of the mid-points from vesting to expiration of
the options.
Subsequent to the initial grant, we awarded
100,000 restricted common units and 58,000 common unit
options. The awards were issued at weighted average grant date
fair values of $20.51 per restricted common unit and
$1.20 per unit option. In aggregate, these awards represent
158,000 potential common units. The terms of the awards and
the valuation assumptions are identical to those in the initial
grant, adjusted for the differences in the unit prices and grant
dates.
A total of 2,865,584 common units have been authorized for
delivery under the LTIP. All LTIP awards are subject to a three
year vesting period. For each year completed, one-third of the
award will vest. The options have a maximum contractual term,
expiring ten years after the grant date.
We will make the same distributions to holders of non-vested
restricted common units as those paid to common unit holders.
Upon the vesting of the restricted common units and the exercise
of the common unit options, we intend to settle these
obligations with common units. Accordingly, we expect to
recognize an aggregate of $7.7 million of compensation
expense related to the initial grants under LTIP, or
$2.6 million for each of the three years of the vesting
period for such grants. We adopted SFAS 123(R)
Share-Based Payment in the first quarter of 2006
which had no impact to us as no LTIP awards were outstanding
during 2005.
Senior members of management and outside directors who held
Class B or Class D units of HMTF Regency, L.P. entered
into exchange agreements in connection with the consummation of
the Partnerships initial public offering whereby they
exchanged their Class B or Class D units for common
and subordinated units in Regency Energy Partners LP and an
interest in Regency GP LLC. We have evaluated the impact of the
exchange agreements and will not record a material amount of
compensation expense related to this exchange.
60
Results of Operations
Year Ended December 31,
2005 vs. Combined Year Ended December 31, 2004
The table below contains key company-wide performance indicators
related to our discussion of the results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency LLC | |
|
|
|
|
|
|
Predecessor | |
|
Predecessor | |
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
Year Ended | |
|
|
|
|
|
|
December 31, | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
2005 | |
|
2004(d) | |
|
$ Change | |
|
% Change | |
|
|
| |
|
| |
|
| |
|
| |
|
|
|
|
(combined) | |
|
|
|
|
|
|
($ in millions) | |
Revenues(a)
|
|
$ |
692.6 |
|
|
$ |
480.2 |
|
|
$ |
212.4 |
|
|
|
44 |
% |
Cost of sales
|
|
|
620.7 |
|
|
|
403.8 |
|
|
|
216.9 |
|
|
|
54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment margin(b)
|
|
|
71.9 |
|
|
|
76.4 |
|
|
|
(4.5 |
) |
|
|
(6 |
) |
Operating expenses
|
|
|
21.8 |
|
|
|
19.6 |
|
|
|
2.2 |
|
|
|
11 |
|
General and administrative
|
|
|
14.4 |
|
|
|
7.2 |
|
|
|
7.2 |
|
|
|
100 |
|
Transaction expenses
|
|
|
- |
|
|
|
7.0 |
|
|
|
(7.0 |
) |
|
|
(100 |
) |
Depreciation and amortization
|
|
|
22.0 |
|
|
|
11.7 |
|
|
|
10.3 |
|
|
|
88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
13.7 |
|
|
|
30.9 |
|
|
|
(17.2 |
) |
|
|
(56 |
) |
Interest expense, net
|
|
|
(17.4 |
) |
|
|
(6.5 |
) |
|
|
(10.9 |
) |
|
|
168 |
|
Loss on debt refinancing
|
|
|
(8.5 |
) |
|
|
(3.0 |
) |
|
|
(5.5 |
) |
|
|
183 |
|
Other income and deductions, net
|
|
|
0.3 |
|
|
|
0.2 |
|
|
|
0.1 |
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income from continuing operations
|
|
|
(11.9 |
) |
|
|
21.6 |
|
|
|
(33.5 |
) |
|
|
(155 |
) |
Discontinued operations
|
|
|
0.7 |
|
|
|
(0.1 |
) |
|
|
0.8 |
|
|
|
(800 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$ |
(11.2 |
) |
|
$ |
21.5 |
|
|
$ |
(32.7 |
) |
|
|
(152 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
System inlet volumes (MMBtu/d)(c)
|
|
|
565,991 |
|
|
|
493,956 |
|
|
|
72,035.0 |
|
|
|
15 |
% |
Processing volumes (MMBtu/d)
|
|
|
220,500 |
|
|
|
271,555 |
|
|
|
(51,055.0 |
) |
|
|
(19 |
) |
|
|
|
(a) |
|
Includes $0.3 million of net unrealized gains on hedging
transactions for the year ended December 31, 2004. Includes
$9.5 million of net unrealized losses on hedging
transactions and $2.0 million of put option expiration for
the year ended December 31, 2005. |
|
(b) |
|
For a reconciliation of total segment margin to its most
directly comparable financial measure calculated and presented
in accordance with GAAP, please read Selected Financial
Data. |
|
(c) |
|
System inlet volumes include total volumes taken into our
gathering and processing and transportation systems. |
|
(d) |
|
We combined the results of operations for the period from
acquisition date (December 1, 2004) of the Predecessor and
the period from January 1, 2004 to November 30, 2004
of the Regency LLC Predecessor to provide an annual reporting
period for a more meaningful comparison versus the year ended
December 31, 2005. To the extent operations for the 2005
period are not comparable to the combined 2004 period; we have
disclosed such differences in the discussion of results of
operations. See the separate discussion of the one month ended
December 31, 2004. |
61
The table below contains key segment performance indicators
related to our discussion of the results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency LLC | |
|
|
|
|
|
|
Predecessor | |
|
Predecessor | |
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
Year Ended | |
|
|
|
|
|
|
December 31, | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
2005 | |
|
2004(b) | |
|
$ Change | |
|
% Change | |
|
|
| |
|
| |
|
| |
|
| |
|
|
|
|
(combined) | |
|
|
|
|
|
|
($ in millions) | |
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Margin(a)
|
|
$ |
56.2 |
|
|
$ |
67.6 |
|
|
$ |
(11.4 |
) |
|
|
(17 |
)% |
|
|
|
Operating expenses
|
|
|
19.9 |
|
|
|
17.9 |
|
|
|
2.0 |
|
|
|
11 |
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput (thousand MMBtu/d)
|
|
|
308 |
|
|
|
304 |
|
|
|
4.0 |
|
|
|
1 |
|
|
|
|
NGL gross production (Bbls/d)
|
|
|
14,312 |
|
|
|
14,588 |
|
|
|
(276.0 |
) |
|
|
(2 |
) |
|
Transportation Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Margin
|
|
$ |
15.7 |
|
|
$ |
8.8 |
|
|
$ |
6.9 |
|
|
|
78 |
% |
|
|
|
Operating expenses
|
|
|
1.9 |
|
|
|
1.7 |
|
|
|
0.2 |
|
|
|
12 |
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput (thousand MMBtu/d)
|
|
|
258 |
|
|
|
190 |
|
|
|
68.0 |
|
|
|
36 |
|
|
|
|
(a) |
|
Includes $0.3 million of net unrealized gains on hedging
transactions for the year ended December 31, 2004. Includes
$9.5 million of net unrealized losses on hedging
transactions and $2.0 million of put option expiration for
the year ended December 31, 2005. |
|
(b) |
|
We combined the results of operations for the period from
acquisition date (December 1, 2004) of the Predecessor and
the period from January 1, 2004 to November 30, 2004
of the Regency LLC Predecessor to provide an annual reporting
period for a more meaningful comparison versus the year ended
December 31, 2005. To the extent operations for the 2005
period are not comparable to the combined 2004 period, we have
disclosed such differences in the discussion of results of
operations. See the separate discussion of the one month ended
December 31, 2004. |
Net Income. Net income for the year ended
December 31, 2005 decreased $32.7 million compared
with the combined year ended December 31, 2004. Interest
expense, net increased $10.9 million primarily due to
higher net interest expense related to debt incurred to fund the
HM Capital Transaction. Depreciation and amortization expense
increased $10.3 million primarily due to our higher
depreciable basis following purchase accounting for the HM
Capital Transaction. In the year ended December 31, 2005 we
wrote off $8.5 million of debt issuance costs (consisting
of $5.8 million of unamortized debt issuance costs,
$1.9 million of costs incurred in July 2005 and
$0.8 million of costs incurred in November 2005 in
connection with amendments to our credit facilities). In the
combined year ended December 31, 2004, we wrote off
$3.0 million of unamortized debt issuance costs. The
decrease in net income also included a reduction in total
segment margin of $4.5 million, which included a
$9.5 million net unrealized loss and a $12.7 million
realized loss from risk management activities partially offset
by a positive price variance in our Gathering and Processing
Segment and improved segment margin in our Transmission Segment.
General and administrative expense increased $7.2 million
primarily as a result of higher employee-related expenses.
Operating expenses increased $2.2 million primarily due to
our west Texas facilities operating twelve months in 2005 versus
ten months in 2004 and higher taxes, other than income. In the
combined year ended 2004, the Regency LLC Predecessor incurred
transaction expenses of $7.0 million related to certain
non-recurring costs associated with the HM Capital
transaction.
62
During the year ended December 31, 2005, we realized losses
of $12.7 million on risk management activities. This loss
consists of $10.8 million of swap settlements and
$1.9 million of premiums associated with expired crude put
options which were paid in a prior period. As noted below, these
amounts were offset by a positive price variance of
$10.8 million, demonstrating the effectiveness of our
hedging program with respect to stabilizing the cash generated
by the sale of our NGLs.
Total Segment Margin. Total segment margin for the year
ended December 31, 2005 decreased to $71.9 million
from $76.4 million for the combined year ended
December 31, 2004, representing a 6% decline. Non-cash
losses reduced total segment margin by $11.5 million. These
non-cash losses were caused by the net change in the fair value
of derivative contracts during such time as the contracts were
not designated as hedges in 2005 and the expiration of certain
crude oil put options. This decrease was offset in part by
increased pipeline throughput volumes, which produced additional
margin of $7.2 million. Pricing effects were negligible, as
$10.8 million of increased total segment margin
attributable to commodity prices was offset by
$10.8 million in cash hedge settlements demonstrating the
effectiveness of our hedging program. Please read
Critical Accounting Policies and
Estimates for a detailed discussion of this matter.
Segment margin for the Gathering and Processing Segment for the
year ended December 31, 2005 decreased to
$56.2 million from $67.6 million for the combined year
ended December 31, 2004, representing a 17% decline. The
elements driving this reduction in segment margin are as follows:
|
|
|
|
|
Pricing effects were negligible, as $10.8 million of
increased segment margin attributable to higher commodity prices
was offset by $10.8 million in cash hedge settlements, |
|
|
|
$0.3 million of increase segment margin attributable to
increased pipeline throughput volumes, |
|
|
|
$11.5 million of decreased segment margin attributable to
non-cash losses reflecting the net change in the fair value of
derivatives contracts during the first six months of 2005 and
the expiration of certain crude oil put option in 2005, and |
|
|
|
Segment margin in 2004 was increased by $0.3 million of
non-cash gains reflecting the net change in the fair value of
derivative contracts for the period. |
Segment margin for the Transportation segment for the year ended
December 31, 2005 increased to $15.7 million from
$8.8 million for the comparable combined period in 2004, a
78% increase. The increase was attributable to increased
throughputs across the system in 2005.
Operating Expenses. Operating expenses for the year ended
December 31, 2005 increased to $21.8 million from
$19.6 million for the combined year ended December 31,
2004, representing a 11% increase. This increase resulted in
part from higher operating expenses of $1.0 million
associated with our west Texas assets in the Gathering and
Processing Segment for the full year ended December 31,
2005 as compared to ten months in 2004. Higher taxes, other than
income, primarily property taxes in the mid-continent region
within the Gathering and Processing Segment, resulted in an
increase of $0.8 million. Also contributing to the increase
in operating expenses were higher materials and parts expense of
$0.7 million in the Transportation Segment and the
remainder of the Gathering and Processing segment. These
increases were partially offset by lower employee costs and
rental expense of $0.3 million in the mid-continent region
of the Gathering and Processing Segment related to our
previously planned shut down of our Lakin gas processing plant.
See the discussion on Gathering and Processing
Segment for additional information regarding the Lakin
shut down.
General and Administrative. General and administrative
expense increased to $14.4 million in the year ended
December 31, 2005 from $7.2 million for the combined
year ended December 31, 2004. This increase was primarily
attributable to higher employee-related expenses of
$3.1 million, including higher salary expense associated
with increased headcount and bonus accruals. Also contributing
to the increase were increased professional and consulting
expenses of $2.9 million, consisting primarily of legal
fees for regulatory and contract related matters, business
development expenses and consulting fees for Sarbanes-Oxley
compliance support. Further contributing to the increase were
higher management fees of
63
$0.7 million, resulting from our relationship with HM
Capital, increased insurance costs of $0.2 million and
various other general and administrative expenses of
$0.3 million.
Transaction Expenses. Regency LLC Predecessor incurred
non-recurring expenses related to the HM Capital transaction in
the amount of $7.0 million in 2004. These expenses were
comprised of compensation, legal and other expenses and were
paid prior to the HM Capital transaction.
Depreciation and Amortization. Depreciation and
amortization increased to $22.0 million in the year ended
December 31, 2005 from $11.7 million for the combined
year ended December 31, 2004, representing an 88% increase.
Depreciation expense increased $8.6 million primarily due
to the acquisition of Regency Gas Services LLC by the HM Capital
Investors in December 2004, which increased the book basis of
our depreciable assets to their fair market value. Also
contributing to the increase was the amortization of
identifiable intangible assets of $1.7 million in the 2005
period related to purchase accounting following the HM Capital
Transaction.
Interest Expense, Net. Interest expense, net increased
$10.9 million, or 168%, in the year ended December 31,
2005 compared to the combined year ended December 31, 2004
due to higher net interest expense of $10.1 million,
primarily related to debt incurred to fund the HM Capital
Transaction, and increased amortization of debt issuance costs
of $0.8 million.
Loss on Debt Refinancing. In the year ended
December 31, 2005 and combined year ended December 31,
2004, we wrote-off $8.5 million and $3.0 million,
respectively, of debt refinancing costs related to our amended
credit facilities in accordance with EITF 96-19,
Debtors Accounting for a Modification or Exchange of
Debt Instruments. The $8.5 million write-off
consisted of $5.8 million of unamortized debt issuance
costs, $1.9 million of costs incurred in July 2005 and
$0.8 million of costs incurred in November 2005 in
connection with amendments to our credit facilities. The
write-off for the combined year ended December 31, 2004
consisted of unamortized debt issuance costs.
Federal Income Tax. As a pass-through entity, we are not
subject to federal income taxes. The liability for federal
income taxes associated with income produced by our business is
passed through to and recognized by entities that are investors
on our indirect parent.
Discontinued Operations. On April 1, 2004, we
completed the purchase of natural gas processing and treating
interests located in Louisiana and Texas from Cardinal for
$3.5 million. On May 2, 2005, we sold all of the
assets acquired from Cardinal, together with certain related
assets, for $6.0 million. The results of these operations
are presented as discontinued operations, and we recorded a gain
on the sale of $0.6 million during the year ended
December 31, 2005.
See Note 2 to the accompanying consolidated financial
statements and Formation, Acquisition and Asset Disposal
History and Financial Statement Presentation above for
additional information on Cardinal.
The Month of December
2004
The HM Capital Investors purchased Regency Gas Services LLC
effective December 1, 2004. As a result of accounting for
the acquisition as a purchase and using push-down accounting, we
incurred additional depreciation and amortization expense.
Depreciation and amortization expense for this one month
increased over the preceding monthly amount by $0.6 million
or 61% resulting from the
step-up in
basis of tangible assets as well as the recording of new
identifiable intangible assets from the purchase price
allocation. The additional interest expense resulted primarily
from higher levels of borrowings associated with the
acquisition. These levels of borrowings increased to
$250.0 million at December 31, 2004 from
$66.6 million at December 31, 2003.
64
Period from January 1, 2004 to November 30, 2004
vs. Period from Inception (April 2, 2003) to
December 31, 2003
The table below contains key company-wide performance indicators
related to our discussion of the results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency LLC | |
|
|
|
|
|
|
Regency LLC | |
|
Predecessor | |
|
|
|
|
|
|
Predecessor | |
|
| |
|
|
|
|
|
|
| |
|
Period from | |
|
|
|
|
|
|
Period from | |
|
Inception | |
|
|
|
|
|
|
January 1, 2004 | |
|
(April 2, 2003) | |
|
|
|
|
|
|
to November 30, | |
|
to December 31, | |
|
|
|
|
|
|
2004 | |
|
2003 | |
|
$ Change | |
|
% Change | |
|
|
| |
|
| |
|
| |
|
| |
|
|
($ in millions) | |
Revenues
|
|
$ |
432.3 |
|
|
$ |
186.5 |
|
|
$ |
245.8 |
|
|
|
132 |
% |
Cost of sales
|
|
|
362.7 |
|
|
|
163.4 |
|
|
|
199.3 |
|
|
|
122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment margin(a)
|
|
|
69.6 |
|
|
|
23.1 |
|
|
|
46.5 |
|
|
|
201 |
|
Operating expenses
|
|
|
17.8 |
|
|
|
7.0 |
|
|
|
10.8 |
|
|
|
154 |
|
General and administrative
|
|
|
6.6 |
|
|
|
2.7 |
|
|
|
3.9 |
|
|
|
144 |
|
Transaction expenses
|
|
|
7.0 |
|
|
|
0.7 |
|
|
|
6.3 |
|
|
|
900 |
|
Depreciation and amortization
|
|
|
10.1 |
|
|
|
4.3 |
|
|
|
5.8 |
|
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
28.1 |
|
|
|
8.4 |
|
|
|
19.7 |
|
|
|
235 |
|
Interest expense, net
|
|
|
(5.1 |
) |
|
|
(2.4 |
) |
|
|
(2.7 |
) |
|
|
113 |
|
Loss on debt refinancing
|
|
|
(3.0 |
) |
|
|
|
|
|
|
(3.0 |
) |
|
|
n/m |
|
Other income and deductions, net
|
|
|
0.1 |
|
|
|
0.2 |
|
|
|
(0.1 |
) |
|
|
(50 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
20.1 |
|
|
|
6.2 |
|
|
|
13.9 |
|
|
|
224 |
|
Discontinued operations
|
|
|
(0.1 |
) |
|
|
|
|
|
|
(0.1 |
) |
|
|
n/m |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
20.0 |
|
|
$ |
6.2 |
|
|
$ |
13.8 |
|
|
|
223 |
% |
|
|
|
|
|
|
|
|
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System inlet volumes (MMBtu/d)(b)
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495,581 |
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423,043 |
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72,538 |
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17 |
% |
Processing volumes (MMBtu/d)
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237,247 |
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136,127 |
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101,120 |
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74 |
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(a) |
|
For a reconciliation of total segment margin to its most
directly comparable financial measure calculated and presented
in accordance with GAAP, please read Selected Financial
Data. |
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(b) |
|
System inlet volumes include total volumes taken into our
gathering and processing and transportation systems. |
n/m = not meaningful
65
The table below contains key segment performance indicators
related to our discussion of the results of operations.
