e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
|
|
|
þ
|
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the fiscal year ended
December 31, 2007
|
or
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the transition period
from to
|
Commission file
number: 001-33303
TARGA RESOURCES PARTNERS
LP
(Exact name of registrant as
specified in its charter)
|
|
|
Delaware
(State or other jurisdiction
of
incorporation or organization)
|
|
65-1295427
(I.R.S. Employer
Identification No.)
|
1000 Louisiana St, Suite 4300
Houston, Texas
(Address of principal
executive offices)
|
|
77002
(Zip Code)
|
(713) 584-1000
(Registrants telephone
number, including area code)
Securities registered pursuant to section 12(b) of the
Act:
|
|
|
Title of Each Class
|
|
Name of Each Exchange on Which Registered
|
|
Common Units Representing Limited Partnership Interests
|
|
The NASDAQ Stock Market LLC
|
Securities registered pursuant to section 12(g) of the
Act:
Title of Class: None
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 not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
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, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2 of the Exchange Act. (Check one):
|
|
|
|
|
|
|
Large accelerated
filer o
|
|
Accelerated
filer o
|
|
Non-accelerated
filer þ
|
|
Smaller reporting
company o
|
|
|
(Do not check if a smaller reporting company)
|
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ.
The aggregate market value of the Common Units representing
limited partner interests held by non-affiliates of the
registrant was approximately $644,684,000 on June 29, 2007,
based on $33.50 per unit, the closing price of the Common Units
as reported on The NASDAQ Stock Market LLC on such date.
At March 25, 2008, there were 34,652,000 Common Units,
11,528,231 Subordinated Units, and 942,455 General Partner Units
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
None
TABLE OF
CONTENTS
DESCRIPTION
2
TARGA
RESOURCES PARTNERS LP
CAUTIONARY
STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Targa Resources Partners LPs (together with its
subsidiaries (we, us, our or
the Partnership)) reports, filings and other public
announcements may from time to time contain statements that do
not directly or exclusively relate to historical facts. Such
statements are forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995.
You can typically identify forward-looking statements by the use
of forward-looking words, such as may,
could, project, believe,
anticipate, expect,
estimate, potential, plan,
forecast and other similar words.
All statements that are not statements of historical facts,
including statements regarding our future financial position,
business strategy, budgets, projected costs and plans and
objectives of management for future operations, are
forward-looking statements.
These forward-looking statements reflect our intentions, plans,
expectations, assumptions and beliefs about future events and
are subject to risks, uncertainties and other factors, many of
which are outside our control. Important factors that could
cause actual results to differ materially from the expectations
expressed or implied in the forward-looking statements include
known and unknown risks. Known risks and uncertainties include,
but are not limited to, the risks set forth in
Item 1A. Risk Factors as well as the following
risks and uncertainties:
|
|
|
|
|
our ability to access the debt and equity markets, which will
depend on general market conditions and the credit ratings for
our debt obligations;
|
|
|
|
our success in risk management activities, including the use of
derivative financial instruments to hedge commodity and interest
rate risks;
|
|
|
|
the level of creditworthiness of counterparties to transactions;
|
|
|
|
the amount of collateral required to be posted from time to time
in our transactions;
|
|
|
|
changes in laws and regulations, particularly with regard to
taxes, safety and protection of the environment or the gathering
and processing industry;
|
|
|
|
the timing and extent of changes in natural gas, NGLs and
commodity prices, interest rates and demand for our services;
|
|
|
|
weather and other natural phenomena;
|
|
|
|
industry changes, including the impact of consolidations and
changes in competition;
|
|
|
|
our ability to obtain necessary licenses, permits and other
approvals;
|
|
|
|
our ability to grow through acquisitions or internal growth
projects, and the successful integration and future performance
of such assets;
|
|
|
|
the level and success of natural gas drilling around our assets,
and our success in connecting natural gas supplies to our
gathering and processing systems;
|
|
|
|
general economic, market and business conditions; and
|
|
|
|
the risks described elsewhere in this Annual Report.
|
Although we believe that the assumptions underlying our
forward-looking statements are reasonable, any of the
assumptions could be inaccurate, and, therefore, we cannot
assure you that the forward-looking statements included in this
Annual Report will prove to be accurate. Some of these and other
risks and uncertainties that could cause actual results to
differ materially from such forward-looking statements are more
fully described under the heading Risk Factors in this Annual
Report. Except as may be required by applicable
3
law, we undertake no obligation to publicly update or advise of
any change in any forward-looking statement, whether as a result
of new information, future events or otherwise.
Forward-looking statements contained in this Annual Report and
all subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf are expressly
qualified in their entirety by this cautionary statement.
As generally used in the energy industry and in this Annual
Report on
Form 10-K,
the identified terms have the following meanings:
|
|
|
Bbl
|
|
Barrels (equal to 42 gallons)
|
BBtu
|
|
Billion British thermal units
|
Bcf
|
|
Billion cubic feet
|
Btu
|
|
British thermal unit, a measure of heating value
|
/d
|
|
Per day
|
Gal
|
|
Gallons
|
MBbl
|
|
Thousand barrels
|
Mcf
|
|
Thousand cubic feet
|
MMBbl
|
|
Million barrels
|
MMBtu
|
|
Million British thermal units
|
MMcf
|
|
Million cubic feet
|
NGL(s)
|
|
Natural gas liquid(s)
|
Tcf
|
|
Trillion cubic feet
|
|
|
|
Price Index Definitions
|
|
|
|
GD-HH
|
|
Henry Hub Gas Daily average
|
IF-HH
|
|
Inside FERC Gas Market Report, Henry Hub
|
IF-HSC
|
|
Inside FERC Gas Market Report, Houston Ship Channel/Beaumont,
Texas
|
IF-NGPL MC
|
|
Inside FERC Gas Market Report, Natural Gas Pipeline,
Mid-Continent
|
IF-Waha
|
|
Inside FERC Gas Market Report, West Texas Waha
|
NY-HH
|
|
NYMEX, Henry Hub Natural Gas
|
NY-WTI
|
|
NYMEX, West Texas Intermediate Crude Oil
|
OPIS-MB
|
|
Oil Price Information Service, Mont Belvieu, Texas
|
General
We are a growth-oriented Delaware limited partnership formed on
October 26, 2006 by Targa Resources, Inc.
(Targa), a leading provider of midstream natural gas
and NGL services in the United States, to own, operate, acquire
and develop a diversified portfolio of complementary midstream
energy assets. We are engaged in the business of gathering,
compressing, treating, processing and selling natural gas and
fractionating and selling NGLs and NGL products. We currently
operate in the Fort Worth Basin/Bend Arch (the
Fort Worth Basin) in north Texas, the Permian
Basin of west Texas and in southwest Louisiana.
In connection with our Initial Public Offering (IPO)
in February 2007, Targa contributed the assets of the North
Texas System located in the Fort Worth Basin (the
North Texas System) to us. We acquired the assets of
the SAOU System located in the Permian Basin (the SAOU
System) and the assets of the LOU System located in
southwest Louisiana (the LOU System) from Targa in
October 2007.
We intend to leverage our relationship with Targa to acquire and
construct additional midstream energy assets and to utilize the
significant experience of Targas management team to
execute our growth strategy.
4
Business
Strategies
Our primary objective is to provide increasing cash
distributions to our unitholders over time. Our business
strategies focus on creating and increasing value for our
unitholders through efficient operations, prudent risk
management and growth through acquisitions and organic projects.
We intend to accomplish this objective by executing the
following strategies:
|
|
|
|
|
Increasing the profitability of our existing
assets. With our North Texas System, we have an
extensive network of gathering systems and two natural gas
processing facilities, which positions us to capitalize on the
active development and growing production from the Barnett Shale
and the other Fort Worth Basin formations. The SAOU System
is located in the Permian Basin of west Texas, which is
characterized by long-lived, multi-horizon oil and gas reserves
that have low natural production declines. The LOU System has
access to onshore basins in south Louisiana and serves the Lake
Charles industrial market. Our assets provide us opportunities
to:
|
|
|
|
|
|
Utilize excess pipeline and plant capacity to connect and
process new supplies of natural gas at minimal incremental cost;
|
|
|
|
Undertake additional initiatives to improve operating
efficiencies and increase processing yields;
|
|
|
|
Eliminate bottlenecks to allow for increased throughput;
|
|
|
|
Pursue pressure reduction projects to increase volumes of gas to
be gathered and processed; and
|
|
|
|
Expand our footprint in a cost effective manner.
|
|
|
|
|
|
Managing our contract mix to optimize
profitability. The majority of our operating
margin is generated pursuant to percent-of-proceeds contracts or
similar arrangements which, if unhedged, benefit us in
increasing commodity price environments and expose us to a
reduction in profitability in decreasing commodity price
environments. We believe that if appropriately managed, our
current contract mix allows us to optimize our profitability
over time. Although we expect to maintain primarily
percent-of-proceeds arrangements, we continually evaluate the
market for attractive fee-based and other arrangements which
will further reduce the variability of our cash flows as well as
enhance our profitability and competitiveness.
|
|
|
|
Mitigating commodity price exposure through prudent hedging
arrangements. The primary purpose of our
commodity price risk management activities is to hedge our
exposure to commodity price risk inherent in our contract mix
and reduce fluctuations in our operating cash flow despite
fluctuations in commodity prices. We have hedged the commodity
price associated with a significant portion of our expected
natural gas, NGLs and condensate equity volumes for the years
2008 through 2012 by entering into derivative financial
instruments including swaps and purchased puts (or floors). The
percentages of our expected equity volumes that are covered by
our hedges decrease over time. We have structured our hedges to
approximate our actual NGL product composition and to
approximate our actual NGL and natural gas delivery points. We
do not use crude oil prices to approximate NGL prices for
purposes of hedging. We intend to continue to manage our
exposure to commodity prices in the future by entering into
similar hedge transactions using swaps, collars, purchased puts
(or floors) or other hedge instruments as market conditions
warrant.
|
|
|
|
Capitalizing on organic expansion
opportunities. We continually evaluate
economically attractive organic expansion opportunities in
existing or new areas of operation that will allow us to expand
our business.
|
|
|
|
Focusing on producing regions with attractive
characteristics. We seek to focus on those regions and
supplies with attractive characteristics, including regions:
|
|
|
|
|
|
where treating or processing is required to access end-markets;
|
5
|
|
|
|
|
where permitting, drilling and workover activity is high;
|
|
|
|
with the potential for long-term acreage dedications;
|
|
|
|
with a strong base of current production and the potential for
significant future development; and
|
|
|
|
that can serve as a platform to expand into adjacent areas with
existing or new production.
|
|
|
|
|
|
Pursuing strategic and accretive
acquisitions. We plan to pursue strategic and
accretive acquisition opportunities within the midstream energy
industry, both from Targa and from third parties. We will seek
acquisitions in our existing areas of operation that provide the
opportunity for operational efficiencies, the potential for
higher capacity utilization and expansion of existing assets, as
well as acquisitions in other related midstream businesses
and/or expansion into new geographic areas of operation. Among
the factors we will consider in deciding whether to acquire
assets include, but are not limited to, the economic
characteristics of the acquisition (such as return on capital
and cash flow stability), the region in which the assets are
located (both regions contiguous to our areas of operation and
other regions with attractive characteristics) and the
availability and sources of capital to finance the acquisition.
We intend to finance our expansion through a combination of debt
and equity, including commercial debt facilities and public and
private offerings of debt and equity securities.
|
|
|
|
Leveraging our relationship with Targa. Our
relationship with Targa provides us access to its extensive pool
of operational, commercial and risk management expertise which
enables all of our strategies. In addition, we intend to pursue
acquisition opportunities as well as organic growth
opportunities with Targa and with Targas assistance. We
may also acquire assets or businesses directly from Targa, which
will provide us access to an array of growth opportunities
broader than that available to many of our competitors.
|
Competitive
Strengths
We believe that we are well positioned to execute our primary
business objective and business strategies successfully because
of the following competitive strengths:
|
|
|
|
|
Affiliation with Targa. We expect that our
relationship with Targa will provide us with significant
business opportunities. Targa is a large gatherer and processor
of natural gas in the United States. Targa owns and operates a
large integrated platform of midstream assets in oil and natural
gas producing regions, including the Permian Basin in west Texas
and southeast New Mexico and the onshore and offshore regions of
the Texas and Louisiana Gulf Coast. These operations are
integrated with Targas NGL logistics and marketing
business that extends services to customers throughout the
United States. Targa has an experienced and knowledgeable
executive management team and experienced and knowledgeable
commercial and operations teams. We believe Targas
relationships throughout the energy industry, including with
producers of natural gas in the United States, will help
facilitate implementation of our acquisition strategy and other
strategies. Targa has indicated that it intends to use us as a
growth vehicle to pursue the acquisition and expansion of
midstream natural gas, NGL and other complementary energy
businesses and assets and we expect to have the opportunity, but
not the obligation, to acquire such businesses and assets
directly from Targa in the future.
|
|
|
|
Strategically located assets. Our North Texas
System is one of the largest integrated natural gas gathering,
compression, treating and processing systems in the
Fort Worth Basin. Current high levels of natural gas
exploration, development and production activities within the
Fort Worth Basin present significant organic growth
opportunities to generate additional throughput on our system.
|
The SAOU System provides us access to the Permian Basin, which
is characterized by long-lived, multi-horizon oil and gas
reserves that have low natural production declines. The SAOU
System has access to liquid market hubs for both natural gas and
NGLs.
6
The LOU System gathers gas primarily from onshore oil and gas
production in southwest Louisiana in the area around and between
Lafayette and Lake Charles, Louisiana. The LOU Systems
processing plants have direct access to the Lake Charles
industrial market through its intrastate pipeline system,
providing the ability to deliver natural gas to industrial users
and electric utilities in the Lake Charles area. It also has
access to both interstate natural gas supplies and markets as
well as access to the NGL markets of the Louisiana and Texas
gulf coast.
|
|
|
|
|
High quality and efficient assets. Our
gathering and processing systems consist of high quality assets
that have been well maintained, resulting in low cost, efficient
operations. We have implemented state of the art processing,
measurement and operations and maintenance technologies. These
technologies have allowed us to proactively manage our
operations with fewer field personnel resulting in lower costs
and minimal downtime. As a result, we believe we have
established a reputation in the midstream business as a reliable
and cost-effective supplier of services to our customers and
have a track record of safe and efficient operation of our
facilities.
|
|
|
|
Low maintenance capital expenditures. We
believe that a low level of maintenance capital expenditures is
sufficient for us to continue operations in a safe, prudent and
cost-effective manner.
|
|
|
|
Prudent hedging arrangements. While our
percent-of-proceeds gathering and processing contracts subject
us to commodity price risk, we have entered into long-term
hedges covering the commodity price exposure associated with a
significant portion of our near to mid-term expected equity gas,
condensate and NGL volumes. This strategy reduces volumetric
risk while managing commodity price risk related to these
arrangements. We manage our business by hedging the commodity
price exposure associated with a significant portion of our
expected equity volumes of natural gas and NGLs in the near to
mid-term.
|
|
|
|
Strong producer customer base. We have a
strong producer customer base consisting of both major oil and
gas companies and independent producers. We believe we have
established a reputation as a reliable operator by providing
high quality services and focusing on the needs of our
customers. Targa also has relationships throughout the energy
industry, including with producers of natural gas in the United
States, and has established a positive reputation in the energy
business which we believe will assist us in our primary business
objectives.
|
|
|
|
Comprehensive package of midstream
services. We provide a comprehensive package of
services to natural gas producers, including natural gas
gathering, compression, treating, processing and NGL
fractionating. We believe our ability to provide all of these
services provides us with an advantage in competing for new
supplies of natural gas because we can provide substantially all
of the services producers, marketers and others require to move
natural gas and NGLs from wellhead to market on a cost-effective
basis.
|
|
|
|
Experienced management team. Targa has an
experienced and knowledgeable executive management team with an
average of 28 years in the energy industry that owns a 3.4%
direct and indirect ownership interest in us. Targas
executive management team has a proven track record of enhancing
value through the acquisition, optimization and integration of
midstream assets. In addition, Targas operations and
commercial management team consists of individuals with an
average of of approximately 25 years of midstream operating
experience. Our relationship with Targa provides us with access
to significant operational, commercial, technical, risk
management and other expertise.
|
While we have set forth our strategies and competitive strengths
above, our business involves numerous risks and uncertainties
which may prevent us from executing our strategies. These risks
include the adverse impact of changes in natural gas and NGL
prices on the amount we are able to distribute to you, our
inability to access sufficient additional production to replace
natural declines in production and our dependence on a single
natural gas producer for a significant portion of our natural
gas supply. For a more complete description of the risks
associated with an investment in us, please see
Item 1A. Risk Factors.
7
Our
Relationship with Targa Resources, Inc.
One of our principal strengths is our relationship with Targa, a
leading provider of midstream natural gas and NGL services in
the United States. Targa was formed in 2004 by its management
team, which consists of former members of senior management of
several midstream and other diversified energy companies, and
Warburg Pincus LLC (Warburg Pincus), a private
equity firm. In April 2004, Targa purchased the SAOU and LOU
Systems from ConocoPhillips Company
(ConocoPhillips), for $247 million and, in
October 2005, Targa purchased substantially all of the midstream
assets of Dynegy, Inc. and its affiliates (Dynegy),
for approximately $2.5 billion. These transactions formed a
large-scale, integrated midstream energy company with the
ability to offer a wide range of midstream services to a diverse
group of natural gas and NGL producers and customers. At
December 31, 2007, Targa had total assets of
$3.8 billion (including the assets of the Partnership,
which represent $1.5 billion of this amount).
Targas businesses include:
Natural Gas Gathering and Processing Division
Targa gathers and processes natural gas from the Permian
Basin in west Texas and southeast New Mexico and the offshore
regions of the Texas and Louisiana Gulf Coast. Most of the NGLs
Targa processes are supplied through its gathering systems
which, in aggregate, consist of approximately 11,000 miles
of natural gas pipelines. The remainder is supplied through
third party owned pipelines. Targas processing plants
include nine facilities that it operates (either wholly or
jointly) as well as six facilities in which it has an ownership
interest but are operated by others. For the year ended
December 31, 2007, these assets processed an average inlet
plant volume of approximately 2 Bcf/d of natural gas and
produced an average of approximately 107 MBbls/d of NGLs,
in each case, net to Targas ownership interests.
NGL Logistics and Marketing Division Targa
has a significant, integrated NGL logistics and marketing
business with 16 storage, marine and transport terminals with an
NGL above ground storage capacity of approximately
900 MBbls, net NGL fractionation capacity of
approximately 300 MBbls/d and 43 owned and operated storage
wells with a net storage capacity of approximately
62 MMBbl. This division uses its extensive platform of
integrated assets to fractionate, store, terminal, transport,
distribute and market NGLs, typically under fee-based and
margin-based arrangements. Its assets are generally connected to
and supplied, in part, by its Natural Gas Gathering and
Processing assets and are primarily located in southwest
Louisiana and near Mont Belvieu, Texas, the primary NGL hub in
the United States. Targa owns, operates or leases assets in a
number of other states, including Alabama, Nevada, California,
Florida, Mississippi, Tennessee, New Jersey and Kentucky. The
geographic diversity of Targas assets provides it direct
access to many NGL end-users in both its geographic markets as
well as markets outside its operating regions via open-access
regulated NGL pipelines owned by third parties. Targa also owns
21 pressurized NGL barges, leases approximately 80 transport
tractors and owns 100 tank trailers, and leases and manages
approximately 800 railcars.
Targa has indicated that it intends to use us as a growth
vehicle to pursue the acquisition and expansion of midstream
natural gas, NGL and other complementary energy businesses and
assets. Over time, Targa intends to offer us the opportunity to
purchase substantially all of its remaining businesses, although
it is not obligated to do so. While Targa believes it will be in
its best interest to contribute additional assets to us given
its significant ownership of limited and general partner
interests in us, Targa constantly evaluates acquisitions and
dispositions and may elect to acquire, construct or dispose of
midstream assets in the future without offering us the
opportunity to purchase or construct those assets. We cannot say
with any certainty which, if any, opportunities to acquire
assets from Targa may be made available to us or if we will
choose to pursue any such opportunity. Moreover, Targa is not
prohibited from competing with us and constantly evaluates
acquisitions and dispositions that do not involve us. In
addition, through our relationship with Targa, we have access to
a significant pool of management talent, strong commercial
relationships throughout the energy industry and access to
Targas broad operational, commercial, technical, risk
management and administrative infrastructure.
Targa has a significant indirect interest in our partnership
through its ownership of a 24.5% limited partner interest and a
2% general partner interest in us. In addition, Targa owns
incentive distribution rights
8
that entitle Targa to receive an increasing percentage of
quarterly distributions of available cash from operating surplus
after the minimum quarterly distribution and the target
distribution levels have been achieved. We are party to an
Omnibus Agreement with Targa that governs our relationship with
them regarding certain reimbursement and indemnification
matters. Please see Item 13. Certain Relationships
and Related Transactions, and Director Independence
Omnibus Agreement. In addition, to carry out operations,
our general partner and its affiliates, which are indirectly
owned by Targa, employ approximately 920 people, some of
whom provide direct support to our operations. We do not have
any employees. Please see Item 1.
Business Employees.
While our relationship with Targa is a significant advantage, it
is also a source of potential conflicts. For example, Targa is
not restricted from competing with us. Targa owns substantial
midstream assets and may acquire, construct or dispose of
midstream or other assets in the future without any obligation
to offer us the opportunity to purchase or construct those
assets. Please see Item 13. Certain
Relationships and Related Transactions, and Director
Independence Conflicts of Interest.
Midstream
Sector Overview
General. Natural gas gathering and processing
is a critical part of the natural gas value chain. Natural gas
gathering and processing systems create value by collecting raw
natural gas from the wellhead and separating dry gas (primarily
methane) from NGL such as ethane, propane, normal butane,
isobutane and natural gasoline. Most natural gas produced at the
wellhead contains NGL. Natural gas produced in association with
crude oil typically contains higher concentrations of NGL than
natural gas produced from gas wells. This rich,
unprocessed natural gas is generally not acceptable for
transportation in the nations interstate transmission
pipeline system or for commercial use. Processing plants extract
the NGL, leaving residual dry gas that meets interstate
transmission pipeline and commercial quality specifications.
Furthermore, they produce marketable NGL, which, on an energy
equivalent basis, usually have a greater economic value as a raw
material for petrochemicals and motor gasolines than as a
component of the natural gas stream.
9
Gathering. At the initial stages of the
midstream value chain, a network of typically small diameter
pipelines known as gathering systems directly connect to
wellheads in the production area. These gathering systems
transport raw natural gas to a central location for processing
and treating. A large gathering system may involve thousands of
miles of gathering lines connected to thousands of wells.
Gathering systems are often designed to be highly flexible to
allow gathering of natural gas at different pressures, flowing
natural gas to multiple plants and quickly connecting new
producers, and most importantly scalable, to allow for
additional production without significant incremental capital
expenditures.
Compression. Since wells produce at
progressively lower field pressures as they deplete, it becomes
increasingly difficult to deliver the remaining production in
the ground against a higher pressure that exists in the
connecting gathering system. Natural gas compression is a
mechanical process in which a volume of natural gas at a given
pressure is compressed to a desired higher pressure, which
allows the natural gas to flow into a higher pressure system.
Field compression is typically used to allow a gathering system
to operate at a lower pressure or provide sufficient discharge
pressure to deliver natural gas into a higher pressure system.
If field compression is not installed, the remaining natural gas
in the ground will not be produced because it cannot overcome
the higher gathering system pressure. In contrast, if field
compression is installed, then a well can continue delivering
natural gas that otherwise would not be produced.
Treating and Dehydration. After gathering, the
second process in the midstream value chain is treating and
dehydration. Natural gas contains various contaminants, such as
water vapor, carbon dioxide and hydrogen sulfide, which can
cause significant damage to intrastate and interstate pipelines
and therefore render the gas unacceptable for transmission on
such pipelines. In addition, end-users will not purchase natural
gas with a high level of these contaminants. To meet downstream
pipeline and end-user natural gas quality standards, the
10
natural gas is dehydrated to remove the saturated water and is
chemically treated to separate the carbon dioxide and hydrogen
sulfide from the gas stream.
Processing. Once the contaminants are removed,
the next step involves the separation of pipeline quality
residue gas from NGL, a method known as processing. Most
decontaminated rich natural gas is not suitable for long-haul
pipeline transportation or commercial use and must be processed
to remove the heavier hydrocarbon components. The removal and
separation of hydrocarbons during processing is possible because
of the differences in physical properties between the components
of the raw gas stream. There are four basic types of natural gas
processing methods, including cryogenic expansion, lean oil
absorption, straight refrigeration and dry bed absorption.
Cryogenic expansion represents the latest generation of
processing, incorporating extremely low temperatures and high
pressures to provide the best processing and most economical
extraction.
Natural gas is processed not only to remove NGL that would
interfere with pipeline transportation or the end use of the
natural gas, but also to separate from the natural gas those
hydrocarbon liquids that could have a higher value as NGL than
as natural gas. The principal components of residue gas are
methane and ethane but processors typically have the option
either to recover ethane from the residue gas stream for
processing into NGL or reject ethane and leave it in the residue
gas stream, depending on whether the ethane is more valuable
being processed or left in the natural gas stream. The residue
gas is sold to industrial, commercial and residential customers
and electric utilities. The premium or discount in value between
natural gas and separated NGL is known as the frac
spread. Because NGL often serve as substitutes for
products derived from crude oil, NGL prices tend to move in
relation to crude prices.
Natural gas processing occurs under a contractual arrangement
between the producer or owner of the raw natural gas stream and
the processor. There are many forms of processing contracts
which vary in the amount of commodity price risk they carry. The
specific commodity exposure to natural gas or NGL prices is
highly dependent on the types of contracts. Processing contracts
can vary in length from one month to the life of the
field. Three typical processing contract types are
described below:
|
|
|
|
|
Percent-of-Proceeds, or Percent-of-Value or
Percent-of-Liquids. In a percent-of-proceeds
arrangement, the processor remits to the producers a percentage
of the proceeds from the sales of residue gas and NGL products
or a percentage of residue gas and NGL products at the tailgate
of its processing facilities. In some percent-of-proceeds
arrangements, the producer is paid a percentage of an index
price for residue gas and NGL products, less agreed adjustments,
rather than remitting a portion of the actual sales proceeds.
The percent-of-value and percent-of-liquids are variations on
this arrangement. These types of arrangements expose the
processor to some commodity price risk as the revenues from the
contracts are directly correlated with the price of natural gas
and NGL.
|
|
|
|
Keep-Whole. A keep-whole arrangement allows
the processor to keep 100% of the NGL produced and requires the
return of the processed natural gas, or value of the gas, to the
producer or owner. A wellhead purchase contract is a variation
of this arrangement. Since some of the gas is used during
processing, the processor must compensate the producer or owner
for the gas shrink entailed in processing by supplying
additional gas or by paying an agreed value for the gas
utilized. These arrangements have the highest commodity price
exposure for the processor because the costs are dependent on
the price of natural gas and the revenues are based on the price
of NGL. As a result, a processor with these types of contracts
benefits when the value of the NGL is high relative to the cost
of the natural gas and is disadvantaged when the cost of the
natural gas is high relative to the value of the NGL.
|
|
|
|
Fee-Based. Under a fee-based contract, the
processor receives a fee per gallon of NGL produced or per Mcf
of natural gas processed. Under this arrangement, a processor
would have no commodity price risk exposure.
|
Fractionation. Fractionation is the separation
of the heterogeneous mixture of extracted NGL into individual
components for end-use sale. Fractionation is accomplished by
controlling the temperature of the stream of mixed liquids in
order to take advantage of the difference in boiling points of
separate products. As the temperature of the stream is
increased, the lightest component boils off the top of the
distillation tower as
11
a gas where it then condenses into a purity liquid that is
routed to storage. The heavier components in the mixture are
routed to the next tower where the process is repeated until all
components have been separated. A typical barrel of NGL consists
of ethane, propane, normal butane, isobutane and natural
gasoline. Described below are the five basic NGL components and
their typical uses:
|
|
|
|
|
Ethane. Ethane is used primarily as feedstock
in the production of ethylene, one of the basic building blocks
for a wide range of plastics and other chemical products.
|
|
|
|
Propane. Propane is used as heating fuel,
engine fuel and industrial fuel, for agricultural burning and
drying and as petrochemical feedstock for production of ethylene
and propylene.
|
|
|
|
Normal Butane. Normal butane is principally
used for motor gasoline blending and as fuel gas, either alone
or in a mixture with propane, and feedstock for the manufacture
of ethylene and butadiene, a key ingredient of synthetic rubber.
Normal butane is also used to derive isobutane.
|
|
|
|
Isobutane. Isobutane is principally used by
refiners to enhance the octane rating of motor gasoline and in
the production of MTBE, an additive in cleaner burning motor
gasoline.
|
|
|
|
Natural Gasoline. Natural gasoline is
principally used as a motor gasoline blend stock or
petrochemical feedstock.
|
Transportation and Storage. Once the raw
natural gas has been conditioned or processed and the raw NGL
mix fractionated into individual NGL components, the natural gas
and NGL components are stored, transported and marketed to
end-use markets. Both the natural gas industry and the NGL
industry have hundreds of thousands of miles of intrastate and
interstate transmission pipelines in addition to a network of
barges, rails, trucks, terminals and storage to deliver natural
gas and NGL to market. The bulk of the NGL storage capacity is
located near the refining and petrochemical complexes of the
Texas and Louisiana Gulf Coasts, with a second major
concentration in central Kansas. Each commodity system typically
has storage capacity located both throughout the pipeline
network and at major market centers to help temper seasonal
demand and daily supply-demand shifts.
12
Our
Systems
The following tables set forth key ownership and operational
information regarding our operating gathering systems and
natural gas processing plants, all of which are 100% owned and
operated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate
|
|
|
Approximate
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Inlet
|
|
|
Approximate
|
|
|
|
|
|
Approximate
|
|
|
|
County/Parish -
|
|
Processing
|
|
|
Throughput
|
|
|
NGL
|
|
|
|
|
|
Fractionation
|
|
|
|
Approximate
|
|
Capacity
|
|
|
Volume
|
|
|
Production
|
|
|
Process
|
|
|
Capacity
|
|
Facility
|
|
Square Miles
|
|
(MMcf/d)
|
|
|
(MMcf/d)
|
|
|
(MBbl/d)
|
|
|
Type
|
|
|
(MBbl/d)
|
|
|
Permian Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mertzon
|
|
Irion, TX
|
|
|
48
|
|
|
|
39.9
|
|
|
|
6.2
|
|
|
|
Cryo(2
|
)
|
|
|
N/A
|
|
Sterling
|
|
Sterling, TX
|
|
|
62
|
|
|
|
48.6
|
|
|
|
7.9
|
|
|
|
Cryo(2
|
)
|
|
|
N/A
|
|
Conger(1)
|
|
Sterling, TX
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
Cryo(2
|
)
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering Area
|
|
10 counties - 4,000 square miles
|
|
|
135
|
|
|
|
88.5
|
|
|
|
14.1
|
|
|
|
|
|
|
|
|
|
Louisiana Gulf Coast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gillis
|
|
Calcasieu, LA
|
|
|
180
|
|
|
|
149.4
|
|
|
|
8.6
|
|
|
|
Cryo(2
|
)
|
|
|
13
|
|
Acadia
|
|
Acadia, LA
|
|
|
80
|
|
|
|
28.9
|
|
|
|
1.5
|
|
|
|
Cryo(2
|
)
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering Area
|
|
12 parishes - 3,800 square miles
|
|
|
260
|
|
|
|
178.3
|
|
|
|
10.1
|
|
|
|
|
|
|
|
13
|
|
North Texas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chico
|
|
Wise, TX
|
|
|
265
|
|
|
|
152.1
|
|
|
|
17.2
|
|
|
|
Cryo(2
|
)
|
|
|
12
|
|
Shackelford
|
|
Shackelford, TX
|
|
|
13
|
|
|
|
10.3
|
|
|
|
1.3
|
|
|
|
Cryo(2
|
)
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering Area
|
|
14 counties - 2,500 square miles
|
|
|
278
|
|
|
|
162.4
|
|
|
|
18.5
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gathering and Processing
|
|
|
|
|
673
|
|
|
|
429.2
|
|
|
|
42.7
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The Conger plant is not currently operating, but is on standby
and can be quickly reactivated on short notice to meet
additional needs for processing capacity.
|
|
|
(2)
|
Cryo Cryogenic Expander.
|
The North
Texas System
The North Texas System consists of two gathering systems
connected via a high-pressure
32-mile,
10-inch
diameter pipeline (the Interconnect Pipeline). This
interconnection between the gathering systems allows us to send
natural gas in excess of the Shackelford plant processing
capacity to the Chico plant. The gathering systems comprise
approximately 4,000 miles of pipelines that, in aggregate,
gather wellhead natural gas from approximately 2,700 meters for
transport to the Chico and Shackelford natural gas processing
facilities.
Gathering. The Chico Gathering System consists
of approximately 1,950 miles of primarily low pressure
gathering pipelines, which gathers natural gas from Denton,
Montague, Wise, Clay, Jack, Palo Pinto and Parker counties on
the eastern part of the North Texas System. The natural gas that
is gathered on the Chico Gathering System is either delivered
directly to the Chico plant, where it is compressed for
processing, or is compressed in the field at approximately 26
compressor stations and then transported via one of several
high-pressure gathering pipelines to the Chico plant.
The Shackelford Gathering System consists of approximately
2,050 miles of natural gas gathering pipelines, which
gathers natural gas from Jack, Palo Pinto, Archer, Young,
Stephens, Eastland, Throckmorton, Shackelford and Haskell
counties on the western part of the North Texas System. The
western and southern portions of the Shackelford Gathering
System gather natural gas that is transported on
intermediate-pressure gathering pipelines to the Shackelford
plant. The approximately
15 MMcf/d
of natural gas gathered from the northern and eastern portions
of the Shackelford Gathering System are typically transported on
the
13
Interconnect Pipeline to the Chico plant for processing. This
natural gas is compressed at approximately 11 compressor
stations to achieve sufficient pressure to enter the high
pressure Interconnect Pipeline.
For the year ended December 31, 2007, the North Texas
System gathered approximately
168 MMcf/d
of natural gas.
Processing. The Chico processing plant is
located in Wise County, Texas, approximately 45 miles
northwest of Fort Worth, Texas. The Chico processing plant
includes a state-of-the-art cryogenic processing train with a
nameplate capacity of approximately
150 MMcf/d
that was installed in 2002 and that has operated at throughputs
of up to approximately
165 MMcf/d.
The Chico processing plants capacity was expanded by
100 MMcf/d
in 2006, with the refurbishment of an idle processing train.
Refrigeration capacity is currently installed to operate this
train at full cryogenic recovery at half capacity or lower
recoveries at higher volumes. This refurbished processing train
ran at full capacity in June of 2007 during a turnaround of the
primary processing train (the
165 MMcf/d
train) at Chico. An additional electric drive refrigeration
compressor that is
on-site will
be installed when needed, which will allow the refurbished
processing train to recover NGLs up to its full design capacity.
The Chico plant also includes a residue recompression turbine
waste heat recovery system, which increases operating
efficiency. The Chico plant also includes an NGL fractionator
with the capacity to fractionate up to approximately
11,500 Bbls/d of raw NGL mix. This fractionation capability
allows the Chico facility to deliver raw NGL mix to Mont Belvieu
primarily through Chevrons WTLPG Pipeline or separated NGL
products to local markets via truck.
Results of drilling in some areas such as Montague County
indicate an increase in the carbon dioxide content of the gas.
In response to this increase in carbon dioxide, we are
refurbishing a carbon dioxide treater which will increase the
Co2 removal capacity to 4,200 Mcf/day.
The Shackelford natural gas processing plant is located in
Shackelford County, Texas near Albany, Texas which is
approximately 120 miles west of Fort Worth, Texas. The
Shackelford plant is a cryogenic plant with a nameplate capacity
of approximately
15 MMcf/d,
but effective capacity is limited to approximately
13 MMcf/d
due to capacity constraints on the residue gas pipeline that
serves the facility.
Market Access. The Chico processing
plants location in northeastern Wise County provides us
and producers with several options for both NGL and residue gas
delivery. The primary outlet for NGLs is Chevrons WTLPG
Pipeline which delivers volumes from the Chico plant to Mont
Belvieu for fractionation. NGL products produced at the Chico
processing facility can be transported via truck to local or
other markets. For 2007, approximately 409,000 gallons per day
of NGLs were delivered from the Chico processing facility by
pipeline and approximately 124,000 gallons per day of NGL
products were delivered from the Chico processing facility by
truck.
Low pressure condensate is composed of heavy hydrocarbons which
condense in the gathering system and are collected in low
pressure separators associated with field compressors and in low
pressure separators upstream of the processing plants. This
product is collected and shipped by truck from various locations
in the system and sold as condensate at oil related index
prices. High pressure condensate is a mix of intermediate and
heavy hydrocarbons which condense in the high pressure gathering
lines between the compressor stations and the processing plants.
This condensate is collected in high pressure separators prior
to the plant and shipped via high pressure trucks to an
injection point on the WTLPG Pipeline at Bridgeport for shipment
to Mont Belvieu, where it is sold as NGLs. Occasionally, this
high pressure condensate product is shipped via truck directly
to Mont Belvieu.
Our connections to multiple interstate and intrastate natural
gas pipelines give the Chico plant and its customers the ability
to maximize realized prices by accessing major trading hubs and
end-use markets throughout the Gulf Coast, Midwest and northeast
regions of the United States. Currently, residue gas is shipped
via the:
|
|
|
|
|
Natural Gas Pipeline Company of America which is owned by Kinder
Morgan, Inc. and serves the Midwest, specifically the Chicago
market;
|
14
|
|
|
|
|
ET Fuel System which is owned by Energy Transfer Partners, L.P.
and has access to the Waha, Carthage and Katy hubs in Texas;
|
|
|
|
Atmos Pipeline Texas (Atmos-Texas) which
is owned by Atmos Energy Corporation and has access to the Waha,
Carthage and Katy hubs in Texas; and
|
|
|
|
Enbridge Pipelines (North Texas) L.P. which is owned by Enbridge
Energy Partners, L.P. and has access to several local residue
gas markets.
|
Residue natural gas from the Shackelford processing plant is
delivered to the Carthage and Katy hubs on Atmos-Texas and NGLs
from the plant are delivered to Mont Belvieu on the WTLPG
Pipeline. Condensate from the Shackelford System is handled
similarly to the description above for the Chico System.
Targa Intrastate Pipeline. Targa Intrastate
Pipeline LLC (Targa Intrastate), our wholly-owned
subsidiary, holds a
41-mile,
6-inch
diameter intrastate pipeline that transports natural gas from
the Shackelford processing plant to an interconnect with
Atmos-Texas and a 1.65 mile,
10-inch
diameter intrastate pipeline that transports natural gas through
part of the Chico System in Denton County, Texas. Targa
Intrastate is regulated by the Railroad Commission of Texas
(RRC).
Competition. In North Texas, our gathering,
processing and fractionation system competes with several
systems located in the Fort Worth Basin. Our competitors
include but are not limited to gathering and processing systems
owned by Devon Energy Corp (Devon), Enbridge Energy
Partners, L.P. (Enbridge),
J-W
Operating Company, Davis Gas Processing Inc., Hanlon Gas
Processing, Ltd. and Upham Oil and Gas Company. A number of the
gathering and processing competitors in the region are smaller
entities with assets serving a particular field, producer or
limited area but lack a basin-wide presence. As for the larger
competitors, Devon and Enbridges operations are the most
extensive and are closest in proximity to our area of
operations, based on publicly available information.
Devons processing capacity is greater than ours, while
Enbridges is approximately the same. Currently, Devon
almost exclusively gathers and processes its own production.
Competition within the Fort Worth Basin may increase as new
ventures are formed or as existing competitors expand their
operations. Competitive factors include processing and fuel
efficiencies, operational costs, commercial terms offered to
producers and capital expenditures required for new producer
connections, along with the location and available capacity of
gathering systems and processing plants.
Customers and Contracts. The North Texas
System gathers and processes natural gas for approximately 430
customers. For the year ended December 31, 2007, natural
gas received from ConocoPhillips represented approximately 33%
of the North Texas System volumes. No other customer represented
over 10% of the North Texas System volumes. This diverse
customer base enhances the stability of our volumes.
In North Texas, we have a long-term strategic relationship with
ConocoPhillips, which is our largest producer by volume. Subject
to limited exceptions, substantially all of ConocoPhillips
current production from leases covering an approximately
30,000 acre area in Wise and Denton counties has been
committed to us for gathering and processing through a prior
agreement with Burlington Resources entities. ConocoPhillips is
under no obligation to deliver minimum volumes or to continue to
develop its leasehold position under its agreement with us. This
commitment extends through 2015, with a ten year renewal, at
ConocoPhillips option. The North Texas System has no other
significant customers. Our producer contracts in north Texas are
primarily percent-of-proceeds and most have a remaining term
greater than 3 years or a term for life-of-lease. A portion
of our existing contracts on the North Texas System are in the
evergreen portion of their term, meaning that the original term
of these contracts has expired and that they will continue to
roll-over on an on-going basis until either party elects to
discontinue the contract. Our experience is that we retain, and
sometimes renegotiate, essentially all of these contracts.
The SAOU
System
The SAOU System consists of approximately 1,350 miles of
pipeline in the Permian Basin of west Texas and the Mertzon,
Sterling and Conger processing plants. The broad geographic
scope of the SAOU System, covering portions of 10 counties and
approximately 4,000 square miles in west Texas, and
proximity to
15
production and development provides us the ability to connect
new wells and to process additional natural gas in our existing
processing plants.
Gathering. The SAOU System is connected to
approximately 3,000 producing wells
and/or
central delivery points. For the year ended December 31,
2007, the system gathered approximately
94 MMcf/d
of natural gas. The system has approximately 850 miles of
low-pressure gathering systems. The system also contains
approximately 500 miles of high-pressure gathering
pipelines to deliver the natural gas to its processing plants.
The gathering system has 27 compressor stations to inject
low-pressure gas into these high-pressure pipelines.
Processing. The SAOU System includes two
currently operating processing plants. The Mertzon plant and the
Sterling plant, both of which are refrigerated cryogenic plants,
have aggregate processing capacity of approximately
110 MMcf/d.
The system also includes the Conger cryogenic plant with a
capacity of approximately
25MMcf/d,
which is on standby and can be quickly reactivated on short
notice to meet additional needs for processing capacity.
Market Access. The Mertzon processing plant
currently delivers residue gas to Kinder Morgan Texas Pipeline,
L.P.s Rancho pipeline and to Northern Natural Gas Company.
NGLs produced by the plant are delivered to a pipeline owned by
TEPPCO Partners, L.P. that transports the NGLs to Cedar
Bayou Fractionators (CBF, in which Targa owns an
interest) located at the Mont Belvieu hub. The Sterling
processing plant has residue gas connections to pipelines owned
by affiliates of Atmos Energy Corporation, El Paso Natural
Gas Company, ONEOK and Enterprise Products Partner LP
(Enterprise)/ET Fuel Pipeline, L.P., and NGLs
are delivered to the West Texas LPG pipeline, owned by Chevron,
which also delivers to CBF at the Mont Belvieu hub.
Competition. The SAOU System competes
primarily with Davis Gas Processing to the south and southwest,
DCP Midstream LLC to the north and Atlas Gas Pipeline Company,
formerly Western Gas Resources, Inc., to the west. Several of
the processing plants that compete with the SAOU System are very
near or at full capacity. The SAOU System, with its remaining
excess capacity of approximately
20 MMcf/d
at the Sterling and Mertzon plants and
25 MMcf/d
available for reactivation at the Conger plant, has the ability
to process new volumes of gas in proximity to its gathering
system without requiring significant capital expenditures.
Consistent with other gathering and processing systems,
competitive factors for the SAOU System include processing and
fuel efficiencies, operational costs, commercial terms offered
to producers and capital expenditures required for new producer
connections, along with the location and available capacity of
gathering systems and processing plants.
Customers and Contracts. For the year ended
December 31, 2007, the SAOU Systems major customers
include Range Production Company, TXP, Inc. and Chevron,
representing approximately 25%, 18% and 15% of the SAOU
Systems volumes. No other customer represented more than
10% of the SAOU Systems volumes. The producer contracts
under which the SAOU System operates are primarily
percent-of-proceeds based contracts and most have a remaining
term greater than 3 years. A portion of our existing
contracts on the SAOU System are in the evergreen portion of
their term. Our experience is that we retain, and sometimes
renegotiate, essentially all of these contracts.
The LOU
System
The LOU System consists of approximately 600 miles of
gathering system pipelines, covering approximately
3,800 square miles in southwest Louisiana between Lafayette
and Lake Charles, the Gillis and Acadia processing plants and an
intrastate pipeline system.
Gathering. The LOU System is connected to
approximately 200 producing wells
and/or
central delivery points in the area between Lafayette and Lake
Charles, Louisiana. The gathering system is a high-pressure
gathering system that delivers natural gas for processing to
either the Acadia or Gillis plants via three main trunk lines.
For the year ended December 31, 2007, the gathering system
gathered approximately
191 MMcf/d
of natural gas.
16
Processing. The processing plants are the
Gillis and Acadia processing plants. The Gillis plant is a
refrigerated cryogenic plant. These processing plants have an
aggregate processing capacity of approximately
260 MMcf/d.
Natural gas can be readily moved between the Gillis and Acadia
plants in order to optimize operational efficiencies, meet
customer needs and improve profitability.
Raw NGL mix from the Acadia plant is transported to, and
combined with raw NGL mix from the Gillis plant via the
systems pipelines, with fractionation occurring at the
integrated fractionation facility at the Gillis plant. Excess
raw NGL mix can also be transported to Targas Lake Charles
fractionation facility. The operating capacity of the Gillis
fractionator is approximately 13 MBbls/d. Component NGL
products are delivered from the Gillis fractionator via the
systems pipelines to local or other markets via pipeline,
truck and/or barge.
Market Access. The residue gas produced from
the processing plants has direct access to the Lake Charles
industrial market through the systems intrastate pipeline
system. This intrastate system has the ability to deliver
natural gas to industrial users and electric utilities in the
Lake Charles area, which currently consume approximately
500 MMcf/d
of natural gas, through both medium-pressure and high-pressure
pipelines. As a result of the flexibility of these intrastate
pipeline assets and the reliability of the systems natural
gas supplies in the area, the system has a significant market
share in the Lake Charles industrial market. Most of the major
customers have contracts with terms of one year or more; the
remainder are multi-month contracts. In addition to access to
the Lake Charles market, the Acadia plant also has the ability
to deliver high-pressure residue gas to attractive markets
throughout the United States by accessing the Trunkline,
Transco, Tennessee, Columbia Gulf and GulfSouth pipelines. The
location of the intrastate pipeline serving the Lake Charles
market and the ability of LOUs gathering system to
interconnect with other pipelines carrying processable gas,
positions the LOU System and the market to benefit from other
supply sources, including imported LNG. Currently, there are a
number of LNG regasification plants that are either operating or
have been approved by either the Federal Energy Regulatory
Commission (FERC) or Coast Guard for construction
along the Gulf Coast in close proximity to the system.
Competition. The LOU System is crossed by
numerous interstate and intrastate pipelines. The primary
competition for wellhead gas production is with the intrastate
pipeline systems owned by Crosstex Gulf Coast Marketing, LTD
(Crosstex) and Enterprise along the eastern portion
of the LOU System, particularly in Lafayette and Vermilion
Parishes. The LOU System has traditionally been viewed favorably
by producers for quick, reliable connections and flexible
purchase and processing options. Interstate pipelines generally
bringing gas from offshore, although more numerous and more
broadly situated across southwest Louisiana, provide some level
of competition but are not considered to be pipelines preferred
by onshore producers due to high connection costs, longer lead
times for connections and agreements, and more restrictive
quality requirements. For the industrial customers in the Lake
Charles Market, the primary competitors include GulfSouth
Pipeline Company, LP, which utilizes local production as well as
LNG sourced gas, Varibus Pipeline, utilizing connections to four
interstate pipelines, and a Texaco/Chevron pipeline delivering
gas from an interstate pipeline. The LOU System has a long
history of providing reliable supply for these industrial
customers. Consistent with other gathering and processing
systems, competitive factors for the LOU System include
processing and fuel efficiencies, operational costs, commercial
terms offered to producers and capital expenditures required for
new producer connections, along with the location and available
capacity of gathering systems and processing plants.
Customers and Contracts. For the year ended
December 31, 2007, no individual producer represented more
than 10% of the LOU Systems volumes. The LOU Systems
producer contract mix is primarily percent-of-liquids
(approximately 57% by volume) and to a lesser extent short term
wellhead purchase and keep whole contracts (approximately 43% by
volume). In addition, there is a gas gatherer who is a
significant supplier to the system and sells gas to us on a spot
basis. This gatherer delivered approximately 26% of the LOU
Systems volumes in 2007. The LOU Systems industrial
customers ability to readily burn richer (higher Btu) gas
provides the system with operational and commercial flexibility
to process less NGLs from the gas stream. Unlike almost any
other gathering and processing system, the Gillis plant has a
residue tailgate that directly serves the Lake Charles
industrial market and this market readily and easily burns
higher Btu gas (more NGLs left in the gas stream). If NGL prices
are significantly lower than their value as natural gas, then we
have the
17
ability to not remove the NGLs, selling them instead in the
natural gas stream. A majority of our existing contracts on the
LOU System are in the evergreen portion of their term. Our
experience is that we retain, and renegotiate, essentially all
of these contracts.
The Combined Systems. Our aggregate gas supply
contract profile for the year ended December 31, 2007 is
approximately 79% percent-of-proceeds contracts, approximately
19% wellhead purchase/keep whole contracts, approximately 1%
fee-based contracts on a volume basis and approximately 1%
hybrid contracts. Substantially all of the wellhead and
keep-whole contracts are associated with a portion of the LOU
Systems contracts. The LOU Systems industrial
customers that burn the Gillis plant residue gas readily burn
richer (higher Btu) gas, thereby providing the system with
operational and commercial flexibility to process less NGLs from
the gas stream if unexpected operating conditions occur or if
NGLs are more valuable as natural gas. Such volumes are
typically under short term contracts. The above factors mitigate
the commodity price risk typically associated with wellhead
purchase or keep-whole contracts. In addition, our largest
natural gas suppliers for the year ended December 31, 2007
were ConocoPhillips and Crosstex, who accounted for
approximately 12% and 11%, respectively, of our supply.
Approximately half of the gas supply contracts by volume have a
remaining term greater than 3 years, a term for life of
lease, or have been in evergreen status for more than three
years.
Regulation
of Operations
Regulation of pipeline gathering and transportation services,
natural gas sales and transportation of NGLs may affect certain
aspects of our business and the market for our products and
services.
Gathering
Pipeline Regulation
Our natural gas gathering operations are subject to ratable take
and common purchaser statutes in the states in which we operate.
The common purchaser statutes generally require our gathering
pipelines to purchase or take without undue discrimination as to
source of supply or producer. These statutes are designed to
prohibit discrimination in favor of one producer over another
producer or one source of supply over another. The regulations
under these statutes can have the effect of imposing some
restrictions on our ability as an owner of gathering facilities
to decide with whom we contract to gather natural gas. The
states in which we operate have adopted complaint-based
regulation of natural gas gathering activities, which allows
natural gas producers and shippers to file complaints with state
regulators in an effort to resolve grievances relating to
gathering access and rate discrimination. The rates we charge
for gathering are deemed just and reasonable unless challenged
in a complaint. We cannot predict whether such a complaint will
be filed against us in the future. Failure to comply with state
regulations can result in the imposition of administrative,
civil and criminal penalties.
Section 1(b) of the Natural Gas Act of 1938
(NGA), exempts natural gas gathering
facilities from regulation by FERC as a natural gas company
under the NGA. We believe that the natural gas pipelines in our
gathering systems meet the traditional tests FERC has used to
establish a pipelines status as a gatherer not subject to
regulation as a natural gas company. However, 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. Natural gas
gathering may receive greater regulatory scrutiny at both the
state and federal levels now that FERC has taken a more
light-handed approach to regulation of the gathering activities
of interstate pipeline transmission companies and a number of
such companies have transferred gathering facilities to
unregulated affiliates. Our natural gas gathering operations
could be adversely affected should they be subject to more
stringent application of state or federal regulation of rates
and services. Our natural gas gathering operations also may be
or become subject to additional 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 are 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.
18
During the 2007 legislative session, the Texas State Legislature
passed H.B. 3273 (the Competition Bill) and H.B.
1920 (the LUG Bill). The Competition Bill gives the
RRC the ability to use either a cost-of-service method or a
market-based method for setting rates for natural gas gathering
and transportation pipelines in formal rate proceedings. It also
gives the RRC specific authority to enforce its statutory duty
to prevent discrimination in natural gas gathering and
transportation, to enforce the requirement that parties
participate in an informal complaint process and to punish
purchasers, transporters, and gatherers for taking
discriminatory actions against shippers and sellers. The
Competition Bill also provides producers with the unilateral
option to determine whether or not confidentiality provisions
are included in a contract to which a producer is a party for
the sale, transportation, or gathering of natural gas. The LUG
Bill modifies the informal complaint process at the RRC with
procedures unique to lost and unaccounted for gas issues. It
extends the types of information that can be requested and
provides the RRC with the authority to make determinations and
issue orders in specific situations. Both the Competition Bill
and the LUG Bill became effective September 1, 2007. We
cannot predict what effect, if any, either the Competition Bill
or the LUG Bill might have on our operations in Texas.
Intrastate
Pipeline Regulation
Our Texas intrastate pipeline, Targa Intrastate, owns the
intrastate pipeline that transports natural gas from our
Shackelford processing plant to an interconnect with Atmos-Texas
that in turn delivers gas to the West Texas Utilities
Companys Paint Creek Power Station. Targa Intrastate also
owns a 1.65 mile,
10-inch
diameter intrastate pipeline that transports natural gas from a
third party gathering system into the Chico System in Denton,
County, Texas. Targa Intrastate has a tariff on file with the
RRC.
Our Louisiana intrastate pipeline, Targa Louisiana Intrastate
LLC, owns an approximately
60-mile
intrastate pipeline system that receives all of the natural gas
it transports within or at the boundary of the State of
Louisiana. Because all such gas ultimately is consumed within
Louisiana, and since the pipelines rates and terms of
service are subject to regulation by the Office of Conservation
of the Louisiana Department of Natural Resources
(DNR), the pipeline qualifies as a Hinshaw pipeline
under Section 1(c) of the NGA and thus is exempt from most
FERC jurisdiction.
Our intrastate NGL pipelines in Louisiana, gather raw NGL
streams that we own from our processing plants in Louisiana to
our fractionator in Lake Charles, Louisiana, where the raw NGL
streams are fractionated into various products. These pipelines
are not subject to FERC regulation or rate regulation by the
DNR, but are regulated by DOT safety regulations.
Texas and Louisiana have adopted complaint-based regulation of
intrastate natural gas transportation activities, which allows
natural gas producers and shippers to file complaints with state
regulators in an effort to resolve grievances relating to
pipeline access and rate discrimination. The rates we charge for
intrastate transportation are deemed just and reasonable unless
challenged in a complaint. We cannot predict whether such a
complaint will be filed against us in the future. Failure to
comply with state regulations can result in the imposition of
administrative, civil and criminal penalties.
As discussed above in the context of Gathering Pipeline
Regulation, the Competition Bill and the LUG Bill also contain
provisions applicable to intrastate transportation pipelines. We
cannot predict what effect, if any, either the Competition Bill
or the LUG Bill might have on our operations in Texas.
Natural
Gas Processing
Our natural gas processing operations are not presently subject
to FERC regulation. However, there can be no assurance that our
processing operations will continue to be exempt from FERC
regulation in the future.
Our processing facilities are affected by the availability,
terms and cost of pipeline transportation. As noted above, the
price and terms of access to pipeline transportation can be
subject to extensive federal regulations, and in Texas and
Louisiana, if a complaint is filed, state regulation. FERC is
continually proposing and implementing new rules and regulations
affecting the interstate transportation of natural gas, and to a
lesser extent, the interstate transportation of NGLs. These
initiatives also may indirectly affect the intrastate
19
transportation of natural gas and NGLs under certain
circumstances. We cannot predict the ultimate impact of these
regulatory changes to our processing operations.
The ability of our processing facilities and pipelines to
deliver natural gas into third party natural gas pipeline
facilities is directly impacted by the gas quality
specifications required by those pipelines. On June 15,
2006, FERC issued a policy statement on provisions governing gas
quality and interchangeability in the tariffs of interstate gas
pipeline companies and a separate order declining to set generic
prescriptive national standards. FERC strongly encouraged all
natural gas pipelines subject to its jurisdiction to adopt, as
needed, gas quality and interchangeability standards in their
FERC gas tariffs modeled on the interim guidelines issued by a
group of industry representatives, headed by the Natural Gas
Council (the NGC+ Work Group), or to explain how and
why their tariff provisions differ. We do not believe that the
adoption of the NGC+ Work Groups gas quality interim
guidelines by a pipeline that either directly or indirectly
interconnects with our facilities would materially affect our
operations. We have no way to predict, however, whether FERC
will approve of gas quality specifications that materially
differ from the NGC+ Work Groups interim guidelines for
such an interconnecting pipeline.
Sales
of Natural Gas and NGLs
The price at which we buy and sell natural gas and NGLs is
currently not subject to federal regulation and, for the most
part, is not subject to state regulation. However, with regard
to our physical purchases and sales of these energy commodities,
and any related hedging activities that we undertake, we are
required to observe anti-market manipulation laws and related
regulations enforced by the FERC
and/or the
Commodity Futures Trading Commission (CFTC). Should
we violate the anti-market manipulation laws and regulations, we
could also be subject to related third party damage claims by,
among others, sellers, royalty owners and taxing authorities.
Our sales of natural gas and NGLs are affected by the
availability, terms and cost of pipeline transportation. As
noted above, the price and terms of access to pipeline
transportation can be subject to extensive federal and, if a
complaint is filed, state regulation. FERC is continually
proposing and implementing new rules and regulations affecting
the interstate transportation of natural gas, and to a lesser
extent, the interstate transportation of NGLs. These initiatives
also may indirectly affect the intrastate transportation of
natural gas and NGLs under certain circumstances. We cannot
predict the ultimate impact of these regulatory changes to our
natural gas and NGL marketing operations, and we do not believe
that we would be affected by any such FERC action materially
differently than other natural gas and NGL marketers with whom
we compete.
Other
State and Local Regulation of Our Operations
Our business activities are subject to various state and local
laws and regulations, as well as orders of regulatory bodies
pursuant thereto, governing a wide variety of matters, including
marketing, production, pricing, community right-to-know,
protection of the environment, safety and other matters. For
additional information regarding the potential impact of
federal, state or local regulatory measures on our business,
please see Item 1A. Risk Factors Risks
Related to Our Business.
Other
Federal Laws and Regulation Affecting Our
Industry
Energy
Policy Act of 2005
On August 8, 2005, President Bush signed into law the
Domenici-Barton Energy Policy Act of 2005 (EP Act
2005). The EP Act 2005 is a comprehensive compilation of
tax incentives, authorized appropriations for grants and
guaranteed loans, and significant changes to the statutory
policy that affects all segments of the energy industry. Among
other matters, EP Act 2005 amends the NGA to add an anti-market
manipulation provision which makes it unlawful for any entity to
engage in prohibited behavior to be prescribed by FERC, and
furthermore provides FERC with additional civil penalty
authority. The EP Act 2005 provides the FERC with the power to
assess civil penalties of up to $1 million per day for
violations of the NGA and increases the FERCs civil
penalty authority under the NGPA from $5 thousand per violation
per day to $1 million per
20
violation per day. The civil penalty provision are applicable to
entities that engage in the sale of natural gas for resale in
interstate commerce. On January 19, 2006, FERC issued Order
No. 670, a rule implementing the anti-market manipulation
provision of EP Act 2005, and subsequently denied rehearing. The
rules make it unlawful to: (1) in connection with the
purchase or sale of natural gas subject to the jurisdiction of
FERC, or the purchase or sale of transportation services subject
to the jurisdiction of FERC, for any entity, directly or
indirectly, to use or employ any device, scheme or artifice to
defraud; (2) to make any untrue statement of material fact
or omit to make any such statement necessary to make the
statements made not misleading; or (3) to engage in any act
or practice that operates as a fraud or deceit upon any person.
The new anti-market manipulation rule does not apply to
activities that relate only to intrastate or other
non-jurisdictional sales or gathering, but does apply to
activities of gas pipelines and storage companies that provide
interstate services, as well as otherwise non-jurisdictional
entities to the extent the activities are conducted in
connection with gas sales, purchases or transportation
subject to FERC jurisdiction. The anti-market manipulation rule
and enhanced civil penalty authority reflect an expansion of
FERCs NGA enforcement authority.
FERC
Standards of Conduct for Transmission Providers
Since 2002, FERC has been engaged in a lengthy process of
revising its standards of conduct that regulate the manner in
which interstate natural gas pipelines and certain natural gas
storage companies which provide storage services in interstate
commerce (defined as Transmission Providers) may
interact with certain affiliated entities. Delay in the revision
process has resulted from a disagreement on the appropriate
scope of affiliate relationships to be governed by the revised
standards. In response to a remand in late 2006 from the United
States Court of Appeals for the District of Columbia Circuit
vacating the FERCs last series of affiliate standards of
conduct (the Energy Affiliate Rules), the FERC
issued on March 21, 2008, a notice of proposed rulemaking
(NOPR) proposing to change the approach of its
standards of conduct from a corporate functional approach to an
employee functional approach. The NOPR proposes to regulate the
interactions between employees, either employed by a
Transmission Provider or one of its affiliates, performing a
natural gas transmission function and employees, either employed
by a Transmission Provider or one of its affiliates, performing
a natural gas marketing function. While we do not believe that
our operations would be affected by the new standards of conduct
as proposed, we have no way to predict with certainty the scope
of the final standards of conduct that FERC may adopt.
FERC
Market Transparency Rulemakings
On April 19, 2007, FERC issued a NOPR in which it proposed
to require intrastate natural gas pipelines, which may include
both gathering and transportation pipelines, to post daily on
their Internet websites the actual volumes flowing on their
systems. In addition, FERC proposed to require all buyers and
sellers of more than a minimum volume of natural gas to report
to FERC on an annual basis the number and total volume of their
transactions. FERC has asserted that it has the jurisdiction to
issue these regulations with respect to intrastate pipelines and
otherwise non-jurisdictional buyers and sellers of gas in order
to facilitate market transparency in the interstate natural gas
market pursuant to Section 23 of the NGA, which was added
by Section 316 of EP Act 2005. FERC has bifurcated the two
issues, issuing a new NOPR on pipeline posting requirements on
December 21, 2007, and a final rule on the annual natural
gas transaction reporting requirements (Order 704), on
December 26, 2007.
Under Order No. 704, wholesale buyers and sellers of more
than a minimum volume of natural gas are now required to report,
on May 1 of each year, beginning in 2009, aggregate volumes of
natural gas purchased or sold at wholesale in the prior calendar
year. In such report, buyers and sellers must categorize volumes
reported as fixed price or index-based. FERC retreated from its
earlier position that would have also required reporting of the
number of transactions as well as the volumes. Order
No. 704 also requires market participants to indicate
whether they report prices to any index publishers, and if so,
whether their reporting complies with FERCs Policy
Statement on price reporting. Several parties have filed
requests for clarification or rehearing that are currently
pending before FERC.
Under the revised NOPR on pipeline posting requirements, FERC is
proposing to require intrastate pipelines to post daily actual
and scheduled flows on an Internet website. FERC has suggested
certain
21
exemptions from the proposed rule such as an annual throughput
minimum, an exemption for pipelines that lie entirely upstream
of gas processing plants and an exemption for pipelines that
deliver ninety-five percent (95%) or more of their gas to
end-users. At the same time, FERC has also proposed to require
that interstate pipelines add actual daily volumes to their
Internet websites. Currently, interstate pipelines are only
required to post design capacity, scheduled volumes and
operationally available capacity. FERC has received comments on
the revised NOPR on pipeline posting requirements, but has not
yet issued a final rule. While we do not believe that our
operations will be affected by the new posting requirements as
proposed materially any differently than other midstream natural
gas companies with whom we compete, we have no way to predict
with certainty the scope of the final requirements that FERC may
adopt.
Additional proposals and proceedings that might affect the
natural gas industry are pending before Congress, FERC and the
courts. We cannot predict the ultimate impact of these
regulatory changes to our natural gas operations. We do not
believe that we would be affected by any such FERC action
materially differently than other midstream natural gas
companies with whom we compete.
Environmental,
Health and Safety Matters
General
Our operations are subject to stringent and complex federal,
state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to the
protection of the environment. Please see Item 1.
Business Our Systems. As with the industry
generally, compliance with current and anticipated environmental
laws and regulations increases our overall cost of business,
including our capital costs to construct, maintain, and upgrade
equipment and facilities. These laws and regulations may, among,
other things, require the acquisition of various permits to
conduct regulated activities, require the installation of
pollution control equipment or otherwise restrict the way we can
handle or dispose of our wastes; limit or prohibit construction
activities in sensitive areas such as wetlands, wilderness areas
or areas inhabited by endangered or threatened species; require
investigatory and remedial action to mitigate pollution
conditions caused by our operations or attributable to former
operations; and enjoin some or all of the operations of
facilities deemed in non-compliance with permits issued pursuant
to such environmental laws and regulations. Failure to comply
with these laws and regulations may result in assessment of
administrative, civil and criminal penalties, the imposition of
removal or remedial obligations, and the issuance of injunctions
limiting or prohibiting our activities.
We have implemented programs and policies designed to keep our
pipelines, plants, and other facilities in compliance with
existing environmental laws and regulations. The clear trend in
environmental regulation, however, is to place more restrictions
and limitations on activities that may affect the environment,
and thus, any changes in environmental laws and regulations that
result in more stringent and costly waste handling, storage,
transport, disposal, or remediation requirements could have a
material adverse effect on our operations and financial
position. We may be unable to pass on such increased compliance
costs to our customers. Moreover, accidental releases or spills
may occur in the course of our operations, and we cannot assure
you that we will not incur significant costs and liabilities as
a result of such releases or spills, including any third party
claims for damage to property or persons. While we believe that
we are in substantial compliance with existing environmental
laws and regulations and that continued compliance with current
requirements would not have a material adverse effect on us,
there is no assurance that this trend will continue in the
future.
The following is a summary of the more significant existing
environmental, health and safety laws and regulations to which
our business operations are subject and for which compliance may
have a material adverse impact on our capital expenditures,
results of operations or financial position.
Hazardous
Substances and Waste
The Comprehensive Environmental Response, Compensation, and
Liability Act, as amended, (CERCLA or 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 who are
considered to be responsible for the release of a
hazardous substance into the environment. These
persons include current and prior owners or operators of
22
the site where the release occurred and entities that disposed
or arranged for the disposal of the hazardous substances found
at the site. Under CERCLA, these responsible 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 EPA and, in some instances, third parties to act
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 the release of
hazardous substances or other pollutants into the environment.
We generate materials in the course of our operations that are
regulated as hazardous substances under CERCLA or
similar state statutes and, as a result, may be jointly and
severally liable under CERCLA for all or part of the costs
required to clean up sites at which these hazardous substances
have been released into the environment.
We also generate solid wastes, including hazardous wastes that
are subject to the requirements of the Resource Conservation and
Recovery Act, as amended (RCRA), and comparable
state statutes. While RCRA regulates both solid and hazardous
wastes, it imposes strict requirements on the generation,
storage, treatment, transportation and disposal of hazardous
wastes. Certain petroleum production wastes are excluded from
RCRAs hazardous waste regulations. However, it is possible
that these wastes, which could include wastes currently
generated during our operations, will in the future be
designated as hazardous wastes and therefore be
subject to more rigorous and costly disposal requirements. Any
such changes in the laws and regulations could have a material
adverse effect on our maintenance capital expenditures and
operating expenses.
We currently own or lease, and have in the past owned or leased,
properties where hydrocarbons are being or have been handled for
many years. Although we have utilized operating and disposal
practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by us or on
or under the other locations where these hydrocarbons and wastes
have been taken for treatment or disposal. In addition, certain
of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other
wastes was not under our control. These properties and wastes
disposed thereon 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), to clean up
contaminated property (including contaminated groundwater) or to
perform remedial operations to prevent future contamination. We
are not currently aware of any facts, events or conditions
relating to such requirements that could materially impact our
operations or financial condition.
Air
Emissions
The Clean Air Act, as amended, and comparable state laws and
regulations restrict the emission of air pollutants from many
sources, including processing plants and compressor stations,
and also impose various monitoring and reporting requirements.
These laws and regulations may require us to obtain pre-approval
for the construction or modification of certain projects or
facilities expected to produce or significantly increase air
emissions, obtain and strictly comply with stringent air permit
requirements, or utilize specific equipment or technologies to
control emissions. We are currently reviewing the air emissions
monitoring systems at certain of our facilities. We may be
required to incur capital expenditures in the next few years to
implement various air emissions leak detection and monitoring
programs as well as to install air pollution control equipment
as a result of our review or in connection with maintaining or
obtaining operating permits and approvals for air emissions. We
currently believe, however, that such requirements will not have
a material adverse affect on our operations.
Global
Warming and Climate Control
Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to warming of the Earths atmosphere. In
response to such studies, the United States Congress is actively
considering legislation to reduce emissions of greenhouse gases.
One bill recently approved by the United States Senate
Environment
23
and Public Works Committee, known as the Lieberman-Warner
Climate Security Act or S.2191, would require a 70% reduction in
emissions of greenhouse gases from sources within the United
States between 2012 and 2050. The Lieberman-Warner bill proposes
a cap and trade scheme of regulation of greenhouse
gas emissions a ban on emissions above a defined
reducing annual cap. Covered parties will be authorized to emit
greenhouse emissions through the acquisition and subsequent
surrender of emission allowances that may be traded or acquired
on the open market. Debate and a possible vote on this bill by
the full Senate are anticipated to occur before mid-year 2008.