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Regency LLC | |
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Regency LLC | |
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Predecessor | |
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Predecessor | |
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Period from | |
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Period from | |
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January 1, | |
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Inception | |
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2004 | |
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(April 2, 2003) | |
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to November 30, | |
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to December 31, | |
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2004 | |
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2003 | |
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$ Change | |
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% Change | |
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($ in millions) | |
Segment Financial and Operating Data:
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Gathering and Processing Segment
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Financial data:
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Segment Margin
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$ |
61.4 |
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$ |
18.9 |
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$ |
42.5 |
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225 |
% |
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Operating expenses
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16.2 |
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6.1 |
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10.1 |
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166 |
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Operating data:
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Throughput (thousand MMBtu/d)
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303 |
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211 |
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92 |
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44 |
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NGL gross production (Bbls/d)
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14,487 |
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9,434 |
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5,053 |
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54 |
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Transportation Segment
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Financial data:
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Segment Margin
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$ |
8.2 |
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$ |
4.2 |
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$ |
4.0 |
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95 |
% |
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Operating expenses
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1.6 |
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0.9 |
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0.7 |
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78 |
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Operating data:
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Throughput (thousand MMBtu/d)
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192 |
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212 |
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(20 |
) |
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(9 |
) |
Results of operations for the year ended December 31, 2003
comprise the period from inception from April 2, 2003
through December 31, 2003; however, the period included
only seven months of active operations which began on
June 2, 2003.
Net Income. Net income for the eleven months ended
November 30, 2004 increased $13.8 million compared
with the seven months of active operations in 2003. Net income
was significantly enhanced due to the contribution of
$22.1 million of segment margin related to the purchase of
the west Texas assets in 2004. Interest expense, net increased
$2.7 million primarily due to higher net interest expense
related to debt incurred to fund the west Texas assets
acquisition. In the eleven months ended November 30, 2004,
we wrote off $3.0 million of debt issuance costs in
connection with the amendment of our current credit facilities
and the repayment of our prior facility. Depreciation and
amortization expense increased $5.8 million primarily due
to our higher depreciable basis following the purchase of the
west Texas assets. General and administrative expense increased
$3.9 million primarily as a result of higher
employee-related expenses and professional and consulting
expenses. Operating expenses increased $10.8 million
primarily due to our west Texas facilities operating seven
months in 2004 versus none in the 2003 period and the difference
of four more months in the comparable periods.
Total Segment Margin. Total segment margin for the eleven
months ended November 30, 2004 increased to
$69.6 million from $23.1 million for the seven months
of active operations in 2003, a 201% increase. Of this increase:
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$22.1 million was produced by operating assets acquired in
west Texas in March of 2004; |
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$14.5 million was attributable to the operation of our
north Louisiana and mid-continent assets, which were acquired in
June 2003, for eleven months in the 2004 period compared with
seven months of active operations in 2003 period; |
66
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$0.7 million resulted from NGL marketing operations, which
were present in the eleven months ended November 30, 2004
but absent in the seven months of active operations in 2003; and |
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the remaining $9.2 million resulted from increased margins
per unit of throughput. |
Segment margin for the Gathering and Processing segment
increased to $61.4 million for the eleven months ended
November 30, 2004 from $18.9 million for the seven
months of active operations in 2003, a 225% increase. Of this
increase:
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$22.1 million was produced by operating assets acquired in
west Texas in March of 2004; |
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$12.1 million was attributable to the operation of our
north Louisiana and mid-continent gathering and processing
assets, which were acquired in June 2003, for eleven months in
the 2004 period as compared to seven months of active operations
in the 2003 period; |
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$0.7 million was attributable to NGL marketing operations;
and |
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the remaining $7.6 million resulted from increased margins
per unit of throughput, primarily as a result of commodity price
changes. |
Segment margin for the Transportation segment increased to
$8.2 million for the eleven months ended November 30,
2004 from $4.2 million for the seven months of active
operations in 2003, a 95% increase. Of this increase:
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$2.4 million was attributable to operation of the north
Louisiana and mid-continent assets for eleven months in the 2004
period as compared to seven months of active operations in the
2003 period; and |
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$1.5 million was attributable to increased margins per unit
of throughput, primarily as a result of changes in contract mix
in 2004. |
Operating Expenses. Operating expenses for the eleven
months ended November 30, 2004 increased to
$17.8 million from $7.0 million in the seven months
ended of active operations in 2003, a 154% increase. The
addition of the west Texas assets to our Gathering and
Processing segment accounted for $6.5 million of the
increase. The remaining increase is attributable to operations
for eleven months in the 2004 period as compared to seven months
of active operations in the 2003 period, with $3.6 million
of the increase resulting from our Gathering and Processing
segment and $0.7 million of the increase resulting from our
Transportation segment.
General and Administrative Expense. General and
administrative expense increased to $6.6 million in 2004
from $2.7 million in 2003, a 144% increase. The increase is
primarily attributable to employee related expenses of
$2.1 million and professional and consulting expenses of
$1.3 million. The employee related expenses and the
professional and consulting expenses were impacted by the eleven
months of expense in 2004 versus seven months of active
operations in 2003 as well as an increase in payroll expense in
2004 associated with our west Texas assets.
Transaction Expense. Regency LLC Predecessor incurred
internal non-recurring expenses related to the sale of Regency
Gas Services LLC to the HM Capital Investors in the amount of
$7.0 million in 2004. These expenses consist of
compensation, legal and other expenses and were paid by Regency
LLC Predecessor prior to the HM Capital Investors
acquisition. In 2003, the Regency LLC Predecessor incurred
$0.7 million of legal and other organization expenses
related to the formation of Regency LLC Predecessor.
Depreciation and Amortization. Depreciation and
amortization increased to $10.1 million in 2004 from
$4.3 million in 2003, a 135% increase. In 2004,
depreciation expense of $3.0 million was associated with
our west Texas assets in the Gathering and Processing segment.
The remaining increase in depreciation and amortization expense
results from eleven months of expense in 2004 versus seven
months of active operations in 2003, primarily in the non-west
Texas portion of the Gathering and Processing segment.
67
Interest Expense, Net. Interest expense increased
$2.7 million or 113% in 2004 compared to 2003 primarily due
to the increased level of borrowings, which were used to finance
acquisitions and provide the necessary working capital for the
larger enterprise.
Loss on Debt Refinancing. We expensed approximately
$3.0 million of unamortized debt issuance costs upon the
March 1, 2004 amendment and the December 1, 2004
repayment of our prior credit facility.
Federal Income Tax. We are a limited liability company.
Accordingly, we are not subject to federal income taxes. Our
members incur the liability for federal income taxes associated
with income produced by our business.
Other Matters
Hurricane Katrina and Hurricane Rita. Hurricanes Katrina
and Rita struck the Gulf Coast region of the United States on
August 29, 2005 and September 24, 2005, respectively,
causing widespread damage to the energy infrastructure in the
region. The storms did not cause material direct damage to any
of our assets in the region. The storms negatively affected the
nations short term energy supply and natural gas and NGL
prices increased significantly thereafter. These higher
commodity prices had a favorable net effect on our results of
operations as we were, and continue to be, a net seller of these
commodities.
While neither Hurricane Katrina nor Hurricane Rita caused
material direct damage to our facilities, Hurricane Rita did
disrupt the operations of NGL pipelines and fractionators in the
Houston, Texas area. As a result of these disruptions, we were
forced temporarily to curtail producers in the west Texas region
for approximately four days and to operate our north Louisiana
processing assets in a reduced recovery mode for approximately
six days. We have not experienced ongoing effects from these
temporary disruptions.
Environmental. A Phase I environmental study was
performed on our west Texas assets by an environmental
consultant engaged by us in connection with our pre-acquisition
due diligence process in 2004. The study indicated that 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. We have an
environmental pollution liability insurance policy that covers
any undetected or unknown pollution discovered in the future.
The policy pays for
clean-up costs and
damages to third parties and has a ten-year term with a
$10 million limit subject to certain deductibles.
In March 2005, the Oklahoma Department of Environmental Quality,
or ODEQ, sent a notice of violation, alleging that we operate
the Mocane processing plant in Beaver County, Oklahoma in
violation of the National Emission Standard for Hazardous Air
Pollutants from Oil and Natural Gas Production Facilities, or
NESHAP, and the requirements to apply for and obtain a federal
operating permit (Title V permit). After seeking and
obtaining advice from the Environmental Protection Agency, the
ODEQ issued an order requiring us to apply for a Title V
permit with respect to emissions from the Mocane processing
plant by April 2006. No fine or penalty was imposed by the ODEQ
and we intend to comply with the order. Resolution of this
matter will not have a material adverse effect on our
consolidated results of operations, financial condition, or cash
flows.
In November 2004, the Texas Commission on Environmental Quality,
or TCEQ, sent a Notice of Enforcement, or NOE, to us relating to
the operation of the Waha processing plant in 2001 before it was
acquired by us. We settled this NOE with the TCEQ in November
2005.
Absent the alleged physical or operational changes at the Waha
processing plant that precipitated the NOE, the air emissions at
the plant would have been limited, based on the plants
grandfathered status under the relevant federal
statutory standards, only by historical amounts until 2007. In
anticipation of the expiration of that status, we submitted to
the TCEQ in early February 2005 an application for a state air
permit for emissions from the Waha plant predicated on the
construction of an acid gas reinjection well and, after
completion of the well and facilities, the reinjection of the
emitted gases. That permit has been issued and
68
requires completion of construction of the well by the end of
February 2007. We estimate the capital expenditure relating to
the well at approximately $6.0 million.
Liquidity and Capital Resources
We expect our sources of liquidity to include:
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cash generated from operations; |
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borrowings under our credit facilities; |
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debt offerings; and |
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issuance of additional partnership units. |
We believe that the cash generated from these sources will be
sufficient to meet our minimum quarterly cash distributions and
our requirements for short-term working capital and growth
capital expenditures for the next twelve months.
Cash Flows and Capital
Expenditures
Since the inception of our operations in June 2003 through
December 31, 2005, there have been several key events that
have had major impacts on our cash flows. They are:
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the acquisition of the El Paso assets on June 2, 2003
in the amount of approximately $119.5 million which was
financed through equity of $53.7 million and debt of
$70 million; |
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|
the acquisition of the Waha assets on March 1, 2004 for
$67.3 million of cash and $1 million of assumed
liabilities. We financed this acquisition with $10 million
of new equity with the balance in debt; |
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|
the acquisition of Regency Gas Services LLC by the HM Capital
Investors on December 1, 2004 for approximately
$414 million, net of working capital adjustments, which was
funded primarily through $243 million of term notes and
$171 million of equity; and |
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|
construction of our Regency Intrastate Enhancement Project at an
estimated cost of $157 million, which began in May 2005 and
was financed through cash flows from operations, long-term debt
and a $15 million equity contribution. |
Working Capital (Deficit). Working capital is the amount
by which current assets exceed current liabilities and is a
measure of our ability to pay our liabilities as they become
due. Our working capital was $(5.5) million at
December 31, 2003, $1.9 million at December 31,
2004 and $(27.7) million at December 31, 2005.
The net increase in working capital from December 31, 2003
to December 31, 2004 of $7.4 million resulted
primarily from the following factors:
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an increase in cash and cash equivalents of $1.7 million; |
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a $2.8 million increase in the value of risk management
assets, resulting from the purchase of calendar 2005 crude oil
put options for $2.0 million that we partially funded with
an equity investment, and from a $0.8 million unrealized
increase in the value of NGL swap contracts; |
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|
a $9.2 million reduction in the amount of short-term debt
partially offset by; |
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|
both accounts receivable and accounts payable increased from
2003 to 2004 due to the addition of the west Texas operations in
March 2004 resulting in a net $6.6 million decrease. |
69
The net decrease in working capital from December 31, 2004
to December 31, 2005 of $29.6 million resulted from
three primary factors:
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a $18.7 million decrease in the net of accounts receivable
and accounts payable. This change is primarily attributable to a
$21.4 million increase in accounts payable related to the
construction of our Regency Intrastate Enhancement Project.
Since June 30, 2005, we have financed the project with
long-term debt and a $15 million equity contribution. The
decrease is partially offset by the payment in February 2005 of
a post-closing adjustment payment to our former owners in the
amount of $5.8 million. |
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a $12.3 million decrease in the value of our current risk
management net assets. As a result of increases in NGL prices,
the market value of these contracts has resulted in a liability
which, if prices remained unchanged, would be paid over the
course of the next twelve months. |
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|
these amounts were offset in part by a $2.0 million
decrease in current portion of long-term debt, due to our second
amended credit facility, which no longer requires scheduled
principal payments. |
We expect to improve our working capital position during the
first quarter of 2006 as a result of the completion of the
Regency Intrastate Enhancement Project and paying the related
construction expenses. We cannot predict the impact of our
derivative instruments on working capital. With respect to the
net risk management liabilities, our cash flows from the sale of
products at their market prices will allow us to satisfy these
obligations should they materialize.
Cash Flows from Operations. Our cash flows from
operations for the eleven months ended November 30, 2004
increased by $25.9 million or 399% from the seven-month
period from our date of commencement of operations (June 2,
2003) through December 31, 2003. For the year ended
December 31, 2005, our cash flows from operations increased
by $3.5 million or 13% from the combined year ended
December 31, 2004.
The increase in the operating cash flows during the eleven-month
period ended November 30, 2004 as compared to the seven
months ended December 31, 2003 resulted primarily from the
increased volumes attributable to the acquisition of our west
Texas assets in March 2004. In addition, we commenced active
operations in June 2003 and, as a result, 2003 included only
seven months of operations while the 2004 period included eleven
months of operations. For the eleven months ended
November 30, 2004, the west Texas operations contributed
the following increases over the seven months ended
December 31, 2003: total revenue of $104.6 million,
cost of gas and liquids and other cost of sales in the amount of
$82.5 million and segment margin of $22.1 million.
During the eleven-month period ended November 30, 2004,
higher natural gas prices also contributed to improved operating
cash flow.
Net cash provided by operating activities increased to
$31.0 million for the year ended December 31, 2005
compared with $27.5 million for the combined year ended
December 31, 2004. The increase was primarily due to
increased throughput volumes from the Transportation Segment and
north Louisiana region of the Gathering and Processing Segment.
The increased price levels for NGLs increased our cash flows
from operations, but these increases were matched by cash
outflows from our risk management activities, achieving the cash
stabilizations goals of our risk management policy. The increase
in cash flows from operations was partially offset by an
increase in cash interest paid of $10.4 million, as the
amount of our debt financing significantly increased following
the HM Capital Transaction and in connection with our Regency
Intrastate Enhancement Project.
For further information regarding our risk management portfolio,
please read Quantitative and Qualitative
Disclosures About Market Risk.
For all periods, we used our cash flows from operating
activities together with borrowings under our revolving credit
facility for our working capital requirements, which include
operating expenses, maintenance capital expenditures and
repayment of working capital borrowings. From time to time
during each period, the timing of receipts and disbursements
required us to borrow under our revolving lines of credit. The
maximum amounts of revolving line of credit borrowings
outstanding during the eleven months
70
ended November 30, 2004 and during the year ended
December 31, 2005 were $15.0 million and
$50.0 million, respectively.
Cash Flows Used in Investing Activities. Our cash flows
used in investing activities for the eleven months ended
November 30, 2004 decreased by $38.4 million or
approximately 31% over the seven-month period ended
December 31, 2003. For the year ended December 31,
2005, our cash flows used in investing activities decreased by
$64.5 million compared to the combined year ended
December 31, 2004.
Our investing cash flows in 2003 were $123.2 million,
consisting of $119.5 million invested in our mid-continent
and north Louisiana assets in the acquisition from El Paso
Field Services LP and affiliates and $3.6 million in
capital expenditures.