In addition, at least 17 states have declined to wait on
Congress to develop and implement climate control legislation
and have already taken legal measures to reduce emissions of
greenhouse gases, primarily through the planned development of
greenhouse gas emission inventories
and/or
regional greenhouse gas cap and trade programs. Most of these
cap and trade programs work by requiring either major sources of
emissions, such as electric power plants, or major producers of
fuels, such as refineries or gas processing plants, to acquire
and surrender emission allowances. The number of allowances
available for purchase is reduced each year until the overall
greenhouse gas emission reduction goal is achieved. Depending on
the particular program, we could be required to purchase and
surrender allowances, either for greenhouse gas emissions
resulting from our operations (e.g., compressor stations) or
from combustion of fuels (e.g., natural gas or NGLs) we process.
Although we would not be impacted to a greater degree than other
similarly situated transporters of natural gas or NGLs, a
stringent greenhouse gas control program could have an adverse
effect on our cost of doing business and could reduce demand for
the natural gas and NGLs we transport.
Also, as a result of the United States Supreme Courts
decision on April 2, 2007 in Massachusetts, et
al. v. EPA, the EPA may regulate greenhouse gas
emissions from mobile sources such as cars and trucks even if
Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. The EPA has publicly stated its
goal of issuing a proposed rule to address carbon dioxide and
other greenhouse gas emissions from vehicles and automobile
fuels but the timing for issuance of this proposed rule has not
been finalized by the agency. The Courts holding in
Massachusetts that greenhouse gases including carbon
dioxide fall under the federal Clean Air Acts definition
of air pollutant may also result in future
regulation of carbon dioxide and other greenhouse gas emissions
from stationary sources under certain Clean Air Act programs.
New federal or state restrictions on emissions of carbon dioxide
that may be imposed in areas in which we conduct business could
also have an adverse affect on our cost of doing business and
demand for the natural gas and NGLs we transport.
Water
Discharges
The Federal Water Pollution Control Act, as amended (Clean
Water Act or CWA), and analogous state laws
impose restrictions and strict controls regarding the discharge
of pollutants into navigable waters. Pursuant to the CWA and
analogous state laws, permits must be obtained to discharge
pollutants into state waters or waters of the United States. Any
such discharge of pollutants into regulated waters must be
performed in accordance with the terms of the permit issued by
EPA or the analogous state agency. Spill prevention, control and
countermeasure requirements under federal law require
appropriate containment berms and similar structures to help
prevent the contamination of navigable waters in the event of a
petroleum hydrocarbon tank spill, rupture or leak. In addition,
the CWA and analogous state laws require individual permits or
coverage under general permits for discharges of storm water
runoff from certain types of facilities. These permits may
require us to monitor and sample the storm water runoff. The CWA
can impose substantial civil and criminal penalties for
non-compliance. State laws for the control of water pollution
may also provide varying civil and criminal penalties and
liabilities. We believe that we are in substantial compliance
with the requirements of the CWA and analogous state laws.
The Oil Pollution Act of 1990, as amended (OPA),
which amends and augments the Clean Water Act, establishes
strict liability for owners and operators of facilities that are
the site of a release of oil into waters of the United States.
OPA and its associated regulations impose a variety of
requirements on responsible parties related to the prevention of
oil spills and liability for damages resulting from such spills.
A responsible party under OPA includes owners and
operators of vessels, including barges, offshore platforms, and
onshore facilities, such as our pipelines and marine terminals.
Under OPA, owners and operators of vessels
24
and shore facilities that handle, store, or transport oil are
required to develop and implement oil spill response plans, and
establish and maintain evidence of financial responsibility
sufficient to cover liabilities related to an oil spill for
which such parties could be statutorily responsible. We believe
that we are in substantial compliance with the Clean Water Act,
OPA and analogous state laws.
Endangered
Species Act
The federal Endangered Species Act, as amended
(ESA), restricts activities that may affect
endangered or threatened species or their habitats. While some
of our facilities may be located in areas that are designated as
habitat for endangered or threatened species, we believe that we
are in substantial compliance with the ESA. However, the
designation of previously unidentified endangered or threatened
species could cause us to incur additional costs or become
subject to operating restrictions or bans in the affected areas.
Pipeline
Safety
The pipelines we use to gather and transport natural gas and
transport NGLs are subject to regulation by the United States
Department of Transportation, or the DOT, under the Natural Gas
Pipeline Safety Act of 1968, as amended, or NGPSA, with respect
to natural gas and the Hazardous Liquids Pipeline Safety Act of
1979, as amended, or HLPSA with respect to crude oil, NGLs and
condensates. The NGPSA and HLPSA govern the design,
installation, testing, construction, operation, replacement and
management of natural gas and NGL pipeline facilities. Where
applicable, the NGPSA and HLPSA require any entity that owns or
operates pipeline facilities to comply with the regulations
under these acts, 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 existing NGPSA and HLPSA requirements; however, due
to the possibility of new or amended laws and regulations or
reinterpretation of existing laws and regulations, future
compliance with the NGPSA and HLPSA could result in increased
costs.
Our pipelines are also subject to regulation by the DOT under
the Pipeline Safety Improvement Act of 2002, which was
reauthorized and amended by the Pipeline Inspection, Protection,
Enforcement, and Safety Act of 2006. The DOT, through the
Pipeline and Hazardous Materials Safety Administration, or
PHMSA, has established a series of rules, which require pipeline
operators to develop and implement integrity management programs
for gas transmission pipelines that, in the event of a failure,
could affect high consequence areas. High
consequence areas are currently defined as areas with
specified population densities, buildings containing populations
of limited mobility, and areas where people gather that are
located along the route of a pipeline. Similar rules are also in
place for operators of hazardous liquid pipelines including
lines transporting NGLs and condensates. The DOT also is
required by the Pipeline Inspections, Protection, Enforcement,
and Safety Act of 2006 to issue new regulations that set forth
safety standards and reporting requirements applicable to low
stress pipelines and gathering lines transporting hazardous
liquids, including NGLs and condensate. A final rule addressing
safety standards for hazardous liquid low-stress pipelines and
gathering lines is anticipated to be issued by PHMSA in 2008.
These safety standards may include applicable integrity
management program requirements.
In addition, states have adopted regulations, similar to
existing DOT regulations, for intrastate gathering and
transmission lines. Texas and Louisiana have developed
regulatory programs that parallel the federal regulatory scheme
and are applicable to intrastate pipelines transporting natural
gas and NGLs. We currently estimate an annual average cost of
$0.3 million for years 2008 through 2010 to perform
necessary integrity management program testing on our pipelines
required by existing DOT and state regulations. This estimate
does not include the costs, if any, of any repair, remediation,
preventative or mitigating actions that may be determined to be
necessary as a result of the testing program, which costs could
be substantial. However, we do not expect that any such costs
would be material to our financial condition or results of
operations.
25
Employee
Health and Safety
We are subject to a number of federal and state laws and
regulations, including the federal Occupational Safety and
Health Act, as amended (OSHA), and comparable state
statutes, whose purpose is to protect the health and safety of
workers, both generally and within the pipeline industry. In
addition, the OSHA hazard communication standard, the
Environmental Protection Agency (EPA) community
right-to-know regulations under Title III of the federal
Superfund Amendment and Reauthorization Act and comparable state
statutes require that information be maintained concerning
hazardous materials used or produced in our operations and that
this information be provided to employees, state and local
government authorities and citizens. We and the entities in
which we own an interest are also subject to OSHA Process Safety
Management regulations, which are designed to prevent or
minimize the consequences of catastrophic releases of toxic,
reactive, flammable or explosive chemicals. These regulations
apply to any process which involves a chemical at or above the
specified thresholds or any process which involves flammable
liquid or gas, pressurized tanks, caverns and wells in excess of
10,000 pounds at various locations. Flammable liquids stored in
atmospheric tanks below their normal boiling point without the
benefit of chilling or refrigeration are exempt. We have an
internal program of inspection designed to monitor and enforce
compliance with worker safety requirements. We believe that we
are in substantial compliance with all applicable laws and
regulations relating to worker health and safety.
Other
Laws and Regulations
In addition, our operations and the operations of the natural
gas and oil industry in general may be subject to laws and
regulations regarding the security of industrial facilities,
including natural gas and oil facilities. The Department of
Homeland Security Appropriations Act of 2007 required the
Department of Homeland Security (DHA) to issue
regulations establishing risk-based performance standards for
the security of chemical and industrial facilities, including
oil and gas facilities that are deemed to present high
levels of security risk. The DHS issued an interim final
rule, known as the Chemical Facility Anti-Terrorism Standards
interim rule, in April 2007 regarding risk-based performance
standards to be attained pursuant to the act and on
November 20, 2007 further issued an Appendix A to the
interim rule that established the chemicals of interest and
their respective threshold quantities that will trigger
compliance with these interim rules.
In January 2008, we prepared and submitted to the DHS initial
screening surveys for facilities operated by us that possess
regulated chemicals of interest in excess of the Appendix A
threshold levels. Covered facilities that are determined by DHS
to pose a high level of security risk will be required to
prepare and submit Security Vulnerability Assessments and Site
Security Plans as well as comply with other regulatory
requirements, including those regarding inspections, audits,
recordkeeping, and protection of chemical-terrorism
vulnerability information. Because we are currently awaiting a
response from DHS on the extent to which some or all of our
surveyed facilities may be determined to present a high level of
security risk, the associated costs for complying with this
interim rule has not been determined by us, and it is possible
that such costs ultimately could be substantial.
Title to
Properties and Rights-of-Way
Our real property falls into two categories: (1) parcels
that we own in fee and (2) parcels in which our interest
derives from leases, easements, rights-of-way, permits or
licenses from landowners or governmental authorities permitting
the use of such land for our operations. Portions of the land on
which our plants and other major facilities are located are
owned by us in fee title, and we believe that we have
satisfactory title to these lands. The remainder of the land on
which our plant sites and major facilities are located are held
by us pursuant to ground leases between us, as lessee, and the
fee owner of the lands, as lessors and we believe that we have
satisfactory leasehold estates to such lands. We have no
knowledge of any challenge to any material lease, easement,
right-of-way, permit or lease, and we believe that we have
satisfactory title to all of our material leases, easements,
rights-of-way, permits and licenses.
Targa may continue to hold record title to portions of certain
assets until we make the appropriate filings in the
jurisdictions in which such assets are located and obtain any
consents and approvals that are not
26
obtained prior to transfer. Such consents and approvals would
include those required by federal and state agencies or
political subdivisions. In some cases, Targa may, where required
consents or approvals have not been obtained, temporarily hold
record title to property as nominee for our benefit and in other
cases may, on the basis of expense and difficulty associated
with the conveyance of title, cause its affiliates to retain
title, as nominee for our benefit, until a future date. We
anticipate that there will be no material change in the tax
treatment of our common units resulting from the holding by
Targa of title to any part of such assets subject to future
conveyance or as our nominee.
Employees
To carry out its operations, Targa employs approximately
920 people, some of whom provide direct support for our
operations. None of these employees are covered by collective
bargaining agreements. Targa considers its employee relations to
be good. We do not have any employees.
Available
Information
We make certain filings with the Securities and Exchange
Commission (SEC), including our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and all amendments and exhibits to those reports, available free
of charge through our website,
http://www.targaresources.com,
as soon as reasonably practicable after they are filed with the
SEC. The filings are also available through the SEC at the
SECs Public Reference Room at 100 F Street,
N.E., Washington, D.C. 20549 or by calling
1-800-SEC-0330.
Also, these filings are available on the internet at
http://www.sec.gov.
Our press releases and recent analyst presentations are also
available on our website.
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 similar businesses. The nature
of our business activities subject us to certain hazards and
risks. You should consider carefully the following risk factors
together with all of the other information contained in this
report. Additional risks not presently known to us or which we
consider immaterial based on information currently available to
us may also materially adversely affect us. If any of the
following risks were actually to occur, then our business,
financial condition or results of operations could be materially
adversely affected.
Risks
Related to Our Business
Our
cash flow is affected by supply and demand for natural gas and
NGL products, natural gas and NGL prices, and decreases in these
prices could adversely affect our ability to make distributions
to holders of our common units and subordinated
units.
Our operations can be affected by the level of natural gas and
NGL prices and the relationship between these prices. The prices
of natural gas and NGLs have been volatile and we expect this
volatility to continue. Our future cash flow will be materially
adversely affected if we experience significant, prolonged
pricing deterioration below general price levels experienced
over the past few years in our industry. The markets and prices
for natural gas and NGLs depend upon factors beyond our control.
These factors include demand for these commodities, which
fluctuate with changes in market and economic conditions and
other factors, including:
|
|
|
|
|
the impact of seasonality and weather;
|
|
|
|
general economic conditions;
|
|
|
|
the level of domestic crude oil and natural gas production and
consumption;
|
|
|
|
the availability of imported natural gas, liquified natural gas,
NGLs and crude oil;
|
|
|
|
actions taken by foreign oil and gas producing nations;
|
27
|
|
|
|
|
the availability of local, intrastate and interstate
transportation systems;
|
|
|
|
the availability and marketing of competitive fuels;
|
|
|
|
the impact of energy conservation efforts; and
|
|
|
|
the extent of governmental regulation and taxation.
|
Our primary natural gas gathering and processing arrangements
that expose us to commodity price risk are our
percent-of-proceeds arrangements. For the year ended
December 31, 2007, our percent-of-proceeds arrangements
accounted for approximately 79% of our gathered natural gas
volume. Under percent-of-proceeds arrangements, we generally
process natural gas from producers and remit to the producers an
agreed percentage of the proceeds from the sale of residue gas
and NGL products at market prices or a percentage of residue gas
and NGL products at the tailgate of our processing facilities.
In some percent-of-proceeds arrangements, we remit to the
producer a percentage of an index price for residue gas and NGL
products, less agreed adjustments, rather than remitting a
portion of the actual sales proceeds. Under these types of
arrangements, our revenues and our cash flows increase or
decrease, whichever is applicable, as the price of natural gas,
NGLs and crude oil fluctuates. For additional information
regarding our hedging activities, please see Item 7A.
Quantitative and Qualitative Disclosures about Market
Risk Commodity Price Risk.
Because
of the natural decline in production from existing wells in our
operating regions, our success depends on our ability to obtain
new sources of supplies of natural gas and NGLs, which depends
on certain factors beyond our control. Any decrease in supplies
of natural gas or NGLs could adversely affect our business and
operating results.
Our gathering systems are connected to natural gas wells from
which the production will naturally decline over time, which
means that our cash flows associated with these wells will
likely also decline over time. To maintain or increase
throughput levels on our gathering systems and the utilization
rate at our processing plants and our treating and fractionation
facilities, we must continually obtain new natural gas supplies.
Additionally, our profitability is materially affected by the
volume of raw NGL mix fractionated at our fractionation
facilities. A material decrease in natural gas production from
producing areas that we rely on for raw NGL mix, as a result of
depressed commodity prices or otherwise, could result in a
decline in the volume of NGL products delivered to our
fractionation facilities. Our ability to obtain additional
sources of natural gas depends in part on the level of
successful drilling activity near our gathering systems.
We have no control over the level of drilling activity in the
areas of our operations, the amount of reserves associated with
the wells or the rate at which production from a well will
decline. In addition, we have no control over producers or their
drilling or production decisions, which are affected by, among
other things, prevailing and projected energy prices, demand for
hydrocarbons, the level of reserves, geological considerations,
governmental regulations, availability of drilling rigs and
other production and development costs and the availability and
cost of capital. Fluctuations in energy prices can greatly
affect production rates and investments by third parties in the
development of new oil and natural gas reserves. Drilling
activity generally decreases as oil and natural gas prices
decrease. In the past, the prices of natural gas have been
extremely volatile, and we expect this volatility to continue.
In the past, the prices of natural gas have been extremely
volatile, and we expect this volatility to continue. Natural gas
prices reached historic highs in 2005 and early 2006, but
declined substantially in the second half of 2006 and continued
to decline until late August 2007. Reductions in exploration or
production activity or shut-ins by producers in the areas in
which we operate as a result of a sustained decline in natural
gas prices would lead to reduced utilization of our gathering
and processing assets.
Because of these factors, even if new natural gas reserves are
discovered in areas served by our assets, producers may choose
not to develop those reserves. If, due to reductions in drilling
activity or competition, we are not able to obtain new supplies
of natural gas to replace the natural decline in volumes from
existing wells, throughput on our pipelines and the utilization
rates of our treating, processing and fractionation facilities
would decline, which could reduce our revenue and impair our
ability to make distributions to our unitholders.
28
If we
fail to balance our purchases of natural gas and our sales of
residue gas and NGLs, our exposure to commodity price risk will
increase.
We may not be successful in balancing our purchases of natural
gas and our sales of residue gas and NGLs. In addition, a
producer could fail to deliver promised volumes to us or deliver
in excess of contracted volumes, or a purchaser could purchase
less than contracted volumes. Any of these actions could cause
an imbalance between our purchases and sales. 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 income.
Our
hedging activities may not be effective in reducing the
variability of our cash flows and may, in certain circumstances,
increase the variability of our cash flows. Moreover, our hedges
may not fully protect us against volatility in basis
differentials. Finally, the percentage of our expected equity
commodity volumes that are hedged decreases substantially over
time.
We have entered into derivative transactions related to only a
portion of our equity volumes. As a result, we will continue to
have direct commodity price risk to the unhedged portion. Our
actual future volumes may be significantly higher or lower than
we estimated at the time we entered into the derivative
transactions for that period. If the actual amount is higher
than we estimated, we will have greater commodity price risk
than we intended. If the actual amount is lower than the amount
that is subject to our derivative financial instruments, we
might be forced to satisfy all or a portion of our derivative
transactions without the benefit of the cash flow from our sale
of the underlying physical commodity, resulting in a reduction
of our liquidity. The percentages of our expected equity volumes
that are covered by our hedges decrease over time. The
derivative instruments we utilize for these hedges are based on
posted market prices, which may be lower than the actual natural
gas, NGLs and condensate prices that we realize in our
operations. These pricing differentials may be substantial and
could materially impact the prices we ultimately realize. As a
result of these factors, our hedging activities may not be as
effective as we intend in reducing the variability of our cash
flows, and in certain circumstances may actually increase the
variability of our cash flows. To the extent we hedge our
commodity price risk, we may forego the benefits we would
otherwise experience if commodity prices were to change in our
favor. For additional information regarding our hedging
activities, please see Item 7A. Quantitative and
Qualitative Disclosures About Market Risk.
We
depend on one natural gas producer for a significant portion of
our supply of natural gas. The loss of this customer or the
replacement of its contracts on less favorable terms could
result in a decline in our volumes, revenues and cash available
for distribution.
Our largest natural gas supplier for the year ended
December 31, 2007 was ConocoPhillips, who accounted for
approximately 12% of our supply. In addition, there is a gas
gatherer who is a significant supplier to the system and sells
gas to us on a spot basis. This gatherer delivered approximately
11% of our systems volumes in 2007. The loss of all or
even a portion of the natural gas volumes supplied by these
customers or the extension or replacement of these contracts on
less favorable terms, if at all, as a result of competition or
otherwise, could reduce our revenue or increase our cost for
product purchases, impairing our ability to make distributions
to our unitholders.
If
third party pipelines and other facilities interconnected to our
natural gas pipelines and processing facilities become partially
or fully unavailable to transport natural gas and NGLs, our
revenues could be adversely affected.
We depend upon third party pipelines and other facilities that
provide delivery options to and from our pipelines and
processing facilities. Since we do not own or operate these
pipelines or other facilities, their continuing operation in
their current manner is not within our control. If any of these
third party pipelines and other facilities become partially or
fully unavailable to transport natural gas and NGLs, or if the
gas quality specifications for their pipelines or facilities
change so as to restrict our ability to transport gas on those
pipelines or facilities, our revenues and cash available for
distribution could be adversely affected.
29
We
depend on our Chico plant in north Texas and our Gillis plant in
southwest Louisiana for a substantial portion of our revenues
and if those revenues were reduced, there would be a material
adverse effect on our results of operations and ability to make
distributions to unitholders. To a similar but lesser degree, we
are dependent on other gathering and processing systems, such as
Mertzon, and Sterling.
Any significant curtailment of gathering, compressing, treating,
processing or fractionation of natural gas at our Chico plant,
Gillis plant or at our other plants could result in our
realizing materially lower levels of revenues and cash flow for
the duration of such curtailment. For the year ended
December 31, 2007, our Chico and Gillis plant inlet volumes
each accounted for approximately 35% of our total plant inlet
volumes. Operations at our Chico plant, Gillis plant or our
other plants could be partially curtailed or completely shut
down, temporarily or permanently, as a result of:
|
|
|
|
|
competition from other systems that may be able to meet producer
needs or supply end-user markets on a more cost-effective basis;
|
|
|
|
operational problems such as catastrophic events at a processing
plant or our gathering lines, labor difficulties or
environmental proceedings or other litigation that compel
cessation of all or a portion of the operations at a plant or on
a system;
|
|
|
|
an inability to obtain sufficient quantities of natural gas for
a system at competitive terms; or
|
|
|
|
reductions in exploration or production activity, or shut-ins by
producers in the areas in which we operate.
|
The magnitude of the effect on us of any curtailment of
operations will depend on the length of the curtailment and the
extent of the operations affected by such curtailment. We have
no control over many of the factors that may lead to a
curtailment of operations.
In addition, our business interruption insurance is subject to
limitations and deductibles. If a significant accident or event
occurs at our Chico plant or the Mertzon, Sterling and Gillis
plants and their respective gathering systems that is not fully
insured, it could adversely affect our operations and financial
condition.
If
future acquisitions do not perform as expected, out future
financial performance may be negatively impacted.
Acquisitions may significantly increase the size of the
Partnership and diversify the geographic areas in which we
operate. We can not assure you that we will achieve the desired
affect from acquisitions we may complete in the future. In
addition, failure to assimilate future acquisitions could
adversely affect our financial condition and results of
operations.
Our acquisitions involve numerous risks, including:
|
|
|
|
|
operating a significantly larger combined organization and
adding operations;
|
|
|
|
difficulties in the assimilation of the assets and operations of
the acquired businesses, especially if the assets acquired are
in a new business segment or geographic area;
|
|
|
|
the risk that natural gas reserves expected to support the
acquired assets may not be of the anticipated magnitude or may
not be developed as anticipated;
|
|
|
|
the failure to realize expected profitability or growth;
|
|
|
|
the failure to realize any expected synergies and cost
savings; and
|
|
|
|
coordinating geographically disparate organizations, systems and
facilities.
|
Further unexpected costs and challenges may arise whenever
businesses with different operations or management are combined,
and we may experience unanticipated delays in realizing the
benefits of an acquisition. If we consummate any future
acquisition, our capitalization and results of operations may
change significantly, and you may not have the opportunity to
evaluate the economic, financial and other relevant information
that we will consider in evaluating future acquisitions.
30
We are
exposed to the credit risk of Targa and any material
nonperformance by Targa could reduce our ability to make
distributions to our unitholders.
We have entered into purchase agreements with Targa pursuant to
which Targa will purchase (i) all of the North Texas
Systems natural gas, NGLs and high-pressure condensate for
a term of 15 years and (ii) substantially all of the
SAOU and LOU Systems natural gas for a term of
15 years and NGLs for a term of one year. Targa also
manages the SAOU and LOU Systems natural gas sales to
third parties under contracts that remain in the name of the
SAOU and LOU Systems. We are also party to an amended and
restated Omnibus Agreement with Targa which addresses, among
other things, the provision of general and administrative and
operating services to us. At February 29, 2008, the
corporate credit ratings of Targa as assigned by Moodys
and Standard & Poor are B1 and B, respectively, which
are speculative ratings. These speculative ratings signify a
higher risk that Targa will default on its obligations,
including its obligations to us, than does an investment grade
credit rating. Any material nonperformance under the omnibus and
purchase agreements by Targa could materially and adversely
impact our ability to operate and make distributions to our
unitholders.
Our
general partner is an obligor under, and subject to a pledge
related to, Targas credit facility; in the event Targa is
unable to meet its obligations under that facility, or is
declared bankrupt, Targas lenders may gain control of our
general partner or, in the case of bankruptcy, our partnership
may be dissolved.
Our general partner is an obligor under, and all of its assets
and Targas ownership interest in it are subject to a lien
related to, Targas credit facility. In the event Targa is
unable to satisfy its obligations under the credit facility and
the lenders foreclose on their collateral, the lenders will own
our general partner and all of its assets, which include the
general partner interest in us and our incentive distribution
rights. In such event, the lenders would control our management
and operation. Moreover, in the event Targa becomes insolvent or
is declared bankrupt, our general partner may be deemed
insolvent or declared bankrupt as well. Under the terms of our
partnership agreement, the bankruptcy or insolvency of our
general partner will cause a dissolution of our partnership.
Our
industry is highly competitive, and increased competitive
pressure could adversely affect our business and operating
results.
We compete with similar enterprises in our respective areas of
operation. Some of our competitors are large oil, natural gas
and petrochemical companies that have greater financial
resources and access to supplies of natural gas and NGLs than we
do. Some of these competitors may expand or construct gathering,
processing and transportation systems that would create
additional competition for the services we provide to our
customers. In addition, our customers who are significant
producers of natural gas may develop their own gathering,
processing and transportation systems in lieu of using ours. 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 and our customers. 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.
We
typically do not obtain independent evaluations of natural gas
reserves dedicated to our gathering pipeline systems; therefore,
volumes of natural gas on our systems in the future could be
less than we anticipate.
We typically 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 independent estimates of total reserves dedicated to our
gathering systems or the anticipated life of such reserves. If
the total reserves or estimated life 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 transported on our gathering systems in
the future could be less than we anticipate. A decline in the
volumes of natural gas on our systems could have a material
adverse effect on our business, results of operations, and
financial condition and our ability to make cash distributions
to our unitholders.
31
A
reduction in demand for NGL products by the petrochemical,
refining or heating industries could materially adversely affect
our business, results of operations and financial
condition.
The NGL products we produce have a variety of applications,
including as heating fuels, petrochemical feedstocks and
refining blend stocks. A reduction in demand for NGL products,
whether because of general economic conditions, new government
regulations, reduced demand by consumers for products made with
NGL products, increased competition from petroleum-based
products due to pricing differences, mild winter weather or
other reasons, could result in a decline in the volume of NGL
products we handle or reduce the fees we charge for our
services. Our NGL products and their demand are affected as
follows:
Ethane. Ethane is typically supplied as purity
ethane and as part of ethane-propane mix. 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. Although ethane is typically
extracted as part of the mixed NGL stream at gas processing
plants, if natural gas prices increase significantly in relation
to NGL product prices or if the demand for ethylene falls, it
may be more profitable for natural gas producers to leave the
ethane in the natural gas stream thereby reducing the volume of
NGLs delivered for fractionation and marketing. We have
experienced periods where natural gas producers have retained
ethane in the natural gas stream and may experience such periods
in the future.
Propane. Propane is used as a petrochemical
feedstock in the production of ethylene and propylene, as a
heating, engine and industrial fuel, and in agricultural
applications such as crop drying. Changes in demand for ethylene
and propylene could adversely affect demand for propane. The
demand for propane as a heating fuel is significantly affected
by weather conditions. The volume of propane sold is at its
highest during the six-month peak heating season of October
through March. Demand for our propane may be reduced during
periods of warmer-than-normal weather.
Normal Butane. Normal butane is used in the
production of isobutane, as a refined product blending
component, as a fuel gas, either alone or in a mixture with
propane, and in the production of ethylene and propylene.
Changes in the composition of refined products resulting from
governmental regulation, demand for heating fuel and for
ethylene and propylene, could adversely affect demand for normal
butane.
Isobutane. Isobutane is predominantly used in
refineries to produce alkylates to enhance octane levels.
Accordingly, any action that reduces demand for motor gasoline
or demand for isobutane to produce alkylates for octane
enhancement might reduce demand for isobutane.
Natural Gasoline. Natural gasoline is used as
a blending component for certain refined products and as a
feedstock used in the production of ethylene and propylene.
Changes in the composition of motor gasoline resulting from
governmental regulation and in demand for ethylene and propylene
could adversely affect demand for natural gasoline.
Any reduced demand for ethane, propane, normal butane, isobutane
or natural gasoline for any of the reasons stated above could
adversely affect demand for the services we provide as well as
NGL prices, which would negatively impact our results of
operations and financial condition.
We do
not own most of the land on which our pipelines and facilities
are located, which could disrupt our operations.
We do not own most of the land on which our pipelines and
facilities are located, and we are therefore subject to the
possibility of more onerous terms
and/or
increased costs to retain necessary land use if we do not have
valid rights of way or leases or if such rights of way or leases
lapse or terminate. We sometimes obtain the rights to land owned
by third parties and governmental agencies for a specific period
of time. Our loss of these rights, through our inability to
renew right-of-way contracts, leases or otherwise, could cause
us to cease operations on the affected land, increase costs
related to continuing operations elsewhere, reduce our revenue
and impair our ability to make distributions to our unitholders.
32
Weather
may limit our ability to operate our business and could
adversely affect our operating results.
The weather in the areas in which we operate can cause delays in
our operations and, in some cases, work stoppages. For example,
natural gas sales volumes for the first six months of 2007 were
negatively impacted by unseasonably wet weather, which limited
our ability to complete connections to new wells. Any similar
delays or work stoppages caused by the weather could adversely
affect our operating results for the affected periods.
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 many hazards inherent in the
gathering, compressing, treating, processing and transporting of
natural gas and NGLs, including:
|
|
|
|
|
damage to pipelines and plants, related equipment and
surrounding properties caused by hurricanes, tornadoes, floods,
fires and other natural disasters, explosions and acts of
terrorism;
|
|
|
|
inadvertent damage from third parties, including from
construction, farm and utility equipment;
|
|
|
|
leaks of natural gas, NGLs and other hydrocarbons or losses of
natural gas or NGLs as a result of the malfunction of equipment
or facilities; and
|
|
|
|
other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.
|
These risks could result in substantial losses due to personal
injury
and/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.
For example, Hurricanes Katrina and Rita damaged gathering
systems, processing facilities, NGL fractionators and pipelines
along the Gulf Coast, including, in the case of Hurricane Rita,
certain of our facilities. These hurricanes disrupted the
operations of our customers in August and September 2005, which
curtailed or suspended the operations of various energy
companies with assets in the region. Our insurance is provided
under Targas insurance programs. We are not fully insured
against all risks inherent to our business. We are not insured
against all environmental accidents that might occur which may
include toxic tort claims, other than those considered to be
sudden and accidental. If a significant accident or event occurs
that is not fully insured, it could adversely affect our
operations and financial condition. In addition, Targa may not
be able to maintain or obtain insurance of the type and amount
we desire at reasonable rates. Moreover, significant claims by
Targa may limit or eliminate the amount of insurance proceeds
available to us. As a result of market conditions, premiums and
deductibles for certain of our insurance policies have increased
substantially, and could escalate further. For example,
following Hurricanes Katrina and Rita, insurance premiums,
deductibles and co-insurance requirements increased
substantially, and terms generally are less favorable than terms
that could be obtained prior to such hurricanes. In some
instances, certain insurance could become unavailable or
available only for reduced amounts of coverage.
Our
debt levels may limit our flexibility in obtaining additional
financing and in pursuing other business
opportunities.
As of December 31, 2007, we had approximately
$626.3 million of borrowings outstanding under our amended
credit facility. Our level of debt could have important
consequences for us, including the following:
|
|
|
|
|
our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
|
|
|
|
we need a portion of our cash flow to make interest payments on
our debt, reducing the funds that would otherwise be available
for operations, future business opportunities and distributions
to unitholders;
|
33
|
|
|
|
|
our debt level makes us more vulnerable to competitive pressures
or a downturn in our business or the economy generally; and
|
|
|
|
our debt level may limit our flexibility in responding to
changing business and economic conditions.
|
Our ability to service our debt depends upon, among other
things, our future financial and operating performance, which
will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing distributions,
reducing or delaying our business activities, acquisitions,
investments or capital expenditures, selling assets,
restructuring or refinancing our debt, or seeking additional
equity capital. We may not be able to effect any of these
actions on satisfactory terms, or at all. Please see
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations
Liquidity and Capital Resources.
Increases
in interest rates could adversely affect our
business.
In addition to our exposure to commodity prices, we have
significant exposure to increases in interest rates. As of
December 31, 2007, we had approximately $626.3 million
of debt outstanding under our amended credit facility at
variable interest rates. In December 2007, we entered into
interest rate swaps with notional amounts of $200 million.
Our results of operations, cash flows and financial condition
could be materially adversely affected by significant increases
in interest rates. Please see Item 7A. Quantitative
and Qualitative Disclosures about Market Risk
Interest Rate Risk.
Restrictions
in our amended credit facility may interrupt distributions to us
from our subsidiaries, which may limit our ability to make
distributions to you, satisfy our obligations and capitalize on
business opportunities.
We are a holding company with no business operations. As such,
we depend on the earnings and cash flow of our subsidiaries and
the distribution of that cash to us in order to meet our
obligations and to allow us to make distributions to our
unitholders. Our amended credit facility contains covenants
limiting our ability to make distributions, incur indebtedness,
grant liens, and engage in transactions with affiliates.
Furthermore, our amended credit facility contains covenants
requiring us to maintain a ratio of consolidated indebtedness to
consolidated EBITDA initially of not more than 5.00 to 1.00 and
a ratio of consolidated EBITDA to consolidated interest expense
of not less than 2.25 to 1.00. If we fail to meet these tests or
otherwise breach the terms of our amended credit facility our
operating subsidiary will be prohibited from making any
distribution to us and, ultimately, to you. Any interruption of
distributions to us from our subsidiaries may limit our ability
to satisfy our obligations and to make distributions to you. For
more information regarding our amended credit facility, please
see Item 7. Managements Discussion and Analysis
of Financial Condition and Results of Operations
Liquidity and Capital Resources.
Our
acquisition strategy requires access to new capital. Tightened
capital markets or increased competition for investment
opportunities could impair our ability to grow through
acquisitions.
We continuously consider and enter into discussions regarding
potential acquisitions. Any limitations on our access to capital
will impair our ability to execute this strategy. If the cost of
such capital becomes too expensive, our ability to develop or
acquire strategic and accretive assets will be limited. We may
not be able to raise the necessary funds on satisfactory terms,
if at all. The primary factors that influence our initial cost
of equity include market conditions, fees we pay to underwriters
and other offering costs, which include amounts we pay for legal
and accounting services. The primary factors influencing our
cost of borrowing include interest rates, credit spreads,
covenants, underwriting or loan origination fees and similar
charges we pay to lenders.
In addition, we are experiencing increased competition for the
types of assets we contemplate purchasing. Increased competition
for a limited pool of assets could result in our losing to other
bidders more often or acquiring assets at less attractive
prices. Either occurrence would limit our ability to fully
execute our growth
34
strategy. Our inability to execute our growth strategy could
materially adversely affect our ability to maintain or pay
higher distributions in the future.
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 or
hydrocarbons into the environment.
Our operations are subject to stringent and complex federal,
state and local environmental laws and regulations governing the
discharge of materials into the environment or otherwise
relating to environmental protection. Please see
Item 1. Business Our Systems. These
laws include, for example, (1) the federal Clean Air Act
and comparable state laws that impose obligations related to air
emissions, (2) the federal Resource Conservation and
Recovery Act (RCRA) and comparable state laws that
impose requirements for the handling, storage, treatment or
disposal of solid and hazardous waste from our facilities,
(3) the federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980 (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 at locations to which our hazardous substances have
been transported for disposal, and (4) the Federal Water
Pollution Control Act (the Clean Water Act) and
comparable state laws that regulate discharges of wastewater
from our facilities to state and federal waters. 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 or imposing
additional compliance requirements on such operations. Certain
environmental laws, including CERCLA and analogous state laws,
impose strict, joint and several liability for costs required to
clean up and restore sites where hazardous substances or
hydrocarbons 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,
hydrocarbons or other waste products into the environment.
There is inherent risk of incurring environmental costs and
liabilities in connection with our operations due to our
handling of natural gas and other petroleum products, air
emissions and water discharges related to our operations, and
historical industry operations and waste disposal practices. For
example, an accidental release from one of our 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, natural
resource and property damages 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
operational or compliance costs and the cost of any remediation
that may become necessary. In particular, we may incur
expenditures in order to maintain compliance with legal
requirements governing emissions of air pollutants from our
facilities. We may not be able to recover all or any of these
costs from insurance. Please see Item 1.
Business Environmental, Health and Safety
Matters.
A
change in the jurisdictional characterization of some of our
assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased
regulation of our assets, which may cause our revenues to
decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938
(NGA) exempts natural gas gathering facilities from
regulation by FERC as a natural gas company under the NGA. We
believe that the natural gas pipelines in our gathering systems
meet the traditional tests FERC has used to establish a
pipelines status as a gatherer not subject to regulation
as a natural gas company. However, 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.
While our natural gas gathering operations are generally exempt
from FERC regulation under the NGA, FERC regulation still
affects our gas gathering operations and the markets for
products related to these operations. FERC has recently issued a
final rule requiring certain intrastate pipelines, including
gathering
35
facilities engaged in natural gas transactions, to submit annual
reports to FERC. In addition, FERC has recently proposed to
require certain intrastate pipelines to post daily scheduled and
actual flows on their lines.
Other FERC regulations may indirectly impact our businesses and
the markets for products derived from these businesses.
FERCs policies and practices across the range of its
natural gas regulatory activities, including, for example, its
policies on open access transportation, gas quality, ratemaking,
capacity release and market center promotion, may indirectly
affect the intrastate natural gas market. In recent years, FERC
has pursued pro-competitive policies in its regulation of
interstate natural gas pipelines. However, we cannot assure you
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 transportation capacity. For more
information regarding the regulation of Targas operations,
please see Item 1. Business Regulation of
Operations.
Should
we fail to comply with all applicable FERC administered
statutes, rules, regulations and orders, we could be subject to
substantial penalties and fines.
Under the Energy Policy Act of 2005 (EP Act 2005),
FERC has civil penalty authority under the NGA to impose
penalties for current violations of up to $1 million per
day for each violation and disgorgement of profits associated
with any violation. While our operations have traditionally not
been subject to FERC regulation, FERC has recently adopted and
proposed regulations that may subject certain of our facilities
to reporting and posting requirements. Additional rules and
legislation pertaining to those and other matters may be
considered or adopted by FERC from time to time. Failure to
comply with those regulations in the future could subject Targa
to civil penalty liability. For more information regarding
regulation of Targas operations, please see
Item 1. Business Regulation of
Operations.
Unexpected
volume changes due to production variability or to gathering,
plant, or pipeline system disruptions may increase our exposure
to commodity price movements.
Targa sells our processed natural gas to third parties and other
Targa affiliates at our plant tailgates or at pipeline pooling
points. Targa also manages the SAOU and LOU Systems
natural gas sales to third parties under contracts that remain
in the name of the SAOU and LOU Systems. Sales made to natural
gas marketers and end-users may be interrupted by disruptions to
volumes anywhere along the system. Targa will attempt to balance
sales with volumes supplied from our processing operations, but
unexpected volume variations due to production variability or to
gathering, plant, or pipeline system disruptions may expose us
to volume imbalances which, in conjunction with movements in
commodity prices, could materially impact our income from
operations and cash flow.
We may
incur significant costs and liabilities resulting from pipeline
integrity programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, as
reauthorized and amended by the Pipeline Inspections,
Protection, Enforcement and Safety Act of 2006, the DOT, through
the Pipeline and Hazardous Materials Safety Administration
(PHMSA) has adopted regulations requiring pipeline
operators to develop integrity management programs for
transmission pipelines located where a leak or rupture could do
the most harm in high consequence areas, including
high population areas, areas that are sources of drinking water,
ecological resource areas that are unusually sensitive to
environmental damage from a pipeline release and commercially
navigable waterways, unless the operator effectively
demonstrates by risk assessment that the pipeline could not
affect the area. The regulations require operators of covered
pipelines to:
|
|
|
|
|
perform ongoing assessments of pipeline integrity;
|
|
|
|
identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;
|
|
|
|
improve data collection, integration and analysis;
|
36
|
|
|
|
|
repair and remediate the pipeline as necessary; and
|
|
|
|
implement preventive and mitigating actions.
|
We currently estimate that we will incur an aggregate cost of
approximately $0.3 million between 2008 and 2010 to
implement pipeline integrity management program testing along
certain segments of our natural gas and NGL pipelines. This
estimate does not include the costs, if any, of any repair,
remediation, preventative or mitigating actions that may be
determined to be necessary as a result of the testing program,
which costs could be substantial. At this time, we cannot
predict the ultimate cost of compliance with this regulation, as
the cost will vary significantly depending on the number and
extent of any repairs found to be necessary as a result of the
pipeline integrity testing. Following this initial round of
testing and repairs, we will continue our pipeline integrity
testing programs to assess and maintain the integrity or our
pipelines. The results of these tests could cause us to incur
significant and unanticipated capital and operating expenditures
for repairs or upgrades deemed necessary to ensure the continued
safe and reliable operations of our pipelines.
The PHMSA also is required by the Pipeline Inspections,
Protection, Enforcement, and Safety Act of 2006 to issue new
regulations that set forth safety standards and reporting
requirements applicable to low stress pipelines and gathering
lines transporting hazardous liquids, including NGLs and
condensate. A final rule addressing safety standards for
hazardous liquid low-stress pipelines and gathering lines is
anticipated to be issued by PHMSA in 2008. These safety
standards may include applicable integrity management program
requirements.
Our
construction of new assets may not result in revenue increases
and is subject to regulatory, environmental, political, legal
and economic risks, which could adversely affect our results of
operations and financial condition.
One of the ways we intend to grow our business is through the
construction of new midstream assets. 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 and may require the expenditure of
significant amounts of capital. If we undertake these projects,
they may not be completed on schedule or at the budgeted cost,
or at all. Moreover, our revenues may not increase immediately
upon the expenditure of funds on a particular project. For
instance, if we expand a new pipeline, the construction may
occur over an extended period of time, and we will not receive
any material increases in revenues until the project is
completed. Moreover, we may construct facilities to capture
anticipated future growth in production in a region in which
such growth does not materialize. Since we are not engaged in
the exploration for and development of natural gas and oil
reserves, we do not possess reserve expertise and we often do
not have access to third party estimates of potential reserves
in an area prior to constructing facilities in such area. To the
extent we rely on estimates of future production in our decision
to construct additions to our systems, such estimates may prove
to be inaccurate because there are numerous uncertainties
inherent in estimating quantities of future production. As a
result, new facilities may not be able to attract enough
throughput to achieve our expected investment return, which
could adversely affect our results of operations and financial
condition. In addition, the construction of additions to our
existing gathering and transportation assets may require us to
obtain new rights-of-way prior to constructing new pipelines. We
may be unable to obtain such rights-of-way to connect new
natural gas supplies to our existing gathering lines or
capitalize on other attractive expansion opportunities.
Additionally, it may become more expensive for us to obtain new
rights-of-way or to renew existing rights-of-way. If the cost of
renewing or obtaining new rights-of-way increases, our cash
flows could be adversely affected.
If we
do not make acquisitions on economically acceptable terms, or
efficiently and effectively integrate the acquired assets with
our asset base, our future growth will be limited.
Our ability to grow depends, in part, on our ability to make
acquisitions that result in an increase in cash generated from
operations per unit. If we are unable to make these accretive
acquisitions either because we are (1) unable to identify
attractive acquisition candidates or negotiate acceptable
purchase contracts with them,
37
(2) unable to obtain financing for these acquisitions on
economically acceptable terms, or (3) outbid by
competitors, then our future growth and ability to increase
distributions will be limited.
Any acquisition involves potential risks, including, among other
things:
|
|
|
|
|
inaccurate assumptions about volumes, revenues and costs,
including synergies;
|
|
|
|
an inability to integrate successfully the businesses we acquire;
|
|
|
|
the assumption of unknown liabilities;
|
|
|
|
limitations on rights to indemnity from the seller;
|
|
|
|
inaccurate assumptions about the overall costs of equity or debt;
|
|
|
|
the diversion of managements and employees attention
from other business concerns;
|
|
|
|
unforeseen difficulties operating in new product areas or new
geographic areas; and
|
|
|
|
customer or key employee losses at the acquired businesses.
|
If these risks materialize, the acquired assets may inhibit our
growth or fail to deliver expected benefits.
Our acquisition strategy is based, in part, on our expectation
of ongoing divestitures of energy assets by 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.
We do
not have any officers or employees and rely solely on officers
of our general partner and employees of Targa.
None of the officers of our general partner are employees of our
general partner. We have entered into an Omnibus Agreement with
Targa, pursuant to which Targa operates our assets and performs
other administrative services for us such as accounting, legal,
regulatory, corporate development, finance, land and
engineering. Affiliates of Targa conduct businesses and
activities of their own in which we have no economic interest,
including businesses and activities relating to Targa. As a
result, there could be material competition for the time and
effort of the officers and employees who provide services to our
general partner and Targa. If the officers of our general
partner and the employees of Targa do not devote sufficient
attention to the management and operation of our business, our
financial results may suffer and our ability to make
distributions to our unitholders may be reduced.
If our
general partner fails to maintain an effective system of
internal controls, then we may not be able to accurately report
our financial results or prevent fraud. As a result, current and
potential unitholders could lose confidence in our financial
reporting, which would harm our business and the trading price
of our common units.
Targa Resources GP LLC, our general partner, has sole
responsibility for conducting our business and for managing our
operations. Effective internal controls are necessary for our
general partner, on our behalf, to provide reliable financial
reports, prevent fraud and operate us successfully as a public
company. If our general partners efforts to develop and
maintain its internal controls are not successful, it is unable
to maintain adequate controls over our financial processes and
reporting in the future or it is unable to assist us in
complying with our obligations under Section 404 of the
Sarbanes-Oxley Act of 2002, our operating results could be
harmed or we may fail to meet our reporting obligations.
Ineffective internal controls also could cause investors to lose
confidence in our reported financial information, which would
likely have a negative effect on the trading price of our common
units.
38
The
amount of cash we have available for distribution to holders of
our common units and subordinated units depends primarily on our
cash flow and not solely on profitability. Consequently, even if
we are profitable, we may not be able to make cash distributions
to holders of our common units and subordinated
units.
You should be aware that the amount of cash we have available
for distribution depends primarily upon our cash flow and not
solely on profitability, which will be affected by non-cash
items. As a result, we may make cash distributions during
periods when we record losses for financial accounting purposes
and may not make cash distributions during periods when we
record net earnings for financial accounting purposes.
Terrorist
attacks, and the threat of terrorist attacks, have resulted in
increased costs to our business. 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 our industry in general, and on us
in particular, is not known at this time.
Increased security measures taken by us as a precaution against
possible terrorist attacks have resulted in increased costs to
our business. Uncertainty surrounding continued hostilities in
the Middle East or other sustained military campaigns may affect
our operations in unpredictable ways, including disruptions of
crude oil supplies and markets for our products, and the
possibility that infrastructure facilities could be direct
targets of, or indirect casualties of, an act of terror.
Changes in the insurance markets attributable to terrorist
attacks may make certain types of insurance more difficult for
us to obtain. Moreover, the insurance that may be available to
us may be significantly more expensive than our existing
insurance coverage. Instability in the financial markets as a
result of terrorism or war could also affect our ability to
raise capital.
Risks
Inherent in an Investment in Us
Cash
distributions are not guaranteed and may fluctuate with our
performance and the establishment of financial
reserves.
Because distributions on the common units are dependent on the
amount of cash we generate, distributions may fluctuate based on
our performance. The actual amount of cash that is available to
be distributed each quarter will depend on numerous factors,
some of which are beyond our control and the control of the
general partner. Cash distributions are dependent primarily on
cash flow, including cash flow from financial reserves and
working capital borrowings, and not solely on profitability,
which is affected by non-cash items. Therefore, cash
distributions might be made during periods when we record losses
and might not be made during periods when we record profits
In order to make cash distributions at our current distribution
rate of $0.3975 per common unit and subordinated unit per
complete quarter, or $1.59 per unit per year, we will require
available cash of approximately $18.7 million per quarter,
or $74.9 million per year, based on common units and
subordinated units outstanding at December 31, 2007. We may
not have sufficient available cash from operating surplus each
quarter to enable us to make cash distributions at our current
distribution rate under our cash distribution policy. The amount
of cash we can distribute on our units principally depends upon
the amount of cash we generate from our operations, which will
fluctuate from quarter to quarter based on, among other things:
|
|
|
|
|
the fees we charge and the margins we realize for our services;
|
|
|
|
the prices of, levels of production of, and demand for, natural
gas and NGLs;
|
|
|
|
the volume of natural gas we gather, treat, compress, process,
transport and sell, and the volume of NGLs we process or
fractionate and sell;
|
39
|
|
|
|
|
the relationship between natural gas and NGL prices;
|
|
|
|
cash settlements of hedging positions;
|
|
|
|
the level of competition from other midstream energy companies;
|
|
|
|
the level of our operating and maintenance and general and
administrative costs; and
|
|
|
|
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:
|
|
|
|
|
the level of capital expenditures we make;
|
|
|
|
our ability to make borrowings under our credit facility to pay
distributions;
|
|
|
|
the cost of acquisitions;
|
|
|
|
our debt service requirements and other liabilities;
|
|
|
|
fluctuations in our working capital needs;
|
|
|
|
general and administrative expenses, including expenses we incur
as a result of being a public company;
|
|
|
|
restrictions on distributions contained in our debt
agreements; and
|
|
|
|
the amount of cash reserves established by our general partner
for the proper conduct of our business.
|
Targa
controls our general partner, which has sole responsibility for
conducting our business and managing our operations. Targa has
conflicts of interest with us and may favor its own interests to
your detriment.
Targa owns and controls our general partner. Some of our general
partners directors, and some of its executive officers,
are directors or officers of Targa. Therefore, conflicts of
interest may arise between Targa, 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:
|
|
|
|
|
neither our partnership agreement nor any other agreement
requires Targa to pursue a business strategy that favors us.
Targas directors and officers have a fiduciary duty to
make decisions in the best interests of the owners of Targa,
which may be contrary to our interests;
|
|
|
|
our general partner is allowed to take into account the
interests of parties other than us, such as Targa, or its
owners, including Warburg Pincus, in resolving conflicts of
interest; and
|
|
|
|
Targa is not limited in its ability to compete with us and is
under no obligation to offer assets to us.
|
The
credit and business risk profile of our general partner and its
owners could adversely affect our credit ratings and
profile.
The credit and business risk profiles of the general partner and
its owners may be factors in credit evaluations of a master
limited partnership. This is because the general partner can
exercise significant influence over the business activities of
the partnership, including its cash distribution and acquisition
strategy and business risk profile. Another factor that may be
considered is the financial condition of the general partner and
its owners, including the degree of their financial leverage and
their dependence on cash flow from the partnership to service
their indebtedness.
Targa, the owner of our general partner, has significant
indebtedness outstanding and is partially dependent on the cash
distributions from their indirect general partner and limited
partner equity interests in us to service such indebtedness. Any
distributions by us to such entities will be made only after
satisfying our then current obligations to our creditors. Our
credit ratings and business risk profile could be adversely
40
affected if the ratings and risk profiles of the entities that
control our general partner were viewed as substantially lower
or more risky than ours.
Our
partnership agreement limits our general partners
fiduciary duties to holders of our units and restricts the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.
The directors and officers of our general partner have a
fiduciary duty to manage our general partner in a manner
beneficial to its owner, Targa. Our partnership agreement
contains provisions that reduce the standards to which our
general partner would otherwise be held by state fiduciary duty
laws. For example, our partnership agreement:
|
|
|
|
|
permits our general partner to make a number of decisions in its
individual capacity, as opposed to in 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;
|
|
|
|
provides that our general partner does 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;
|
|
|
|
generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner acting in good
faith 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 must be fair
and reasonable to us, as determined by our general partner
in good faith and that, in determining whether a transaction or
resolution is fair and reasonable, our general
partner may consider the totality of the relationships between
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us;
|
|
|
|
provides that our general partner and its officers and directors
are not 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 or, in the case of a criminal matter, acted
with knowledge that the conduct was criminal; and
|
|
|
|
provides that in resolving conflicts of interest, it is presumed
that in making its decision the general partner acted in good
faith, and in any proceeding brought by or on behalf of any
limited partner or us, the person bringing or prosecuting such
proceeding will have the burden of overcoming such presumption.
|
Targa
is not limited in its ability to compete with us, which could
limit our ability to acquire additional assets or
businesses.
Neither our partnership agreement nor the Omnibus Agreement
between us and Targa prohibits Targa from owning assets or
engaging in businesses that compete directly or indirectly with
us. In addition, Targa 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
any of those assets. Targa is a large, established participant
in the midstream energy business, and has significantly greater
resources and experience than we have, which factors may make it
more difficult for us to compete with Targa with respect to
commercial activities as well as for acquisition candidates. As
a result, competition from Targa could adversely impact our
results of operations and cash available for distribution.
41
Cost
reimbursements due our general partner and its affiliates for
services provided, which will be determined by our general
partner, will be substantial and will reduce our cash available
for distribution to you.
Pursuant to the Omnibus Agreement we entered into with Targa and
Targa Resources GP LLC, our general partner, Targa receives
reimbursement for the payment of operating expenses related to
our operations and for the provision of various general and
administrative services for our benefit. Payments for these
services are substantial and reduce the amount of cash available
for distribution to unitholders. Please see Item 13.
Certain Relationships and Related Transactions, and Director
Independence. In addition, under Delaware partnership law,
our general partner has unlimited liability for our obligations,
such as our debts and environmental liabilities, except for our
contractual obligations that are expressly made without recourse
to our general partner. To the extent our general partner incurs
obligations on our behalf, we are obligated to reimburse or
indemnify our general partner. If we are unable or unwilling to
reimburse or indemnify our general partner, our general partner
may take actions to cause us to make payments of these
obligations and liabilities. Any such payments could reduce the
amount of cash otherwise available for distribution to our
unitholders.
Holders
of our common units 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
will not elect our general partner or our general partners
board of directors, and have no right to elect our general
partner or our general partners board of directors on an
annual or other continuing basis. The board of directors of our
general partner is chosen by Targa. Furthermore, if the
unitholders are dissatisfied with the performance of our general
partner, they have little ability to remove our general partner.
As a result of these limitations, the price at which the common
units trade could be diminished because of the absence or
reduction of a takeover premium in the trading price.
Removal
of our general partner without its consent will dilute and
adversely affect our common unitholders.
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 our common units
will be extinguished. A removal of our general partner under
these circumstances would adversely affect our common units by
prematurely eliminating their distribution and liquidation
preference over our subordinated units, which would otherwise
have continued until we had met certain distribution and
performance tests. Cause is narrowly defined to mean that a
court of competent jurisdiction has entered a final,
non-appealable judgment finding the general partner liable for
actual fraud or willful or wanton misconduct in its capacity as
our general partner. Cause does not include most cases of
charges of poor management of the business, so the removal of
the general partner because of the unitholders
dissatisfaction with our general partners performance in
managing our partnership will most likely result in the
termination of the subordination period and conversion of all
subordinated units to common units.
We may
issue additional units without your approval, which would dilute
your existing ownership interests.
Our partnership agreement does not limit the number of
additional limited partner interests that we may issue at any
time without the approval of our unitholders. The issuance by us
of additional common units or other equity securities of equal
or senior rank will have the following effects:
|
|
|
|
|
our unitholders proportionate ownership interest in us
will decrease;
|
|
|
|
the amount of cash available for distribution on each unit may
decrease;
|
42
|
|
|
|
|
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;
|
|
|
|
the ratio of taxable income to distributions may increase;
|
|
|
|
the relative voting strength of each previously outstanding unit
may be diminished; and
|
|
|
|
the market price of the common units may decline.
|
Affiliates
of our general partner may sell common units in the public
markets, which sales could have an adverse impact on the trading
price of the common units.
Management of our general partner and Targa beneficially hold
96,152 common units and 11,528,231 subordinated units. All of
the subordinated units will convert into common units at the end
of the subordination period and may convert earlier. The sale of
these units in the public markets could have an adverse impact
on the price of the common units or on any trading market that
may develop.
Our
general partner may elect to cause us to issue Class B
units to it in connection with a resetting of the target
distribution levels related to our general partners
incentive distribution rights without the approval of the
conflicts committee of our general partner or holders of our
common units. This ability may result in lower distributions to
holders of our common units in certain situations.
Our general partner has the right, at a time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled (48%)
for each of the prior four consecutive fiscal quarters, to reset
the initial cash target distribution levels at higher levels
based on the distribution at the time of the exercise of the
reset election. Following a reset election by our general
partner, the minimum quarterly distribution amount will be reset
to an amount equal to the average cash distribution amount per
common unit for the two fiscal quarters immediately preceding
the reset election (such amount is referred to as the
reset minimum quarterly distribution) and the target
distribution levels will be reset to correspondingly higher
levels based on percentage increases above the reset minimum
quarterly distribution amount.
In connection with resetting these target distribution levels,
our general partner will be entitled to receive Class B
units. The Class B units will be entitled to the same cash
distributions per unit as our common units and will be
convertible into an equal number of common units. The number of
Class B units to be issued will be equal to that number of
common units whose aggregate quarterly cash distributions
equaled the average of the distributions to our general partner
on the incentive distribution rights in the prior two quarters.
We anticipate that our general partner would exercise this reset
right in order to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash
distributions per common unit without such conversion; however,
it is possible that our general partner could exercise this
reset election at a time when it is experiencing, or may be
expected to experience, declines in the cash distributions it
receives related to its incentive distribution rights and may
therefore desire to be issued our Class B units, which are
entitled to receive cash distributions from us on the same
priority as our common units, rather than retain the right to
receive incentive distributions based on the initial target
distribution levels. As a result, a reset election may cause our
common unitholders to experience dilution in the amount of cash
distributions that they would have otherwise received had we not
issued new Class B units to our general partner in
connection with resetting the target distribution levels related
to our general partners incentive distribution rights.
Increases
in interest rates could adversely impact our unit price and our
ability to issue additional equity to make acquisitions, for
expansion capital expenditures or for other
purposes.
As with other yield-oriented securities, our unit price is
impacted by the level of our cash distributions and implied
distribution yield. The distribution yield is often used by
investors to compare and rank related yield-oriented securities
for investment decision-making purposes. Therefore, changes in
interest rates, either positive or negative, may affect the
yield requirements of investors who invest in our units, and a
rising
43
interest rate environment could have an adverse impact on our
unit price and our ability to issue additional equity to make
acquisitions, for expansion capital expenditures or for other
purposes.
Our
partnership agreement restricts the voting rights of 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 the board of directors 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.
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 owners of our general partner from transferring
all or a portion of their respective ownership interest in our
general partner to a third party. The new owners of our general
partner would then be in a position to replace the board of
directors and officers of our general partner with its own
choices and thereby influence the decisions taken by the board
of directors and officers.
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. At the end
of the subordination period, assuming no additional issuances of
common units, our general partner and its affiliates will own
approximately 24.5% of our aggregate outstanding common units.
Your
liability may not be limited if a court finds that unitholder
action constitutes control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in Louisiana and Texas. 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.
You could be liable for any and all of our obligations as if you
were a general partner if:
|
|
|
|
|
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
|
|
|
|
your right to act with other unitholders to remove or replace
the general partner, to approve some amendments to our
partnership agreement or to take other actions under our
partnership agreement constitute control of our
business.
|
Unitholders
may have liability to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to you if the distribution would cause
our liabilities to exceed the fair value of our assets. Delaware
law provides that for a period of three years from the date of
the impermissible distribution, limited
44
partners who received the 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 contributions to the partnership that are
known to the substituted limited partner at the time it became a
limited partner and for unknown obligations if the liabilities
could be determined from the partnership agreement. Liabilities
to partners on account of their partnership interest and
liabilities that are non-recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted.
Tax Risks
to Common Unitholders
Our
tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to a
material amount of entity-level taxation by individual states.
If the Internal Revenue Service, or IRS, were to treat us as a
corporation or if we were to become subject to a material amount
of entity-level taxation for state tax purposes, then our cash
available for distribution to you would be substantially
reduced.
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 have not
requested, and do not plan to request, a ruling from the IRS on
this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe based
upon our current operations that we are so treated, a change in
our business (or a change in current law) could cause us to be
treated as a corporation for federal income tax purposes or
otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable 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, treatment of us as a
corporation would result in a material reduction in the
anticipated cash flow and after-tax return to the unitholders,
likely causing a substantial reduction in the value of 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. At the federal level, legislation
has been proposed that would eliminate partnership tax treatment
for certain publicly traded partnerships. Although such
legislation would not apply to us as currently proposed, it
could be amended prior to enactment in a manner that does apply
to us. We are unable to predict whether any of these changes, or
other proposals will ultimately be enacted. Moreover, any
modification to the federal income tax laws and interpretations
thereof may or may not be applied retroactively. Any such
changes could negatively impact the value of an investment in
our common units. At the state level, because of widespread
state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation
through the imposition of state income, franchise and other
forms of taxation. For example, we are required to pay Texas
franchise tax at a maximum effective rate of 0.7% of our gross
income apportioned to Texas in the prior year. Imposition of any
such tax on us by any other state will reduce the cash available
for distribution to you.
Our partnership agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects
us to entity-level taxation for federal, state or local income
tax purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the
impact of that law on us.
45
We
prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be
permitted under existing Treasury regulations. If the IRS were
to challenge this method or new Treasury regulations were
issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely affected, and the
cost of any contest will reduce our cash available for
distribution to you.
We have not requested 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 some or all of
the positions we take. Any contest with the IRS may materially
and adversely impact the market for our common units and the
price at which they trade. In addition, our costs of any contest
with the IRS will be borne indirectly by our unitholders and our
general partner because the costs will reduce our cash available
for distribution.
You
may be required to pay taxes on your share of our income even if
you do not receive any cash distributions from us.
Because our unitholders are treated as partners to whom we will
allocate taxable income which could be different in amount than
the cash we distribute, you may 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 actual tax liability that results from that income.
Tax
gain or loss on disposition of our 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 you receive is less than your original
cost. A substantial portion of the amount realized, whether or
not representing gain, may be ordinary income due to potential
recapture items, including depreciation recapture. In addition,
because the amount realized includes a unitholders share
of our non-recourse liabilities, if you sell your units, you may
incur a tax liability in excess of the amount of cash you
receive from the sale.
Tax-exempt
entities and
non-United
States persons face unique tax issues from owning our 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-United
States 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-United
States persons will be reduced by withholding taxes at the
highest applicable effective tax rate, and
non-United
States 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
non-United
States person, you should consult your tax advisor before
investing in our common units.
46
We
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 adopt depreciation
and amortization positions that may not conform to all aspects
of existing Treasury Regulations and may result in audit
adjustments to our unitholders tax returns without the
benefit of additional deductions. 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.
A
unitholder whose units are loaned to a short seller
to cover a short sale of units may be considered as having
disposed of those units. If so, he would no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of the loaned units, he may no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan to the short seller and the unitholder
may recognize gain or loss from such disposition. Moreover,
during the period of the loan to the short seller, any of our
income, gain, loss or deduction with respect to those units may
not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing their units.
We
have adopted certain valuation methodologies that may result in
a shift of income, gain, loss and deduction between the general
partner and the unitholders. The IRS may challenge this
treatment, which could adversely affect the value of our common
units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
the general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent
purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our valuation methods,
or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of income, gain, loss and deduction between the
general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could
have a negative impact on the value of our common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered to have terminated our partnership for
federal income tax purposes if there is a sale or exchange of
50% or more of the total interests in our capital and profits
within a twelve-month period. Our termination would, among other
things, result in the closing of our taxable year for all
unitholders, which would result in us filing two tax returns
(and our unitholders could receive two Schedules K-1) for one
fiscal year and could result in a deferral of depreciation
deductions allowable in computing our taxable income. In the
case of a unitholder reporting on a taxable year other than a
fiscal year ending December 31, the closing
47
of our taxable year may also result in more than twelve months
of our taxable income or loss being includable in his taxable
income for the year of termination. Our termination currently
would not affect our classification as a partnership for federal
income tax purposes, but instead, we would be treated as a new
partnership for tax purposes. If treated as a new partnership,
we must make new tax elections and could be subject to penalties
if we are unable to determine that a termination occurred.
You
may be subject to foreign, state and local taxes and return
filing requirements in jurisdictions where you do not live as a
result of investing in our common units.
In addition to federal income taxes, you might be subject to
return filing requirements and other taxes, including foreign,
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, now or in
the future, even if you do not live in any of those
jurisdictions. Further, you may be subject to penalties for
failure to comply with those requirements. We own assets and
conduct business in the States of Texas and Louisiana.
Currently, Texas does not impose a personal income tax on
individuals. As we make acquisitions or expand our business, we
may own assets or do business in 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
|
None
A description of our properties is contained in Item 1 of
this annual report.
Our principal executive offices are located at 1000 Louisiana
Street, Suite 4300, Houston, Texas 77002 and our telephone
number is
713-584-1000.
|
|
Item 3.
|
Legal
Proceedings
|
On December 8, 2005, WTG Gas Processing (WTG)
filed suit in the 333rd District Court of Harris County,
Texas against several defendants, including Targa Resources,
Inc., and three other Targa entities and private equity funds
affiliated with Warburg Pincus LLC, seeking damages from the
defendants. The suit alleges that Targa and private equity funds
affiliated with Warburg Pincus LLC, along with ConocoPhillips
Company (ConocoPhillips) and Morgan Stanley,
tortiously interfered with (i) a contract WTG claims to
have had to purchase the SAOU System from ConocoPhillips, and
(ii) prospective business relations of WTG. WTG claims the
alleged interference resulted from Targas competition to
purchase the ConocoPhillips assets and its successful
acquisition of those assets in 2004. On October 2, 2007,
the District Court granted defendants motions for summary
judgment on all of WTGs claims. Targa has agreed to
indemnify us for any claim or liability arising out of the WTG
suit. WTGs motion to reconsider and for a new trial was
overruled. On January 2, 2008, WTG filed a notice of
appeal. Targa will contest any appeal filed by WTG, but can give
no assurances regarding the outcome of the proceeding.
We are not a party to any other legal proceedings other than
legal proceedings arising in the ordinary course of our
business. We are a party to various administrative and
regulatory proceedings that have arisen in the ordinary course
of our business. Please see Item 1.
Business Regulation of Operations and Environmental
Matters.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
None
48
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity Securities
|
Market
Information
Our common units have been listed on The NASDAQ Stock Market LLC
(NASDAQ) under the symbol NGLS since
February 9, 2007. Prior to February 9, 2007, our
equity securities were not listed on any exchange or traded on
any public trading market. The following table sets forth the
high and low sales prices of the common units, as reported by
the NASDAQ, as well as the amount of cash distributions declared
per quarter for the period from February 14, 2007, the
closing of our IPO, through December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
Distribution
|
|
|
|
|
|
|
per Common
|
|
per Subordinated
|
Quarter Ended
|
|
High
|
|
Low
|
|
Unit
|
|
Unit
|
|
December 31, 2007
|
|
$
|
29.84
|
|
|
$
|
25.10
|
|
|
$
|
0
|
.3975
|
|
$
|
0
|
.3975
|
September 30, 2007
|
|
|
35.00
|
|
|
|
24.39
|
|
|
|
0
|
.3375
|
|
|
0
|
.3375
|
June 30, 2007
|
|
|
35.28
|
|
|
|
27.70
|
|
|
|
0
|
.3375
|
|
|
0
|
.3375
|
February 14, 2007 to March 31, 2007
|
|
|
29.30
|
|
|
|
22.75
|
|
|
|
0
|
.16875
|
|
|
0
|
.16875
|
As of March 11, 2008, there were approximately
40 unitholders of record of our common units. This number
does not include unitholders whose units are held in trust by
other entities. The actual number of unitholders is greater than
the number of holders of record. We have also issued 11,528,231
subordinated units, for which there is no established public
trading market. The subordinated units are held by affiliates of
Targa Resources GP LLC, our general partner. Our general partner
and its affiliates will receive a quarterly distribution on
these units only after sufficient funds have been paid to the
common units.
Distributions
of Available Cash
General. Our partnership agreement requires
that, within 45 days after the end of each quarter, we
distribute all of our available cash to unitholders of record on
the applicable record date, as determined by our general partner.
Definition of Available Cash. The term
available cash, for any quarter, means all cash and
cash equivalents on hand on the date of determination of
available cash for that quarter less the amount of cash reserves
established by our general partner to:
|
|
|
|
|
provide for the proper conduct of our business;
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distribution to our unitholders and to our
general partner for any one or more of the next four quarters.
|
Minimum Quarterly Distribution. We will
distribute to the holders of common units and subordinated units
on a quarterly basis at least the minimum quarterly distribution
of $0.3375 per unit, or $1.35 per unit on an annualized basis,
to the extent we have sufficient cash from our operations after
establishment of cash reserves and payment of fees and expenses,
including payments to our general partner. However, there is no
guarantee that we will pay the minimum quarterly distribution on
the units in any quarter. Even if our cash distribution policy
is not modified or revoked, the amount of distributions paid
under our policy and the decision to make any distribution is
determined by our general partner, taking into consideration the
terms of our partnership agreement. The board of directors of
our general partner has broad discretion to establish cash
reserves that it determines are necessary or appropriate to
properly conduct our business. These can include cash reserves
for future capital and maintenance expenditures, reserves to
stabilize distributions of cash to our unitholders, reserves to
reduce debt or, as necessary, reserves to comply with the term
of any of our agreements or obligations. We will be prohibited
from making any distributions to unitholders if it would cause
an event of default, or an event of default exists, under our
credit agreement.
49
Please see Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Description of Credit Agreement for
a discussion of the restrictions included in our credit
agreement that may restrict our ability to make distributions.
During 2007, we distributed to the holders of our common units
and subordinated units on a quarterly basis a quarterly
distribution of $0.3375 per unit, or $1.35 per year. For the
fourth quarter of 2007, a distribution of $0.3975 per unit, or
$1.59 per unit on an annualized basis, was declared on
January 24, 2008, and was paid on February 14, 2008.
General Partner Interest. Our general partner
is currently entitled to 2% of all quarterly distributions that
we make prior to our liquidation. This general partner interest
is represented by 942,128 general partner units. Our general
partner has the right, but not the obligation, to contribute a
proportional amount of capital to us to maintain its current
general partner interest. The general partners 2% interest
in these distributions will be reduced if we issue additional
units in the future and our general partner does not contribute
a proportional amount of capital to us to maintain its 2%
general partner interest.
Incentive Distribution Rights. Our general
partner also currently holds incentive distribution rights that
entitle it to receive up to a maximum of 50% of the cash we
distribute in excess of $0.5063 per unit per quarter. The
maximum distribution of 50% includes distributions paid to our
general partner on its general partner interest and assumes that
our general partner maintains its general partner interest at
2%. The maximum distribution of 50% does not include any
distributions that our general partner may receive on limited
partner units that it owns.