Items comprising our investing activities during the
eleven-month period ended November 30, 2004 include:
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$67.3 million invested in our west Texas assets acquired
from Duke Energy Field Services in March 2004; |
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$3.5 million invested in gas processing assets acquired
from Cardinal on April 1, 2004; |
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$15.1 million invested in capital expenditures partially
offset by; |
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$1.2 million received in connection with a distribution
from an escrow account relating to the El Paso acquisition. |
For the one month ended December 31, 2004 cash flows used
in investing activities were $129.9 million, consisting of
$127.8 million of cash payments in connection with the
acquisition of Regency Gas LLC by the HM Capital Investors on
December 1, 2004 and $2.1 million invested in capital
expenditures.
Our cash flows used in investing activities for the year ended
December 31, 2005 were $150.2 million, consisting of:
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$151.5 million invested in capital expenditures relating to
our Regency Intrastate Enhancement Project and maintenance
capital expenditures; |
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$5.8 million invested in acquisition expenses that were
paid in February 2005 relating to the acquisition of Regency Gas
Services LLC by the HM Capital Investors partially offset by; |
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$6.0 million of proceeds from the sale of Cardinal assets;
and |
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$1.1 million of proceeds from the sale of NGL line pack. |
Cash Flows Provided by Financing Activities. Our cash
flows provided by financing activities for the eleven months
ended November 30, 2004 decreased by $61.9 million or
approximately 52% from the seven-month period ended
December 31, 2003. For the year ended December 31,
2005, our cash flows provided by financing activities decreased
by $69.3 million or approximately 37% as compared to the
combined year ended December 31, 2004.
Our cash flows in 2003 were $118.2 million, consisting of
$53.8 million of net increases in member equity investments
and $70.0 million in proceeds of borrowings under our
credit agreement, all of which were used to finance the
acquisition of our
mid-continent and north
Louisiana assets. These amounts were offset by principal
repayments of $3.4 million and the payment of debt issuance
costs in the amount of $2.0 million.
Our cash flows provided by financing activities during the
eleven months ended November 30, 2004 were
$56.4 million, consisting of:
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$10.0 million in proceeds from member equity investments to
finance our investment in our west Texas assets; |
71
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$45.4 million in proceeds from borrowings under our credit
agreement, also to finance our investment in our west Texas
assets; |
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$10.5 million of repayments under our credit facilities; |
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|
$13.0 million of borrowings under our revolving credit
facility to finance our investment in our west Texas
assets; and |
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|
|
payment of $1.5 million for debt issuance costs associated
with the establishment of credit facilities. |
For the one-month period ended December 31, 2004, our
financing cash flows consisted of:
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|
|
$250.0 million in proceeds of borrowings under our credit
agreement which was established for our acquisition by the HM
Capital Investors; |
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|
$114.5 million of repayments of principal under credit
agreements terminated as part of the acquisition by the HM
Capital Investors; |
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|
|
payment of $7.5 million for debt issuance costs associated
with the establishment of our credit facilities; and |
|
|
|
$4.5 million in proceeds from member equity investments to
finance a portion of our purchase of crude oil puts. |
In comparison, our net financing cash flows for the year ended
December 31, 2005 were $119.6 million, consisting of:
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|
|
$60.0 million in proceeds of borrowings under the term loan
provisions of our credit facility; |
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|
|
$15.0 million in equity contributions from the HM Capital
Investors; |
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|
$50.0 million in proceeds and repayments of borrowings
under our revolving credit facility; |
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|
|
$3.8 million in debt issuance costs related to amendments
to our credit facility; |
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|
|
$1.6 million in scheduled repayments of borrowings under
our term loan credit facility. |
Capital Requirements
The midstream energy business can be capital intensive,
requiring significant investment for the acquisition or
development of new facilities. We categorize our capital
expenditures as either:
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|
|
Growth capital expenditures, which are made to acquire
additional assets to increase our business, to expand and
upgrade existing systems and facilities or to construct or
acquire similar systems or facilities; or |
|
|
|
Maintenance capital expenditures, which are made to replace
partially or fully depreciated assets, to maintain the existing
operating capacity of our assets and extend their useful lives
or to maintain existing system volumes and related cash flows. |
During the year ended December 31, 2005, our growth capital
expenditures were $162.3 million and our maintenance
capital expenditures were $7.8 million, including non-cash
expenditures in accounts payable. The major portion of our
growth capital expenditures for 2005 was incurred in connection
with our Regency Intrastate Enhancement Project.
Since our inception in 2003, we have made substantial growth
capital expenditures, including those relating to the
acquisition of our north Louisiana assets and mid-continent
assets in 2003, our west Texas assets in 2004, and the
construction of the Regency Intrastate Enhancement Project in
2005. We anticipate that we will continue to make significant
growth capital expenditures. Consequently, our ability to
develop and maintain sources of funds to meet our capital
requirements is critical to our ability to meet our growth
objectives.
72
Our 2006 budget includes $25.1 million of identified
organic growth capital expenditures. These expenditures relate
to several projects, including a dewpoint control conditioning
facility in our north Louisiana region, a gathering system
development project in our
mid-continent region,
an acid gas reinjection well at the Waha gas processing plant
and the remaining expenditures on our Regency Intrastate
Enhancement Project. We expect that these growth capital
expenditures will be funded by borrowings under our credit
facility.
We continually review opportunities for both organic growth
projects and acquisitions that will enhance our financial
performance. Since we will distribute most of our available cash
to our unitholders, we will depend on borrowings under our
credit facility and the incurrence of debt and equity securities
to finance any future growth capital expenditures or
acquisitions.
In January 2005, we initiated the planning, design,
implementation and construction of our Regency Intrastate
Enhancement Project. In July 2005, we amended and restated our
credit facilities, increasing the available term loans to
$309.0 million from $249.0 million, increasing the
available revolving credit to $150.0 million from
$40.0 million and increasing the available credit for the
issuance of letters of credit (which reduces available revolving
credit) to $30.0 million from $20.0 million. We also
negotiated for, and received, an increase in the capital
spending covenant that allowed us to construct the project. The
term loans originally consisted of $260.0 million of first
lien debt and $50.0 million of second lien debt.
Prior to consummation of the additional financing, we repaid the
$10.0 million in outstanding revolving credit loans and at
the consummation we borrowed an additional $25.0 million in
term loans, increasing the outstanding borrowings under our
credit facilities to $274.0 million. We subsequently
borrowed $35.0 million on September 26, 2005 to meet
capital expenditure requirements associated with the Regency
Intrastate Enhancement Project.
On November 30, 2005, we amended our credit facilities
further to consolidate our secured indebtedness under a single
credit facility and to permit the reorganization and operation
of our company as a publicly traded limited partnership.
Second Amended and Restated
Credit Agreement
On November 30, 2005, Regency Gas Services LLC, or RGS, our
wholly owned subsidiary and operating partnership, amended and
restated its $410.0 million first lien credit agreement in
order to increase the facility to $470.0 million and to
increase the availability for letters of credit to
$50.0 million. In addition, RGS has the option to increase
the term loan commitments under the facility on up to four
separate occasions, provided that each such increase must be at
least $5.0 million, all such increases must not exceed
$40.0 million in the aggregate, no default or event of
default shall have occurred or would result due to such
increase, and all other additional conditions for the increase
of term loan commitments set forth in the facility have been met.
As of December 31, 2005, the facility consisted of
$258.4 million of outstanding term loans,
$50.0 million of term loan commitments and
$160.0 million of revolving loan commitments. RGS
obligations under the facility are secured by substantially all
of our assets. The revolving loans under the facility will
mature on December 1, 2009, and the term loans thereunder
will mature on June 1, 2010.
Interest on borrowings under the second amended and restated
credit facility will be calculated, at the option of RGS, at
either (a) a base rate plus an applicable margin of
1.25% per annum or (b) an adjusted LIBOR rate plus an
applicable margin of 2.25% per annum. RGS shall pay
(i) a commitment fee equal to 0.50% per annum of the
unused portion of the revolving loan commitments, (ii) a
participation fee for each revolving lender participating in
letters of credit equal to 2.25% per annum of the average
daily amount of such lenders letter of credit exposure,
and (iii) a fronting fee to the issuing bank of letters of
credit equal to 0.125% per annum of the average daily
amount of the letter of credit exposure.
In addition, RGS amended and restated its $50.0 million
second lien credit agreement on November 30, 2005; however,
such second lien credit facility was repaid in full through a
draw down of
73
the $50.0 million of term loan commitments under the
facility described above and terminated on December 2, 2005.
Third Amended and Restated
Credit Agreement
Upon the consummation of our initial public offering, the second
amended and restated credit facility was amended and restated
automatically, and the third amended and restated credit
facility became effective. The revolving loan commitments, the
ability to increase its term loan commitments, and the maturity
dates under the third amended and restated credit facility are
the same as they were under the second amended and restated
credit facility and RGS obligations are secured by
substantially all of our assets.
The Third Amended and Restated Credit Facility contains
financial covenants requiring us to maintain total leverage and
interest coverage ratios within certain thresholds.
The Third Amended and Restated Credit Facility restricts
RGS ability to pay dividends, but it authorizes RGS to
reimburse us for expenses, and to pay dividends to us, pursuant
to our Amended and Restated Agreement of Limited Partnership (so
long as no default or event of default has occurred or is
continuing). The Third Amended and Restated Credit Facility also
contains various covenants that limit (subject to certain
exceptions and negotiated baskets), among other things,
RGS ability (but not our ability) to:
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incur indebtedness; |
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grant liens; |
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enter into sale and leaseback transactions; |
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make certain investments, loans and advances; |
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dissolve or enter into a merger or consolidation; |
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enter into asset sales or make acquisitions; |
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enter into transactions with affiliates; |
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prepay other indebtedness or amend organizational documents or
transaction documents (as defined in the third amended and
restated credit facility); |
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issue capital stock or create subsidiaries; or |
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engage in any business other than those businesses in which it
was engaged at the time of the effectiveness of the third
amended and restated credit facility or reasonable extensions
thereof. |
At December 31, 2005, RGS had outstanding letters of credit
totaling $10.7 million related to our risk management
activities. The total fees for letters of credit accrue at an
annual rate of 2.38%, which is applied to the daily amount of
letters of credit exposure. As of March 22, 2006, we had
$0.3 million outstanding letters of credit related to our
risk management activities.
Off-Balance Sheet Transactions and Guarantees. We have no
off-balance sheet transactions or obligations.
Credit Ratings and Debt Covenants. The current credit
ratings on our debt under our credit facility are B1 with a
negative outlook by Moodys Investor Service and B+ with a
stable outlook by Standard and Poors. At December 31,
2005, we were in compliance with the covenants of the credit
facilities. See Note 3 to the accompanying financial
statements for additional information on the credit facilities.
Total Contractual Cash Obligations. The following table
summarizes our total contractual cash obligations as of
December 31, 2005. The $308.4 million of term loans
outstanding on December 31, 2005 is scheduled for interest
rate resets on three-month intervals.
74
Interest rates were reset on December 31, 2005.
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Payments Due by Period | |
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| |
Contractual Obligations |
|
Total | |
|
2006 | |
|
2007-2008 | |
|
2009-2010 | |
|
Thereafter | |
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| |
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| |
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| |
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| |
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| |
Long-term Debt (including interest)(1)
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$ |
483.5 |
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|
$ |
24.6 |
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|
$ |
51.5 |
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$ |
407.4 |
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|
$ |
- |
|
Operating Leases
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1.5 |
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0.5 |
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0.9 |
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0.1 |
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- |
|
Purchase Obligations(2)(3)(4)
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3.8 |
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3.8 |
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- |
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- |
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- |
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Total Contractual Obligations
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$ |
488.8 |
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$ |
28.9 |
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$ |
52.4 |
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$ |
407.5 |
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$ |
- |
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(1) |
Assumes a current LIBOR interest rate of 4.53% plus the
applicable margin, which remains constant in all periods. The
contractual obligations also include the effect of interest rate
hedges on a notional amount of $200 million through March
2009. |
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(2) |
Represents the purchase obligation for a pipeline project in
north Louisiana. |
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(3) |
Excludes physical and financial purchases of natural gas, NGLs,
and other energy commodities due to the nature of both the price
and volume components of such purchases, which vary on a daily
or monthly basis. Additionally, we do not have contractual
commitments for fixed price and/or fixed quantities of any
material amount. |
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(4) |
These amounts do not include an estimated $4.5 million and
$1.5 million that we expect to spend in 2006 and 2007,
respectively, for the construction of an acid gas reinjection
well at our Waha gas processing plant. |
The table above does not include our existing obligations as of
December 31, 2005 under our ten year financial advisory and
monitoring and oversight agreements between us and an affiliate
of HM Capital to pay certain management fees and transaction
advisory fees to the affiliate of HM Capital. We paid
$9.0 million of the proceeds from our initial public
offering to the affiliate of HM Capital to terminate these
agreements. As a result, we do not have any continuing
obligation to make payments under these agreements.
Recent Accounting Pronouncements
On October 6, 2005, the Financial Accounting Standards
Board (the FASB) issued Staff Position
FAS 13-1
concerning the accounting for rental expenses associated with
operating leases for land or buildings that are incurred during
a construction period. We have considered how this might apply
to our payment for
rights-of-way
associated with the construction of pipelines, and we do not
anticipate any changes to our accounting practices or impacts on
our results of operations or financial condition in light of the
recently issued Staff Position
FAS 13-1.
In May 2005, the FASB issued Statement of Financial Accounting
Standard (SFAS) No. 154, Accounting
Changes and Error Corrections a replacement of APB
Opinion No. 20 and FASB Statement No. 3. This
accounting standard is effective for fiscal years beginning
after December 15, 2005. We do not believe this accounting
standard will have a material adverse effect on our results of
operations, financial condition or cash flows.
We account for our asset retirement obligations in accordance
with Statement of Financial Standards (SFAS) No. 143,
Accounting for Asset Retirement Obligations and
FIN 47 Accounting for Conditional Asset Retirement
Obligations. These accounting standards require us to
recognize on the balance sheet the net present value of any
legally binding obligation to remove or remediate the physical
assets that we retire from service, as well as any similar
obligations for which the timing and/or method of settlement are
conditional on a future event that may or may not be within our
control. While we are obligated under contractual agreements to
remove certain facilities upon their retirement, we are unable
to reasonably determine the fair value of any asset retirement
obligations as of December 31, 2005 and 2004
75
because the settlement dates, or ranges thereof, were
indeterminable and could range up to ninety-six years, and the
undiscounted amounts are immaterial. An asset retirement
obligation will be recorded in the periods wherein we can
reasonably determine the settlement dates.
In December 2004, the FASB issued SFAS No. 123
(revised 2004), Share-based Payment, which is a
revision of SFAS No. 123, Accounting for
Stock-Based Compensation. This statement establishes
standards for the accounting for transactions in which an entity
exchanges its equity instruments for goods or services.
SFAS No. 123 (revised 2004) is effective for the first
interim or annual reporting period that begins after
June 15, 2005. We adopted SFAS 123(R)
Share-Based Payment in the first quarter of 2006
which had no impact to us as no LTIP awards were outstanding
during 2005.
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ITEM 7A. |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Risk and Accounting
Policies
We are exposed to market risks associated with commodity prices,
counterparty credit and interest rates. Our management has
established comprehensive risk management policies and
procedures to monitor and manage these market risks. Our
Managing GP is responsible for delegation of transaction
authority levels, and the Risk Management Committee of our
general partner is responsible for the overall approval of
market risk management policies. The Risk Management Committee
is composed of directors (including, on an ex officio basis, our
chief executive officer) who receive regular briefings on
positions and exposures, credit exposures and overall risk
management in the context of market activities. The Risk
Management Committee is responsible for the overall management
of credit risk and commodity price risk, including monitoring
exposure limits.
See Critical Accounting Policies and
Estimates Risk Management Activities for
further discussion of the accounting for derivative contracts.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the
prices of natural gas, NGLs and other commodities as a result of
our gathering, processing and marketing activities, which in the
aggregate produce a naturally long position in both natural gas
and NGLs. We attempt to mitigate commodity price risk exposure
by matching pricing terms between our purchases and sales of
commodities. To the extent that we market commodities in which
pricing terms cannot be matched and there is a substantial risk
of price exposure, we attempt to use financial hedges to
mitigate the risk. It is our policy not to take any speculative
marketing positions.
In some cases, we may not be able to match pricing terms or to
cover our risk to price exposure with financial hedges and may
be exposed to commodity price risk. For example, under many of
our contracts in place in west Texas, we are obligated to
purchase gas at a price derived from published first of the
month, or FOM, index prices. We then sell the gas at the same
index price. In November 2005, in a highly unusual circumstance,
there were very few baseload FOM index sales reported and we
were unable to find buyers at these prices. The ensuing daily
cash price was substantially less than the posted FOM index. We
were able to convince most of the producers of this natural gas
that the index price was an anomaly and that the purchase price
and the sale price should be matched. In order to prevent this
from occurring again, we are in the process of amending these
contracts to provide for a closer matching of the pricing of
purchases and sales in these circumstances.
Both our profitability and our cash flow are affected by
volatility in prevailing natural gas and NGL prices. Natural gas
and NGL prices are impacted by changes in the supply and demand
for NGLs and natural gas, as well as market uncertainty.
Historically, changes in the prices of heavy NGLs, such as
natural gasoline, have generally correlated with changes in the
price of crude oil. For a discussion of the volatility of
natural gas and NGL prices, please read Risk
Factors. Adverse effects on our cash flow from reductions
in natural gas and NGL product prices could adversely affect our
ability to make distributions to unitholders. We manage this
commodity price exposure through an integrated strategy that
76
includes management of our contract portfolio, matching sales
prices of commodities with purchases, optimization of our
portfolio by monitoring basis and other price differentials in
our areas of operations, and the use of derivative contracts.