Sales of
Unregistered Units
None
Repurchase
of Equity by Targa Resources Partners LP
None
Use of
Proceeds
Not applicable.
50
|
|
Item 6.
|
Selected
Financial Data
|
SELECTED
FINANCIAL AND OPERATING DATA
On February 14, 2007, we had Targas ownership
interests in the North Texas System contributed to us. On
October 24, 2007, we acquired Targas ownership
interests in the SAOU System and the LOU System. As required by
Statement of Financial Accounting Standards (SFAS)
141, we accounted for these transactions as transfers of net
assets between entities under common control. For combinations
of entities under common control, the purchase cost provisions
(as they relate to purchase business combinations involving
unrelated entities) of SFAS 141 explicitly do not apply;
instead the method of accounting prescribed by SFAS 141 for
such transfers is similar to the pooling-of-interests method of
accounting. Under this method, the carrying amount of net assets
recognized in the balance sheets of each combining entity are
carried forward to the balance sheet of the combined entity, and
no other assets or liabilities are recognized as a result of the
combination (that is, no recognition is made for a purchase
premium or discount representing any difference between the cash
consideration paid and the book value of the net assets
acquired).
Although in connection with our IPO, the North Texas System
was presented as our predecessor entity, as a result of our
October 2007 acquisition of the SAOU and LOU Systems, the
predecessor entity for us is now considered to be the net assets
of the SAOU and LOU Systems as these were the first assets
acquired by Targa on April 16, 2004. Therefore, subsequent
to the contribution of the North Texas System from Targa on
February 14, 2007, we recognized the assets and liabilities
of the North Texas System contributed to us at their carrying
amounts (historical cost) in the accounts of the SAOU and LOU
Systems (the predecessor entity) at the date of transfer. The
accounting treatment for combinations of entities under common
control is consistent with the concept of poolings as
combinations of common shareholder (or unitholder) interests, as
all of the North Texas Systems equity accounts were also
carried forward intact initially, and subsequently adjusted due
to the cash consideration we paid for the acquired net
assets.
In addition to requiring that assets and liabilities be
carried forward at historical costs, SFAS 141 also
prescribes that for transfers of net assets between entities
under common control, all income statements presented be
combined as of the date of common control. Accordingly, our
consolidated financial statements and all other financial
information included in this report have been restated to assume
that the transfer of the North Texas System net assets from
Targa to us had occurred at the date when both the North Texas
System and the SAOU and LOU Systems met the accounting
requirements for entities under common control (October 31,
2005). As a result, financial statements and financial
information presented for prior periods in this report have been
restated.
Accordingly, our historical results include the historical
results of the SAOU and LOU Systems (acquired by Targa effective
April 16, 2004) for the years ended December 31,
2007, 2006 and 2005; and the historical results of the North
Texas System (acquired by Targa effective November 1,
2005) subsequent to October 31, 2005.
The financial and operating data as of and for the year ended
December 31, 2004 are derived from the audited consolidated
financial statements of Targa. Targas consolidated
financial results for the year ended December 31, 2004
includes the results of operations for the eight and a half
month period commencing with its April 16, 2004 acquisition
of the predecessor business from ConocoPhillips, combined with
the acquisition-related activities of Targa for the period from
January 1 to April 15, 2004. The selected combined
financial and operating data of the predecessor for the three
and a half months ended April 15, 2004 and as of and for
the year ended December 31, 2003 are derived from the
audited financial statements of the predecessor business.
The information contained herein should be read together
with, and is qualified in its entirety by reference to, the
historical combined financial statements and the accompanying
notes included elsewhere in this
Form 10-K.
Please see Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations
for a discussion of factors that affect the comparability of the
information reflected in the selected financial and operating
data.
51
As used in this report, unless we indicate otherwise, the
terms our, we, us and
similar terms refer to Targa Resources Partners LP, together
with our subsidiaries, and the term Targa refers to
Targa Resources, Inc. and its subsidiaries and affiliates (other
than us). The following table summarizes selected financial and
operating data for the periods and as of the dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 12
|
|
|
|
SAOU/LOU Systems Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
(Inception)
|
|
|
|
106-Day Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
through
|
|
|
|
Period Ended
|
|
|
Year Ended
|
|
|
|
Years Ended December 31,
|
|
|
December 31,
|
|
|
|
April 15,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
|
(in millions of dollars, except operating and price data)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,661.5
|
|
|
$
|
1,738.5
|
|
|
$
|
1,172.5
|
|
|
$
|
602.6
|
|
|
|
$
|
232.8
|
|
|
$
|
724.7
|
|
Product purchases
|
|
|
1,406.8
|
|
|
|
1,517.7
|
|
|
|
1,061.7
|
|
|
|
544.9
|
|
|
|
|
212.3
|
|
|
|
665.4
|
|
Operating expense
|
|
|
50.9
|
|
|
|
49.1
|
|
|
|
24.4
|
|
|
|
15.3
|
|
|
|
|
7.9
|
|
|
|
23.2
|
|
Depreciation and amortization expense
|
|
|
71.8
|
|
|
|
69.9
|
|
|
|
23.1
|
|
|
|
10.4
|
|
|
|
|
3.8
|
|
|
|
12.9
|
|
General and administrative expense
|
|
|
18.9
|
|
|
|
16.1
|
|
|
|
16.7
|
|
|
|
11.1
|
|
|
|
|
0.8
|
|
|
|
3.3
|
|
Taxes other than income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.4
|
|
|
|
4.3
|
|
Other
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.0
|
|
Interest expense, net
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, allocated from Parent
|
|
|
19.4
|
|
|
|
88.0
|
|
|
|
21.2
|
|
|
|
6.1
|
|
|
|
|
|
|
|
|
|
|
Loss on debt extinguishment
|
|
|
|
|
|
|
|
|
|
|
3.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
|
|
(1.3
|
)
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense(1)
|
|
|
1.5
|
|
|
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
|
2.6
|
|
|
|
6.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
40.3
|
|
|
$
|
11.6
|
|
|
$
|
9.7
|
|
|
$
|
16.1
|
|
|
|
$
|
4.0
|
|
|
$
|
9.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to predecessor operations
|
|
|
12.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocable to partners
|
|
|
28.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest in net income
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common and subordinated unitholders
|
|
$
|
27.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit basic
|
|
$
|
0.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit diluted
|
|
$
|
0.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit
|
|
$
|
1.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial and Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin(2)
|
|
$
|
203.8
|
|
|
$
|
171.7
|
|
|
$
|
86.4
|
|
|
$
|
42.4
|
|
|
|
$
|
12.6
|
|
|
$
|
36.1
|
|
Adjusted EBITDA(3)
|
|
$
|
185.8
|
|
|
$
|
154.1
|
|
|
$
|
66.0
|
|
|
$
|
31.3
|
|
|
|
$
|
11.8
|
|
|
$
|
32.8
|
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 12
|
|
|
|
SAOU/LOU Systems Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
(Inception)
|
|
|
|
106-Day Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
through
|
|
|
|
Period Ended
|
|
|
Year Ended
|
|
|
|
Years Ended December 31,
|
|
|
December 31,
|
|
|
|
April 15,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
|
(in millions of dollars, except operating and price data)
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering throughput,
MMcf/d(4)
|
|
|
452.0
|
|
|
|
433.8
|
|
|
|
302.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d(5)
|
|
|
429.2
|
|
|
|
419.6
|
|
|
|
253.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d
|
|
|
42.6
|
|
|
|
42.4
|
|
|
|
23.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales, BBtu/d
|
|
|
410.2
|
|
|
|
489.4
|
|
|
|
259.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL sales, MBbl/d
|
|
|
36.4
|
|
|
|
36.0
|
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate sales, MBbl/d
|
|
|
3.6
|
|
|
|
3.3
|
|
|
|
1.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Realized Prices:(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas, $/MMBtu
|
|
$
|
6.66
|
|
|
$
|
6.68
|
|
|
$
|
9.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL, $/gal
|
|
|
1.03
|
|
|
|
0.85
|
|
|
|
0.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate, $/Bbl
|
|
|
65.62
|
|
|
|
59.87
|
|
|
|
58.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property plant and equipment, net
|
|
$
|
1,259.6
|
|
|
$
|
1,288.6
|
|
|
$
|
1,325.9
|
|
|
$
|
237.6
|
|
|
|
$
|
266.0
|
|
|
$
|
268.8
|
|
Total Assets
|
|
|
1,480.0
|
|
|
|
1,416.4
|
|
|
|
1,500.0
|
|
|
|
323.4
|
|
|
|
|
288.8
|
|
|
|
316.8
|
|
Long-term allocated debt (including current portion)
|
|
|
|
|
|
|
1,047.3
|
|
|
|
1,053.3
|
|
|
|
103.0
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (including current portion)
|
|
|
626.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital/Net parent equity
|
|
|
614.2
|
|
|
|
245.9
|
|
|
|
281.2
|
|
|
|
139.2
|
|
|
|
|
170.9
|
|
|
|
177.3
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
265.7
|
|
|
$
|
124.4
|
|
|
$
|
10.5
|
|
|
$
|
28.2
|
|
|
|
$
|
11.5
|
|
|
$
|
(6.3
|
)
|
Investing activities
|
|
|
(40.7
|
)
|
|
|
(32.9
|
)
|
|
|
(6.8
|
)
|
|
|
(2.9
|
)
|
|
|
|
(1.2
|
)
|
|
|
(2.4
|
)
|
Financing activities
|
|
|
(174.0
|
)
|
|
|
(91.5
|
)
|
|
|
(3.7
|
)
|
|
|
(25.4
|
)
|
|
|
|
(10.3
|
)
|
|
|
8.8
|
|
|
|
|
(1) |
|
In May 2006, Texas adopted a margin tax consisting of a 1% tax
on the amount by which total revenue exceeds cost of goods sold,
as apportioned to Texas. The amount presented represents our
estimated liability for this tax. |
|
(2) |
|
Operating margin is total operating revenues less product
purchases and operating expense. Please see
Non-GAAP Financial Measures Operating Margin,
included in this Item 6. |
|
(3) |
|
Adjusted EBITDA is net income before interest, income taxes,
depreciation and amortization and non-cash income or loss
related to derivative instruments. Please see Non-GAAP Financial
Measures Adjusted EBITDA, included in this
Item 6. |
|
(4) |
|
Gathering throughput represents the volume of natural gas
gathered and passed through natural gas gathering pipelines from
connections to producing wells and central delivery points. |
|
(5) |
|
Plant natural gas inlet represents the volume of natural gas
passing through the meter located at the inlet of a natural gas
processing plant. |
|
(6) |
|
Average realized prices include the impact of hedging activities. |
Non-GAAP Financial
Measures
Adjusted EBITDA. We define Adjusted EBITDA as
net income before interest, income taxes, depreciation and
amortization and non-cash income or loss related to derivative
instruments. Adjusted EBITDA is used as a supplemental financial
measure by our management and by external users of our financial
statements such as investors, commercial banks and others, to
assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
53
|
|
|
|
|
our operating performance and return on capital as compared to
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.
|
The economic substance behind managements use of Adjusted
EBITDA is to measure the ability of our assets to generate cash
sufficient to pay interest costs, support our indebtedness, and
make distributions to our investors.
The GAAP measures most directly comparable to Adjusted EBITDA
are net cash provided by operating activities and net income.
Our non-GAAP financial measure of Adjusted EBITDA should not be
considered as an alternative to GAAP net cash provided by
operating activities and GAAP net income. Adjusted EBITDA is not
a presentation made in accordance with GAAP and has important
limitations as an analytical tool. You should not consider
Adjusted EBITDA in isolation or as a substitute for analysis of
our results as reported under GAAP. Because Adjusted EBITDA
excludes some, but not all, items that affect net income and net
cash provided by operating activities and is defined differently
by different companies in our industry, our definition of
Adjusted EBITDA may not be comparable to similarly titled
measures of other companies. Management compensates for the
limitations of Adjusted EBITDA as an analytical tool by
reviewing the comparable GAAP measures, understanding the
differences between the measures and incorporating these
insights into managements decision-making processes.
Operating Margin. We define operating margin
as total operating revenues, which consist of natural gas and
NGL sales plus service fee revenues, less product purchases,
which consist primarily of producer payments and other natural
gas purchases, and operating expense. Management reviews
operating margin monthly for consistency and trend analysis.
Based on this monthly analysis, management takes appropriate
action to maintain positive trends or to reverse negative
trends. Management uses operating margin as an important
performance measure of the core profitability of our operations.
The GAAP measure most directly comparable to operating margin is
net income. Our non-GAAP financial measure of operating margin
should not be considered as an alternative to GAAP net income.
Operating margin is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You
should not consider operating margin in isolation or as a
substitute for analysis of our results as reported under GAAP.
Because operating margin excludes some, but not all, items that
affect net income and is defined differently by different
companies in our industry, our definition of operating margin
may not be comparable to similarly titled measures of other
companies, thereby diminishing its utility. Management
compensates for the limitations of operating margin as an
analytical tool by reviewing the comparable GAAP measure,
understanding the differences between the measures and
incorporating these insights into managements
decision-making processes.
We believe that investors benefit from having access to the same
financial measures that our management uses in evaluating our
operating results. Operating margin provides useful information
to investors because it is used as a supplemental financial
measure by our management and by external users of our financial
statements, including such investors, commercial banks and
others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
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.
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 12
|
|
|
|
SAOU/LOU Systems Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
(Inception)
|
|
|
|
106 Day
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
through
|
|
|
|
Period Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
April 15,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
2004
|
|
|
2003
|
|
|
|
(in millions)
|
|
Reconciliation of Adjusted EBITDA to net cash
provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
270.5
|
|
|
$
|
124.4
|
|
|
$
|
10.5
|
|
|
$
|
28.2
|
|
|
|
|
11.5
|
|
|
$
|
(6.3
|
)
|
Allocated interest expense from parent(1)
|
|
|
18.5
|
|
|
|
81.8
|
|
|
|
16.5
|
|
|
|
5.2
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net(1)
|
|
|
21.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in operating working capital which used (provided) cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(89.8
|
)
|
|
|
(78.5
|
)
|
|
|
61.8
|
|
|
|
76.7
|
|
|
|
|
(23.7
|
)
|
|
|
30.3
|
|
Accounts payable
|
|
|
(1.9
|
)
|
|
|
13.7
|
|
|
|
(11.4
|
)
|
|
|
(3.1
|
)
|
|
|
|
21.3
|
|
|
|
(1.5
|
)
|
Accrued liabilities
|
|
|
(33.5
|
)
|
|
|
15.4
|
|
|
|
(13.3
|
)
|
|
|
(76.5
|
)
|
|
|
|
0.1
|
|
|
|
(0.2
|
)
|
Other, including changes in noncurrent assets and liabilities
|
|
|
(29.3
|
)
|
|
|
14.1
|
|
|
|
(10.1
|
)
|
|
|
2.1
|
|
|
|
|
2.6
|
|
|
|
10.5
|
|
Noncash mark-to-market loss (gain)
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
|
|
(1.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
185.8
|
|
|
$
|
154.1
|
|
|
$
|
66.0
|
|
|
$
|
31.3
|
|
|
|
$
|
11.8
|
|
|
$
|
32.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to net
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40.3
|
|
|
$
|
11.6
|
|
|
$
|
9.7
|
|
|
$
|
16.1
|
|
|
|
$
|
4.0
|
|
|
$
|
9.5
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated interest expense, net
|
|
|
19.4
|
|
|
|
88.0
|
|
|
|
21.2
|
|
|
|
6.1
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense
|
|
|
1.5
|
|
|
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
|
2.6
|
|
|
|
6.1
|
|
Taxes other than income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.4
|
|
|
|
4.3
|
|
Depreciation and amortization expense
|
|
|
71.8
|
|
|
|
69.9
|
|
|
|
23.1
|
|
|
|
10.4
|
|
|
|
|
3.8
|
|
|
|
12.9
|
|
Risk Management Activities
|
|
|
0.6
|
|
|
|
(1.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash mark-to-market loss (gain)
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
|
|
(1.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
185.8
|
|
|
$
|
154.1
|
|
|
$
|
66.0
|
|
|
$
|
31.3
|
|
|
|
$
|
11.8
|
|
|
$
|
32.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of operating margin to net
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40.3
|
|
|
$
|
11.6
|
|
|
$
|
9.7
|
|
|
$
|
16.1
|
|
|
|
$
|
4.0
|
|
|
$
|
9.5
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense
|
|
|
71.8
|
|
|
|
69.9
|
|
|
|
23.1
|
|
|
|
10.4
|
|
|
|
|
3.8
|
|
|
|
12.9
|
|
Deferred income tax expense
|
|
|
1.5
|
|
|
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
|
2.6
|
|
|
|
6.1
|
|
Allocated interest expense, net
|
|
|
19.4
|
|
|
|
88.0
|
|
|
|
21.2
|
|
|
|
6.1
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
3.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
|
|
(1.3
|
)
|
|
|
|
|
|
|
|
|
|
General and administrative expense
|
|
|
18.9
|
|
|
|
16.1
|
|
|
|
16.7
|
|
|
|
11.1
|
|
|
|
|
0.8
|
|
|
|
3.3
|
|
Taxes other than income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.4
|
|
|
|
4.3
|
|
Gain on sale of assets
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin
|
|
$
|
203.8
|
|
|
$
|
171.7
|
|
|
$
|
86.4
|
|
|
$
|
42.4
|
|
|
|
$
|
12.6
|
|
|
$
|
36.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55
|
|
|
|
(1)
|
Net of amortization of debt issuance costs of $1.8 million
for the year ended December 31, 2007, $6.2 million for
the year ended December 31, 2006 and $4.7 million for the
year ended December 31, 2005.
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
On February 14, 2007, we had Targas ownership
interests in the North Texas System contributed to us. On
October 24, 2007, we acquired Targas ownership
interests in the SAOU System and the LOU System. As required by
Statement of Financial Accounting Standards (SFAS)
141, we accounted for these transactions as transfers of net
assets between entities under common control. For combinations
of entities under common control, the purchase cost provisions
(as they relate to purchase business combinations involving
unrelated entities) of SFAS 141 explicitly do not apply;
instead the method of accounting prescribed by SFAS 141 for
such transfers is similar to the pooling-of-interests method of
accounting. Under this method, the carrying amount of net assets
recognized in the balance sheets of each combining entity are
carried forward to the balance sheet of the combined entity, and
no other assets or liabilities are recognized as a result of the
combination (that is, no recognition is made for a purchase
premium or discount representing any difference between the cash
consideration paid and the book value of the net assets
acquired).
Although in connection with our IPO, the North Texas System
was presented as our predecessor entity, as a result of our
October 2007 acquisition of the SAOU and LOU Systems, the
predecessor entity for us is now considered to be the net assets
of the SAOU and LOU Systems as these were the first assets
acquired by Targa on April 16, 2004. Therefore, subsequent
to the contribution of the North Texas System from Targa on
February 14, 2007, we recognized the assets and liabilities
of the North Texas System contributed to us at their carrying
amounts (historical cost) in the accounts of the SAOU and LOU
Systems (the predecessor entity) at the date of transfer. The
accounting treatment for combinations of entities under common
control is consistent with the concept of poolings as
combinations of common shareholder (or unitholder) interests, as
all of the North Texas Systems equity accounts were also
carried forward intact initially, and subsequently adjusted due
to the cash consideration we paid for the acquired net
assets.
In addition to requiring that assets and liabilities be
carried forward at historical costs, SFAS 141 also
prescribes that for transfers of net assets between entities
under common control, all income statements presented be
combined as of the date of common control. Accordingly, our
consolidated financial statements and all other financial
information included in this report have been restated to assume
that the transfer of the North Texas System net assets from
Targa to us had occurred at the date when both the North Texas
System and the SAOU and LOU Systems met the accounting
requirements for entities under common control (October 31,
2005). As a result, financial statements and financial
information presented for prior periods in this report have been
restated.
Accordingly, our historical results include the historical
results of the SAOU and LOU Systems (acquired by Targa effective
April 16, 2004) for the years ended December 31,
2007, 2006 and 2005; and the historical results of the North
Texas System (acquired by Targa effective November 1,
2005) subsequent to October 31, 2005.
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 financial statements and notes
included elsewhere in this annual report.
Overview
We are a Delaware limited partnership formed by Targa to own,
operate, acquire and develop a diversified portfolio of
complementary midstream energy assets. We are engaged in the
business of gathering, compressing, treating, processing and
selling natural gas and fractionating and selling NGLs and NGL
products. We currently operate in the Fort Worth Basin in
north Texas, the Permian Basin in west Texas and in southwest
Louisiana.
56
We are owned 98% by our limited partners and 2% by our general
partner, Targa Resources GP LLC, an indirect, wholly-owned
subsidiary of Targa. Our limited partner common units are
publicly traded on the NASDAQ Stock Market LLC under the symbol
NGLS.
Factors
That Significantly Affect Our Results
Our results of operations are substantially impacted by changes
in commodity prices as well as increases and decreases in the
volume of natural gas that we gather and transport through our
pipeline systems, which we refer to as throughput volume.
Throughput volumes and capacity utilization rates generally are
driven by wellhead production, our competitive position on a
regional basis and more broadly by prices and demand for natural
gas and NGLs.
Our processing contract arrangements can have a significant
impact on our profitability. We process natural gas under a
combination of percent-of-proceeds contracts (approximately 79%
of our gathered natural gas volumes), wellhead
purchases/keep-whole contracts (approximately 19% of our
gathered natural gas volumes), fee-based contracts
(approximately 1% of our gathered natural gas volumes) and
hybrid contracts (approximately 1% of our gathered natural gas
volumes). The percent-of-proceeds and keep-whole contracts
expose us to commodity price risk. We attempt to mitigate this
risk through hedging activities which can materially impact our
results of operations. Please see Item 7A.
Quantitative and Qualitative Disclosures about Market
Risk Commodity Price Risk.
Actual contract terms are based upon a variety of factors,
including natural gas quality, geographic location, and the
competitive commodity and pricing environment at the time the
contract is executed and customer requirements. Our gathering
and processing contract mix and, accordingly, our exposure to
natural gas and NGL prices, may change as a result of producer
preferences, competition, and changes in production as wells
decline at different rates or are added, our expansion into
regions where different types of contracts are more common as
well as other market factors. For a more complete discussion of
the types of contracts under which we process natural gas,
please see Item 1. Business Market
Overview.
The historical financial statements of the SAOU and LOU Systems
and the North Texas System include certain items that will not
materially impact our future results of operations and liquidity
and do not fully reflect a number of other items that will
materially impact future results of operations and liquidity,
including the items described below:
Affiliate Indebtedness and
Borrowings. Affiliate indebtedness prior to our
acquisition of the SAOU and LOU Systems and the contribution of
the North Texas System, consisted of borrowings incurred by
Targa and allocated to us for financial reporting purposes.
Prior to Targas acquisition of the Dynegy Inc.s
interest in Dynegy Midstream Services, Limited Partnership (the
DMS Acquisition), which included the North Texas
System, the Predecessor Business was financed through borrowings
by Targa and reflected allocated indebtedness on its balance
sheet and allocated interest expense on its income statement. A
substantial portion of the DMS Acquisition was also financed
through borrowings by Targa. Following the October 31, 2005
DMS Acquisition, a significant portion of Targas
acquisition borrowings were allocated to the North Texas System,
resulting in approximately $868.9 million of allocated
indebtedness and corresponding levels of interest expense. This
indebtedness was incurred by Targa in connection with the DMS
Acquisition and the entity holding the North Texas System
provided a guarantee of this indebtedness. This
indebtedness was also secured by a collateral interest in both
the equity of the entity holding the North Texas System as well
as its assets. In connection with our IPO, this guarantee
was terminated, the collateral interest was released and the
allocated indebtedness was retired.
On February 14, 2007, we borrowed approximately
$294.5 million under our credit facility. The proceeds from
this borrowing, together with approximately $371.2 million
of net proceeds from our IPO (including 2,520,000 common units
sold pursuant to the full exercise by the underwriters of their
option to purchase additional common units), were used to repay
approximately $665.7 million of affiliate
57
indebtedness and the remaining balance of this indebtedness was
retired and treated as a capital contribution to us.
On October 24, 2007, we completed our acquisition of the
SAOU and LOU Systems concurrently with the sale of 13,500,000
common units representing limited partnership interests in us
for gross proceeds of $362.7 million (approximately
$349.2 million after underwriting discount and structuring
fees). The net proceeds from the sale of the
13,500,000 units were used to pay approximately
$2.5 million in expenses associated with the sale of the
common units, and $24.2 million to Targa for certain hedge
transactions associated with the SAOU and LOU Systems. We used
the net proceeds after offering expenses and the hedge
transactions of $322.5 million along with net borrowings of
$375.5 million to pay approximately $698.0 million of
the acquisition costs of the SAOU and LOU Systems. The allocated
indebtedness from Targa related to the SAOU and LOU Systems was
$124.0 million. Targa debt was guaranteed by the entities
that own the SAOU and LOU Systems and was secured by a
collateral interest in both the equity interests of those
entities as well as their underlying assets. In conjunction with
our acquisition of the SAOU and LOU Systems, this guarantee was
terminated, the collateral interest was released and the
allocated indebtedness was retired.
On November 20, 2007, the Underwriters exercised their
option to purchase an additional 1,800,000 common units. The
gross proceeds from the Underwriters exercise of their option to
purchase additional common units were $48.4 million
(approximately $46.5 million after underwriting discounts).
The proceeds from the exercise of the underwriters option
were used to reduce outstanding borrowings under our credit
facility.
Concurrent with the acquisition of the SAOU and LOU Systems, we
entered into a Commitment Increase Supplement (the
Supplement) to our existing five-year
$500 million senior secured revolving credit facility. The
Supplement increased the aggregate commitment under our credit
agreement by $250 million to an aggregate of
$750 million. On October 24, 2007, we entered into the
First Amendment to Credit Agreement (the Amendment).
The Amendment increased by $250 million the maximum amount
of increases to the aggregate commitments that may be requested
by us. The Amendment allows us to request commitments under our
credit agreement, as supplemented and amended, of up to
$1 billion.
Impact of Our Hedging Activities. In an effort
to reduce the variability of our cash flows, we have hedged the
commodity price associated with a portion of our expected
natural gas, NGLs and condensate equity volumes for the years
2008 through 2012 by entering into derivative financial
instruments including swaps and purchased puts (or floors). With
these arrangements, we have attempted to mitigate our exposure
to commodity price movements with respect to our forecasted
volumes for this period. For additional information regarding
our hedging activities, please see Item 7A.
Quantitative and Qualitative Disclosures about Market
Risk Commodity Price Risk.
General and Administrative Expenses. Prior to
the contribution of the assets of the North Texas System to us
and the acquisition of the assets from the SAOU and LOU Systems
by us from Targa, general and administrative expenses were
allocated from Targa to the North Texas, SAOU and LOU Systems in
accordance with the general and administrative expenses
allocation policies of Targa. On February 14, 2007, we
entered into an Omnibus Agreement with Targa, pursuant to which
our allocated general and administrative expenses related to the
North Texas System are capped at $5.0 million per year for
three years, subject to adjustment. For a more complete
description of this agreement, see Item 13. Certain
Relationships and Related Transactions, and Director
Independence Omnibus Agreement. In addition to
these allocated general and administrative expenses, we incur
incremental general and administrative expenses as a result of
operating as a separate publicly held limited partnership. These
direct, incremental general and administrative expenses of
approximately $3.1 million for the year ended
December 31, 2007, including one-time expenses associated
with our equity offerings, financing arrangements and
acquisitions, are not subject to the cap contained in the
Omnibus Agreement. These costs include costs associated with
annual and quarterly reports to unitholders, tax return and
Schedule K-1
preparation and distribution, incremental independent auditor
fees, registrar and transfer
58
agent fees and independent director compensation. These
incremental general and administrative expenditures are not
reflected in the historical financial statements of the North
Texas, SAOU and LOU Systems.
On October 24, 2007, we amended and restated our Omnibus
Agreement with Targa (the Amended and Restated Omnibus
Agreement). The Amended and Restated Omnibus Agreement
governs certain relationships between Targa and us, including:
i. Targas obligation to provide certain general and
administrative services to us;
ii. our obligation to reimburse Targa and its affiliates
for the provision of general and administrative services
(a) subject to a cap of $5 million (relating solely to
the North Texas System) in the first year, with increases in the
subsequent two years based on a formula specified in the Amended
and Restated Omnibus Agreement and (b) fully allocated as
to the SAOU and LOU Systems according to Targas previously
established allocation practices;
iii. our obligation to reimburse Targa and its affiliates
for direct expenses incurred on our behalf; and
iv. Targas obligation to indemnify us for certain
liabilities and our obligation to indemnify Targa for certain
liabilities.
Allocated general and administrative expenses were
$13.9 million, $16.1 million and $16.7 million
for the years ended December 31, 2007, 2006 and 2005,
respectively.
Working Capital Adjustments. Prior to our IPO
and the contribution of the North Texas System in February 2007
and the acquisition of the SAOU and LOU Systems in October 2007,
all intercompany transactions, including commodity sales and
expense reimbursements, were not cash settled with the
Predecessor Business respective parent, but were recorded
as an adjustment to parent equity on the balance sheet. The
primary intercompany transactions between the respective parent
and the Predecessor Business are natural gas and NGL sales, the
provision of operations and maintenance activities and the
provision of general and administrative services. Accordingly,
the working capital of the Predecessor Business does not reflect
any affiliate accounts receivable for intercompany commodity
sales or affiliate accounts payable for the personnel and
services provided or paid for by the applicable parent on behalf
of the Predecessor Business.
Distributions to our Unitholders. We intend to
make cash distributions to our unitholders and our general
partner at least at the minimum quarterly distribution rate of
$0.3375 per common unit per quarter ($1.35 per common unit on an
annualized basis). On January 24, 2008, a cash distribution
of $0.3975 per common unit ($1.59 per common unit on an
annualized basis) was declared for the fourth quarter of 2007.
Due to our cash distribution policy, we expect that we will
distribute to our unitholders most of the cash generated by our
operations. As a result, we expect that we will rely upon
external financing sources, including other debt and common unit
issuances, to fund our acquisition and expansion capital
expenditures, as well as our working capital needs.
Historically, we have relied on internally generated cash flows
for these purposes. Due to the timing of our IPO, a pro-rated
distribution for the first quarter of 2007 of $0.16875 per
common unit was paid. The following table shows the timing and
payments of our distributions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
Distribution
|
|
|
|
|
|
|
per Common
|
|
per Subordinated
|
|
|
|
|
Quarter Ended
|
|
Unit
|
|
Unit
|
|
Declared
|
|
Paid
|
|
December 31, 2007
|
|
$
|
0
|
.3975
|
|
$
|
0
|
.3975
|
|
January 24, 2008
|
|
February 14, 2008
|
September 30, 2007
|
|
|
0
|
.3375
|
|
|
0
|
.3375
|
|
October 23, 2007
|
|
November 14, 2007
|
June 30, 2007
|
|
|
0
|
.3375
|
|
|
0
|
.3375
|
|
July 23. 2007
|
|
August 14, 2007
|
February 14, 2007 to March 31, 2007
|
|
|
0
|
.16875
|
|
|
0
|
.16875
|
|
April 23, 2007
|
|
May 15, 2007
|
59
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 and Outlook. Fluctuations
in energy prices can affect production rates and investments by
third parties in the development of new natural gas reserves.
Generally, drilling and production activity will increase as
natural gas prices increase. In 2007, the prices we realized for
natural gas decreased to an average of $6.58 per MMBtu from an
average of $6.66 per MMBtu for 2006. For 2006, the prices we
realized for natural gas declined to an average of $6.66 per
MMBtu from an average of $9.36 per MMBtu for 2005. We believe
that current natural gas prices will continue to cause
relatively high levels of natural gas-related drilling in our
systems as producers seek to increase their level of natural gas
production.
Commodity Prices. Our operating income
generally improves in an environment of higher natural gas and
NGL prices, primarily as a result of our percent-of-proceeds
contracts. For 2007, excluding the impact of hedging activities,
we sold an average of 410.2 BBtu/d of residue gas at an average
price of $6.58 per MMBtu, as compared to 489.4 BBtu/d at an
average price of $6.66 per MMBtu for 2006, and 259.3 BBtu/d at
an average price of $9.36 per MMBtu for 2005. For 2007, we sold
an average of 36.4 MBbl/d of NGLs at an average price of
$44.10 per Bbl, as compared to 36.0 MBbl/d at an average
price of $36.12 per Bbl for 2006, and 22.0 MBbl/d at an
average price of $33.18 per Bbl for 2005. Our processing
profitability is largely dependent upon pricing and market
demand for natural gas, NGLs and condensate, which are beyond
our control and have been volatile. In a declining commodity
price environment, without taking into account our hedges, we
will realize a reduction in cash flows under our
percent-of-proceeds contracts proportionate to average price
declines. We have attempted to mitigate our exposure to
commodity price movements by entering into hedging arrangements.
For additional information regarding our hedging activities,
please see Item 7A. Quantitative and Qualitative
Disclosures about Market Risk Commodity Price
Risk.
Rising Operating Costs. The current high
levels of natural gas exploration, development and production
activities are increasing competition for personnel and
equipment. This increased competition is placing upward pressure
on the prices we pay for labor, supplies, property, plant and
equipment. We attempt to recover increased costs from our
customers. To the extent we are unable to procure necessary
supplies or to recover higher costs, our operating results will
be negatively impacted.
Our
Operations
Our results of operations are determined primarily by the
volumes of natural gas gathered, compressed, treated, processed,
transported and sold through our gathering, processing and
pipeline systems; the volumes of NGLs and residue natural gas
sold; and the level of natural gas and NGL prices. We generate
our revenues and our operating margins principally under
percent-of-proceeds contractual arrangements. Under these
arrangements, we generally gather natural gas from producers at
the wellhead or central delivery points, transport the wellhead
natural gas through our gathering system, treat and process the
natural gas, and then sell the resulting residue natural gas and
NGLs at index prices based on published index market prices. We
remit to the producers either an agreed upon percentage of
recovered volumes or the actual proceeds that we receive from
our sales of the residue natural gas and NGLs or an agreed upon
percentage of the proceeds based on index related prices for the
natural gas and NGLs. Under these types of arrangements, our
revenues correlate directly with the price of natural gas and
NGLs. For the year ended December 31, 2007, our
percent-of-proceeds activities accounted for approximately 79%
of our natural gas throughput volumes. The balance of our
throughput volumes are processed under wellhead purchase
contracts, keep-whole contracts, fee based contracts and hybrid
contractual arrangements.
We sell all of our processed natural gas, NGLs and high pressure
condensate to Targa at market-based rates pursuant to natural
gas, NGL and condensate purchase agreements. Low-pressure
condensate is sold to third parties. For a more complete
description of these arrangements, please see
Item 13. Certain Relationships and Related
Transactions and Director Independence and
Item 1. Business Market Access.
60
How We
Evaluate Our Operations
Our profitability is a function of the difference between the
revenues we receive from our operations, including revenues from
the natural gas, NGLs and condensate we sell, and the costs
associated with conducting our operations, including the costs
of wellhead natural gas that we purchase as well as operating
and general and administrative costs. Because commodity price
movements tend to impact both revenues and costs, increases or
decreases in our revenues alone are not necessarily indicative
of increases or decreases in our profitability. Our contract
portfolio, the prevailing pricing environment for natural gas
and NGLs and the natural gas and NGL throughput on our system
are important factors in determining our profitability. Our
profitability is also affected by the NGL content in gathered
wellhead natural gas, demand for our products and changes in our
customer mix.
Our management uses a variety of financial and operational
measurements to analyze our performance. These measurements
include the following: (1) throughput volumes, facility
efficiencies and fuel consumption, (2) operating margin,
(3) operating expenses, (4) general and administrative
expenses, (5) Adjusted EBITDA and (6) distributable
cash flow.
Throughput Volumes, Facility Efficiencies and Fuel
Consumption. Our profitability is impacted by our
ability to add new sources of natural gas supply to offset the
natural decline of existing volumes from natural gas wells that
are connected to our systems. This is achieved by connecting new
wells as well as by capturing supplies currently gathered by
third parties. In addition, we seek to increase operating
margins by limiting volume losses and reducing fuel consumption
by increasing compression efficiency. With our gathering
systems extensive use of remote monitoring capabilities,
we monitor the volumes of natural gas received at the wellhead
or central delivery points along our gathering systems, the
volume of natural gas received at our processing plant inlets
and the volumes of NGLs and residue natural gas recovered by our
processing plants. This information is tracked through our
processing plants to determine customer settlements and helps us
increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we
measure the difference between the volume of natural gas
received at the wellhead or central delivery points on our
gathering systems and the volume received at the inlet of our
processing plants as an indicator of fuel consumption and line
loss. We also track the difference between the volume of natural
gas received at the inlet of the processing plant and the NGLs
and residue gas produced at the outlet of such plants to monitor
the fuel consumption and recoveries of the facilities. These
volume, recovery and fuel consumption measurements are an
important part of our operational efficiency analysis.
Operating Margin. We review performance based
on the non-generally accepted accounting principle
(non-GAAP) financial measure of operating margin. We
define operating margin as total operating revenues, which
consist of natural gas and NGL sales plus service fee revenues,
less product purchases, which consist primarily of producer
payments and other natural gas purchases, and operating expense.
Natural gas and NGL sales revenue includes settlement gains and
losses on commodity hedges. Our operating margin is impacted by
volumes and commodity prices as well as by our contract mix and
hedging program, which are described in more detail below. We
view our operating margin as an important performance measure of
the core profitability of our operations. We review our
operating margin monthly for consistency and trend analysis.
The GAAP measure most directly comparable to operating margin is
net income. Our non-GAAP financial measure of operating margin
should not be considered as an alternative to GAAP net income.
Operating margin is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You
should not consider operating margin in isolation or as a
substitute for analysis of our results as reported under GAAP.
Because operating margin excludes some, but not all, items that
affect net income and is defined differently by different
companies in our industry, our definition of operating margin
may not be comparable to similarly titled measures of other
companies, thereby diminishing its utility.
We compensate for the limitations of operating margin as an
analytical tool by reviewing the comparable GAAP measure,
understanding the differences between the measures and
incorporating these insights into our decision-making processes.
61
We believe that investors benefit from having access to the same
financial measures that our management uses in evaluating our
operating results. Operating margin provides useful information
to investors because it is used as a supplemental financial
measure by us and by external users of our financial statements,
including such investors, commercial banks and others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
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.
|
Operating Expenses. Operating expenses are
costs associated with the operation of a specific asset. Direct
labor, ad valorem taxes, repair and maintenance, utilities and
contract services compose the most significant portion of our
operating expenses. These expenses generally remain relatively
stable independent of the volumes through our systems but
fluctuate depending on the scope of the activities performed
during a specific period.
Adjusted EBITDA. Adjusted EBITDA is another
non-GAAP financial measure that is used by us. We define
Adjusted EBITDA as net income before interest, income taxes,
depreciation and amortization and non-cash income or loss
related to derivative instruments. Adjusted EBITDA is used as a
supplemental financial measure by us and by external users of
our financial statements such as investors, commercial banks and
others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
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.
|
The economic substance behind our use of Adjusted EBITDA is to
measure the ability of our assets to generate cash sufficient to
pay interest costs, support our indebtedness, and make
distributions to our investors.
The GAAP measures most directly comparable to Adjusted EBITDA
are net cash provided by operating activities and net income.
Our non-GAAP financial measure of Adjusted EBITDA should not be
considered as an alternative to GAAP net cash provided by
operating activities and GAAP net income. Adjusted EBITDA is not
a presentation made in accordance with GAAP and has important
limitations as an analytical tool. You should not consider
Adjusted EBITDA in isolation or as a substitute for analysis of
our results as reported under GAAP. Because Adjusted EBITDA
excludes some, but not all, items that affect net income and net
cash provided by operating activities and is defined differently
by different companies in our industry, our definition of
Adjusted EBITDA may not be comparable to similarly titled
measures of other companies.
We compensate for the limitations of Adjusted EBITDA as an
analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these insights into our decision-making processes.
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in millions)
|
|
|
Reconciliation of Adjusted EBITDA to net cash
provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
270.5
|
|
|
$
|
124.4
|
|
|
$
|
10.5
|
|
Allocated interest expense from parent(1)
|
|
|
18.5
|
|
|
|
81.8
|
|
|
|
16.5
|
|
Interest expense, net(1)
|
|
|
21.1
|
|
|
|
|
|
|
|
|
|
Changes in operating working capital which used (provided) cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(89.8
|
)
|
|
|
(78.5
|
)
|
|
|
61.8
|
|
Accounts payable
|
|
|
(1.9
|
)
|
|
|
13.7
|
|
|
|
(11.4
|
)
|
Accrued liabilities
|
|
|
(33.5
|
)
|
|
|
15.4
|
|
|
|
(13.3
|
)
|
Other, including changes in noncurrent assets and liabilities
|
|
|
(29.3
|
)
|
|
|
14.1
|
|
|
|
(10.1
|
)
|
Noncash mark-to-market loss (gain)
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
185.8
|
|
|
$
|
154.1
|
|
|
$
|
66.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to net
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40.3
|
|
|
$
|
11.6
|
|
|
$
|
9.7
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated interest expense, net
|
|
|
19.4
|
|
|
|
88.0
|
|
|
|
21.2
|
|
Interest expense, net
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense
|
|
|
1.5
|
|
|
|
2.9
|
|
|
|
|
|
Taxes other than income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense
|
|
|
71.8
|
|
|
|
69.9
|
|
|
|
23.1
|
|
Risk Management Activities
|
|
|
0.6
|
|
|
|
(1.5
|
)
|
|
|
|
|
Noncash mark-to-market loss (gain)
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
185.8
|
|
|
$
|
154.1
|
|
|
$
|
66.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of operating margin to net
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40.3
|
|
|
$
|
11.6
|
|
|
$
|
9.7
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense
|
|
|
71.8
|
|
|
|
69.9
|
|
|
|
23.1
|
|
Deferred income tax expense
|
|
|
1.5
|
|
|
|
2.9
|
|
|
|
|
|
Allocated interest expense, net
|
|
|
19.4
|
|
|
|
88.0
|
|
|
|
21.2
|
|
Interest expense, net
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
Loss on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
3.7
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
General and administrative expense
|
|
|
18.9
|
|
|
|
16.1
|
|
|
|
16.7
|
|
Taxes other than income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of assets
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin
|
|
$
|
203.8
|
|
|
$
|
171.7
|
|
|
$
|
86.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Net of amortization of debt issuance costs of $1.8 million
for the year ended December 31, 2007, $6.2 million for
the year ended December 31, 2006 and $4.7 million for the
year ended December 31, 2005.
|
Distributable Cash Flow. Distributable Cash
Flow is a significant performance metric used by us and by
external users of our financial statements, such as investors,
commercial banks, research analysts and others to compare basic
cash flows generated by us (prior to the establishment of any
retained cash reserves by the board of directors of our general
partner) to the cash distributions we expect to pay our
unitholders. Using this metric, management can quickly compute
the coverage ratio of estimated cash flows to planned cash
distributions. Distributable Cash Flow is also an important
non-GAAP financial measure for our unitholders since it serves
as an indicator of our success in providing a cash return on
investment. Specifically, this financial measure indicates to
investors whether or not we are generating cash flow at a level
that can sustain or support an increase in our quarterly
distribution rates. Distributable Cash Flow is also a
quantitative standard used throughout the investment community
with respect to publicly-traded partnerships and limited
63
liability companies because the value of a unit of such an
entity is generally determined by the units yield (which
in turn is based on the amount of cash distributions the entity
pays to a unitholder).
The economic substance behind our use of distributable cash flow
is to measure the ability of our assets to generate cash flow
sufficient to make distributions to our investors.
The GAAP measure most directly comparable to Distributable Cash
Flow is net income. Our non-GAAP measure of distributable cash
flow should not be considered as an alternative to GAAP net
income. Distributable Cash Flow is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider Distributable Cash Flow
in isolation or as a substitute for analysis of our results as
reported under GAAP. Because Distributable Cash Flow excludes
some, but not all, items that affect net income and is defined
differently by different companies in our industry, our
definition of distributable cash flow may not be compatible to
similarly titled measures of other companies, thereby
diminishing its utility.
We compensate for the limitations of Distributable Cash Flow as
an analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these insights into our decision making processes.
Reconciliation
of Distributable Cash Flow to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005(a)
|
|
|
|
(in millions)
|
|
|
Net income (loss)
|
|
$
|
40.3
|
|
|
$
|
11.6
|
|
|
$
|
9.7
|
|
Depreciation and amortization expense
|
|
|
71.8
|
|
|
|
69.9
|
|
|
|
23.1
|
|
Deferred income tax expense
|
|
|
1.5
|
|
|
|
2.9
|
|
|
|
|
|
Amortization of debt issue costs
|
|
|
1.8
|
|
|
|
6.2
|
|
|
|
4.7
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
Maintenance capital expenditures
|
|
|
(21.5
|
)
|
|
|
(16.3
|
)
|
|
|
(6.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow(b)
|
|
$
|
124.1
|
|
|
$
|
57.5
|
|
|
$
|
43.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes two months of operations from North Texas System.
|
|
|
|
|
(b)
|
Distributable cash flow for the years ended December 31,
2007, 2006 and 2005 reflects allocated interest from parent of
$19.4 million $88.0 million and $21.2 million,
respectively.
|
Below is a reconciliation of net income as reported and
Distributable Cash Flow to which unit holders are entitled which
excludes the results of operations of the North Texas System and
the SAOU and LOU Systems prior to their ownership by the
Partnership.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended December 31, 2007
|
|
|
For The Year Ended December 31, 2007
|
|
|
|
|
|
|
Pre-Acquisition
|
|
|
|
|
|
|
|
|
Pre-Acquisition
|
|
|
|
|
|
|
|
|
|
SAOU/LOU
|
|
|
|
|
|
|
|
|
North Texas
|
|
|
SAOU/LOU
|
|
|
|
|
|
|
|
|
|
Oct 1, 2007
|
|
|
Post
|
|
|
|
|
|
Jan 1, 2007
|
|
|
Jan 1, 2007
|
|
|
Post
|
|
|
|
|
|
|
to
|
|
|
Acquisition
|
|
|
|
|
|
to
|
|
|
to
|
|
|
Acquisition
|
|
|
|
TRP LP
|
|
|
Oct 23, 2007
|
|
|
TRP LP
|
|
|
TRP LP
|
|
|
Feb 13, 2007
|
|
|
Oct 23, 2007
|
|
|
TRP LP
|
|
|
Net income (loss)
|
|
$
|
22.7
|
|
|
$
|
4.7
|
|
|
$
|
18.0
|
|
|
$
|
40.3
|
|
|
$
|
(6.9
|
)
|
|
$
|
19.1
|
|
|
$
|
28.1
|
|
Depreciation and amortization expense
|
|
|
18.1
|
|
|
|
0.9
|
|
|
|
17.2
|
|
|
|
71.8
|
|
|
|
6.9
|
|
|
|
11.7
|
|
|
|
53.2
|
|
Deferred income tax expense
|
|
|
0.4
|
|
|
|
(0.1
|
)
|
|
|
0.5
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
1.5
|
|
Amortization of debt issue costs
|
|
|
0.4
|
|
|
|
|
|
|
|
0.4
|
|
|
|
1.8
|
|
|
|
|
|
|
|
0.9
|
|
|
|
0.9
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
1.9
|
|
|
|
1.9
|
|
|
|
|
|
|
|
30.2
|
|
|
|
|
|
|
|
30.2
|
|
|
|
|
|
Maintenance capital expenditures
|
|
|
(6.8
|
)
|
|
|
(0.4
|
)
|
|
|
(6.4
|
)
|
|
|
(21.5
|
)
|
|
|
(1.5
|
)
|
|
|
(5.9
|
)
|
|
|
(14.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
$
|
36.7
|
|
|
$
|
7.0
|
|
|
$
|
29.7
|
|
|
$
|
124.1
|
|
|
$
|
(1.5
|
)
|
|
$
|
56.0
|
|
|
$
|
69.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64
Contract
Mix
We generate revenue based on the contractual arrangements we
have with our producer customers. These arrangements can be in
many forms which vary in the amount of commodity price risk they
carry. Substantially all of our revenues are generated under
percent-of-proceeds arrangements pursuant to which we receive a
portion of the natural gas
and/or NGLs
as payment for services, please see Item 1.
Business Midstream Sector Overview for a more
detailed discussion of the contractual arrangements under which
we operate. Set forth below is a table summarizing our average
contract mix for the year ended December 31, 2007,
including the potential impacts of changes in commodity prices
on operating margins:
|
|
|
|
|
|
|
|
|
|
|
Percent of
|
|
|
Contract Type
|
|
Throughput
|
|
Impact of Commodity Prices
|
|
Percent-of-Proceeds
|
|
|
79%
|
|
|
|
Decreases in natural gas and/or NGL prices generate decreases in
operating margin.
|
|
Wellhead Purchases /Keep Whole
|
|
|
19%
|
|
|
|
Increases in natural gas prices relative to NGL prices generate
decreases in operating margin. Decreases in NGL prices relative
to natural gas prices generate decreases in operating margin.
|
|
Hybrid
|
|
|
1%
|
|
|
|
In periods of favorable processing economics, similar to
percent-of-liquids (or wellhead purchases/keep-whole in some
circumstances, if economically advantageous to the processor).
In periods of unfavorable processing economics, similar to
fee-based.
|
|
Fee Based
|
|
|
1%
|
|
|
|
No direct impact from commodity price movements.
|
|
At times, producer preferences, competitive forces and other
factors cause us to enter into more commodity price sensitive
contracts, such as wellhead purchases and keep-whole
arrangements. We prefer to enter into contracts with less
commodity price sensitivity, including fee-based and
percent-of-proceeds arrangements.
Critical
Accounting Policies and Estimates
The preparation of financial statements in accordance with GAAP
requires our management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the period. Actual results could differ from
these estimates. The policies and estimates discussed below are
considered by management to be critical to an understanding of
our financial statements, because their application requires the
most significant judgments from management in estimating matters
for financial reporting that are inherently uncertain.
Revenue Recognition. The Partnerships
primary types of sales and service activities reported as
operating revenues include:
|
|
|
|
|
sales of natural gas, NGLs and condensate; and
|
|
|
|
natural gas processing, from which we generate revenues through
the compression, gathering, treating, and processing of natural
gas.
|
The Partnership recognizes revenues when all of the following
criteria are met: (1) persuasive evidence of an exchange
arrangement exists, if applicable, (2) delivery has
occurred or services have been rendered, (3) the price is
fixed or determinable and (4) collectibility is reasonably
assured.
For processing services, the Partnership receives either fees or
a percentage of commodities as payment for these services,
depending on the type of contract. Under percent-of-proceeds
contracts, we receive either an agreed upon percentage of the
actual proceeds that we receive from our sales of the residue
natural gas and NGLs or an agreed upon percentage based on index
related prices for the natural gas and NGLs. Percent-of-value
and percent-of-liquids contracts are variations on this
arrangement. Under keep-whole contracts, we keep the NGLs
extracted and return the processed natural gas or value of the
natural gas to the producer. Natural gas or NGLs that the
65
Partnership receives for services or purchases for resale are in
turn sold and recognized in accordance with the criteria
outlined above. Under fee-based contracts, the Partnership
receives a fee based on throughput volumes.
The Partnership generally reports revenues gross in the
consolidated statements of operations, in accordance with
EITF 99-19,
Reporting Revenue Gross as a Principal versus Net as an
Agent. Except for fee-based contracts, the Partnership
acts as the principal in the transactions where we receive
commodities, takes title to the natural gas and NGLs, and incurs
the risks and rewards of ownership.
Use of Estimates. The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the period.
Estimates and judgments are based on information available at
the time such estimates and judgments are made. Adjustments made
with respect to the use of these estimates and judgments often
relate to information not previously available. Uncertainties
with respect to such estimates and judgments are inherent in the
preparation of financial statements. Estimates and judgments are
used in, among other things, (1) estimating unbilled
revenues and operating and general and administrative costs
(2) developing fair value assumptions, including estimates
of future cash flows and discount rates, (3) analyzing
tangible and intangible assets for possible impairment,
(4) estimating the useful lives of assets and
(5) determining amounts to accrue for contingencies,
guarantees and indemnifications. Actual results could differ
materially from estimated amounts.
Property, Plant and Equipment. Property, plant
and equipment are stated at cost less accumulated depreciation.
Depreciation is computed using the straight-line method over the
estimated useful lives of the assets. The estimated service
lives of the Partnerships functional asset groups are as
follows:
|
|
|
|
|
Asset Group
|
|
Range of Years
|
|
Natural gas gathering systems and processing facilities
|
|
|
15 to 25
|
|
Office and miscellaneous equipment
|
|
|
3 to 7
|
|
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures to refurbish assets that extend the
useful lives or prevent environmental contamination are
capitalized and depreciated over the remaining useful life of
the asset. Upon disposition or retirement of property, plant,
and equipment, any gain or loss is charged to operations.
Our determination of the useful lives of property, plant and
equipment requires us to make various assumptions, including the
supply of and demand for hydrocarbons in the markets served by
our assets, normal wear and tear of the facilities, and the
extent and frequency of maintenance programs. From time to time,
we utilize consultants and other experts to assist us in
assessing the remaining lives of the crude oil or natural gas
production in the basins we serve.
We may capitalize certain costs directly related to the
construction of assets, including internal labor costs, interest
and engineering costs. Upon disposition or retirement of
property, plant and equipment, any gain or loss is charged to
operations.
In accordance with SFAS 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, we
evaluate the recoverability of our property, plant and equipment
when events or circumstances such as economic obsolescence, the
business climate, legal and other factors indicate we may not
recover the carrying amount of the assets. We continually
monitor our businesses and the market and business environments
to identify indicators that may suggest an asset may not be
recoverable.
We evaluate an asset for recoverability by comparing the
carrying value of the asset with the assets expected
future undiscounted cash flows. These cash flow estimates
require us to make projections and assumptions for many years
into the future for pricing, demand, competition, operating cost
and other factors. We recognize an impairment loss when the
carrying amount of the asset exceeds its fair value as
determined by quoted market prices in active markets or present
value techniques if quotes are unavailable. The determination of
the fair value using present value techniques requires us to
make projections and assumptions regarding the probability of a
range of outcomes and the rates of interest used in the present
value calculations.
66
Any changes we make to these projections and assumptions could
result in significant revisions to our evaluation of
recoverability of our property, plant and equipment and the
recognition of an impairment loss in our Consolidated Statements
of Operations.
Price Risk Management (Hedging). The
Partnership accounts for derivative instruments in accordance
with SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, as amended. Under
SFAS 133, all derivative instruments not qualifying for the
normal purchases and normal sales exception are recorded on the
balance sheet at fair value. If a derivative does not qualify as
a hedge or is not designated as a hedge, the gain or loss on the
derivative is recognized currently in earnings. If a derivative
qualifies for hedge accounting and is designated as a hedge, the
effective portion of the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(OCI), a component of partners capital, and
reclassified to earnings when the forecasted transaction occurs.
Cash flows from a derivative instrument designated as a hedge
are classified in the same category as the cash flows from the
item being hedged.
The relationship between the hedging instrument and the hedged
item must be highly effective in achieving the offset of changes
in cash flows attributable to the hedged risk both at the
inception of the contract and on an ongoing basis. Hedge
accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in OCI related to
cash flow hedges for which hedge accounting has been
discontinued remain deferred until the forecasted transaction
occurs. If it is probable that a hedged forecasted transaction
will not occur, deferred gains or losses on the hedging
instrument are reclassified to earnings immediately.
The Partnerships policy is to formally document all
relationships between hedging instruments and hedged items, as
well as its risk management objectives and strategy for
undertaking the hedge. This process includes specific
identification of the hedging instrument and the hedged item,
the nature of the risk being hedged and the manner in which the
hedging instruments effectiveness will be assessed. At the
inception of the hedge and on an ongoing basis, the Partnership
assesses whether the derivatives used in hedging transactions
are highly effective in offsetting changes in cash flows of
hedged items. Hedge effectiveness is measured on a quarterly
basis. Any ineffective portion of the unrealized gain or loss is
reclassified to earnings in the current period.
Asset Retirement Obligations. Under the
provisions of SFAS 143, Accounting for Asset
Retirement Obligations, we record legal obligations to
retire tangible, long-lived assets on our balance sheet as
liabilities, recorded at a discount, when such liabilities are
incurred. We have recorded approximately $3.3 million in
asset retirement obligations as of December 31, 2007.
In March 2005, the FASB issued FASB Interpretation
(FIN) 47, Accounting for Conditional Asset
Retirement Obligations. This Interpretation clarifies
the definition and treatment of conditional asset retirement
obligations as discussed in SFAS 143. A conditional asset
retirement obligation is defined as an asset retirement activity
in which the timing
and/or
method of settlement are dependent on future events that may be
outside the control of the company. FIN 47 states that
a company must record a liability when incurred for conditional
asset retirement obligations if the fair value of the obligation
is reasonably estimable. This Interpretation is intended to
provide more information about long-lived assets, more
information about potential future cash outflows for these
obligations and more consistent recognition of these
liabilities. Our adoption of FIN 47 on December 31,
2005 had no effect on our financial position, results of
operations, or cash flows.
Estimated Useful Lives. The estimated useful
lives of our long-lived assets are used to compute depreciation
expense, future asset retirement obligations and in impairment
testing. Estimated useful lives are based, among other things,
on the assumption that we provide an appropriate level of
maintenance capital expenditures while the assets are still in
operation. Without these continued capital expenditures, the
useful lives of these assets could decrease significantly.
Estimated lives could be impacted by such factors as future
energy prices, environmental regulations, various legal factors
and competition. If the useful lives of these assets were found
to be shorter than originally estimated, depreciation expense
may increase, liabilities for future asset retirement
obligations may be insufficient and impairments in carrying
values of tangible and intangible assets may result.
67
Recent Accounting Announcements
For a discussion of recent accounting pronouncements that will
affect us, see Note 3 to our Consolidated Financial
Statements.
Results
of Operations
Our results of operations for the years ended
December 31, 2007 and 2006 are presented and evaluated on a
combined basis, combining the results of operations reflected in
the audited historical financial statements of the SAOU and LOU
Systems with the operations of the North Texas System. The
Predecessor Business for the year ended December 31, 2005
combines the results of operations for the SAOU and LOU Systems
for the year then ended and the results of operations reflected
in the audited historical financial statements of the North
Texas System for the two-months after the DMS Acquisition.
The following table and discussion is a summary of our combined
results of operations for the three years ended
December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in millions of dollars, except operating and price data)
|
|
|
Revenues
|
|
$
|
1,661.5
|
|
|
$
|
1,738.5
|
|
|
$
|
1,172.5
|
|
Product purchases
|
|
|
1,406.8
|
|
|
|
1,517.7
|
|
|
|
1,061.7
|
|
Operating expense
|
|
|
50.9
|
|
|
|
49.1
|
|
|
|
24.4
|
|
Depreciation and amortization expense
|
|
|
71.8
|
|
|
|
69.9
|
|
|
|
23.1
|
|
General and administrative expense
|
|
|
18.9
|
|
|
|
16.1
|
|
|
|
16.7
|
|
Gain on sale of assets
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
113.4
|
|
|
|
85.7
|
|
|
|
46.6
|
|
Interest expense, net
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
Interest expense, allocated from Parent
|
|
|
19.4
|
|
|
|
88.0
|
|
|
|
21.2
|
|
Loss on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
3.7
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
30.2
|
|
|
|
(16.8
|
)
|
|
|
12.0
|
|
Deferred income tax expense(1)
|
|
|
1.5
|
|
|
|
2.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40.3
|
|
|
$
|
11.6
|
|
|
$
|
9.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin(2)
|
|
$
|
203.8
|
|
|
$
|
171.7
|
|
|
$
|
86.4
|
|
Adjusted EBITDA(3)
|
|
$
|
185.8
|
|
|
$
|
154.1
|
|
|
$
|
66.0
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering throughput,
MMcf/d(4)
|
|
|
452.0
|
|
|
|
433.8
|
|
|
|
302.4
|
|
Plant natural gas inlet,
MMcf/d(5)(6)
|
|
|
429.2
|
|
|
|
419.6
|
|
|
|
253.6
|
|
Gross NGL production, MBbl/d
|
|
|
42.6
|
|
|
|
42.4
|
|
|
|
23.5
|
|
Natural gas sales, BBtu/d(6)
|
|
|
410.2
|
|
|
|
489.4
|
|
|
|
259.3
|
|
NGL sales, MBbl/d
|
|
|
36.4
|
|
|
|
36.0
|
|
|
|
22.0
|
|
Condensate sales, MBbl/d
|
|
|
3.6
|
|
|
|
3.3
|
|
|
|
1.3
|
|
Average realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas, $/MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
$
|
6.58
|
|
|
$
|
6.66
|
|
|
$
|
9.36
|
|
Impact of hedging
|
|
|
0.08
|
|
|
|
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
$
|
6.66
|
|
|
$
|
6.68
|
|
|
$
|
9.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL, $/gal
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
$
|
1.05
|
|
|
$
|
0.86
|
|
|
$
|
0.79
|
|
Impact of hedging
|
|
|
(0.02
|
)
|
|
|
(0.01
|
)
|
|
|
(0.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
$
|
1.03
|
|
|
$
|
0.85
|
|
|
$
|
0.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate, $/Bbl
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales price
|
|
$
|
65.43
|
|
|
$
|
59.28
|
|
|
$
|
58.96
|
|
Impact of hedging
|
|
|
0.19
|
|
|
|
0.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
$
|
65.62
|
|
|
$
|
59.87
|
|
|
$
|
58.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68
|
|
|
|
(1)
|
In May 2006, Texas adopted a margin tax, consisting of a 1% tax
on the amount by which total revenue exceeds cost of goods sold,
as apportioned to Texas. The amount presented represents our
estimated liability for this tax.
|
|
|
(2)
|
Operating margin is total operating revenues less product
purchases and operating expense. Please see
Non-GAAP Financial Measures Operating
Margin included in this Item 7.
|
|
|
(3)
|
Adjusted EBITDA is net income before interest, income taxes,
depreciation and amortization and non-cash income or loss
related to derivative instruments. Please see
Non-GAAP Financial Measures Adjusted
EBITDA, included in this Item 7.
|
|
|
(4)
|
Gathering throughput represents the volume of natural gas
gathered and passed through natural gas gathering pipelines from
connections to producing wells and central delivery points.
|
|
|
(5)
|
Plant natural gas inlet represented the volume of natural gas
passing through the meter located at the inlet of a natural gas
processing plant.
|
|
|
(6)
|
Plant inlet volumes include producer
take-in-kind,
while natural gas sales exclude producer
take-in-kind
volumes.
|
Year
Ended December 31, 2007 Compared to Year Ended
December 31, 2006
Total Operating Revenues. Revenues decreased
by $77.0 million, or 4.4%, to $1,661.5 million
(including $1.0 million in losses related to net hedge
settlements) for 2007 compared to $1,738.5 million
(including $0.9 million in losses related to net hedge
settlements) for 2006. This decrease was primarily due to the
following factors:
|
|
|
|
|
a net increase attributable to prices of $104.0 million,
consisting of a decrease in natural gas revenues of
$2.4 million and increases in NGLs and condensate revenues
of $99.0 million and $7.4 million, respectively;
|
|
|
|
a net decrease attributable to volumes of $182.5 million,
consisting of a decrease in natural gas revenues of
$193.0 million and increases of NGLs and condensate
revenues of $5.7 million and $4.8 million,
respectively; and
|
|
|
|
an increase in fee and other revenues of $1.5 million.
|
Average realized prices (net of the impact of hedging) for our
sales of:
|
|
|
|
|
natural gas decreased by $0.02 per MMBtu ($0.06 net
increase per MMBtu due to hedging) or less than 1%, to $6.66 per
MMBtu during 2007 compared to $6.68 per MMBtu for 2006.
|
|
|
|
NGLs increased by $0.18 per gallon ($0.01 net decrease per
gallon due to hedging), or 21%, to $1.03 per gallon for 2007
compared to $0.85 per gallon for 2006.
|
|
|
|
condensate increased by $5.75 per Bbl ($0.40 net increase
per Bbl due to hedging), or 10%, to $65.62 per Bbl for 2007
compared to $59.87 per Bbl for 2006.
|
Natural gas sales volume decreased by 79.2 BBtu/d, or 16%, to
410.2 BBtu/d during 2007 compared to 489.4 BBtu/d for 2006. This
decrease in sales of natural gas volumes was attributable to a
net decrease in natural gas purchased from affiliates and
increased
take-in-kind
volumes by producers for whom we process natural gas offset by
net increases in other non-wellhead supply sources and wellhead
supplies attributable to additional well connections which were
partially offset by the natural decline of field production. Net
NGL production increased by 0.4 MBbl/d, or 1%, to
36.4 MBbl/d for 2007 compared to 36.0 MBbl/d for 2006.
The volume increases were primarily attributable to additional
well connections partially offset by the natural decline in
field production. Condensate production increased by
0.3 MBbl/d, or 9%, to 3.6 MBbl/d for 2007 compared to
3.3 MBbl/d for 2006.
Product Purchases. Product purchases during
2007 were $1,406.8 million, which decreased by
$110.9 million, or 7%, compared to $1,517.7 million
during 2006.
69
Operating Expenses. Operating expenses during
2007 were $50.9 million, which increased by
$1.8 million, or 4%, compared to $49.1 million during
2006. The increase over 2006 was partially attributable to
increased operating costs due to our processing plant and
gathering system expansions, as well as increased prices for
labor, supplies and equipment.
Depreciation and Amortization. Depreciation
and amortization expense for 2007 was $71.8 million
compared to $69.9 million for 2006, for an increase of
$1.9 million, or 3%. The increase is due to the higher
carrying value of property, plant and equipment as a result of
plant and gathering system expansions.
General and Administrative. General and
administrative expense of $18.9 million for 2007 is an
increase of $2.8 million, or 17%, compared to
$16.1 million for 2006. The general and administrative
expense increase was primarily attributable to higher direct
general and administrative costs of being a public reporting
entity in 2007 of approximately $3.1 million.
Interest Expense. Interest expense for 2007
was $41.4 million. Allocated interest expense from Targa in
2006 was $88.0 million. Interest expense in 2007 consisted
of (i) a $9.6 million allocation from Targa for the
periods from January 1, 2007 through October 24, 2007
related to the SAOU and LOU Systems, (ii) a
$9.8 million allocation from January 1 through
February 13, 2007 related to the North Texas System and
(iii) $22.0 million of interest for borrowings under
our credit facility. Please see Liquidity and Capital
Resources included in this Item 7 regarding our
outstanding debt obligations.
Year
Ended December 31, 2006 Compared to Year Ended
December 31, 2005
Total Operating Revenues. Revenues increased
by $566.1 million, or 48%, to $1,738.5 million
(including $0.9 million in losses related to net hedge
settlements) during 2006 compared to $1,172.5 million
(including $7.9 million in losses related to net hedge
settlements) for 2005. This increase was primarily due to the
following factors:
|
|
|
|
|
During 2006, we recorded a full year of production volume for
the SAOU, LOU and North Texas Systems versus a full year of
production volume for the SAOU and LOU Systems and only two
months of production volume for the North Texas System in 2005;
|
|
|
|
a net decrease attributable to prices of $432.8 million,
consisting of a decrease to natural gas revenues of
$478.8 million and increases to NGL and condensate revenues
of $44.9 million and $1.1 million, respectively;
|
|
|
|
a net increase attributable to volumes of $995.9 million,
consisting of increases to natural gas, NGLs and condensate
volumes of $786.0 million, $165.1 million and
$44.8 million, respectively, and
|
|
|
|
an increase in fee and other revenues of $2.9 million.
|
Average realized prices (net of the impact of hedging) for our
sales of:
|
|
|
|
|
natural gas decreased by $2.68 per MMBtu (including a $0.02
increase per MMBtu due to hedging), or 29%, to $6.68 per MMBtu
during 2006 compared to $9.36 per MMBtu for 2005.
|
|
|
|
NGLs increased by $0.08 per gallon (with a $0.01 increase
per gallon due to hedging), or 11%, to $0.85 per gallon for 2006
compared to $0.77 per gallon for 2005.
|
|
|
|
condensate increased by $0.91 per Bbl ($0.59 increase per Bbl
due to hedging), or 2%, to $59.87 per Bbl for 2006 compared to
$58.96 per Bbl for 2005.
|
Natural gas sales volumes increased by 230.1 BBtu/d, or 89%, to
489.4 BBtu/d during 2006 compared to 259.3 BBtu/d for 2005. This
increase in sales of natural gas volumes was attributable to a
full year of North Texas sales volumes in 2006 compared to two
months of sales volumes following our acquisition of North Texas
in 2005, a net increase in natural gas purchased from affiliates
and wellhead supplies attributable to additional well
connections which were partially offset by the natural decline
of field production. The increase in condensate sales volumes
was primarily due to the full year of production for the North
Texas System in 2006 compared to only tow months of 2005. NGL
sales volumes increased by 14.0 MBbl/d, or 64%, to
70
36.0 MBbl/d during 2006 compared to 22.0 MBbl/d for
2005. Condensate volumes increased by 2.0 MBbl/d, or 154%,
to 3.3 MBbl/d during 2006 compared to 1.3 MBbl/d for
2005. The increases in both natural gas and condensate sales
volumes were primarily due the full year of production for the
North Texas System in 2006 compared to only two months of 2005.
Product Purchases. Product purchases increased
by $456.0 million, or 43%, to $1,517.7 million for
2006 compared to $1,061.7 million for 2005.
Operating Expenses. Operating expenses
increased by $24.7 million, or 101%, to $49.1 million
for 2006 compared to $24.4 million for 2005. Again, the
primary factor was the addition of a full years operating
expense for the North Texas System in 2006 versus two months in
2005.
Depreciation and Amortization. Depreciation
and amortization expense increased by $46.8 million, or
203%, to $69.9 million for 2006 compared to
$23.1 million for 2005. The increase is due primarily to
the higher carrying value of property, plant and equipment of
the North Texas System for a full year in 2006 versus two months
in 2005.
General and Administrative. General and
administrative expense decreased by $0.6 million, or 4%, to
$16.1 million for 2006 compared to $16.7 million for
2005. The decrease was the result of lower allocated costs
following the DMS Acquisition due to lower parent costs and to
adjustments to the factors used to allocate general and
administrative expense.