Our overall expected direct exposure to movements in natural gas
prices is minimal as a result of natural hedges inherent in our
contract portfolio. Natural gas prices, however, can also affect
our profitability indirectly by influencing the level of
drilling activity and related opportunities for our service. We
are a net seller of NGLs, and as such our financial results are
exposed to fluctuations in NGLs pricing. We have executed swap
contracts settled against ethane, propane, butane and natural
gasoline market prices, supplemented with crude oil put options.
As a result, we have hedged approximately 95% of our expected
exposure to NGL prices in 2006, approximately 75% in 2007 and
approximately 50% in 2008. We continually monitor our hedging
and contract portfolio and expect to continue to adjust our
hedge position as conditions warrant.
The following table sets forth certain information regarding our
NGL swaps outstanding at December 31, 2005:
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Notional | |
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Volume | |
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We | |
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Fair Value | |
Period |
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Commodity | |
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(MBbls) | |
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We Pay | |
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Receive ($/gallon) | |
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(Thousands) | |
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Jan. 2006 - Dec 2007
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Ethane |
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929 |
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Index |
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$ |
0.55 to $0.58 |
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$ |
(4,529 |
) |
Jan. 2006 - Dec 2007
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Propane |
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811 |
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Index |
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$ |
0.66 to $0.825 |
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(7,937 |
) |
Jan. 2006 - Dec 2007
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Butane |
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427 |
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Index |
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$ |
1.02 to $1.085 |
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(3,076 |
) |
Jan. 2006 - Dec 2007
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Natural |
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Gasoline |
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164 |
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Index |
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$ |
1.22 to $1.26 |
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(665 |
) |
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Total Fair Value
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$ |
(16,207 |
) |
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The following table sets forth certain information regarding our
crude oil puts:
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Notional | |
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Volume | |
|
Strike | |
|
Fair Value | |
Period |
|
Commodity | |
|
(MBbls) | |
|
Prices ($/Bbl) | |
|
(Thousands) | |
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| |
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| |
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| |
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| |
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NYMEX West Texas |
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Jan. 2006 - Dec 2007
|
|
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Intermediate Crude |
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|
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2,438 |
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$ |
30.00 to $36.50 |
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|
$ |
575 |
|
The table below summarizes the changes in commodity and interest
rate risk management assets and liabilities for the year ended
December 31, 2005.
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$ in millions | |
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| |
Net Risk Management Asset at December 31, 2004
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$ |
9.0 |
|
Settlements of positions included in beginning balance
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2.7 |
|
Unrealized mark-to-market valuations of positions held at
June 30, 2005
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(15.3 |
) |
Other*
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(0.7 |
) |
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Balance of Risk Management Assets (Liability) at June 30,
2005
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|
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(4.3 |
) |
Settlements of positions included in June 30, 2005 balance
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|
2.7 |
|
Unrealized mark-to-market valuations of positions held at
December 31, 2005
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|
0.6 |
|
Effective portion of hedges included within Other Comprehensive
Income
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(11.0 |
) |
Other*
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(1.2 |
) |
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|
Balance of Net Risk Management Liability at December 31,
2005
|
|
$ |
(13.2 |
) |
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* |
The amounts reported as other represents the
expiration of options for which premiums were paid in prior
periods. |
77
Credit Risk
Our purchase and resale of natural gas exposes us to credit
risk, as the margin on any sale is generally a very small
percentage of the total sale price. Therefore a credit loss can
be very large relative to our overall profitability. We attempt
to ensure that we issue credit only to credit-worthy
counterparties and that in appropriate circumstances any such
extension of credit is backed by adequate collateral such as a
letter of credit or parental guarantees.
In January 2005, one of our customers filed for Chapter 11
reorganization under U.S. bankruptcy law. The customer
operates a merchant power plant, for which we provide firm
transportation of natural gas. Under the contract with the
customer, the customer is obligated to make fixed payments in
the amount of approximately $3.2 million per year. The
contract expires in mid-2012 and was secured by a
$10.0 million letter of credit. In December 2005, in
connection with other contract negotiations, the letter of
credit was reduced to $3.3 million and we accepted a
Parental Guarantee in the amount of $6.7 million. The
customer has accepted the firm transportation contract in
bankruptcy. The customers plan of reorganization has been
confirmed by the bankruptcy court and the customer has since
emerged from bankruptcy protection. At the date of this Annual
Report on
Form 10-K, the
customer was current in its payment obligations.
Interest Rate Risk
The credit markets recently have experienced
50-year record lows in
interest rates. As the overall economy strengthens, it is likely
that monetary policy will tighten further, resulting in higher
interest rates to counter possible inflation. Interest rates on
future credit facilities and debt offerings could be higher than
current levels, causing our financing costs to increase
accordingly.
We are exposed to variable interest rate risk as a result of
borrowings under our existing credit agreement. To minimize this
risk, we entered into an interest rate swap in January 2005 for
a notional $125 million of the initial $250 million of
term loans which effectively fixed our interest rate at 6.47% on
this notional amount for a period of two years. When we
amended and restated our credit facility in July 2005, we
entered into two additional interest rate swaps. The first had a
notional amount of $75.0 million, bringing the total
notional amount to $200 million with a March 2007 maturity.
As a result, we converted $200 million of $309 million
of term loans, or approximately two-thirds, of our variable
interest rate debt to fixed interest rate debt through March
2007 at a fixed rate of 6.70%. The second interest rate swap had
a notional amount of $200.0 million that is effective from
April 2007 through March 2009, and effectively fixed our
interest rate at 7.36% on this amount for two years. Our
variable interest rate debt bears interest at variable rates
based on LIBOR or the banks prime rate. The fair value of
our interest rate swaps as of December 31, 2005 was
$2.5 million.
On November 30, 2005, we amended and restated our credit
agreement. This amendment reduced the applicable margin on our
first lien debt by 0.5%, reducing our effective fixed interest
rate to 6.20% through March 2007 and 6.86% from April 2007
through March 2009 on a notional amount of $200 million.
ITEM 8. Financial
Statements and Supplementary Data.
The financial statements set forth starting on page F-1 of this
report are incorporated herein by reference.
ITEM 9. Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
ITEM 9A. Controls
and Procedures.
We maintain controls and procedures designed to ensure that
information required to be disclosed in the reports that we file
or submit under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods
specified in the rules and forms of the SEC. An
78
evaluation was performed under the supervision and with the
participation of our management, including the Chief Executive
Officer and Chief Financial Officer of our Managing GP, of the
effectiveness of the design and operation of our disclosure
controls and procedures (as such terms are defined in
Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based on
that evaluation, management, including the Chief Executive
Officer and Chief Financial Officer of our Managing GP,
concluded that our disclosure controls and procedures were
effective as of December 31, 2005 to provide reasonable
assurance that information required to be disclosed by us in the
reports that we file or submit under the Exchange Act are
recorded, processed, summarized and reported, within the time
periods specified in the SECs rules and forms.
Our management does not expect that our disclosure controls and
procedures will prevent all errors. The design of a control
system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered
relative to their costs. Because of the inherent limitations in
all control systems, no evaluation of controls can provide
absolute assurance that all disclosure control issues within the
Partnership have been detected. These inherent limitations
include the realties that judgments in decision-making can be
faulty and that breakdowns can occur because of simple errors or
mistakes. The design of any system of controls also is based in
part on certain assumptions about the likelihood of future
events. Therefore, a control system, no matter how well
conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system
are met. Our disclosure controls and procedures are designed to
provide such reasonable assurances of achieving our desired
control objectives and the Chief Executive Officer and the Chief
Financial Officer of our Managing GP have concluded, as of
December 31, 2005, that our disclosure controls and
procedures are effective in achieving that level of reasonable
assurance.
Management has acknowledged that it is responsible for
establishing and maintaining a system of disclosure controls and
procedures for the Partnership. We have designed those
disclosure controls and procedures to ensure that material
information relating to the Partnership, including its
consolidated subsidiaries, is made known to management by others
within those entities. We have evaluated the effectiveness of
our disclosure controls and procedures, as of the end of fiscal
year 2005, and concluded that they are effective.
The Partnership is not yet subject to Section 404 of the
Sarbanes-Oxley Act which, when applicable, will require the
Partnership to include Managements Annual Report on
Internal Control Over Financial Reporting and an Attestation
Report of Independent Registered Public Accounting Firms in its
Annual Report on
Form 10-K. Under
the applicable rules of the Securities and Exchange Commission,
or SEC, Section 404 will not apply to the Partnership until
the due date of our annual report for the year ending
December 31, 2007.
In anticipation of becoming subject to the provisions of
Section 404 of the Sarbanes-Oxley Act of 2002, we initiated
in early 2005 a program of documentation, implementation and
testing of internal control over financial reporting. This
program will continue through this year and next, culminating
with our initial Section 404 certification and attestation
in early 2008. While our independent registered public
accounting firm has not attested to or reported on our internal
control over financial reporting as of the end of fiscal 2005,
we have evaluated the effectiveness of our system of internal
control over financial reporting, as well as changes therein, in
compliance with
Rule 13a-15 of the
SECs rules under the Securities Exchange Act and have
filed the certifications with this annual report required by
Rule 13a-14.
In the course of that evaluation, we found no fraud, whether or
not material, that involved management or other employees who
have a significant role in our internal control over financial
reporting and, except to the extent set forth below, no material
weaknesses. To the extent that we discovered any matter in the
design or operation of our system of internal control over
financial reporting that might be considered to be a significant
deficiency or a material weakness, whether or not considered
reasonably likely to adversely affect our ability to record,
process, summarize and report financial information, we reported
that matter to our independent registered public accounting firm
and to the audit committee of our board of directors.
79
In the course of preparation of our financial statements for the
year ended December 31, 2005, an accounting error was
discovered relating to the reclassification of losses from other
comprehensive income to earnings which could have understated
net income (loss) and overstated other comprehensive income
(loss) during the year ended 2005.
The financial statements included herein reflect the correct
reclassification of net losses from other comprehensive income
and no prior periods were materially misstated. However, the
error may have been the result of a material weakness in our
internal controls over financial reporting. As a result,
management has instituted a change in our internal control over
financial reporting designed to avoid any repetition of the
error. That change in our internal control over financial
reporting was a requirement to conduct a thorough reconciliation
of the components of other comprehensive income (loss) on a
monthly basis. It is reasonably likely that this change will
materially affect our internal control over financial reporting.
ITEM 9B. Other
Information.
None.
Part III
ITEM 10. Directors
and Executive Officers of the Registrant.
Partnership Management
Regency GP (the General Partner) is our General
Partner. The General Partner manages and directs all of our
activities. The activities of the General Partner are managed
and directed by its general partner, Regency GP LLC (the
Managing GP). Our officers and directors are
officers and directors of the Managing GP. The owners of the
Managing GP may appoint up to ten persons to serve on the Board
of Directors of the Managing GP. Although there is no
requirement that he do so, the President and Chief Executive
Officer of the Managing GP is currently a director of the
Managing GP and serves as Chairman of the Board of Directors.
Commencing in December 2005 prior to the initial public offering
of the Partnership, our Board of Directors was comprised of its
Chairman (the President and Chief Executive Officer of the
Managing GP), three persons who qualify as
independent under the NASDs standards for
audit committee members, and six persons who were either
appointed by the sole member of the Managing GP or elected by
the other members of the Board of Directors.
Corporate Governance
The Board has adopted Corporate Governance Guidelines to assist
it in the exercise of its responsibilities to provide effective
governance over our affairs for the benefit of our unitholders.
In addition, we have adopted a Code of Business Conduct, which
sets forth legal and ethical standards of conduct for all our
officers, directors and employees. Specific provisions are
applicable to the principal executive officer, principal
financial officer, principal accounting officer and controller,
or those persons performing similar functions, of our Managing
GP. The Corporate Governance Guidelines, the Code of Business
Conduct and the charters of our audit, compensation, nominating
and executive committees are available on our website at
www.regencyenergy.com and in print to any Unitholder who
requests any of them. Amendments to, or waivers from, the Code
of Business Conduct will also be available on our website and
reported as may be required under SEC rules; however, any
technical, administrative or other non-substantive amendments to
the Code of Business Conduct may not be posted. Please note that
the preceding Internet address is for information purposes only
and is not intended to be a hyperlink. Accordingly, no
information found or provided at that Internet addresses or at
our website in general is intended or deemed to be incorporated
by reference herein.
80
Conflicts Committee
The Board of Directors appoints members of the Board to serve on
the Conflicts Committee with the authority to review specific
matters for which the Board of Directors believes there may be a
conflict of interest in order to determine if the resolution of
such conflict proposed by the Managing GP is fair and reasonable
to the Partnership and its Common Unitholders. Any matters
approved by the Conflicts Committee will be conclusively deemed
to be fair and reasonable to the Partnership, approved by all
partners of the Partnership and not a breach by the General
Partner, the Managing GP or its Board of Directors of any duties
they may owe the Partnership or the Common Unitholders. The
members of the Conflicts Committee are A. Dean Fuller
(Chairman), Robert W. Shower and J. Otis Winters. The Conflicts
Committee has not yet held a meeting.
Audit Committee
The Board of Directors has established an Audit Committee in
accordance with Section 3(a)(58)(A) of the Exchange Act.
The Board of Directors has appointed five directors as members
of the Audit Committee, including three individuals who are
independent under the NASDs standards for audit committee
members to serve on its Audit Committee. In addition, the Board
has determined that at least one member of the Audit Committee
(Robert W. Shower) has such accounting or related financial
management expertise sufficient to qualify such person as the
audit committee financial expert in accordance with
Item 401 of
Regulation S-K. A
description of the qualifications of Mr. Shower may be
found in this Item 10 under Directors and Executive
Officers of the General Partner.
The Audit Committee meets on a regularly scheduled basis with
our independent accountants at least four times each year and is
available to meet at their request. The Audit Committee has the
authority and responsibility to review our external financial
reporting, review our procedures for internal auditing and the
adequacy of our internal accounting controls, consider the
qualifications and independence of our independent accountants,
engage and resolve disputes with our independent accountants,
including the letter of engagement and statement of fees
relating to the scope of the annual audit work and special audit
work which may be recommended or required by the independent
accountants, and to engage the services of any other advisors
and accountants as the Audit Committee deems advisable. The
Audit Committee reviews and discusses the audited financial
statements with management, discusses with our independent
auditors matters required to be discussed by SAS 61
(Communications with Audit Committees), and makes
recommendations to the Board of Directors relating to our
audited financial statements. The Audit Committee is authorized
to recommend periodically to the Board of Directors any changes
or modifications to its charter that the Audit Committee
believes may be required. The Board of Directors adopts the
Charter for the Audit Committee. Since December 2005, the Audit
Committee has been composed of Robert W. Shower (Chairman), A.
Dean Fuller and J. Otis Winters, all of whom have been
determined by the Board of Directors to be independent within
the requirements of the applicable NASD rules, and J. Edward
Herring and Robert D. Kincaid.
Compensation and Nominating Committees
Although we are not required under NASD rules to appoint a
Compensation Committee or a Nominating/ Corporate Governance
Committee because we are a limited partnership, the Board of
Directors of the Managing GP has established a Compensation
Committee to establish standards and make recommendations
concerning the compensation of our officers and directors. In
addition, the Compensation Committee determines and establishes
the standards for any awards to our employees and officers,
including the performance standards or other restrictions
pertaining to the vesting of any such awards, under our existing
Long Term Incentive Plan, as well as any other equity
compensation plans adopted by our Common Unitholders. The
Compensation Committee is composed of Jason H. Downie
(Chairman), Joe Colonnetta and J. Otis Winters, none of whom is
an officer or employee of the Managing GP or the Partnership.
81
The Board of Directors has also appointed a Nominating Committee
to assist the Board and the member of our Managing GP (the
Member) by identifying and recommending to the Board
of Directors individuals qualified to become Board members, to
recommend to the Board director nominees for each committee of
the Board and to advise the Board about and recommend to the
Board appropriate corporate governance practices. The Nominating
Committee is composed of Joe Colonnetta (Chairman), Jason H.
Downie, J. Edward Herring and Robert W. Shower. Matters relating
to the election of Directors or to Corporate Governance are
addressed to and determined by the full Board of Directors.
Code of Business Conduct
The Board of Directors has adopted a Code of Business Conduct
applicable to our officers, directors and employees. Specific
provisions are applicable to the principal executive officer,
principal financial officer, principal accounting officer and
controller, or those persons performing similar functions, of
our Managing GP. The Code of Business Conduct is available on
our website at www.regencygas.com and in print to any Unitholder
who requests it. Amendments to, or waivers from, the Code of
Business Conduct will also be available on our website and
reported as may be required under SEC rules; however, any
technical, administrative or other non-substantive amendments to
the Code of Business Conduct may not be posted. Please note that
the preceding Internet address is for information purposes only
and is not intended to be a hyperlink. Accordingly, no
information found or provided at that Internet addresses or at
our website in general is intended or deemed to be incorporated
by reference herein.
Meetings of Non-management Directors and Communications with
Directors
Our non-management directors (as defined by the NASD rules) are
required to meet in executive session at each regularly
scheduled Board meeting. The position of the presiding director
at these meetings is required to be rotated among the
independent directors. J. Otis Winters is the presiding director
for the meetings of the non-management directors to be held
prior to the 2007 Annual Meeting of the Board. Interested
parties may make their concerns known to the non-management
directors directly and anonymously by writing to the Chairman of
the Audit Committee, Regency GP LLC, 1700 Pacific Avenue,
Suite 2900, Dallas, Texas 75201.