Interest Expense. Interest expense for 2006
was $88.0 million compared to $21.2 million for 2005.
Interest expense recorded for 2006 reflects an allocation of
debt and related interest expense incurred by Targa and
allocated to the SAOU, LOU and North Texas Systems in connection
with debt incurred associated with the acquisitions made by
Targa. Interest expense for 2006 represents a full year of
interest allocation related to the North Texas System that was
acquired as part of the DMS acquisition in October 2005, whereas
interest expense for 2005 represents two months of allocated
interest.
Liquidity
and Capital Resources
Our ability to finance our operations, including funding capital
expenditures and acquisitions, to meet our indebtedness
obligations, to refinance our indebtedness or to meet our
collateral requirements depends on our ability to generate cash
in the future. Our ability to generate cash is subject to a
number of factors, some of which are beyond our control,
including commodity prices, particularly for natural gas and
NGLs, operating costs and maintenance capital expenditures.
Please see Item 1A. Risk Factors.
Historically, our cash generated from operations has been
sufficient to finance our operating expenditures and maintenance
and expansion capital expenditures, with remaining amounts being
distributed to Targa, during its period of ownership and to our
unitholders since Targas contribution of assets to us and
our acquisition of assets from Targa. Our sources of liquidity
include:
|
|
|
|
|
cash generated from operations;
|
|
|
|
borrowings under our credit facility;
|
|
|
|
issuance of additional partnership units; and
|
|
|
|
debt offerings.
|
We believe that cash generated from these sources will be
sufficient to meet our short-term working capital requirements,
long-term capital expenditure requirements and our minimum
quarterly cash distributions for at least the next year.
Working Capital. Working capital is the amount
by which current assets exceed current liabilities. Our working
capital requirements are primarily driven by changes in accounts
receivable and accounts payable. These changes are impacted by
changes in the prices of commodities that we buy and sell. In
general, our working capital requirements increase in periods of
rising commodity prices and decrease in periods of declining
commodity prices. However, our working capital needs do not
necessarily change at the same rate as
71
commodity prices because both accounts receivable and accounts
payable are impacted by the same commodity prices. In addition,
the timing of payments received by our customers or paid to our
suppliers can also cause fluctuations in working capital because
we settle with most of our larger suppliers and customers on a
monthly basis and often near the end of the month. We expect
that our future working capital requirements will be impacted by
these same factors.
Prior to our IPO and the contribution of the North Texas System
in February 2007 and the acquisition of the SAOU and LOU Systems
in October 2007, all intercompany transactions, including
commodity sales and expense reimbursements, were not cash
settled with Targa, but were recorded as an adjustment to parent
equity on the balance sheet. The primary transactions between us
and Targa are natural gas and NGL sales, the provision of
operations and maintenance activities and the provision of
general and administrative services. As a result of this
accounting treatment, our working capital does not reflect any
affiliate accounts receivable for intercompany commodity sales
or any affiliate accounts payable for the personnel and services
provided by or paid for by our parent prior to the acquisition
of the North Texas System and the subsequent acquisition of the
SAOU and LOU Systems.
We had positive working capital of $15.9 million as of
December 31, 2007, compared to negative working capital of
$369.0 million as of December 31, 2006. Excluding the
current portion of allocated debt that was retired by Targa with
proceeds received from the IPO, our negative working capital
balance at December 31, 2006 would have been
$28.2 million. This increase in the amount of working
capital is attributable to operations of the larger organization
and cash generated from their operations.
Cash Flow. Net cash provided by or used in
operating activities, investing activities and financing
activities for the years ended December 31, 2007, 2006 and
2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in millions)
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
270.5
|
|
|
$
|
124.4
|
|
|
$
|
10.5
|
|
Investing activities
|
|
|
(40.7
|
)
|
|
|
(32.9
|
)
|
|
|
(6.8
|
)
|
Financing activities
|
|
|
(178.8
|
)
|
|
|
(91.5
|
)
|
|
|
(3.7
|
)
|
Operating Activities. Net cash provided by
operating activities increased by $146.1 million, or 117%,
for the year ended December 31, 2007 compared to the year
ended December 31, 2006. This increase is attributable to a
increase in our net income, increased non-cash charges and
increases in working capital balances. Net cash provided by
operating activities increased by $113.9 million for the
year ended December 31, 2006 compared to the year ended
December 31, 2005. This increase is primarily attributable
to the inclusion of a full year of operations for the North
Texas System in 2006, compared to only two months for 2005, as
the North Texas System was acquired as part of the DMS
Acquisition in October 2005, and its net income, adjusted for
non-cash charges, as presented in the combined statements of
cash flows and changes in working capital was only included for
the period subsequent to the acquisition.
Investing Activities. Net cash used in
investing activities for the year ended December 31, 2007
increased $7.8 million, or 24%, compared to the year ended
December 31, 2006, primarily due to the completion of
gathering system expansion projects and higher major maintenance
expenditures of $5.2 million primarily due to the increased
size of our gathering systems and the effect of higher
utilization of our field compression facilities.
Financing Activities. The net cash used in
financing activities for the year ended December 31, 2007
increased by $87.3 million compared to the year ended
December 31, 2006. This increase primarily reflects the
proceeds from our equity offerings, borrowings under our credit
facility, and deemed parent contributions prior to the
contribution or transfer of assets to us, partially offset by
payments of debt, offering costs, debt issuance costs related to
our credit facility, distributions to our equity holders and
payments to Targa for assets transferred under common control.
72
Capital Requirements. The midstream energy
business can be capital intensive, requiring significant
investment to maintain and upgrade existing operations. A
significant portion of the cost of constructing new gathering
lines to connect to our gathering system is generally paid for
by the natural gas producer. However, we expect to incur
significant expenditures during 2008 related to the expansion of
our natural gas gathering and processing infrastructure.
We categorize our capital expenditures as either:
(i) maintenance expenditures or (ii) expansion
expenditures. Maintenance expenditures are those expenditures
that are necessary to maintain the service capability of our
existing assets including the replacement of system components
and equipment which is worn, obsolete or completing its useful
life, the addition of new sources of natural gas supply to our
systems to replace natural gas production declines and
expenditures to remain in compliance with environmental laws and
regulations. Expansion expenditures improve the service
capability of the existing assets, extend asset useful lives,
increase capacities from existing levels, reduce costs or
enhance revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expansion
|
|
$
|
22.4
|
|
|
$
|
16.0
|
|
|
$
|
0.6
|
|
|
|
|
|
Maintenance
|
|
|
21.5
|
|
|
|
16.3
|
|
|
|
6.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
43.9
|
|
|
$
|
32.3
|
|
|
$
|
6.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We estimate that our capital expenditures will be approximately
$60 million in 2008. Given our objective of growth through
acquisitions, expansions of existing assets and other internal
growth projects, we anticipate that we will invest significant
amounts of capital to grow and acquire assets. Expansion capital
expenditures may vary significantly based on investment
opportunities.
We expect to fund future capital expenditures with funds
generated from our operations, borrowings under our credit
facility, the issuance of additional partnership units and debt
offerings.
Description of Credit Agreement. On
February 14, 2007, we entered into a five-year
$500 million senior secured revolving credit agreement (the
Credit Agreement) and borrowed approximately
$294.5 million. The proceeds from this borrowing, together
with approximately $371.2 million of net proceeds from the
IPO (including 2,520,000 common units sold pursuant to the full
exercise by the underwriters of their option to purchase
additional common units), were used to repay approximately
$665.7 million of allocated indebtedness.
Concurrent with the acquisition of the SAOU and LOU Systems on
October 24, 2007, we entered into a Commitment Increase
Supplement (the Supplement) to the Credit Agreement.
The Supplement increased the aggregate commitments under the
Credit Agreement by $250 million to an aggregate of
$750 million. We paid for our acquisition of the SAOU and
LOU Systems with the proceeds from our offering of common units
and borrowings under the increased Credit Agreement.
On October 24, 2007, we entered into the First Amendment to
Credit Agreement (the Amendment). The Amendment
increased by $250 million the maximum amount of increases
to the aggregate commitments that may be requested by us. The
Amendment allows us to request commitments under the Credit
Agreement, as supplemented and amended (the Amended Credit
Agreement), up to $1 billion.
The Amended Credit Agreement restricts our ability to make
distributions of available cash to unitholders if we are in any
default or an event of default (as defined in the Amended Credit
Agreement) exists. The Amended Credit Agreement requires us to
maintain a leverage ratio (the ratio of consolidated
indebtedness to our consolidated EBITDA, as defined in the
credit agreement) of no more than 5.00 to 1.00, subject to
certain adjustments. The Amended Credit Agreement also requires
us to maintain an interest coverage ratio (the ratio of our
consolidated EBITDA to our consolidated interest expense, as
defined in the Amended Credit Agreement) of no less than 2.25 to
1.00 determined as of the last day of each quarter for the
four-fiscal
73
quarter period ending on the date of determination. In addition,
the Amended Credit Agreement contains various covenants that may
limit, among other things, our ability to:
|
|
|
|
|
incur indebtedness;
|
|
|
|
grant liens; and
|
|
|
|
engage in transactions with affiliates.
|
Any subsequent replacement of our Amended Credit Agreement or
any new indebtedness could have similar or greater restrictions.
In December 2007, we entered into interest rate swaps with a
notional amount of $200 million. At December 31, 2007,
we had the following open interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective Date
|
|
Expiration Date
|
|
|
Notional Amount
|
|
|
Index
|
|
|
Fixed Rate
|
|
|
12/13/2007
|
|
|
1/24/2011
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.0775
|
%
|
12/18/2007
|
|
|
1/24/2011
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.2100
|
%
|
12/21/2007
|
|
|
1/24/2012
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.0750
|
%
|
12/21/2007
|
|
|
1/24/2012
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.0750
|
%
|
Each of these interest rate swaps have been designated as cash
flow hedges of variable rate interest payments on a notional
amount of $50 million in borrowings under our Amended
Credit Agreement.
Contractual Obligations. Following is a
summary of our contractual cash obligations over the next
several fiscal years, as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
Contractual Obligations
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
4-5 Years
|
|
|
5 Years
|
|
|
|
(in millions)
|
|
|
Debt obligations
|
|
$
|
626.3
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
626.3
|
|
|
$
|
|
|
Interest on debt obligations(1)
|
|
|
150.3
|
|
|
|
36.4
|
|
|
|
72.9
|
|
|
|
41.0
|
|
|
|
|
|
Operating lease obligations
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capacity payments(2)
|
|
|
16.8
|
|
|
|
9.2
|
|
|
|
6.8
|
|
|
|
0.8
|
|
|
|
|
|
Right of way
|
|
|
4.9
|
|
|
|
0.3
|
|
|
|
0.5
|
|
|
|
0.5
|
|
|
|
3.6
|
|
Asset retirement obligation
|
|
|
3.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
801.7
|
|
|
$
|
46.0
|
|
|
$
|
80.2
|
|
|
$
|
668.6
|
|
|
$
|
6.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents interest expense on partnership debt, based on
interest rates as of December 31, 2007. We used an average
rate of 5.8% to estimate our interest on variable rate debt
obligations.
|
|
|
(2)
|
Consists of capacity payments for natural gas pipelines.
|
Available Credit. As of March 11, 2008,
we had approximately $110.2 million in capacity available
under our Amended Credit Agreement, after giving effect to
outstanding borrowings of $601.3 million and the issuance
of $38.5 million of letters of credit.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
Our principal market risks are our exposure to changes in
commodity prices, particularly to the prices of natural gas and
NGLs, changes in interest rates, as well as nonperformance by
our customers. We do not use risk sensitive instruments for
trading purposes.
Commodity Price Risk. A majority of our
revenues are derived from percent-of-proceeds contracts under
which we receive a portion of the natural gas
and/or NGLs,
or equity volumes, as payment for services. The prices of
natural gas and NGLs are subject to fluctuations in response to
changes in supply, demand, market uncertainty and a variety of
additional factors beyond our control. We monitor these risks
and enter into
74
hedging transactions designed to mitigate the impact of
commodity price fluctuations on our business. Cash flows from a
derivative instrument designated as hedge are classified in the
same category as the cash flows from the item being hedged.
The primary purpose of our commodity risk management activities
is to hedge our exposure to commodity price risk and reduce
fluctuations in our operating cash flow despite fluctuations in
commodity prices. In an effort to reduce the variability of our
cash flows, as of December 31, 2007, we have hedged the
commodity price associated with a significant portion of our
expected natural gas, NGL and condensate equity volumes for the
years 2008 through 2012 by entering into derivative financial
instruments including swaps and purchased puts (or floors). The
percentages of our expected equity volumes that are hedged
decrease over time. With swaps, we typically receive an agreed
fixed price for a specified notional quantity of natural gas or
NGLs, and we pay the hedge counterparty a floating price for
that same quantity based upon published index prices. Since we
receive from our customers substantially the same floating index
price from the sale of the underlying physical commodity, these
transactions are designed to effectively lock-in the agreed
fixed price in advance for the volumes hedged. In order to avoid
having a greater volume hedged than our actual equity volumes,
we typically limit our use of swaps to hedge the prices of less
than our expected natural gas and NGL equity volumes. We utilize
purchased puts (or floors) to hedge additional expected equity
commodity volumes without creating volumetric risk. We intend to
continue to manage our exposure to commodity prices in the
future by entering into similar hedge transactions using swaps,
collars, purchased puts (or floors) or other hedge instruments
as market conditions permit.
We have tailored our hedges to generally match the NGL product
composition and the NGL and natural gas delivery points to those
of our physical equity volumes. Our NGL hedges cover baskets of
ethane, propane, normal butane, iso-butane and natural gasoline
based upon our expected equity NGL composition. We believe this
strategy avoids uncorrelated risks resulting from employing
hedges on crude oil or other petroleum products as
proxy hedges of NGL prices. Additionally, our NGL
hedges are based on published index prices for delivery at Mont
Belvieu, and our natural gas hedges are based on published index
prices for delivery at Waha and Mid-Continent, which closely
approximate our actual NGL and natural gas delivery points. We
hedge a portion of our condensate sales using crude oil hedges
that are based on the NYMEX futures contracts for West Texas
Intermediate light, sweet crude.
Our commodity price hedging transactions are typically
documented pursuant to a standard International Swap Dealers
Association (ISDA) form with customized credit and
legal terms. Our principal counterparties (or, if applicable,
their guarantors) have investment grade credit ratings. Our
payment obligations in connection with substantially all of
these hedging transactions, and any additional credit exposure
due to a rise in natural gas and NGL prices relative to the
fixed prices set forth in the hedges, are secured by a first
priority lien in the collateral securing our senior secured
indebtedness that ranks equal in right of payment with liens
granted in favor of our senior secured lenders. As long as this
first priority lien is in effect, we expect to have no
obligation to post cash, letters of credit, or other additional
collateral to secure these hedges at any time even if our
counterpartys exposure to our credit increases over the
term of the hedge as a result of higher commodity prices or
because there has been a change in our creditworthiness. A
purchased put (or floor) transaction does not create credit
exposure to us for our counterparties.
75
For the years ended December 31, 2007 and 2006, our
operating revenues were decreased by net hedge settlements of
$1.0 million and $0.9 million, respectively. During
2007 and 2006, we entered into hedging arrangements for a
portion of our forecast of equity volumes. Floor volumes and
floor pricing are based solely on purchased puts (or floors). At
December 31, 2007, we had the following open commodity
derivative positions:
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
MMBtu per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/MMBtu
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Natural Gas Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
NY-HH
|
|
|
8.34
|
|
|
|
1,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(341
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(341
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-HSC
|
|
|
8.09
|
|
|
|
2,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
513
|
|
Swap
|
|
IF-HSC
|
|
|
7.39
|
|
|
|
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(551
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,328
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.43
|
|
|
|
6,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,475
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.02
|
|
|
|
|
|
|
|
6,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,110
|
|
Swap
|
|
IF-NGPL MC
|
|
|
7.43
|
|
|
|
|
|
|
|
|
|
|
|
5,685
|
|
|
|
|
|
|
|
|
|
|
|
(667
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
|
|
|
|
(387
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
(435
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,964
|
|
|
|
6,256
|
|
|
|
5,685
|
|
|
|
2,750
|
|
|
|
2,750
|
|
|
|
4,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-Waha
|
|
|
8.20
|
|
|
|
7,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,000
|
|
Swap
|
|
IF-Waha
|
|
|
7.61
|
|
|
|
|
|
|
|
6,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(618
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.38
|
|
|
|
|
|
|
|
|
|
|
|
5,709
|
|
|
|
|
|
|
|
|
|
|
|
(1,288
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
|
|
|
|
(709
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
(789
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,389
|
|
|
|
6,936
|
|
|
|
5,709
|
|
|
|
3,250
|
|
|
|
3,250
|
|
|
|
(404
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
16,681
|
|
|
|
15,158
|
|
|
|
11,394
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
3,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-Waha
|
|
|
6.85
|
|
|
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
140
|
|
Floor
|
|
IF-Waha
|
|
|
6.55
|
|
|
|
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
670
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
1,670
|
|
|
|
1,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap Jan 2008 Rec IF-HH minus $0.01, pay GD-HH,
403,000 MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/gal
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
NGL Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
OPIS-MB
|
|
|
1.02
|
|
|
|
7,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(40,051
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.96
|
|
|
|
|
|
|
|
6,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,573
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.91
|
|
|
|
|
|
|
|
|
|
|
|
4,809
|
|
|
|
|
|
|
|
|
|
|
|
(5,506
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,400
|
|
|
|
|
|
|
|
(3,210
|
)
|
Swap
|
|
OPIS-MB
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,700
|
|
|
|
(2,030
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,127
|
|
|
|
6,248
|
|
|
|
4,809
|
|
|
|
3,400
|
|
|
|
2,700
|
|
|
$
|
(71,370
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76
Condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/Bbl
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Condensate Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
NY-WTI
|
|
|
70.68
|
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,013
|
)
|
Swap
|
|
NY-WTI
|
|
|
69.00
|
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,008
|
)
|
Swap
|
|
NY-WTI
|
|
|
68.10
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(1,705
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
384
|
|
|
|
322
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(6,726
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
NY-WTI
|
|
|
60.50
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Floor
|
|
NY-WTI
|
|
|
60.00
|
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
55
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
439
|
|
|
|
372
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
$
|
(6,715
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
Hedges
Customer
Hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Instrument
|
|
Daily
|
|
Average
|
|
|
|
|
|
Period
|
|
Commodity
|
|
Type
|
|
Volume
|
|
Price
|
|
Index
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 June 2008
|
|
Natural gas
|
|
Swap
|
|
8,440 MMBtu
|
|
7.23 per MMBtu
|
|
NY-HH
|
|
$
|
8
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 June 2008
|
|
Natural gas
|
|
Fixed price sale
|
|
8,440 MMBtu
|
|
7.23 per MMBtu
|
|
NY-HH
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These contracts may expose us to the risk of financial loss in
certain circumstances. Our hedging arrangements provide us
protection on the hedged volumes if prices decline below the
prices at which these hedges are set. If prices rise above the
prices at which we have hedged, we will receive less revenue on
the hedged volumes than we would receive in the absence of
hedges.
Interest
Rate Risk
We are exposed to changes in interest rates, primarily as a
result of our variable rate debt under our credit facility. To
the extent that interest rates increase, our interest expense
for our revolving debt will also increase. As of March 11,
2008, there were borrowings of approximately $601.3 million
outstanding under our amended Credit Agreement.
Because of the interest rate risk on our credit facility we
entered into four interest rate swaps as of December 31,
2007 to reduce this risk, as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
Trade Date
|
|
Term
|
|
|
From
|
|
|
To
|
|
|
Rate
|
|
|
Amount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
12/11/07
|
|
|
3 years
|
|
|
|
12/13/07
|
|
|
|
1/24/11
|
|
|
|
4.0775
|
%
|
|
$
|
50,000
|
|
12/14/07
|
|
|
3 years
|
|
|
|
12/18/07
|
|
|
|
1/24/11
|
|
|
|
4.2100
|
%
|
|
|
50,000
|
|
12/19/07
|
|
|
4 years
|
|
|
|
12/21/07
|
|
|
|
1/24/12
|
|
|
|
4.0750
|
%
|
|
|
50,000
|
|
12/19/07
|
|
|
4 years
|
|
|
|
12/21/07
|
|
|
|
1/24/12
|
|
|
|
4.0750
|
%
|
|
|
50,000
|
|
Each swap fixes the three month LIBOR rate, prior to credit
margin, at the indicated rates for the specified amounts of
related debt outstanding over the term of each swap agreement.
We have designated all interest rate swaps as cash flow hedges.
Accordingly, unrealized gains and losses relating to the
interest rate swaps are recorded in OCI until the interest
expense on the related debt is recognized in earnings. A
77
hypothetical increase of 100 basis points in the underlying
interest rate, after taking into account our interest rate
swaps, would increase our annual interest expense by
$4.3 million.
Credit
Risk
We are subject to risk of losses resulting from nonpayment or
nonperformance by our customers. We operate under the Targa
credit policy and closely monitor the creditworthiness of
customers to whom we grant credit and establish credit limits in
accordance with this credit policy. In addition to third party
contracts, we have entered into several agreements with Targa.
For example, we are party to natural gas, NGL and condensate
purchase agreements that have terms of 15 years pursuant to
which Targa purchases all of our natural gas, NGLs and
high-pressure condensate. In addition, we are also party to an
omnibus agreement with Targa which addresses, among other
things, the provision of general and administrative and
operating services to us. As of September 6, 2007,
Moodys and Standard & Poors assigned Targa
corporate credit ratings of B1 and B, respectively, which are
speculative ratings. A speculative rating signifies a higher
risk that Targa will default on its obligations, including its
obligations to us, than does an investment grade rating. Any
material nonperformance under the omnibus and purchase
agreements by Targa could materially and adversely impact our
ability to operate and make distributions to our unitholders.
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
Our consolidated financial statements, together with the report
of our independent registered public accounting firm begin on
page F-1
of this report.
|
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
None.
|
|
Item 9A.
|
Controls
and Procedures
|
Disclosure
Controls and Procedures
Our management, under the supervision of and with the
participation of our Chief Executive Officer and Chief Financial
Officer, has evaluated the effectiveness of our disclosure
controls and procedures, as such term is defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934, as amended (the
Exchange Act) as of the end of the period covered by
this report. Based on such evaluation, our Chief Executive
Officer and Chief Financial Officer have concluded that, as of
the end of such period, our disclosure controls and procedures
were effective to provide reasonable assurance that (i) all
material information relating to us required to be included in
our reports filed or submitted under the Exchange Act is
recorded, processed, summarized and reported within the time
periods specified in the rules and forms of the Securities and
Exchange Commission and (ii) such information is
accumulated and communicated to our management, including our
Chief Executive Office and Chief Financial Officer, as
appropriate to allow timely decisions regarding required
disclosure.
Internal
Control Over Financial Reporting
Our management is responsible for establishing and maintaining
an adequate system of internal control over financial reporting,
as such term is defined in Exchange Act
Rules 13a-15(f)
and
15d-15(f).
Our internal control system was designed to provide reasonable
assurance to our management and board of directors of our
general partner regarding the preparation and fair presentation
of published financial statements.
All internal control systems, no matter how well designed, have
inherent limitations. Therefore, internal control over financial
reporting may not prevent or detect misstatements. Projections
of any evaluation of effectiveness to future periods are subject
to the risk that controls may become inadequate because of
changes in conditions, or that the degree of compliance with
policies and procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief
Financial Officer, has conducted an evaluation of the
effectiveness of our internal control over financial reporting
as of December 31, 2007 based
78
on the framework in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on that
evaluation, management concluded that our internal control over
financial reporting was effective as of December 31, 2007.
This annual report does not include an attestation report of our
registered public accounting firm regarding internal control
over financial reporting. Managements report was not
subject to attestation by our registered public accounting firm
pursuant to temporary rules of the Securities and Exchange
Commission that permit us to provide only managements
report in this annual report.
There has been no change in our internal control over financial
reporting during the quarter ended December 31, 2007 that
has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
|
|
Item 9B.
|
Other
Information
|
Not applicable.
Part III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
We are a limited partnership and, therefore have no officers or
directors.
Management
of Targa Resources Partners LP
Targa Resources GP LLC, our general partner, manages our
operations and activities. Our general partner is not elected by
our unitholders and is not subject to re-election on a regular
basis in the future. Unitholders are not entitled to elect the
directors of our general partner or directly or indirectly
participate in our management or operation. Our general partner
owes a fiduciary duty to our unitholders, but our partnership
agreement contains various provisions modifying and restricting
the fiduciary duty. Our general partner is liable, as general
partner, for all of our debts (to the extent not paid from our
assets), except for indebtedness or other obligations that are
made expressly nonrecourse to it. Our general partner therefore
may cause us to incur indebtedness or other obligations that are
nonrecourse to it.
The directors of our general partner oversee our operations. Our
general partner currently has seven directors. Targa elects all
members to the board of directors of our general partner and our
general partner has three directors that are independent as
defined under the independence standards established by The
NASDAQ Stock Market LLC. The NASDAQ Stock Market LLC does not
require a listed limited partnership like us to have a majority
of independent directors on the board of directors of our
general partner or to establish a compensation committee or a
nominating committee.
Our general partner has a standing Audit Committee that consists
of three directors. Messrs. Robert B. Evans, Barry R. Pearl
and William D. Sullivan serve as the members of the Audit
Committee. The Board of Directors of our general partner has
affirmatively determined that Messrs. Evans, Pearl and
Sullivan are independent as described in the rules of The NASDAQ
Stock Market LLC and the Exchange Act, as amended. In addition,
the Board of Directors of our general partner has determined
that, based upon relevant experience, Audit Committee member
Barry R. Pearl is an audit committee financial
expert as defined in Item 407 of
Regulation S-
K of the Exchange Act, as amended. Mr. Pearl serves as the
Chairman of the Audit Committee. The Audit Committee assists the
board in its oversight of the integrity of our financial
statements and our compliance with legal and regulatory
requirements and partnership policies and controls. The Audit
Committee has sole authority to retain and terminate our
independent registered public accounting firm, approve all
auditing services and related fees and the terms thereof, and
pre-approve any non-audit services to be rendered by our
independent registered public accounting firm. The Audit
Committee is also responsible for confirming the independence
and objectivity of our independent registered public accounting
firm. Our independent registered public accounting firm has been
given unrestricted access to the Audit Committee.
79
The compensation of our general partners executive
officers is set by Targa, with the board of directors of our
general partner playing no role in the process. Compensation
decisions relating to oversight of the long-term incentive plan
described below, however, are made by the board of directors of
our general partner. While the board may establish a
compensation committee in the future, it has no current plans to
do so.
Three independent members of the board of directors of our
general partner serve on a conflicts committee to review
specific matters that the board believes may involve conflicts
of interest. Messrs. Evans, Pearl and Sullivan serve as the
initial members of the conflicts committee. Mr. Pearl
serves as the Chairman of the Conflicts Committee. The conflicts
committee determines if the resolution of the conflict of
interest is fair and reasonable to us. The members of the
conflicts committee may not be officers or employees of our
general partner or directors, officers, or employees of its
affiliates, and must meet the independence and experience
standards established by The NASDAQ Stock Market LLC and the
Exchange Act, amended, to serve on an audit committee of a board
of directors, and certain other requirements. Any matters
approved by the conflicts committee in good faith will be
conclusively deemed to be fair and reasonable to us, approved by
all of our partners, and not a breach by our general partner of
any duties it may owe us or our unitholders.
All of our executive management personnel are employees of Targa
and devote their time as needed to conduct our business and
affairs. These officers of Targa Resources GP LLC manage the
day-to-day affairs of our business. We also utilize a
significant number of employees of Targa to operate our business
and provide us with general and administrative services. We
reimburse Targa for allocated expenses of operational personnel
who perform services for our benefit, allocated general and
administrative expenses and certain direct expenses. Please see
Reimbursement of Expenses of Our General Partner
included in this Item 10.
Directors
and Executive Officers
The following table shows information regarding the current
directors and executive officers of Targa Resources GP LLC.
|
|
|
|
|
|
|
|
|
Name
|
|
Age(1)
|
|
Position with Targa Resources GP LLC
|
|
Rene R. Joyce
|
|
|
60
|
|
|
|
Chief Executive Officer and Director
|
|
Joe Bob Perkins
|
|
|
47
|
|
|
|
President
|
|
James W. Whalen
|
|
|
66
|
|
|
|
President Finance and Administration and
Director
|
|
Roy E. Johnson
|
|
|
63
|
|
|
|
Executive Vice President
|
|
Michael A. Heim
|
|
|
59
|
|
|
|
Executive Vice President and Chief Operating Officer
|
|
Jeffrey J. McParland
|
|
|
53
|
|
|
|
Executive Vice President, and Chief Financial Officer
|
|
Paul W. Chung
|
|
|
48
|
|
|
|
Executive Vice President, General Counsel and Secretary
|
|
Peter R. Kagan
|
|
|
39
|
|
|
|
Director
|
|
Chansoo Joung
|
|
|
47
|
|
|
|
Director
|
|
Robert B. Evans
|
|
|
59
|
|
|
|
Director
|
|
Barry R. Pearl
|
|
|
58
|
|
|
|
Director
|
|
William D. Sullivan
|
|
|
51
|
|
|
|
Director
|
|
Our directors hold office until the earlier of their death,
resignation, removal or disqualification or until their
successors have been elected and qualified. Officers serve at
the discretion of the board of directors of our general partner.
There are no family relationships among any of our directors or
executive officers.
Rene R. Joyce has served as a director and Chief
Executive Officer of our general partner since October 2006 and
of Targa since its formation in February 2004 and was a
consultant for the Targa predecessor company during 2003.
Mr. Joyce has also served as a member of Targas board
of directors since February 2004. He is also a member of the
supervisory directors of Core Laboratories N.V. Mr. Joyce
served as a consultant in the energy industry from 2000 through
2003 providing advice to various energy companies and investors
regarding their operations, acquisitions and dispositions.
Mr. Joyce served as President of onshore
80
pipeline operations of Coral Energy, LLC, a subsidiary of Shell
Oil Company (Shell) from 1998 through 1999, and
President of energy services of Coral Energy Holding, L.P.
(Coral) a subsidiary of Shell which was the gas and
power marketing joint venture between Shell and Tejas Gas
Corporation (Tejas) during 1999. Mr. Joyce
served as President of various operating subsidiaries of Tejas,
a natural gas pipeline company, from 1990 until 1998 when Tejas
was acquired by Shell.
Joe Bob Perkins has served as President of our general
partner since October 2006 and of Targa since February 2004 and
was a consultant for the Targa predecessor company during 2003.
Mr. Perkins also served as a consultant in the energy
industry from 2002 through 2003 and was an active partner in RTM
Media (an outdoor advertising firm) during such time period.
Mr. Perkins served as President and Chief Operating
Officer, for the Wholesale Businesses, Wholesale Group, and
Power Generation Group of Reliant Resources, Inc. and its
parent/predecessor companies, from 1998 to 2002, and Vice
President, Corporate Planning and Development, Houston
Industries from 1996 to 1998. He served as Vice President,
Business Development, of Coral from 1995 to 1996 and as
Director, Business Development, of Tejas from 1994 to 1995.
Prior to 1994, Mr. Perkins held various positions with the
consulting firm of McKinsey & Company and with an
exploration and production company.
James W. Whalen has served as a director of our general
partner since February 2007 and has served as President-Finance
and Administration of our general partner since October 2006 and
of Targa since January 2006 and as a director of Targa since May
2004. Since November 2005, Mr. Whalen has served as
President Finance and Administration for various
Targa subsidiaries. Between October 2002 and October 2005,
Mr. Whalen served as the Senior Vice President and Chief
Financial Officer of Parker Drilling Company. Between January
2002 and October 2002, he was the Chief Financial Officer of
Diversified Diagnostic Products, Inc. He served as Chief
Commercial Officer of Coral from February 1998 through January
2000. Previously, he served as Chief Financial Officer for Tejas
from 1992 to 1998. Mr. Whalen is also a director of Parker
Drilling Company and Equitable Resources, Inc.
Roy E. Johnson has served as Executive Vice President of
our general partner since October 2006 and of Targa since April
2004 and was a consultant for the Targa predecessor company
during 2003. Mr. Johnson also served as a consultant in the
energy industry from 2000 through 2003 providing advice to
various energy companies and investors regarding their
operations, acquisitions and dispositions. He served as Vice
President, Business Development and President of the
International Group of Tejas from 1995 to 2000. In these
positions, he was responsible for acquisitions, pipeline
expansion and development projects in North and South America.
Mr. Johnson served as President of Louisiana Resources
Company, a company engaged in intrastate natural gas
transmission, from 1992 to 1995. Prior to 1992, Mr. Johnson
held various positions with a number of different companies in
the upstream and downstream energy industry.
Michael A. Heim has served as Executive Vice President
and Chief Operating Officer of our general partner since October
2006 and of Targa since April 2004 and was a consultant for the
Targa predecessor company during 2003. Mr. Heim also served
as a consultant in the energy industry from 2001 through 2003
providing advice to various energy companies and investors
regarding their operations, acquisitions and dispositions.
Mr. Heim served as Chief Operating Officer and Executive
Vice President of Coastal Field Services, a subsidiary of The
Coastal Corp. (Coastal), a diversified energy
company, from 1997 to 2001 and President of Coastal States Gas
Transmission Company from 1997 to 2001. In these positions, he
was responsible for Coastals midstream gathering,
processing, and marketing businesses. Prior to 1997, he served
as an officer of several other Coastal exploration and
production, marketing, and midstream subsidiaries.
Jeffrey J. McParland has served as Executive Vice
President and Chief Financial Officer of our general partner
since October 2006 and of Targa since April 2004 and was a
consultant for the Targa predecessor company during 2003. He
served as a director of our general partner from October 2006 to
February 2007. Mr. McParland served as Treasurer of our
general partner from October 2006 until May 2007, and he has
served as Treasurer of Targa from April 2004 until May 2007.
Mr. McParland served as Secretary of Targa since February
2004 until May 2004, at which time he was elected as Assistant
Secretary. Mr. McParland served as Senior Vice President,
Finance of Dynegy Inc., a company engaged in power generation,
the midstream natural gas business and energy marketing, from
2000 to 2002. In this position, he was responsible
81
for corporate finance and treasury operations activities. He
served as Senior Vice President, Chief Financial Officer and
Treasurer of PG&E Gas Transmission, a midstream natural gas
and regulated natural gas pipeline company, from 1999 to 2000.
Prior to 1999, he worked in various engineering and finance
positions with companies in the power generation and engineering
and construction industries.
Paul W. Chung has served as Executive Vice President,
General Counsel and Secretary of our general partner since
October 2006 and of Targa since May 2004. Mr. Chung served
as Executive Vice President and General Counsel of Coral from
1999 to April 2004; Shell Trading North America Company, a
subsidiary of Shell, from 2001 to April 2004; and Coral Energy,
LLC from 1999 to 2001. In these positions, he was responsible
for all legal and regulatory affairs. He served as Vice
President and Assistant General Counsel of Tejas from 1996 to
1999. Prior to 1996, Mr. Chung held a number of legal
positions with different companies, including the law firm of
Vinson & Elkins L.L.P.