If the group of the non-management directors includes directors
who have not been determined by the Nominating Committee to be
independent directors, then, in addition to the meetings of the
non-management directors, the independent directors are required
to meet in executive session at least once a year. The presiding
director shall be chosen by the group of independent directors
to preside over and to be responsible for preparing an agenda
for the meetings of the independent directors if such meetings
are necessary.
82
Directors and Executive Officers
The following table shows information regarding the current
directors and executive officers of Regency GP LLC. Directors
are elected for one-year terms.
|
|
|
|
|
|
|
Name |
|
Age | |
|
Position with Regency GP LLC |
|
|
| |
|
|
James W. Hunt(1)(4)(5)
|
|
|
62 |
|
|
Chairman of the Board, President and Chief Executive Officer |
Michael L. Williams
|
|
|
46 |
|
|
Executive Vice President and Chief Operating Officer |
Stephen L. Arata
|
|
|
40 |
|
|
Executive Vice President and Chief Financial Officer |
William E. Joor III
|
|
|
66 |
|
|
Executive Vice President, Chief Legal and Administrative Officer
and Secretary |
Charles M. Davis, Jr.(7)
|
|
|
44 |
|
|
Senior Vice-President-Corporate Development |
Durell J. Johnson
|
|
|
43 |
|
|
Vice President, Operations and Engineering |
Lawrence B. Connors
|
|
|
55 |
|
|
Vice President, Finance and Chief Accounting Officer |
Alvin Suggs
|
|
|
53 |
|
|
Vice President and General Counsel |
Joe Colonnetta(1)(4)(6)
|
|
|
44 |
|
|
Director |
Jason H. Downie(1)(4)(5)(6)
|
|
|
35 |
|
|
Director |
A. Dean Fuller(2)(3)
|
|
|
58 |
|
|
Director |
Jack D. Furst
|
|
|
47 |
|
|
Director |
J. Edward Herring(2)(6)
|
|
|
35 |
|
|
Director |
Robert D. Kincaid(2)
|
|
|
45 |
|
|
Director |
Gary W. Luce(5)
|
|
|
45 |
|
|
Director |
Robert W. Shower(2)(3)(6)
|
|
|
68 |
|
|
Director |
J. Otis Winters(2)(3)(4)
|
|
|
73 |
|
|
Director |
|
|
(1) |
Member of the Executive Committee. Mr. Colonnetta is
chairman of this committee. |
(2) |
Member of the Audit Committee. Mr. Shower is chairman of
this committee. |
(3) |
Member of Conflicts Committee. Mr. Fuller is chairman of
this committee. |
(4) |
Member of Compensation Committee. Mr. Downie is chairman of
this committee. Mr. Hunt is an ex-officio member. |
(5) |
Member of Risk Management Committee. Mr. Luce is chairman
of this committee. Mr. Hunt is an ex-officio member. |
(6) |
Member of Nominating Committee. Mr. Colonnetta is chairman
of this committee. |
(7) |
Mr. Davis was elected an officer on March 21, 2006 and
commenced employment in March 2006. |
James W. Hunt was elected Chairman of the Board of Directors of
Regency GP LLC and Regency Gas Services in November 2005.
Mr. Hunt has served as President and Chief Executive
Officer of Regency GP LLC from September 2005 to present.
Mr. Hunt has, since his election effective December 1,
2004, served as President, Chief Executive Officer and Director
of Regency Gas Services LLC. From 1978 until January 1981,
Mr. Hunt served as President and Chief Executive Officer of
Diamond M Company, a major offshore drilling company and the
predecessor of Diamond Offshore Company. From 1981 through 1987,
he served as Chairman and Chief Executive Officer of Cenergy
Corporation, a NYSE listed oil and gas exploration, production
and pipeline company. During the period from 1987 to 1989,
Mr. Hunt was an independent financial consultant. From 1989
until December 2004, Mr. Hunt was engaged in energy
investment banking, three years as head of the Houston office of
Lehman Brothers Incorporated and most recently as head of the
U.S. Energy Group of UBS Securities LLC. Mr. Hunt is
an attorney and member of the State Bar of Texas.
83
Michael L. Williams, P.E., was elected Executive Vice President
and Chief Operating Officer of Regency GP LLC in September 2005.
From December 2004 to the present, Mr. Williams served as
Executive Vice President and Chief Operating Officer of Regency
Gas Services LLC. Mr. Williams served as Vice President of
Engineering and Operations from October 2002 through September
2004 heading up operations and engineering at Energy Transfer
Partners, L.P. Mr. Williams also served as Vice President
of Engineering and Operations for Aquila Inc. from 2000 through
September 2002 where he was responsible for the Operation and
Engineering of Aquilas gas gathering, processing,
fractionation, and storage assets.
Stephen L. Arata was elected Executive Vice President and Chief
Financial Officer of Regency GP LLC in September 2005. From June
2005 to the present, Mr. Arata served as Executive Vice
President and Chief Financial Officer of Regency Gas Services
LLC. From September 1996 to June 2005, Mr. Arata worked for
UBS Investment Bank, covering the power and pipeline sectors; he
was Executive Director from 2000 through June 2005. Prior to
UBS, Mr. Arata worked for Deloitte Consulting, focusing on
the energy sector.
William E. Joor III was elected Executive Vice President,
Chief Legal and Administrative Officer and Secretary of Regency
GP LLC in September 2005. Mr. Joor has, since his election
effective January 1, 2005, served as Executive Vice
President, Chief Legal and Administrative Officer and Secretary
of Regency Gas Services LLC. From May 1966 through December
1973, Mr. Joor was associated with, and from then until
December 31, 2004 was a partner of, Vinson &
Elkins LLP. Mr. Joors area of specialization was the
law of corporate finance and mergers and acquisitions with
particular emphasis in the energy sector.
Charles M. Davis, Jr. was elected Senior Vice
President Corporate Development for Regency Energy
Partners in March 2006. From September 2004 to February 2005,
Mr. Davis was Managing Director and Head of Mergers and
Acquisitions for Challenger Capital Group Ltd. From July 2002
until September 2004, Mr. Davis was a Managing Director in
the Energy and Power Group of UBS Investment Bank. From March
1992 until August 2002, Mr. Davis was a Managing Director
in the Global Energy and Power Group of Merrill Lynch. Prior to
Merrill, Mr. Davis worked in the Energy Groups of The First
Boston Corporation and McKinsey & Co. Mr. Davis
has over 20 years experience with Mergers and Acquisitions
as well as financing in the pipeline industry.
Durell J. Johnson, P.E., was elected Vice President of
Operations and Engineering of Regency GP LLC in September 2005.
From December 2004 to the present, Mr. Johnson served as
Vice President of Operations and Engineering of Regency Gas
Services LLC. Mr. Johnson was Director of Engineering for
Energy Transfer Partners, L.P. from October 2003 through October
2004 providing engineering support for all of Energy
Transfers midstream operations. Mr. Johnson was Vice
President of engineering for Garrison LTD. from October 2002
until October 2003 where he was responsible for drilling and
facilities operations. Mr. Johnson was Manager of
Engineering and Construction at Aquila Inc. from 1999 until
October 2002. Mr. Johnson has 20 years of diversified
experience in the natural gas industry.
Lawrence B. Connors was elected Vice President of Finance and
Chief Accounting Officer of Regency GP LLC in September 2005.
From December 2004 to the present, Mr. Connors served as
Vice President, Finance and Chief Accounting Officer of Regency
Gas Services LLC. From June 2003 through November 2004,
Mr. Connors served as Controller of Regency Gas Services
LLC. From August 2000 through November 2001, Mr. Connors
was an independent accounting and financial consultant. From
2001 through May 2003 Mr. Connors was a Registered
Representative with Foster Financial Group. From 1996 through
July 2000, Mr. Connors was the Controller and Chief
Accounting Officer of Central and South West Corporation, or
CSW; he had managerial responsibilities at three CSW operating
companies and CSW Services. Prior to his employment at CSW, he
was with Arthur Andersen working with energy and health care
audit clients. Mr. Connors is a Certified Public Accountant.
Alvin Suggs was elected Vice President and General Counsel of
Regency GP LLC in September 2005. From June 2005 to the present,
Mr. Suggs served as Vice President and General Counsel of
Regency Gas Services LLC. From June 2003 to June 2005,
Mr. Suggs engaged in the private practice of law
representing clients in the energy sector, first as a sole
practitioner and, after June 2004, with
84
Thompson & Knight, LLP. Mr. Suggs served as Vice
President and Associate General Counsel with El Paso Energy
Corporation and General Counsel of El Paso Field Services,
L.P. from September 1999 through June 2003. Mr. Suggs
served as Senior Counsel to El Paso Field Services, L.P.
and El Paso Energy Marketing, L.P. from September 1997 to
September 1999, and from 1987 to 1999 he served Texas
Oil & Gas Corp., American Oil and Gas Corporation and
KN Energy, Inc. in various capacities from Counsel to
Assistant General Counsel. Prior to that service, Mr. Suggs
was in private practice of law for five years, and also served
as Assistant District Attorney for the Fifth Circuit Court
District in Mississippi in 1978.
Joe Colonnetta was elected to the Board of Directors of Regency
GP LLC in September 2005 and served as Chairman of the Board of
Directors until November 2005. From December 2004 to the
present, Mr. Colonnetta has served as a director of Regency
Gas Services LLC, including service as Chairman of the Board
until November 2005. Mr. Colonnetta is a partner at HM
Capital. Mr. Colonnetta joined HM Capital in 1998.
Prior to joining HM Capital, Mr. Colonnetta was a partner
with Metropoulos and Co., an affiliate of HM Capital.
Mr. Colonnetta is also Chairman of the Board of Directors
of TexStar Field Services and BlackBrush Oil & Gas, and
he serves on the Board of Directors of Swift & Company.
Jason H. Downie was elected to the Board of Directors of Regency
GP LLC in September 2005. From December 2004 to the present,
Mr. Downie has served as a director of Regency Gas Services
LLC. Mr. Downie is a partner of HM Capital and has been
with the firm since September 2000. From June 1999 to August
2000, Mr. Downie was an associate at Rice Sangalis
Toole & Wilson, a mezzanine private equity firm based
in Houston, Texas, and from June 1992 through June 1997,
Mr. Downie served in various capacities with Donaldson,
Lufkin & Jenrette in New York, lastly as an Associate
Position Trader in their Capital Markets Group. From June 1997
to June 1999, Mr. Downie attended the McCombs School of
Business at the University of Texas. Mr. Downie also serves
on the Board of Directors of TexStar Field Services, BlackBrush
Oil & Gas and Activant Solutions Holdings Inc.
A. Dean Fuller was elected to the Board of Directors of
Regency GP LLC on November 14, 2005. Having sold in 1993 a
company he co-founded, Mr. Fuller become President and
Chief Executive Officer of Transok, Inc., the natural gas
pipeline subsidiary of Central and South West Corporation, until
its sale in 1996. Mr. Fuller continued to manage the fuels
and gas marketing function of CSW until late 2000 at which time
he became Senior Vice President of the midstream business of
Aquila, Inc. At the time of the acquisition of Aquilas
midstream business by Energy Transfer, Mr. Fuller continued
to manage those assets as Senior Vice President, and served as
President of Oasis Pipeline Company after its acquisition by
Energy Transfer. Mr. Fuller resigned his positions with
Energy Transfer in August 2004.
Jack D. Furst was elected to the Board of Directors of Regency
GP LLC on December 8, 2005. Mr. Furst is a partner
with HM Capital and has been with the firm since its formation
in 1989. From 1987 to 1989, Mr. Furst served as a vice
president and subsequently a partner of Hicks & Haas.
From 1984 to 1986, Mr. Furst was a merger &
acquisitions/corporate finance specialist for The First Boston
Corporation in New York. Before joining First Boston,
Mr. Furst was a financial consultant at Price Waterhouse.
Mr. Furst received his MBA from the Graduate School of
Business at the University of Texas. Mr. Furst also serves
on the Board of Directors of Activant Solutions Holdings Inc.
and various other privately held companies.
J. Edward Herring was elected to the Board of Directors of
Regency GP LLC in September 2005. From December 2004 to the
present, Mr. Herring has served as a director of Regency
Gas Services LLC. Mr. Herring is a partner at HM Capital
and has been with the firm since 1998. From 1996 to 1998,
Mr. Herring attended Harvard Business School. From 1993 to
1996, Mr. Herring was an investment banker with Goldman,
Sachs & Co. Mr. Herring also serves on the Board
of Directors of Swift & Company, BlackBrush
Oil & Gas, TexStar Field Services and Swett &
Crawford.
Robert D. Kincaid was elected to the Board of Directors of
Regency GP LLC in September 2005. From January 2005 to the
present, Mr. Kincaid has served as a director of Regency
Gas Services LLC. Mr. Kincaid is a co-founder, with
Mr. Luce, and Managing Director of K-L Energy Partners,
LLC, a private equity management firm formed in April 2004 to
focus on investments in the midstream and
85
downstream energy and power sectors. From October 1998 until
December 2003, Mr. Kincaid was a principal of Haddington
Ventures, LLC, another private equity management firm focused on
energy-related investing. From December 2003 until March 2004,
Mr. Kincaid served as a consultant to Haddington Ventures.
Mr. Kincaid served as Treasurer of TPC Corporation, a firm
engaged in the natural gas marketing, pipeline and storage
sectors, from 1992 until its sale to PacifiCorp in April 1997.
Mr. Kincaid began his career in investment banking and
mezzanine fund management in Houston, Texas.
Gary W. Luce was elected to the Board of Directors of Regency GP
LLC in September 2005. From January 2005 to the present,
Mr. Luce has served as a director of Regency Gas Services
LLC. Mr. Luce is a co-founder, with Mr. Kincaid, and
has been Managing Director of K-L Energy Partners, LLC since its
inception in April 2004. During the period from November 2002
until April 2004, Mr. Luce, in order to comply with the
non-competition provisions of his employment agreement with
Reliant Resources, Inc., acted as an independent financial
consultant. Mr. Luce served as a member of the senior
management team for two public energy-related companies, EOTT
Energy Partners, LP from April 1994 to December 1998 and Reliant
Resources, Inc. from October 1999 to November 2002.
Mr. Luce also served in various capacities with
McKinsey & Company, Inc., the international
management-consulting firm, most recently as a downstream energy
practice principal.
Robert W. Shower was elected to the Board of Directors of
Regency GP LLC on November 14, 2005. During the period from
1964 through 1986, Mr. Shower was employed by The Williams
Companies, ultimately serving as Executive Vice President,
Finance and Administration, Chief Financial Officer and a
director. Since then, Mr. Shower has served as a managing
director of Shearson Lehman Hutton Incorporated from 1986 to
1990, Vice President and Chief Financial Officer of AmeriServe
from 1990 to 1991, Senior Vice President, Corporate Development
for Albert Fisher, Inc. from 1991 to 1992 and Executive Vice
President, Chief Financial Officer and a director of Seagull
Energy Corporation from 1992 to 1996. Currently, Mr. Shower
is a member of the board of directors and chairman of the audit
committee of Edge Petroleum Corporation. Mr. Shower was
formerly a member of the board of directors and chairman of the
audit committee of Lear Corporation, Highlands Insurance Group,
Inc. and Nuevo Energy Company.
J. Otis Winters was elected to the Board of Directors of
Regency GP LLC on November 14, 2005. The following are
exemplary of Mr. Winters extensive business
experience: Vice President of Warren American Oil Company from
1964 to 1965; President and a director of Educational
Development Corporation from 1966 to 1973; Executive Vice
President and a director of The Williams Companies, Inc. from
1973 to 1977; Executive Vice President and a director of First
National Bank of Tulsa from 1978 to 1979; President and a
director of Avanti Energy Corporation from 1980 to 1987;
Managing Director of Mason Best Company from 1988 to 1989;
Chairman, director and co-founder of The PWS Group from 1990 to
2000 and from 2001 to date Chairman and Chief Executive Officer
of Oriole Oil Company. Mr. Winters has served on the board
of directors of 20 publicly owned corporations, including Alton
Box Board Company, AMFM, Inc., AMX Corporation, Dynegy,
Inc., Liberty Bancorp., Inc., Tidel Engineering, Inc., Trident
NGL, Inc. and Walden Residential Properties, Inc.
Reimbursement of Expenses of Our General Partner
Our general partner will not receive any management fee or other
compensation for its management of our partnership. Our general
partner and its affiliates will, however, be reimbursed for all
expenses incurred on our behalf. These expenses include the cost
of employee, officer and director compensation benefits properly
allocable to us and all other expenses necessary or appropriate
to the conduct of our business and allocable to us. The
partnership agreement provides that our general partner will
determine the expenses that are allocable to us. There is no
limit on the amount of expenses for which our general partner
and its affiliates may be reimbursed.
86
ITEM 11.
Executive Compensation.
We, our general partner and Regency GP LLC were formed in
September 2005. Because our general partner is a limited
partnership, its general partner, Regency GP LLC, will manage
our operations and activities through its board of directors and
executive officers. All of our officers and employees are
employed by Regency GP LLC. Because they are employees of
Regency GP LLC, the compensation of the executive officers of
Regency GP LLC (other than any awards under the benefit plans
described below) will be set and paid by Regency GP LLC.
Officers and employees of Regency GP LLC may participate in
employee benefit plans and arrangements sponsored by Regency GP
LLC or its affiliates, including plans that may be established
in the future.
Our chief executive officer and our chief operating officer were
employed by Regency Gas Services LLC on December 1, 2004.
Each of our three other most highly compensated executive
officers were employed by Regency Gas Services LLC on
January 1, 2005 or later. All these officers now hold the
same positions with Regency GP LLC. The following table sets
forth the rates of compensation paid to our chief executive
officer and our four other most highly compensated executive
officers by Regency GP LLC during 2005, which are the same rates
at which these officers were compensated by Regency Gas Services
LLC through January 2006. We refer to these executives as the
named executive officers elsewhere in this report.
Summary Compensation Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual | |
|
Long-Term | |
|
All Other | |
|
|
Compensation | |
|
Compensation | |
|
Compensation | |
|
|
| |
|
| |
|
| |
|
|
Annual | |
|
|
|
Restricted | |
|
|
|
|
|
|
Salary and | |
|
Other | |
|
Common | |
|
Underlying | |
|
|
|
|
Bonuses | |
|
Compensation | |
|
Units | |
|
Options | |
|
|
Name and Principal Position |
|
($) (1) | |
|
($) (2)(3) | |
|
($) | |
|
(Units) | |
|
|
|
|
| |
|
| |
|
| |
|
| |
|
|
James W. Hunt
|
|
$ |
246,000 |
|
|
$ |
4,200 |
|
|
|
|
|
|
|
100,000 |
|
|
|
|
|
|
President, Chief Executive Officer and
Chairman of the Board |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael L. Williams
|
|
|
215,250 |
|
|
|
3,675 |
|
|
|
|
|
|
|
40,000 |
|
|
|
|
|
|
Executive Vice President and
Chief Operating Officer |
|
|
|
|
|
|
|
|
|
|
|
|
|
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Stephen L. Arata
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205,000 |
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35,000 |
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Executive Vice President and
Chief Financial Officer |
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William E. Joor III
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205,000 |
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3,500 |
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35,000 |
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Executive Vice President and
Chief Legal and Administrative Officer |
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Alvin Suggs
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184,500 |
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2,700 |
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15,000 |
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Vice President and General Counsel |
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(1) |
The board of directors of Regency Gas Services LLC adopted the
Regency Gas Services LLC Annual Performance Incentive Plan (or
the Annual Incentive Plan) in May 2005. Substantially all our
employees, including each of the named executive officers, are
participants in the Annual Incentive Plan. Regency GP LLC has
adopted and continued the plan. The Compensation Committee of
Regency Gas Services LLC has been directed to administer the
Annual Incentive Plan and, in awarding bonuses, the Compensation
Committee considered a number of factors, including annual
personal and company performance goals. These amounts include
small advances of the bonuses that were awarded in March 2006
but paid as Christmas bonuses in December 2005. The amount of
the March 2006 awards not included in the above table are as
follows: Mr. Hunt $134,583;
Mr. Williams $117,760;
Mr. Arata $63,339; Mr. Joor
$94,580; Mr. Suggs $95,500. Upon the completion
of our initial public offering in February 2006, the board of
directors of Regency GP LLC approved salary levels for 2006 in
the following amounts: Mr. Hunt $400,000;
Mr. Williams $300,000;
Mr. Arata $250,000; and
Mr. Joor $215,000. The amounts paid pursuant to
these salary levels will be prorated from completion of the
initial public offering to December 31, 2006. |
|
(2) |
These amounts include the contributions of Regency Gas Services
LLC to our Section 401(k) plan for the entire year. |
|
(3) |
These amounts do not include perquisites because the aggregate
amount of such benefits does not exceed either $50,000 or 10% of
the total of annual salary and bonus reported for the respective
officers. |
87
|
|
(4) |
Regency GP LLC has adopted a Long Term Incentive Plan. Please
read the description of the plan under Long
Term Incentive Plan. |
|
(5) |
All options have an exercise price of $20 per unit (equal
to the initial public offering price) and vest and may be
exercised in one-third increments on the anniversary of the
grant date over a period of three years. |
Section 16(a) Beneficial Ownership Reporting
Compliance
Section 16(a) of the Securities Exchange Act of 1934
requires executive officers, directors and persons who
beneficially own more than ten percent of a security registered
under Section 12 of the Securities Exchange Act of 1934 to
file initial reports of ownership and reports of changes of
ownership of such security with the Securities and Exchange
Commission. Copies of such reports are required to be furnished
to the issuer. The common units of the Partnership were first
registered under Section 12 of the Securities Exchange Act
on January 30, 2006. Accordingly, no reports under
Section 16(a) were required to be filed with respect to any
securities of the Partnership during the fiscal year ended
December 31, 2005.
ITEM 12. Security Ownership
of Certain Beneficial Owners and Management and Related
Unitholder Matters.
The following table sets forth, as of March 15, 2006, the
beneficial ownership of our units by:
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each person who then owned beneficially 5% or more of our units; |
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each member of the board of directors of Regency GP LLC; |
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each named executive officer of Regency GP LLC; and |
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all directors and executive officers of Regency GP LLC, as a
group. |
Ownership information regarding the common and subordinated
units set forth in the following table is derived from:
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the holdings thereof by HMTF Regency, L.P. and the resulting
economic interest therein of the persons named in the table
pursuant to their ownership of Class A Units of HMTF
Regency, L.P.; or |
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|
the exchange of Class B Units and Class D Units of net
profits interests in HMTF Regency, L.P. held by persons named in
the table prior to the IPO for common and subordinated units. |
88
These transactions are described in detail under Certain
Relationships and Related Party Transactions Limited
Partner Interests to be Received by Certain Members of
Management and Limited Partner Interests
to be Received by Certain Directors.
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Percentage of | |
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Percentage of | |
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Outstanding | |
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Outstanding | |
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Percentage | |
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Common | |
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Common | |
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Subordinated | |
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Subordinated | |
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of Total | |
Name of Beneficial Owner |
|
Units | |
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Units(7) | |
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Units | |
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Units(7) | |
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Units | |
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| |
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| |
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| |
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| |
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| |
Regency Acquisition LP(1)
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3,456,255 |
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18.1 |
% |
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16,699,462 |
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87.4 |
% |
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52.8 |
% |
John R. Muse(1)
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3,506,255 |
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18.4 |
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16,699,462 |
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87.4 |
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52.9 |
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James W. Hunt(2)(3)(5)
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73,993 |
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0.4 |
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840,678 |
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4.4 |
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2.4 |
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Michael L. Williams(2)(3)(5)
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99,425 |
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0.5 |
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480,387 |
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2.5 |
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1.5 |
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Stephen L. Arata(2)(3)(5)
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49,712 |
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0.3 |
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240,194 |
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1.3 |
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0.8 |
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William E. Joor III(2)(3)(5)
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74,569 |
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0.4 |
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360,290 |
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1.9 |
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1.1 |
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Durell J. Johnson(2)(3)(5)
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14,914 |
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0.1 |
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72,058 |
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0.4 |
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0.2 |
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Lawrence B. Connors(2)(3)(5)
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14,914 |
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0.1 |
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72,058 |
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0.4 |
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0.2 |
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Alvin Suggs(2)(3)(5)
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14,914 |
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0.1 |
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72,058 |
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0.4 |
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0.2 |
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Charles M. Davis Jr.(6)
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100,000 |
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0.5 |
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0 |
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0.0 |
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0.3 |
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Joe Colonnetta(1)
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25,000 |
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0.1 |
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0 |
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0.0 |
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0.1 |
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Jason H. Downie(1)
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11,000 |
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0.1 |
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0 |
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0.0 |
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Note(8 |
) |
A. Dean Fuller
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12,500 |
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0.1 |
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0 |
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0.0 |
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Note(8 |
) |
Jack D. Furst(1)
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12,500 |
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0.1 |
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0 |
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0.0 |
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Note(8 |
) |
J. Edward Herring(1)
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10,000 |
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0.1 |
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0 |
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0.0 |
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Note(8 |
) |
Robert D. Kincaid(4)(5)
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12,715 |
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0.1 |
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37,278 |
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0.2 |
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0.1 |
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Gary W. Luce(4)(5)
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12,715 |
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0.1 |
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37,278 |
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0.2 |
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0.1 |
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J. Otis Winters
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10,000 |
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0.1 |
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0 |
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0.0 |
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Note(8 |
) |
Robert W. Shower
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10,000 |
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0.1 |
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0 |
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0.0 |
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Note(8 |
) |
All directors and executive Officers as a group (16 persons)
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4,015,126 |
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21.0 |
% |
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18,911,741 |
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99.0 |
% |
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60.0 |
% |
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(1) |
According to Schedule 13D/ A (Amendment
No. 1) dated March 8, 2004 (the
Schedule 13D) filed jointly by Regency
Acquisition LP, a Delaware limited partnership
(Acquisition); Regency Holdings LLC, a Delaware
limited liability company and the general partner of Acquisition
(Holdings); HMTF Regency, L.P., a Delaware limited
partnership which is the sole member of Holdings and owns all of
the limited partnership interest in Acquisition (HMTF
Regency); HMTF Regency, L.L.C., a Texas limited liability
company and the general partner of HMTF Regency (HMTF
GP); Hicks, Muse, Tate & Furst Equity
Fund V, L.P., a Delaware limited partnership and the sole
member of HMTF GP (Fund V); HM5/ GP LLC, a
Texas limited liability company, the general partner of
Fund V (HM5); and John R. Muse, a member and
the sole manager of HM5 (Muse and, together with
Acquisition, Holdings, HMTF Regency, HMTF GP, Fund V and
the General Partner (collectively, the HMTF
Entities), the 13D Parties). Acquisition is
the record and beneficial owner of 3,456,255 common units and
16,699,462 subordinated units. As a result of Muse being the
sole manager of the HM5 and the relationship of HM5 to
Fund V, Fund V to HMTF GP, HMTF GP to HMTF Regency,
HMTF Regency to Holdings, and Holdings to Acquisition, each 13D
Party may be deemed to have shared power to vote, or direct the
disposition of, and to dispose, or direct the disposition of,
the common units and subordinated units held of record by
Acquisition. Muse also is the record owner of 50,000 common
units and has sole power to vote or direct the vote and the
power to dispose or direct the disposition of the common units
owned of record by him. Each of the HMTF Entities disclaims
beneficial ownership of the common units held of record by Muse. |
|
(2) |
Each of these executive officers disclaims beneficial ownership
of any common and subordinated units held by HMTF Regency, L.P.
resulting from his ownership of Class A Units of HMTF
Regency, L.P. by each such person as he does not have voting or
dispositive control of these units. These units include the
following: Mr. Hunt 18,817 common and 90,920
subordinated; Mr. Williams 4,897 common and
23,659 subordinated; Mr. Arata 4,897 common and
23,659 subordinated; Mr. Joor 4,897 common and
23,659 subordinated; Mr. Johnson 1,959 common
and 9,464 subordinated; Mr. Connors 4,897
common and 23,659 subordinated; and Mr. Suggs
1,959 common and 9,464 subordinated. Each of these executive
officers will be treated as regards his ownership of
Class A Units, in the same manner as any other HM Capital
Investor. The address of each of these individuals is 1700
Pacific, Suite 2900, Dallas, Texas 75201. |
|
(3) |
The remaining common and subordinated units owned beneficially
by these individuals were acquired on exchange of Class B
Units of HMTF Regency, L.P. in the manner described under
Certain Relationships and Related Party
Transactions Partnership Interests to be
Received by Executive Officers. |
89
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(4) |
Each of these directors disclaims beneficial ownership of any
common and subordinated units held by HMTF Regency, L.P.
resulting from his ownership of Class A Units of HMTF
Regency L.P. by each such person as he does not have voting or
dispositive control of these units. These units include the
following: Mr. Luce 4,897 common and 23,659
subordinated; and Mr. Kincaid 4,897 common and
23,659 subordinated. Each of these directors will be treated, as
regards his ownership of Class A Units, in the same manner
as any other HMTF Investor. The address of each of these
individuals is 1700 Pacific, Suite 2900, Dallas, Texas
75201. |
|
(5) |
At the time of consummation of our initial public offering, each
of these individuals exchanged Class B or Class D
Units in HMTF Regency, L.P. for common and subordinated units as
described in note (3) and for Class E Units of HMTF
Regency, L.P. The Class E Units evidence the pecuniary
interests of the holders in the general partner interest in our
General Partner, Regency GP LP, owned indirectly by HMTF
Regency, L.P. As a result of their holdings of both Class A
and Class E Units in HMTF Regency, L.P., the following
named individuals own the indicated percentages of undivided
general partner interest in our General Partner:
Mr. Hunt 3.2%; Mr. Williams
1.6%; Mr. Joor 1.3%; Mr. Arata
0.9%; Mr. Connors 0.4%;
Mr. Johnson 0.3%; Mr. Suggs
0.3%; Mr. Kincaid 0.2%;
Mr. Luce 0.2%. |
|
(6) |
Mr. Davis was elected an officer on March 21, 2006 and
commenced employment in March 2006. |
|
(7) |
The number of Common and Subordinated units outstanding are
19,103,896 each. |
|
(8) |
Ownership percentages are less than .1%. |
|
|
ITEM 13. |
Certain Relationships and Related Transactions |
Our general partner and its affiliates own 3,953,896 common
units and 19,103,896 subordinated units representing a 59.1%
limited partner interest in us. In addition, our general partner
owns a 2% general partner interest in us and the incentive
distribution rights.
Distributions and Payments to Our General Partner and Its
Affiliates
The following table summarizes the distributions and payments to
be made by us to our general partner and its affiliates in
connection with the formation, ongoing operation and any
liquidation of the Partnership. These distributions and payments
were determined by and among affiliated entities and,
consequently, are not the result of arms-length
negotiations.
FORMATION STAGE
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The consideration received by our general partner and its
affiliates for the contribution of the assets and liabilities to
us |
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5,353,896
common units; |
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19,103,896
subordinated units; |
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2%
general partner interest; |
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the
incentive distribution rights; and |
OPERATIONAL STAGE
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Distributions of available cash to our general partner and its
affiliates |
|
We will generally make cash distributions of 98% to the
unitholders pro rata, including our general partner and its
affiliates, as the holders of an aggregate 3,953,896 common
units and 19,103,896 subordinated units, and 2% to our general
partner. In addition, if distributions exceed the minimum
quarterly distribution and other higher target distribution
levels, our general partner will be entitled to increasing
percentages of the distributions, up to 50% of the distributions
that exceed the highest target level. |
90
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|
Assuming we have sufficient available cash to pay the full
minimum quarterly distribution on all of our outstanding units
for four quarters, our general partner and its affiliates would
receive an annual distribution of approximately
$1.1 million on its 2% general partner interest and
$32.3 million on their common and subordinated units. |
|
Payments to our general partner and its affiliates |
|
Our general partner and its affiliates will be entitled to
reimbursement for all expenses it incurs on our behalf,
including salaries and employee benefit costs for its employees
who provide services to us, and all other necessary or
appropriate expenses allocable to us or reasonably incurred by
our general partner and its affiliates in connection with
operating our business. The partnership agreement provides that
our general partner will determine the expenses that are
allocable to us in good faith. |
|
Withdrawal or removal of our general partner |
|
If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of those interests. Please read The
Partnership Agreement Withdrawal or Removal of the
General Partner. |
LIQUIDATION STAGE
|
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|
Liquidation |
|
Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their respective capital account balances. |
Agreements Governing the Transactions
We and other parties have entered into the various documents and
agreements pursuant to which we effected the offering
transactions, including the vesting of assets in, and the
assumption of liabilities by, us and our subsidiaries, and the
application of the proceeds of our initial public offering.
These agreements were not the result of arms-length
negotiations, and they, or any of the transactions that they
provide for, may not have been effected on terms at least as
favorable to the parties to these agreements as could have been
obtained from unaffiliated third parties. All of the transaction
expenses incurred in connection with these transactions,
including the expenses associated with transferring assets into
our subsidiaries, were paid from the proceeds of our initial
public offering.
Omnibus Agreement
Upon the closing of our initial public offering, we entered into
an omnibus agreement with Regency Acquisition LP pursuant to
which Regency Acquisition LP agreed to indemnify us against
certain environmental and related liabilities arising out of or
associated with the operation of the assets before the
consummation of our initial public offering. This
indemnification obligation will terminate on February 3,
2009. There is an aggregate cap of $8.6 million on the
amount of indemnity coverage for environmental and related
liabilities. In addition, we are not entitled to indemnification
until the aggregate amount of all claims under the omnibus
agreement exceed $250,000. Liabilities resulting from a change
of law after the offering are excluded from the environmental
indemnity by Regency Acquisition LP for the unknown
environmental liabilities.
91
Regency Acquisition LP has also indemnified us for liabilities
related to:
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|
|
certain defects in the
easement rights or fee ownership interests in and to the lands
on which any assets contributed to us are located and failure to
obtain certain consents and permits necessary to conduct our
business that arise within two years after the closing of the
IPO; and |
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|
certain income tax
liabilities attributable to the operation for the assets
contributed to us prior to the time they were contributed. |
The omnibus agreement may not be amended without the prior
approval of the conflicts committee if the proposed amendment
will, in the reasonable discretion of our general partner,
adversely affect holders of our common units.
Regency Acquisition LP will not be restricted under the omnibus
agreement from competing with us. Regency Acquisition LP may
acquire, construct or dispose of 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.
Limited Partner Interests Received by Certain Members of
Management
Regency Gas Services LLC was acquired in December 2004 by the HM
Capital Investors through the use of a Delaware limited
partnership HMTF Regency, L.P. The HM Capital Investors
purchased units of limited partnership interests (Class A
Units) in HMTF Regency, L.P. for cash, which was used to provide
part of the purchase price for Regency Gas Services LLC. The HM
Capital Investors include the executive officers of Regency Gas
Services LLC and now Regency GP LLC, each of whom purchased
Class A Units of HMTF Regency, L.P. on the same terms as
each other HMTF Investor.
At the time of the acquisition, two members of our management,
the Chief Executive Officer and the Chief Operating Officer,
were awarded net profits interests in the form of Class B
Units in HMTF Regency, L.P. Subsequently, our Chief Legal
Officer, Chief Financial Officer and other executive officers
were also awarded Class B Units.
The Class B Units were designed to provide incentives to
management to enhance the value of the investment by HMTF
Regency, L.P. in Regency Gas Services LLC represented by the
Class A Units. Under the partnership agreement, the
economic benefit of the Class B Units was to be conferred
at the time of liquidation and sale of the investment for cash
and the distribution of the cash to the holders of both
Class A Units and Class B Units. The partnership
agreement provides for distributions to be made to the holders
of the Class B Units only after the holders of Class A
Units have received distributions equal to a return of 150% of
the investment by those holders in Class A Units or,
alternatively, various rates of return on investment.
The consummation of our initial public offering and the related
formation transactions did not result in the liquidation of
Regency Gas Services LLC. They did, however, result in
realization of value by the holders of the Class A Units as
a result of the receipt by HMTF Regency, L.P. of common and
subordinated units and interests in our general partner.
Consequently, the general partner of HMTF Regency, L.P. (through
Regency Acquisition LP, its wholly owned subsidiary) determined
that the common units, subordinated units and general partner
interests to be received by HMTF Regency, L.P. as a result of
those transactions should be allocated among the holders of the
Class A Units and Class B Units as if HMTF Regency,
L.P. were to be liquidated in accordance with the partnership
agreement.
As a result of the consummation of our initial public offering,
HMTF Regency, L.P. received common and subordinated units issued
by us, as well as interests in our general partner. Those units
and
92
interests were allocated between the holders of the Class A
Units and Class B Units based on the partnership agreement
liquidation provisions as follows:
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|
The total number of common
and subordinated units and general partner interests issued or
transferred to HMTF Regency, L.P. were valued at the initial
offering price per common unit ($20.00). |
|
|
From that aggregate number
of units and interests, a number of units and interests with an
equivalent value of $320.6 million (representing a 150%
return on the aggregate investment in Class A Units plus
transaction expenses) were allocated to the Class A Unit
holders. |
|
|
Of the remainder, 87.5% were
allocated to the Class A Unit holders and 12.5% were
allocated to the Class B Unit holders as a group. |
|
|
The common and subordinated
units allocated to the holders of Class A Units will
continue to be held by HMTF Regency, L.P. |
|
|
The common and subordinated
units allocated to the holders of Class B Units were
distributed to those holders in exchange for their Class B
Units. |
|
|
The common and subordinated
units and interests so distributed to the group of Class B
Unit holders were allocated among the group in accordance with
their respective holdings of Class B Units. |
Common and subordinated units and interests were allocated to
the Class B Unit holders in the same percentages as those
held for the benefit of the Class A Unit holders.
As a result of the application of these allocation procedures,
our executive officers as a group received an aggregate of
442,441 common units and 2,137,723 subordinated units in
exchange for their Class B Units and have an indirect
economic interest in an aggregate of 42,323 common units and
204,484 subordinated units by virtue of their continued
ownership of Class A Units. Please see the table under
Security Ownership of Certain Beneficial Owners and
Management for the numbers of common and subordinated
units received by each of the named executive officers of
Regency GP LLC.
The formula for allocation of common and subordinated units of
Regency Energy Partners LP among the holders of Class A
Units and Class B Units of HMTF Regency, L.P. established
by the general partner of HMTF Regency, L.P. was predicated on
the indicative aggregate market capitalization of Regency Energy
Partners LP based on the initial public offering price of common
units.
As a result of distributions of the net proceeds from our
initial public offering to the HM Capital Investors, certain of
our officers received, by virtue of their holdings of
Class A Units and Class C Units of HMTF Regency, L.P.,
an aggregate of approximately $3,300,000.
Limited Partner Interests Received by Certain Directors
Robert D. Kincaid and Gary W. Luce, who were elected as
directors of Regency Gas Services LLC at the time of its
acquisition by HMTF Regency, L.P., were awarded net profits
interests in the form of Class D Units in HMTF Regency,
L.P. as an incentive to serve as directors. Those Class D
Units were converted into and exchanged for common and
subordinated units and general partner interests on the same
basis as Class B Units, except that the allocation between
Class A Units and Class D Units was on the basis of
99.6% and 0.4%, respectively. As a result of the application of
these allocation procedures, these two directors together
received an aggregate of 15,430 common units and 74,556
subordinated units in exchange for their Class D Units and
have an economic interest in an aggregate of 9,794 common units
and 47,318 subordinated units by virtue of their continued
ownership of Class A Units. Please see the table under
Security Ownership of Certain Beneficial Owners and
Management for the numbers of common and subordinated
units and general partner interests received by each director.
93
As a result of distributions of the net proceeds from the IPO to
the HM Capital Investors, Messrs. Kincaid and Luce together
received, by virtue of their holdings of Class A Units of
HMTF Regency, L.P., an aggregate of approximately $765,000.
General Partner Interests
The HM Capital Investors, our executive officers and
Messrs. Kincaid and Luce together own economic interests in
our general partner of 91.6%, 7.9% and 0.5%, respectively, as a
result of their ownership of Class A Units and Class E
Units in HMTF Regency, L.P.
Related Party Transactions with the HM Capital Investors
On December 1, 2004, the HM Capital Investors acquired 100%
of the outstanding member interests of Regency Gas Services LLC
from Regency Services LLC and became the single member owner of
Regency Gas Services LLC. In connection with this acquisition,
we entered into a financial advisory agreement and a monitoring
and oversight agreement with an affiliate of HM Capital. The
financial advisory agreement designated an affiliate of HM
Capital to be our exclusive financial advisor in connection with
any subsequent transactions (as such term is defined in the
financial advisory agreement). The monitoring and oversight
agreement provided that an affiliate of HM Capital will provide
us with financial oversight and monitoring services. Each
agreement had a term of the earlier of 10 years or until HM
Capital or its successors or affiliates no longer owns
securities of Regency Gas Services.
Upon the completion of the acquisition by the HM Capital
Investors and pursuant to the financial advisory agreement, an
advisory transaction fee of approximately $6 million was
paid to the affiliate of HM Capital. This amount was included in
the purchase price and was allocated to the assets. In addition,
Regency Gas Services LLC paid management and financial advisory
fees in the amount of approximately $1.1 million to the
affiliate of HM Capital in the year ended December 31,
2005, and less than $0.1 million for the month of December
2004.
At the closing of our initial public offering and the related
formation transactions, we paid $9.0 million to an
affiliate of HM Capital as consideration for the termination of
the ten-year financial advisory and monitoring and oversight
agreements between the affiliate of HM Capital and us. These
agreements would have required us to pay to the affiliate of HM
Capital certain management fees and transaction advisory fees in
the future, which would decrease our cash available for
distribution. We will continue to be obligated to indemnify HM
Capital, its affiliates, and their respective directors,
officers, controlling persons, agents and employees from all
claims, liabilities, loses, damages, expenses and fees and
disbursements of counsel related to or arising out of or in
connection with the services rendered under these agreements and
not resulting primarily from bad faith or willful misconduct.
Following our initial public offering, the HM Capital Investors
own 3,953,896 common units and 19,103,896 subordinated units
representing a 60.3% limited partner interest in us, as well as
the 2.0% general partner interest.
94
|
|
ITEM 14. |
Principal Accounting Fees and Services |
The following set forth fees billed by Deloitte &
Touche LLP for the audit of our annual financial statements and
other services rendered for the fiscal years ended
December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Audit fees(1)
|
|
$ |
1,180,000 |
|
|
$ |
234,000 |
|
Audit related fees(2)
|
|
|
60,000 |
|
|
|
|
|
Tax fees(3)
|
|
|
53,000 |
|
|
|
164,000 |
|
All other fees(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
1,293,000 |
|
|
$ |
398,000 |
|
|
|
|
|
|
|
|
|
|
(1) |
Includes fees for audits of annual financial statements of our
companies (as well as an audit of our financial statements at
June 30, 2005 in connection with our initial public
offering), reviews of the related quarterly financial
statements, and services that are normally provided by the
independent accountants in connection with statutory and
regulatory filings or engagements, including reviews of
documents filed with the Securities and Exchange Commission. |
|
(2) |
Includes fees related to consultations concerning financial
accounting and reporting standards and services related to the
implementation of our internal controls over financial reporting. |
|
(3) |
Includes fees related to professional services for tax
compliance, tax advice, and tax planning. These tax services
were incurred on behalf of HMTF Regency, L.P. for the years
ended December 31, 2004 and 2005. |
|
(4) |
Consists of fees for services other than services reported above. |
Pursuant to the charter of the Audit Committee, the Audit
Committee is responsible for the oversight of our accounting,
reporting and financial practices. The Audit Committee has the
responsibility to select, appoint, engage, oversee, retain,
evaluate and terminate our external auditors; pre-approve all
audit and non-audit services to be provided, consistent with all
applicable laws, to us by our external auditors; and to
establish the fees and other compensation to be paid to our
external auditors. The Audit Committee also oversees and directs
our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of
audit and permitted non-audit services provided by our principal
independent accountants. The policy requires that all services
provided by Deloitte & Touch LLP, including audit
services, audit-related services, tax services and other
services, must be pre-approved by the Committee.
The Audit Committee reviews the external auditors proposed
scope and approach as well as the performance of the external
auditors. It also has direct responsibility for and sole
authority to resolve any disagreements between our management
and our external auditors regarding financial reporting,
regularly reviews with the external auditors any problems or
difficulties the auditors encountered in the course of their
audit work, and, at least annually, uses its reasonable efforts
to obtain and review a report from the external auditors
addressing the following (among other items):
|
|
|
|
|
the auditors internal quality-control procedures; |
|
|
|
any material issues raised by the most recent internal
quality-control review, or peer review, of the external auditors; |
|
|
|
the independence of the external auditors; |
|
|
|
the aggregate fees billed by our external auditors for each of
the previous two fiscal years; and |
|
|
|
the rotation of the lead partner. |
95
PART IV
|
|
ITEM 15. |
Exhibits, Financial Statement Schedules. |
(a) 1. Financial
Statements.
See
Index to Financial Statements set forth on page F-1.
2. Financial
Statement Schedules.
None.
3. Exhibits.
See
Index to Exhibits set forth on page
E-1.
96
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
|
|
|
REGENCY ENERGY PARTNERS LP |
|
|
|
|
By: |
REGENCY GP LP, its general |
|
|
|
|
By: |
REGENCY GP LLC, its general |
|
|
|
|
|
James W. Hunt |
|
Chief Executive Officer and officer duly |
|
authorized to sign on behalf of the registrant |
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed by the following persons in
the capacities and on the dates indicated:
|
|
|
|
|
|
|
|
|
Title |
|
Date |
Signature |
|
|
|
|
|
/s/ James W. Hunt
James W. Hunt |
|
Chairman, President, and
Chief Executive Officer
(Principal Executive Officer) |
|
March 30, 2006 |
|
/s/ Stephen L. Arata
Stephen L. Arata |
|
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer) |
|
March 30, 2006 |
|
/s/ Lawrence B. Connors
Lawrence B. Connors |
|
Vice President, Finance
and Accounting
(Principal Accounting Officer) |
|
March 30, 2006 |
|
/s/ Joe Colonnetta
Joe Colonnetta |
|
Director |
|
March 30, 2006 |
|
/s/ Jason H. Downie
Jason H. Downie |
|
Director |
|
March 30, 2006 |
|
/s/ A. Dean Fuller
A. Dean Fuller |
|
Director |
|
March 30, 2006 |
|
/s/ Jack D. Furst
Jack D. Furst |
|
Director |
|
March 30, 2006 |
|
/s/ J. Edward Herring
J. Edward Herring |
|
Director |
|
March 30, 2006 |
97
|
|
|
|
|
|
|
|
|
Title |
|
Date |
Signature |
|
|
|
|
|
/s/ Robert D. Kincaid
Robert D. Kincaid |
|
Director |
|
March 30, 2006 |
|
/s/ Gary W. Luce
Gary W. Luce |
|
Director |
|
March 30, 2006 |
|
/s/ Robert W. Shower
Robert W. Shower |
|
Director |
|
March 30, 2006 |
|
/s/ J. Otis Winters
J. Otis Winters |
|
Director |
|
March 30, 2006 |
98
INDEX TO EXHIBITS
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
Number | |
|
|
|
Description |
| |
|
|
|
|
|
3.1* |
|
|
|
|
Certificate of Limited Partnership of Regency Energy Partners LP |
|
3.2* |
|
|
|
|
Form of Amended and Restated Limited Partnership Agreement of
Regency Energy Partners LP (included as Appendix A to the
Prospectus and including specimen unit certificate for the
common units) |
|
3.3* |
|
|
|
|
Certificate of Formation of Regency GP LLC |
|
3.4* |
|
|
|
|
Form of Amended and Restated Limited Liability Company Agreement
of Regency GP LLC |
|
3.5* |
|
|
|
|
Certificate of Limited Partnership of Regency GP LP |
|
3.6* |
|
|
|
|
Form of Amended and Restated Limited Partnership Agreement of
Regency GP LP |
|
4.1* |
|
|
|
|
Form of Common Unit Certificate |
|
10.1* |
|
|
|
|
Amended and Restated Credit Agreement of Regency Gas Services LLC |
|
10.2* |
|
|
|
|
Amended and Restated Second Lien Credit Agreement of Regency Gas
Services LLC |
|
10.3* |
|
|
|
|
Second Amended and Restated Credit Agreement of Regency Gas
Services LLC |
|
10.4* |
|
|
|
|
Regency GP LLC Long-Term Incentive Plan |
|
10.5* |
|
|
|
|
Form of Grant Agreement for the Regency GP LLC Long-Term
Incentive Plan Unit Option Grant |
|
10.6* |
|
|
|
|
Form of Grant Agreement for the Regency GP LLC Long-Term
Incentive Plan Restricted Unit Grant |
|
10.7* |
|
|
|
|
Form of Grant Agreement for the Regency GP LLC Long-Term
Incentive Plan Phantom Unit Grant (With DERS) |
|
10.8* |
|
|
|
|
Form of Grant Agreement for the Regency GP LLC Long-Term
Incentive Plan Phantom Unit Grant (Without DERS) |
|
10.9* |
|
|
|
|
Form of Contribution, Conveyance and Assumption Agreement |
|
10.10* |
|
|
|
|
Executive Employment Agreement dated December 1, 2004
between the Registrant and James W. Hunt |
|
10.11* |
|
|
|
|
Employment Agreement dated December 1, 2004 between the
Registrant and Michael L. Williams |
|
10.12* |
|
|
|
|
Severance Agreement dated January 1, 2005 between the
Registrant and William E. Joor, III |
|
10.13* |
|
|
|
|
Purchase Agreement by and among Regency Acquisition LLC, Regency
Services, LLC, Regency Gas Services LLC, the Members of Regency
Services, LLC and the Partners of CB Offshore Equity
Fund V Holdings, L.P. dated October 21,
2004. |
|
10.14* |
|
|
|
|
Purchase and Sale Agreement between Duke Energy Field Services,
LP and Regency Gas Services Waha, LP Dated January 29, 2004 |
|
10.15* |
|
|
|
|
Pipeline Construction Contract between Regency Gas Services LLC
and H.C. Price dated May 2, 2005 (relating to construction
of 30 natural gas pipeline with facilities in Louisiana) |
|
10.16* |
|
|
|
|
Pipeline Construction Contract between Regency Intrastate Gas
LLC and H.C. Price Co. dated May 2nd, 2005 (relating to the
construction of 24 natural gas pipeline with facilities in
Louisiana) |
|
10.17* |
|
|
|
|
Ground Lease Agreement (Lakin Plant) |
|
10.18* |
|
|
|
|
Ground Lease Agreement (Mocane Plant) |
|
10.19* |
|
|
|
|
Lisbon Lease Agreement |
|
10.20* |
|
|
|
|
Firm Transportation Agreement dated June 8, 2005 between
Regency Intrastate Gas LLC and Anadarko Energy Services Company |
|
10.21* |
|
|
|
|
Form of Third Amended and Restated Credit Agreement of Regency
Gas Services LLC |
|
10.22* |
|
|
|
|
Form of Indemnification Agreement between Regency GP LLC and
Indemnitees |
|
10.23* |
|
|
|
|
Financial Advisory Agreement |
99
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
Number | |
|
|
|
Description |
| |
|
|
|
|
|
10.24* |
|
|
|
|
Monitoring and Oversight Agreement |
|
10.25* |
|
|
|
|
Form of Omnibus Agreement |
|
21.1* |
|
|
|
|
List of Subsidiaries of Regency Energy Partners LP |
|
31.1 |
|
|
|
|
Certifications pursuant to Rule 13a-14(a). |
|
31.2 |
|
|
|
|
Certifications pursuant to Rule 13a-14(a). |
|
32.1 |
|
|
|
|
Certifications pursuant to Section 1350. |
|
32.2 |
|
|
|
|
Certifications pursuant to Section 1350. |
|
99.1 |
|
|
|
|
Financial Statements of Regency GP LP, the general partner of
the registrant. |
|
* |
|
|
|
|
Incorporated by reference to the comparably numbered exhibit to
the registrants registration statement on Form S-1
(File No. 333-128332). |
|
|
|
|
|
|
Portions of this exhibit have been omitted pursuant to a request
for confidential treatment. |
100
INDEX TO CONSOLIDATED FINANCIAL INFORMATION
|
|
|
|
|
Regency Energy Partners LP |
|
|
|
F-2 |
|
|
|
|
F-3 |
|
|
|
|
F-4 |
|
|
Regency Gas Services LLC |
|
|
|
F-5 |
|
|
|
|
F-6 |
|
|
|
|
F-7 |
|
|
|
|
F-8 |
|
|
|
|
F-9 |
|
|
|
|
F-10 |
|
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Regency GP LLC and Unitholders of
Regency Energy Partners LP:
We have audited the accompanying balance sheet of Regency Energy
Partners LP (the Partnership) as of
December 31, 2005. The financial statement is the
responsibility of the Partnerships management. Our
responsibility is to express an opinion on the financial
statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Partnership is not required
to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Partnerships internal control
over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audit provides a reasonable basis for our opinion.
In our opinion, the balance sheet presents fairly, in all
material respects, the financial position of the Partnership as
of December 31, 2005, in conformity with accounting
principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 30, 2006
F-2
Regency Energy Partners LP
Balance Sheet as of December 31, 2005
|
|
|
|
|
|
|
December 31, 2005 | |
|
|
| |
Assets
|
|
|
|
|
Cash
|
|
$ |
1,000 |
|
|
|
|
|
Total assets
|
|
|
1,000 |
|
|
|
|
|
Partners Equity
|
|
|
|
|
Limited partners equity
|
|
$ |
980 |
|
General partners equity
|
|
|
20 |
|
|
|
|
|
Total partners equity
|
|
$ |
1,000 |
|
|
|
|
|
F-3
Regency Energy Partners LP
Notes to Balance Sheet
December 31, 2005
Regency Energy Partners LP (the Partnership), is a
Delaware limited partnership formed on September 8, 2005,
to acquire all of the member interest of Regency Gas Services
LLC (Predecessor). The Partnership is engaged in
gathering, processing, marketing, and transporting natural gas
and natural gas liquids. The Partnerships general partner
is Regency GP LP.
Initial Public Offering On
September 15, 2005, a Registration Statement on
Form S-1 (File
No. 333-128332)
was filed with the United States Securities and Exchange
Commission (the SEC) relating to a proposed
underwritten initial public offering (IPO) of limited
partnership interests in Regency Energy Partners LP. On
January 30, 2006, the Partnership priced 13,750,000 common
units, representing a 35.3% limited partner interest in the
Partnership, for the initial public offering and on
January 31, 2006 the Partnerships common units began
trading on the NASDAQ National Market under the symbol
RGNC. On February 3, 2006, the Partnership
closed its initial public offering of 13,750,000 common units at
a price of $20.00 per unit. Total proceeds from the sale of
the units were $275 million, before offering costs and
underwriting commissions.
The assets of the Predecessor were contributed to the
Partnership by Regency Acquisition LP (Acquisition)
in exchange for 19,103,896 subordinated units representing a 49%
limited partner interest in the Partnership; 5,353,896 common
units representing a 13.7% limited partner interest in the
Partnership; a 2% general partner interest in the Partnership;
incentive distribution rights; and the right to receive
reimbursement of approximately $196 million of capital
expenditures comprising most of the initial investment by HM
Capital Partners LLC (HM Capital) in Regency Gas Services LLC.
Concurrent with the closing of the IPO, Regency Gas Services LLC
was converted to a limited partnership.
The proceeds of the Partnerships initial public offering
were used to: distribute approximately $196 million to HMTF
Regency LP (the Parent) for reimbursement of capital
expenditures and to replenish $48 million of working
capital assets which were distributed to HM Capital immediately
prior to the IPO; pay $9 million to an affiliate of the
Parent to terminate a management services contract; and pay
$22 million of underwriting commissions, structuring fees
and other offering costs.
On March 8, 2006, the Partnership closed the sale of an
additional 1,400,000 common units at a price of $20 per
unit as the underwriters exercised a portion of their over
allotment option. The net proceeds from the sale were used by us
to redeem an equivalent number of common units held by Regency
Acquisition LP for the benefit of the HM Capital Investors,
reducing their partner interest to 61.1%.
Omnibus Agreement Upon the closing of
the Partnerships IPO, the Partnership entered into an
omnibus agreement with Acquisition in which Acquisition
indemnifies the Partnership against certain environmental and
related liabilities arising out of or associated with the
operation of the assets preceding the IPO closing date. The
environmental liability indemnification is limited to
$8.6 million with a deductible of $250,000 and terminates
after three years. In addition, the omnibus agreement
indemnifies the Partnership against certain defects in the
easement rights or fee ownership interests in and to the lands
on which any assets contributed to it are located, and failure
to obtain certain consents and permits necessary to conduct the
business that arise within two years. Further, the omnibus
agreement indemnifies the Partnership against certain income tax
liabilities attributable to the operation of the contributed
assets prior to the closing of the IPO.
F-4
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Regency GP LLC and Unitholders of
Regency Energy Partners LP:
We have audited the accompanying consolidated balance sheets of
Regency Gas Services LLC (Predecessor) and subsidiaries (the
Company) as of December 31, 2005 and 2004, and
the related consolidated statements of operations, changes in
member interest, and cash flows for the year ended
December 31, 2005, the period from acquisition date
(December 1, 2004) to December 31, 2004, and Regency
LLC Predecessor for the period from January 1, 2004 to
November 30, 2004 and for the period from inception
(April 2, 2003) to December 31, 2003. These financial
statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our audits included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Company as of December 31, 2005 and 2004, and the results
of the Companys operations and cash flows for the year
ended December 31, 2005, period from acquisition date
(December 1, 2004) to December 31, 2004 and the
results of Regency LLC Predecessors operations and cash
flows for the period from January 1, 2004 to
November 30, 2004 and the period from inception
(April 2, 2003) to December 31, 2003, in conformity
with accounting principles generally accepted in the United
States of America.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 30, 2006
F-5
Regency Gas Services LLC (Predecessor)
Consolidated Balance Sheets
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency Gas Services LLC | |
|
|
| |
|
|
December 31, | |
|
December 31, | |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
ASSETS
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
3,669 |
|
|
$ |
3,272 |
|
|
Restricted cash
|
|
|
5,533 |
|
|
|
5,410 |
|
|
Accounts receivable, net of allowance of $169 in 2005 and $135
in 2004
|
|
|
78,782 |
|
|
|
49,215 |
|
|
Assets from risk management activities
|
|
|
1,717 |
|
|
|
2,767 |
|
|
Other current assets
|
|
|
3,950 |
|
|
|
2,713 |
|
|
|
|
|
|
|
|
Total current assets
|
|
|
93,651 |
|
|
|
63,377 |
|
Property, plant and equipment
|
|
|
|
|
|
|
|
|
|
Gas plants and buildings
|
|
|
46,399 |
|
|
|
44,606 |
|
|
Gathering and transmission systems
|
|
|
397,481 |
|
|
|
250,392 |
|
|
Other property, plant and equipment
|
|
|
41,470 |
|
|
|
20,427 |
|
|
Construction-in-progress
|
|
|
16,738 |
|
|
|
14,380 |
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
502,088 |
|
|
|
329,805 |
|
|
Less accumulated depreciation
|
|
|
(21,505 |
) |
|
|
(1,457 |
) |
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
480,583 |
|
|
|
328,348 |
|
Intangible and other assets
|
|
|
|
|
|
|
|
|
|
Intangible assets, net of amortization
|
|
|
16,370 |
|
|
|
18,342 |
|
|
Goodwill
|
|
|
57,552 |
|
|
|
58,529 |
|
|
Assets held for sale
|
|
|
|
|
|
|
4,101 |
|
|
Long-term assets from risk management activities
|
|
|
1,333 |
|
|
|
6,243 |
|
|
Other, net of amortization on debt issuance costs of $271 in
2005 and $112 in 2004
|
|
|
4,835 |
|
|
|
7,549 |
|
|
|
|
|
|
|
|
Total intangible and other assets
|
|
|
80,090 |
|
|
|
94,764 |
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
654,324 |
|
|
$ |
486,489 |
|
|
|
|
|
|
|
|
|
LIABILITIES & MEMBER INTEREST
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$ |
99,745 |
|
|
$ |
51,471 |
|
|
Escrow payable
|
|
|
5,533 |
|
|
|
5,410 |
|
|
Accrued taxes payable
|
|
|
2,266 |
|
|
|
1,460 |
|
|
Interest payable
|
|
|
67 |
|
|
|
|
|
|
Liabilities from risk management activities
|
|
|
11,312 |
|
|
|
14 |
|
|
Current portion of long term debt
|
|
|
|
|
|
|
2,000 |
|
|
Other current liabilities
|
|
|
2,378 |
|
|
|
1,170 |
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
121,301 |
|
|
|
61,525 |
|
Long term liabilities from risk management activities
|
|
|
4,895 |
|
|
|
|
|
Long-term debt
|
|
|
358,350 |
|
|
|
248,000 |
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Member interest
|
|
|
169,778 |
|
|
|
176,964 |
|
|
|
|
|
|
|
|
TOTAL LIABILITIES & MEMBER INTEREST
|
|
$ |
654,324 |
|
|
$ |
486,489 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-6
Regency Gas Services LLC (Predecessor)
Consolidated Statements of Operations
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency Gas Services LLC | |
|
|
Regency LLC Predecessor | |
|
|
| |
|
|
| |
|
|
|
|
Period from | |
|
|
|
|
|
|
|
Acquisition | |
|
|
|
|
Period from | |
|
|
|
|
Date | |
|
|
Period from | |
|
Inception | |
|
|
|
|
(December 1, | |
|
|
January 1, | |
|
(April 2, | |
|
|
Year Ended | |
|
2004) to | |
|
|
2004 to | |
|
2003) to | |
|
|
December 31, | |
|
December 31, | |
|
|
November 30, | |
|
December 31, | |
|
|
2005 | |
|
2004 | |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
| |
|
| |
REVENUE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$ |
495,987 |
|
|
$ |
32,616 |
|
|
|
$ |
279,582 |
|
|
$ |
127,149 |
|
NGL sales
|
|
|
179,305 |
|
|
|
11,890 |
|
|
|
|
123,827 |
|
|
|
46,697 |
|
Gathering, transportation and other fees
|
|
|
25,921 |
|
|
|
1,943 |
|
|
|
|
19,016 |
|
|
|
9,439 |
|
Unrealized/realized gain/(loss) from risk management activities
|
|
|
(22,243 |
) |
|
|
322 |
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
13,633 |
|
|
|
1,070 |
|
|
|
|
9,896 |
|
|
|
3,248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
692,603 |
|
|
|
47,841 |
|
|
|
|
432,321 |
|
|
|
186,533 |
|
EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of gas and liquids
|
|
|
611,137 |
|
|
|
39,979 |
|
|
|
|
352,508 |
|
|
|
158,524 |
|
Other cost of sales
|
|
|
9,614 |
|
|
|
1,007 |
|
|
|
|
10,254 |
|
|
|
4,937 |
|
Operating expenses
|
|
|
21,812 |
|
|
|
1,819 |
|
|
|
|
17,786 |
|
|
|
7,012 |
|
General and administrative
|
|
|
14,412 |
|
|
|
638 |
|
|
|
|
6,571 |
|
|
|
2,651 |
|
Transaction expenses
|
|
|
|
|
|
|
|
|
|
|
|
7,003 |
|
|
|
724 |
|
Depreciation and amortization
|
|
|
22,010 |
|
|
|
1,613 |
|
|
|
|
10,129 |
|
|
|
4,324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expense
|
|
|
678,985 |
|
|
|
45,056 |
|
|
|
|
404,251 |
|
|
|
178,172 |
|
OPERATING INCOME
|
|
|
13,618 |
|
|
|
2,785 |
|
|
|
|
28,070 |
|
|
|
8,361 |
|
OTHER INCOME AND DEDUCTIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(17,432 |
) |
|
|
(1,335 |
) |
|
|
|
(5,097 |
) |
|
|
(2,392 |
) |
Loss on debt refinancing
|
|
|
(8,480 |
) |
|
|
|
|
|
|
|
(3,022 |
) |
|
|
|
|
Other income and deductions, net
|
|
|
338 |
|
|
|
14 |
|
|
|
|
186 |
|
|
|
205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income and deductions
|
|
|
(25,574 |
) |
|
|
(1,321 |
) |
|
|
|
(7,933 |
) |
|
|
(2,187 |
) |
NET (LOSS) INCOME FROM CONTINUING OPERATIONS
|
|
|
(11,956 |
) |
|
|
1,464 |
|
|
|
|
20,137 |
|
|
|
6,174 |
|
DISCONTINUED OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations of Regency Gas Treating LP
(including gain on disposal of $626 in 2005; Note 2)
|
|
|
732 |
|
|
|
|
|
|
|
|
(121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (LOSS) INCOME
|
|
$ |
(11,224 |
) |
|
$ |
1,464 |
|
|
|
$ |
20,016 |
|
|
$ |
6,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-7
Regency Gas Services LLC (Predecessor)
Consolidated Statement of Changes in Member Interest
For the Periods from Inception (April 2, 2003) to
December 31, 2005
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
Other | |
|
|
|
|
Comprehensive | |
|
Comprehensive | |
|
Member | |
|
|
Income (Loss) | |
|
Income (Loss) | |
|
Interest | |
|
|
| |
Regency LLC Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Member interest contribution June 2, 2003
|
|
$ |
|
|
|
|
|
|
|
$ |
53,750 |
|
|
Net income for the period from inception (April 2, 2003) to
December 31, 2003
|
|
|
6,174 |
|
|
|
|
|
|
|
6,174 |
|
|
Member interest distributions
|
|
|
|
|
|
|
|
|
|
|
(68 |
) |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$ |
6,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2003
|
|
|
|
|
|
|
|
|
|
|
59,856 |
|
|
Member interest contribution March 1, 2004
|
|
|
|
|
|
|
|
|
|
|
10,000 |
|
|
Net income for the period from January 1, 2004 to
November 30, 2004
|
|
|
20,016 |
|
|
|
|
|
|
|
20,016 |
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$ |
20,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, November 30, 2004
|
|
|
|
|
|
|
|
|
|
|
89,872 |
|
|
Member interest distributions
|
|
|
|
|
|
|
|
|
|
|
(89,872 |
) |
|
|
|
|
|
|
|
|
|
|
|
Balance, December 1, 2004
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Regency Gas Services LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net consideration paid by the HM Capital Investors
|
|
$ |
|
|
|
|
|
|
|
$ |
171,000 |
|
|
Member interest contribution December 2004
|
|
|
|
|
|
|
|
|
|
|
4,500 |
|
|
Net income for the period from December 1, 2004 to
December 31, 2004
|
|
|
1,464 |
|
|
|
|
|
|
|
1,464 |
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
$ |
1,464 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
$ |
|
|
|
|
|
|
|
|
176,964 |
|
|
Member interest contribution July 25, 2005
|
|
|
|
|
|
|
|
|
|
|
15,000 |
|
|
Net loss for the year ended December 31, 2005
|
|
|
(11,224 |
) |
|
|
|
|
|
|
(11,224 |
) |
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in fair value of cash flow hedges
|
|
|
(16,502 |
) |
|
|
(16,502 |
) |
|
|
|
|
|
|
Amounts reclassified to earnings during the period
|
|
|
5,540 |
|
|
|
5,540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Loss
|
|
|
(10,962 |
) |
|
|
|
|
|
|
(10,962 |
) |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Loss
|
|
$ |
(22,186 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
|
|
|
$ |
(10,962 |
) |
|
$ |
169,778 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-8
Regency Gas Services LLC (Predecessor)
Consolidated Statements of Cash Flows
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency Gas Services LLC | |
|
Regency LLC Predecessor | |
|
|
| |
|
| |
|
|
|
|
Period from | |
|
|
|
|
|
|
Acquisition Date | |
|
Period from | |
|
Period from | |
|
|
|
|
(December 1, | |
|
January 1, 2004 | |
|
Inception | |
|
|
Year Ended | |
|
2004) to | |
|
to | |
|
(April 2, 2003) to | |
|
|
December 31, | |
|
December 31, | |
|
November 30, | |
|
December 31, | |
|
|
2005 | |
|
2004 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
(11,224 |
) |
|
$ |
1,464 |
|
|
$ |
20,016 |
|
|
$ |
6,174 |
|
Adjustments to reconcile net income to net cash flows provided
(used) by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation & amortization
|
|
|
23,092 |
|
|
|
1,745 |
|
|
|
10,461 |
|
|
|
4,658 |
|
|
Loss on debt refinancing
|
|
|
8,480 |
|
|
|
|
|
|
|
3,022 |
|
|
|
|
|
|
Risk management portfolio valuation changes
|
|
|
11,191 |
|
|
|
(322 |
) |
|
|
|
|
|
|
|
|
|
Gain on the sale of Regency Gas Treating LP assets
|
|
|
(626 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on the sale of NGL line pack
|
|
|
(628 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows impacted by changes in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(29,567 |
) |
|
|
2,583 |
|
|
|
(20,408 |
) |
|
|
(31,390 |
) |
|
|
|
Advances to affiliates
|
|
|
|
|
|
|
|
|
|
|
576 |
|
|
|
(576 |
) |
|
|
|
Other current assets
|
|
|
(1,237 |
) |
|
|
(2,430 |
) |
|
|
(1,169 |
) |
|
|
(1,070 |
) |
|
|
|
Accounts payable and accrued liabilities
|
|
|
32,722 |
|
|
|
(155 |
) |
|
|
18,122 |
|
|
|
26,880 |
|