Peter R. Kagan has served as a director of our general
partner since February 2007, and has served as a director of
Targa since February 2004. Mr. Kagan is a Managing Director
of Warburg Pincus LLC, where he has been employed since 1997,
and became a partner of Warburg Pincus & Co. in 2002.
He is also a member of Warburg Pincus Executive Management
Group. He is also a director of Antero Resources Corporation,
Broad Oak Energy, Inc., Cambrien Energy, Fairfield Energy
Limited, Laredo Petroleum, MEG Energy Corp. and Universal Space
Network, Inc.
Chansoo Joung has served as a director of our general
partner since February 2007, and has served as a director of
Targa since December 31, 2005. Mr. Joung is a Member
and Managing Director of Warburg Pincus LLC, where he has been
employed since 2005, and became a partner of Warburg
Pincus & Co. in 2005. Prior to joining Warburg Pincus,
Mr. Joung was head of the Americas Natural Resources Group
in the investment banking division of Goldman Sachs. He joined
Goldman Sachs in 1987 and served in the Corporate Finance and
Mergers and Acquisitions departments and also founded and led
the European Energy Group. He is a director of APT Generation,
Broad Oak Energy, Ceres, Inc., and Floridian Natural Gas Storage
Company.
Robert B. Evans has served as a director of our general
partner since February 2007. Mr. Evans was the President
and Chief Executive Officer of Duke Energy Americas, a business
unit of Duke Energy Corp., from January 2004 to March 2006,
after which he retired. Mr. Evans served as the transition
executive for Energy Services, a business unit of Duke Energy,
during 2003. Mr. Evans also served as President of Duke
Energy Gas Transmission beginning in 1998 and was named
President and Chief Executive Officer in 2002. Prior to his
employment at Duke Energy, Mr. Evans served as Vice
President of marketing and regulatory affairs for Texas Eastern
Transmission and Algonquin Gas Transmission from 1996 to 1998.
Barry R. Pearl has served as a director of our general
partner since February 2007. Mr. Pearl is a principal of
Kealine LLC, a private developer and operator of petroleum
infrastructure facilities, and is a director of Seaspan
Corporation and Kayne Anderson Energy Development Company.
Mr. Pearl served as President and Chief Executive Officer
of TEPPCO Partners from May 2002 until December 2005 and as
President and Chief Operating Officer from February 2001 through
April 2002. Mr. Pearl served as Vice President of Finance
and Chief Financial Officer of Maverick Tube Corporation from
June 1998 until December 2000. From 1984 to 1998, Mr. Pearl
was Vice President of Operations, Senior Vice President of
business development and planning and Senior Vice President and
Chief Financial Officer of Santa Fe Pacific Pipeline
Partners, L.P.
William D. Sullivan has served as a director of our
general partner since February 2007. Mr. Sullivan served as
President and Chief Executive Officer of Leor Energy LP from
June 15, 2005 to August 5, 2005. Between 1981 and
August 2003, Mr. Sullivan was employed in various
capacities by Anadarko Petroleum Corporation, including serving
as Executive Vice President, Exploration and Production between
August 2001 and August 2003. Since Mr. Sullivans
departure from Anadarko Petroleum Corporation in August 2003, he
has served on various private energy company boards.
Mr. Sullivan is a director of St. Mary
Land & Exploration Company, Legacy Reserves GP, LLC
and Tetra Technologies, Inc.
82
Reimbursement
of Expenses of our General Partner
Under the terms of the Omnibus Agreement, we reimburse Targa for
the payment of certain operating expenses, including
compensation and benefits of operating personnel, and for the
provision of various general and administrative services for our
benefit. With respect to the North Texas System, we reimburse
Targa for the following expenses:
|
|
|
|
|
general and administrative expenses, which are capped at
$5 million annually for three years, subject to increases
based on increases in the Consumer Price Index and subject to
further increases in connection with expansions of our
operations through the acquisition or construction of new assets
or businesses with the concurrence of our conflicts committee;
thereafter, our general partner will determine the general and
administrative expenses to be allocated to us in accordance with
our partnership agreement; and
|
|
|
|
operations and certain direct expenses, which are not subject to
the $5 million cap for general and administrative expenses.
|
With respect to the SAOU and LOU Systems, we will reimburse
Targa for the following expenses:
|
|
|
|
|
general and administrative expenses, which are not capped,
allocated to the SAOU and LOU Systems according to Targas
allocation practice; and
|
|
|
|
operating and certain direct expenses, which are not capped.
|
Pursuant to these arrangements, Targa performs centralized
corporate functions for us, such as legal, accounting, treasury,
insurance, risk management, health, safety and environmental,
information technology, human resources, credit, payroll,
internal audit, taxes, engineering and marketing. We reimburse
Targa for the direct expenses to provide these services as well
as other direct expenses it incurs on our behalf, such as
compensation of operational personnel performing services for
our benefit and the cost of their employee benefits, including
401(k), pension and health insurance benefits.
General and administrative costs will continue to be allocated
to the SAOU and LOU Systems according to Targas allocation
practice.
Code of
Ethics
Our general partner has adopted a Code of Ethics For Chief
Executive Officer and Senior Financial Officers (the Code
of Ethics), which applies to our general partners
Chief Executive Officer, Chief Financial Officer, Chief
Accounting Officer, Controller and all other senior financial
and accounting officers of our general partner. In accordance
with the disclosure requirements of applicable law or
regulation, we intend to disclose any amendment to, or waiver
from, any provision of the Code of Ethics under Item 10 of
a current report on
Form 8-K.
We make available, free of charge within the Corporate
Governance section of our website at
www.targaresources.com, and in print to any unitholder who so
requests, the Code of Ethics and the Audit Committee Charter.
Requests for print copies may be directed to: Investor
Relations, Targa Resources Partners LP, 1000 Louisiana,
Suite 4300, Houston, Texas 77002, or telephone
(713) 584-1000.
The information contained on, or connected to, our internet
website is not incorporated by reference into this Annual Report
on
Form 10-K
and should not be considered part of this or any other report
that the we file with, or furnish to the SEC.
Section 16(A)
Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934
requires our directors, executive officers and 10% stockholders
to file with the SEC reports of ownership and changes in
ownership of our equity securities. Based solely upon a review
of the copies of the Form 3, 4 and 5 reports furnished to
us and certifications from our directors and executive officers,
we believe that during 2007, all of our directors and executive
officers, other than Mr. Whalen, and beneficial owners of
more than 10% of our common stock complied with
83
Section 16(a) filing requirements applicable to them.
Mr. Whalen filed one late Form 4 with respect to a
purchase of some of our common units.
|
|
Item 11.
|
Executive
Compensation
|
Executive
Compensation
Compensation
Discussion and Analysis
The following discussion and analysis contains statements
regarding our and our executive officers future
performance targets and goals. These targets and goals are
disclosed in the limited context of our compensation programs
and should not be understood to be statements of
managements expectations or estimates of results or other
guidance.
Overview
We do not directly employ any of the persons responsible for
managing our business. Any compensation decisions that are
required to be made by our general partner will be made by its
board of directors (the Board), which does not have
a compensation committee. All of our executive officers are
employees of Targa Resources LLC, a wholly-owned subsidiary of
Targa, and serve in the same capacities for Targa. All of the
outstanding equity of Targa is held indirectly by Targa
Resources Investments Inc. (Targa Investments). We
reimburse Targa and its affiliates for the compensation of our
executive officers based on Targas methodology used for
allocating general and administration expenses during a period
pursuant to the terms of, and subject to the limitations
contained in, the Amended and Restated Omnibus Agreement. During
2006, our executive officers were not specifically compensated
for time expended with respect to our business or assets.
Targa Investments has ultimate decision making authority with
respect to the compensation of our executive officers identified
in the Summary Compensation Table (named executive
officers). Under the terms of the Targa Investments
Amended and Restated Stockholders Agreement, as amended
(the Stockholders Agreement), compensatory
arrangements with Targas named executive officers, who are
also our named executive officers, are required to be submitted
to a vote of Targa Investments stockholders unless such
arrangements have been approved by the Compensation Committee of
Targa Investments (the TRII Compensation Committee).
As such, the TRII Compensation Committee is responsible for
overseeing the development of an executive compensation
philosophy, strategy and framework for our named executive
officers that is based on Targa Investments business
priorities.
The following Compensation Discussion and Analysis describes the
material elements of compensation for our named executive
officers as determined by the TRII Compensation Committee and is
presented from the perspective of our named executive officers
in their roles as officers of Targa. These elements, and the
TRII Compensation Committees decisions with respect to
determinations on payments, are not subject to approval by the
Board or the board of directors of Targa (the Targa
Board). However, certain members of the Board and the
entire Targa Board, including the Targa Boards
compensation committee, are members of the board of directors of
Targa Investments (the Targa Investments Board),
including the TRII Compensation Committee. As used in this
Compensation Discussion and Analysis, references to
our, we, us and similar
terms refer to Targa.
Compensation
Philosophy
The TRII Compensation Committee believes that total compensation
of executives should be competitive with the market in which we
compete for executive talent the energy industry and
midstream natural gas companies. The following compensation
objectives guide the TRII Compensation Committee in its
deliberations about executive compensation matters:
|
|
|
|
|
Provide a competitive total compensation program that enables us
to attract and retain key executives;
|
|
|
|
Ensure an alignment between our strategic and financial
performance and the total compensation received by our named
executive officers;
|
84
|
|
|
|
|
Provide compensation for performance relative to expectations
and our peer group;
|
|
|
|
Ensure a balance between short-term and long-term compensation
while emphasizing at-risk, or variable, compensation as a
valuable means of supporting our strategic goals and aligning
the interests of our named executive officers with those of our
shareholders; and
|
|
|
|
Ensure that our total compensation program supports our business
objectives and priorities.
|
As a result of this philosophy, we do not pay for perquisites
for any of our named executive officers, other than parking
subsidies.
The
Role of Peer Groups and Benchmarking
Our chief executive officer (the CEO), president and
chief financial officer (collectively, Senior
Management) review compensation practices at peer
companies at a general level to ensure that our total
compensation is within a comparable range. In addition, when
evaluating compensation levels for each named executive officer,
the TRII Compensation Committee reviews publicly available
compensation data for executives in our peer group, compensation
surveys, and compensation levels for each named executive
officer with respect to their roles with the Company and levels
of responsibility, accountability and decision-making authority.
Senior Management and the TRII Compensation Committee, however,
do not attempt to set compensation components to meet specific
benchmarks, such as salaries above the median or
total compensation at the 50th percentile.
For 2007, Senior Management identified peer companies that
competed with us in the midstream natural gas industry and
reviewed compensation information filed by the peer companies
with the SEC. The peer group reviewed by Senior Management for
2007 consisted of the following companies: Atlas America, Copano
Energy, Crosstex Energy, DCP Midstream, Enbridge Energy
Partners, Energy Transfer Partners, Magellan Midstream, MarkWest
Energy Partners, Martin Midstream, Oneok Partners, Plains All
American Pipeline, Regency Energy Partners, TEPPCO Partners and
Williams Energy Partners.
Senior Management intends to review our compensation practices
and performance against peer companies on an annual basis.
Role
of Senior Management in Establishing Compensation for Named
Executive Officers
Typically, Senior Management consults with compensation
consultants and reviews market data to determine relevant
compensation levels and compensation program elements. Based on
these consultations and a review of publicly available
information for the peer group, Senior Management submits a
proposal to the chairman of the TRII Compensation Committee. The
proposal includes a recommendation of base salary, annual bonus
and any new long term compensation to be paid or awarded to
executive officers and employees. The chairman of the TRII
Compensation Committee considers this proposal (which he may
request Senior Management to modify based on information
available to him or that he requests of Senior Management) and
his resulting recommendation is then submitted to the TRII
Compensation Committee for consideration. The final compensation
decisions are reported to the Targa Investments Board.
Our Senior Management has no other role in determining
compensation for our executive officers, but our executive
officers are delegated the authority and responsibility to
determine the compensation for all other employees.
Elements
of Compensation for Named Executive Officers
The compensation philosophy for our executive officers centers
on long-term equity awards to attract, motivate and retain our
executive team. For this reason, in connection with our
formation in 2004 and with the DMS Acquisition in 2005, the
named executive officers were granted restricted stock and
options to purchase restricted stock of Targa Investments. As a
result, executive compensation has been weighted toward
long-term equity awards. Our executive officers have also
invested a significant portion of their personal investable
assets in the equity of Targa Investments. Within this context,
elements of compensation for our named executive
85
officers are the following: (i) annual base salary;
(ii) discretionary annual cash awards;
(iii) performance awards under Targa Investments
long-term incentive plan, (iv) contributions under our
401(k) and profit sharing plan; and (v) participation in
our health and welfare plans on the same basis as all of our
other employees.
Base Salary. The base salaries for our named
executive officers are set and reviewed annually by the TRII
Compensation Committee. The salaries are based on historical
salaries paid to our named executive officers for services
rendered to us, the extent of their equity ownership in Targa
Investments, market data and responsibilities of our named
executive officers. Base salaries are intended to provide fixed
compensation comparable to market levels for similarly situated
executive officers.
Annual Cash Incentives. The discretionary
annual cash awards paid to our named executive officers are
designed to supplement the annual base salary of our named
executive officers so that, on a combined basis, the annual cash
compensation for our named executive officers yield competitive
cash compensation levels and drive performance in support of our
business strategies. It is Targa Investments general
policy to pay these awards prior to the end of the first quarter
of the next fiscal year. The payment of individual cash bonuses
to employees, including our named executive officers, are
subject to the sole discretion of the TRII Compensation
Committee.
Our 2007 Annual Incentive Plan (the Bonus Plan) was
adopted on January 23, 2007 to reward our employees for
contributions towards our achievement of financial and
operational goals approved by the TRII Compensation Committee
and to aid us in retaining and motivating employees. Under the
Bonus Plan and similar plans expected to be adopted in
subsequent years, a discretionary cash bonus pool is expected to
be funded annually based on our achievement of certain
strategic, financial and operational objectives recommended by
our CEO and approved by the TRII Compensation Committee. The
Bonus Plan is administered by the TRII Compensation Committee,
which considers certain recommendations by the CEO. Following
the end of each year, the CEO recommends to the TRII
Compensation Committee the total amount of cash to be allocated
to the bonus pool based upon our overall performance relative to
these objectives. Upon receipt of the CEOs recommendation,
the TRII Compensation Committee, in its sole discretion,
determines the total amount of cash to be allocated to the bonus
pool. Additionally, the TRII Compensation Committee, in its sole
discretion, determines the amount of the cash bonus award to
each of our executive officers, including the CEO. The executive
officers determine the amount of the cash bonus pool to be
allocated to certain of our departments, groups and employees
(other than our executive officers) based on the recommendation
of their supervisors, managers and line officers.
For 2007, the TRII Compensation Committee aligned the cash bonus
pool with the following six key business priorities:
(i) involving employees in improving our businesses;
(ii) proactively and aggressively investing in our
businesses and developing the pipeline of projects and
opportunities; (iii) bringing closure to hurricane repair
and recovery; (iv) identifying and pursuing new
opportunities in the downstream sector; (v) debt reduction
and achievement of capital structure goals; and
(vi) executing on all fronts (including the financial
business plan). The Bonus Plan established goals that the TRII
Compensation Committee will consider when making awards under
the Bonus Plan and also established the following overall
threshold, target and maximum levels for the Companys
bonus pool: 50% of the cash bonus pool for the threshold level;
100% for the target level and 200% for the maximum level. The
funding of the cash bonus pool and the payment of individual
cash bonuses to employees, including our named executive
officers, are subject to the sole discretion of the TRII
Compensation Committee.
LTIP Awards. In connection with the initial
public offering of the Partnership, Targa Investments issued to
our named executive officers cash-settled performance unit
awards linked to the performance of the Partnerships
common units that will vest in August of 2010, with the amounts
vesting under such awards dependent on the Partnerships
performance compared to a peer-group consisting of the
Partnership and 12 other publicly traded partnerships. These
performance unit awards are made pursuant to a plan adopted by
Targa Investments.
Retirement Benefits. We offer eligible
employees a Section 401(k) tax-qualified, defined
contribution plan to enable employees to save for retirement
through a tax-advantaged combination of employee and
86
Company contributions and to provide employees the opportunity
to directly manage their retirement plan assets through a
variety of investment options. Our employees, including our
named executive officers, are eligible to participate in our
401(k) plan and may elect to defer up to 30% of their annual
compensation on a pre-tax basis and have it contributed to the
plan, subject to certain limitations under the Internal Revenue
Code. In addition, we make the following contributions to the
401(k) Plan for the benefit of our employees, including our
named executive officers: (i) 3% of the employees eligible
compensation; (ii) an amount equal to the employees
contributions to the 401(k) Plan up to 5% of the employees
eligible compensation and (iii) a discretionary amount
depending on Targas performance.
Health and Welfare Benefits. All full-time
employees, including our named executive officers, may
participate in our health and welfare benefit programs,
including medical, health, life insurance, and dental coverage
and disability insurance.
Perquisites. We believe that the elements of
executive compensation should be tied directly or indirectly to
the actual performance of the Company. It is the TRII
Compensation Committees policy not to pay for perquisites
for any of our named executive officers, other than parking
subsidies.
Relation
of Compensation Elements to Compensation
Philosophy
Our named executive officers, other senior managers and
directors, through a combination of personal investment and
equity grants, own approximately 20% of the fully diluted equity
of Targa Investments. Based on our named executive
officers ownership interests in Targa Investments and
their direct ownership of our common units, they own, directly
and indirectly, approximately 3% of our limited partner
interests. The TRII Compensation Committee believes that the
elements of its compensation program fit the established overall
compensation objectives in the context of managements
substantial ownership of our parents equity, which allows
Targa to provide competitive compensation opportunities to align
and drive the performance of the named executive officers in
support of Targa Investments and our own business
strategies and to attract, motivate and retain high quality
talent with the skills and competencies required by Targa
Investments and us.
Application
of Compensation Elements
Base Salary. In 2007, base salaries for our
named executive officers were generally lower than similar
positions in our peer group.
Annual Cash Incentives. In January 2008, the
TRII Compensation Committee approved a cash bonus pool of 200%
of the target level for the employee group, including our named
executive officers, under the Bonus Plan for performance during
2007. The executive officers received bonus awards equivalent to
the same percentage of target as the Company bonus pool. The
TRII Compensation Committee paid maximum level bonuses under the
Bonus Plan in recognition of outstanding organizational
performance in 2007. Our named executive officers received cash
bonuses under the Bonus Plan based on our achievement of overall
goals in 2007 as follows:
|
|
|
|
|
Rene R. Joyce
|
|
$
|
300,000
|
|
Jeffrey J. McParland
|
|
$
|
235,000
|
|
Joe Bob Perkins
|
|
$
|
270,000
|
|
James W. Whalen
|
|
$
|
270,000
|
|
Michael A. Heim
|
|
$
|
250,000
|
|
Equity/Stock Option Exchange. In May 2007,
options relating to Targa Investments preferred stock held
by the employees, including the named executive officers, were
exchanged for (i) a grant of 10 shares of Targa
Investments common stock for each option and (ii) a right
to receive a cash payment in the amount of $27.69 for each
option. Except for the grant of shares in the stock option
exchange, the TRII Compensation Committee did not award
additional equity to our named executive officers.
Long-term Cash Incentives. In connection with
the Partnerships initial public offering in February 2007,
Targa Investments issued to key employees and the executive
officers of the General Partner cash-settled
87
performance unit awards linked to the performance of the
Partnerships common units that will vest in August of
2010, with the amounts vesting under such awards dependent on
the Partnerships performance compared to a peer-group
consisting of the Partnership and 12 other publicly traded
partnerships. The peer group companies for 2007 were: Energy
Transfer Partners, Oneok Partners, Copano Energy, DCP Midstream,
Regency Energy Partners, Plains All American Pipeline, MarkWest
Energy Partners, Williams Energy Partners, Magellan Midstream,
Martin Midstream, Enbridge Energy Partners, Crosstex Energy and
Targa Resources Partners LP. These performance unit awards were
made pursuant to a plan adopted by Targa Investments and
administered by Targa Resources LLC. The TRII Compensation
Committee has the ability to modify the peer-group in the event
a peer company is no longer determined to be one of the
Partnerships peers. The cash settlement value of each
performance unit award will be the value of an equivalent
Partnership common unit at the time of vesting plus associated
distributions over the vesting period, which may be higher or
lower than the Partnerships common unit price at the time
of the award. If the Partnerships performance equals or
exceeds the performance for the median of the group, 100% of the
award will vest. If the Partnership ranks tenth in the group,
50% of the award will vest, between tenth and seventh, 50% to
100% will vest, and for a performance ranking lower than tenth,
no amounts will vest. In February 2007, our named executive
officers, who are also executive officers of the General
Partner, received an initial award of performance units as
follows: 15,000 performance units to Mr. Joyce, 8,200
performance units to Mr. McParland, 10,800 performance
units to Mr. Perkins, 10,800 performance units to
Mr. Whalen and 10,000 performance units to Mr. Heim.
Retirement Benefits. For 2007, the
discretionary amount contributed to the 401(k) Plan equaled
2.25% of the employees eligible compensation.
Health and Welfare Benefits. For 2007, our
named executive officers participated in our health and welfare
benefit programs, including medical, health, life insurance, and
dental coverage and disability insurance.
Perquisites. Consistent with our compensation
philosophy, we did not pay for perquisites for any of our named
executive officers during 2007, other than parking subsidies.
Changes
for 2008
Annual Cash Incentives. In connection with the
development of our 2008 business plan and discussion of the plan
with the Targa Investments Board, Senior Management proposed a
set of strategic priorities. In January 2008, the TRII
Compensation Committee approved the Targa Investments 2008
Annual Incentive Compensation Plan (the 2008 Bonus
Plan), the cash bonus plan for performance during 2008,
and, with input from the Targa Investments Board, established
the following six key business priorities: (i) identify
opportunities to strengthen organization and develop plans to
address them; (ii) expand on existing processes to enhance
the involvement of the organization in making our businesses
better; (iii) aggressively develop attractive return
projects and opportunities and proactively invest in and expand
the Companys businesses; (iv) improve insurance
recovery situation with resolution or clear path to resolution;
(v) make a significant third-party acquisition(s) at the
Partnership
and/or
continue to effectively drop down Company assets to the
Partnership; and (iv) execute on all fronts (including the
2008 business plan and above priorities). As with the Bonus
Plan, funding of the cash bonus pool and the payment of
individual cash bonuses to employees, including our named
executive officers, are subject to the sole discretion of the
TRII Compensation Committee.
Long-term Cash Incentives. In January 2008,
our named executive officers, who are also executive officers of
the General Partner, received an award of performance units
under Targa Investments long-term incentive plan as
follows: 4,000 performance units to Mr. Joyce, 2,700
performance units to Mr. McParland, 3,500 performance units
to Mr. Perkins, 3,500 performance units to Mr. Whalen
and 3,500 performance units to Mr. Heim.
Compensation
Committee Interlocks and Insider Participation
Our general partner does not maintain a compensation committee.
The following officers of our general partner participated in
deliberations of the Compensation Committee of Targa Investments
concerning
88
executive officer compensation: Messrs. Joyce, Perkins,
Heim, McParland, Whalen and Chung. Please see
Item 13. Certain Relationships and Related
Transactions, and Director Independence for a description
of relationships requiring disclosure under the SECs rules
for requiring disclosure of certain relationships and
related-party transactions.
Compensation
Committee Report
In fulfilling its oversight responsibilities, the Board reviewed
and discussed with management the compensation discussion and
analysis contained in this Annual Report on
Form 10-K.
Based on these reviews and discussions, the Board recommended
that the compensation discussion and analysis be included in the
Annual Report on
Form 10-K
for the year ended December 31, 2007 for filing with the
SEC.
The information contained in this report shall not be deemed to
be soliciting material or to be filed
with the SEC, nor shall such information be incorporated by
reference into any future filings with the SEC, or subject to
the liabilities of Section 18 of the Exchange Act, except
to the extent that the Partnership specifically incorporates it
by reference into a document filed under the Securities Act of
1933, as amended, or the Exchange Act.
Rene R. Joyce
James W. Whalen
Peter R. Kagan
Chansoo Joung
Robert B. Evans
Barry R. Pearl
William D. Sullivan
Executive
Compensation
The following Summary Compensation Table sets forth the
compensation of our named executive officers for 2007.
Additional details regarding the applicable elements of
compensation in the Summary Compensation Table are provided in
the footnotes following the table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Compensation Table for 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
|
|
|
Option
|
|
|
Incentive Plan
|
|
|
All Other
|
|
|
Total
|
|
|
|
Year
|
|
|
Salary
|
|
|
Awards ($)(1)
|
|
|
Awards ($)(1)
|
|
|
Compensation
|
|
|
Compensation(2)
|
|
|
Compensation
|
|
|
Rene R. Joyce
|
|
|
2007
|
|
|
$
|
293,750
|
|
|
$
|
459,769
|
|
|
$
|
3,244
|
|
|
$
|
300,000
|
|
|
$
|
817,850
|
|
|
$
|
1,874,613
|
|
Chief Executive Officer
|
|
|
2006
|
|
|
|
266,530
|
|
|
|
312,513
|
|
|
|
3,244
|
|
|
|
262,000
|
|
|
|
25,536
|
|
|
|
869,823
|
|
Jeffrey J. McParland
|
|
|
2007
|
|
|
|
230,000
|
|
|
|
316,770
|
|
|
|
3,244
|
|
|
|
235,000
|
|
|
|
674,179
|
|
|
|
1,459,193
|
|
Executive Vice President and Chief Financial Officer
|
|
|
2006
|
|
|
|
210,280
|
|
|
|
236,720
|
|
|
|
3,244
|
|
|
|
204,400
|
|
|
|
23,386
|
|
|
|
678,030
|
|
Joe Bob Perkins
|
|
|
2007
|
|
|
|
265,000
|
|
|
|
366,318
|
|
|
|
3,244
|
|
|
|
270,000
|
|
|
|
817,775
|
|
|
|
1,722,337
|
|
President
|
|
|
2006
|
|
|
|
244,030
|
|
|
|
260,294
|
|
|
|
3,244
|
|
|
|
238,000
|
|
|
|
23,474
|
|
|
|
769,042
|
|
James W. Whalen
|
|
|
2007
|
|
|
|
265,000
|
|
|
|
224,796
|
|
|
|
|
|
|
|
270,000
|
|
|
|
817,775
|
|
|
|
1,577,571
|
|
President Finance and Administration
|
|
|
2006
|
|
|
|
244,030
|
|
|
|
227,546
|
|
|
|
|
|
|
|
238,000
|
|
|
|
17,539
|
|
|
|
727,115
|
|
Michael A. Heim
|
|
|
2007
|
|
|
|
243,750
|
|
|
|
366,318
|
|
|
|
3,244
|
|
|
|
250,000
|
|
|
|
817,725
|
|
|
|
1,681,037
|
|
Executive Vice President and Chief Operating Officer
|
|
|
2006
|
|
|
|
217,791
|
|
|
|
260,294
|
|
|
|
3,244
|
|
|
|
214,000
|
|
|
|
23,411
|
|
|
|
718,740
|
|
|
|
|
|
(1)
|
The amounts reported in these columns reflect the aggregate
dollar amounts recognized for stock awards (including
performance units) and option awards, as applicable, for
financial statement reporting purposes with respect to fiscal
year 2007 (disregarding any estimate of forfeitures related to
service-based vesting conditions). No stock awards or option
awards granted to the named executive officers were forfeited
during 2007. Detailed information about the amount recognized
for specific awards is reported in the table under
Outstanding Equity Awards at 2007 Fiscal Year-End
below.
|
89
The fair value of non-vested stock is measured on the grant date
using the estimated market price of Targa Investments common
stock on such date.
The fair value of each option granted since our adoption of
SFAS 123R was estimated on the date of grant using the
Black-Scholes option pricing model, which incorporates various
assumptions for 2007 and 2006, including (i) expected term
of the options of ten years, (ii) a risk-free interest rate
of 4.6% and 4.5%, respectively, (iii) expected dividend
yield of 0%, and (iv) expected stock price volatility on
Targa Investments common stock of 29.7% and 23.8%,
respectively. Our selection of the risk-free interest rate was
based on published yields for United States government
securities with comparable terms. Because Targa Investments is a
non-public company, its expected stock price volatility was
estimated based upon the historical price volatility of the Dow
Jones MidCap Pipelines Index over a period equal to the expected
average term of the options granted. The calculated fair value
of options granted during the twelve months ended
December 31, 2007 and the same period ended
December 31, 2006 is $0.63 and $0.21 per share,
respectively.
|
|
|
|
(2)
|
For 2007 All Other Compensation includes the
(i) payments under the Change of Control Bonus Plan and
individual Bonus Agreements made in August 2007 in connection
with the termination of the Change of Control Bonus Plan and the
Bonus Agreements, (ii) aggregate value of matching,
non-matching and discretionary contributions to our 401(k) plan
and (iii) the dollar value of life insurance coverage.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change of
|
|
|
|
|
|
|
|
|
Change of
|
|
Control
|
|
|
|
|
|
|
|
|
Control
|
|
Agreement
|
|
401(k) and Profit
|
|
Dollar Value of
|
|
|
Name
|
|
Plan Termination
|
|
Termination
|
|
Sharing Plan
|
|
Life Insurance
|
|
Total
|
|
Rene R. Joyce
|
|
$
|
76,614
|
|
|
$
|
717,537
|
|
|
$
|
22,950
|
|
|
$
|
749
|
|
|
$
|
817,850
|
|
Jeffrey J. McParland
|
|
|
76,614
|
|
|
|
574,028
|
|
|
|
22,950
|
|
|
|
587
|
|
|
|
674,179
|
|
Joe Bob Perkins
|
|
|
76,614
|
|
|
|
717,537
|
|
|
|
22,950
|
|
|
|
674
|
|
|
|
817,775
|
|
James W. Whalen
|
|
|
76,614
|
|
|
|
717,537
|
|
|
|
22,950
|
|
|
|
674
|
|
|
|
817,775
|
|
Michael A. Heim
|
|
|
76,614
|
|
|
|
717,537
|
|
|
|
22,950
|
|
|
|
624
|
|
|
|
817,725
|
|
Grants of
Plan-Based Awards
The following table and the footnotes thereto provide
information regarding grants of plan-based equity and non-equity
awards made to the named executive officers during 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grants of Plan Based Awards for 2007
|
|
|
|
|
|
|
|
|
|
|
|
All Other Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Awards: Number of
|
|
|
Grant Date Fair
|
|
|
|
|
|
Estimated Possible Payouts Under
|
|
|
Estimated Future Payouts Under
|
|
|
Shares of Stock or
|
|
|
Value of Stock and
|
|
|
|
|
|
Non-Equity Incentive Plan Awards(1)
|
|
|
Equity Incentive Plan Awards(2)
|
|
|
Units
|
|
|
Option Awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target
|
|
|
|
|
|
|
|
|
|
|
Name
|
|
Grant Date
|
|
Threshold
|
|
|
Target
|
|
|
2X Target
|
|
|
Threshold
|
|
|
(Units)
|
|
|
Maximum
|
|
|
(3)
|
|
|
(4)
|
|
|
Mr. Joyce
|
|
N/A
02/14/07
05/01/07
|
|
$
|
75,000
|
|
|
$
|
150,000
|
|
|
$
|
300,000
|
|
|
|
|
|
|
|
15,000
|
|
|
|
|
|
|
|
84,110
|
|
|
$
|
447,450
0
|
|
Mr. McParland
|
|
N/A
02/14/07
05/01/07
|
|
|
58,750
|
|
|
|
117,500
|
|
|
|
235,000
|
|
|
|
|
|
|
|
8,200
|
|
|
|
|
|
|
|
69,090
|
|
|
|
244,606
0
|
|
Mr. Perkins
|
|
N/A
02/14/07
05/01/07
|
|
|
67,500
|
|
|
|
135,000
|
|
|
|
270,000
|
|
|
|
|
|
|
|
10,800
|
|
|
|
|
|
|
|
84,110
|
|
|
|
322,164
0
|
|
Mr. Whalen
|
|
N/A
02/14/07
05/01/07
|
|
|
67,500
|
|
|
|
135,000
|
|
|
|
270,000
|
|
|
|
|
|
|
|
10,800
|
|
|
|
|
|
|
|
25,140
|
|
|
|
322,164
0
|
|
Mr. Heim
|
|
N/A
02/14/07
05/01/07
|
|
|
62,500
|
|
|
|
125,000
|
|
|
|
250,000
|
|
|
|
|
|
|
|
10,000
|
|
|
|
|
|
|
|
84,100
|
|
|
|
298,300
0
|
|
90
|
|
|
|
(1)
|
These awards were granted under the Bonus Plan. At the time the
Bonus Plan was adopted, the estimated future payouts in the
above table under the heading Estimated Possible Payouts
Under Non-Equity Incentive Plan Awards represented the
cash bonus pool available for awards to the named executive
officers under the Bonus Plan.
|
|
|
(2)
|
These performance unit awards were granted under the Targa
Investments Long-Term Incentive Plan and are discussed in more
detail under the heading Compensation
Discussion & Analysis Application of
Compensation Elements Long-Term Cash
Incentives.
|
|
|
(3)
|
These awards were granted in exchange for options relating to
Targa Investments preferred stock held by the named
executive officers.
|
|
|
(4)
|
The dollar amounts shown are determined by multiplying the
number of units reported in the table by $29.83 (the per unit
fair value under FAS 123R on the grant date) and assume full
payout under the awards at the time of vesting.
|
Narrative
Disclosure to Summary Compensation Table and Grants of Plan
Based Awards table
A discussion of 2007 salaries and bonuses is included in
Compensation Discussion and Analysis.
Targa
Investments 2005 Stock Incentive Plan
Stock Option Grants. Under the Targa
Investments 2005 Stock Incentive Plan, as amended (the
2005 Incentive Plan), incentive stock options and
non-incentive stock options to purchase, in the aggregate, up to
5,159,786 shares of Targa Investments restricted
stock may be granted to our employees, directors and
consultants. Subject to the terms of the applicable stock option
agreement, options granted under the 2005 Incentive Plan have a
vesting period of four years, remain exercisable for ten years
from the date of grant and have an exercise price at least equal
to the fair market value of a share of restricted stock on the
date of grant. Additional details relating to previously granted
non-incentive stock options under the 2005 Incentive Plan are
included in Outstanding Equity Awards at 2007
Fiscal Year-End below.
Restricted Stock Grants. Under the 2005
Incentive Plan, up to 7,293,882 shares of restricted stock
of Targa Investments may be granted to our employees, directors
and consultants. Subject to the terms of the restricted stock
agreement, restricted stock granted under the Incentive Plan has
a vesting period of four years from the date of grant.
Additional details relating to previously granted shares of
common stock are included in Outstanding
Equity Awards at 2007 Fiscal Year-End below.
Targa
Investments 2004 Stock Incentive Plan
Stock Option Grants. No awards have been, or
may be, made under the Targa Investments 2004 Stock Incentive
Plan, as assumed and amended (the 2004 Incentive
Plan), from and after December 31, 2004. The 2004
Stock Incentive Plan governs options to purchase shares of Targa
Investments Series B Convertible Participating
Preferred Stock (Preferred Stock). Subject to the
terms of the applicable stock option agreement, options granted
under the 2004 Incentive Plan have a vesting period of four
years and remain exercisable for ten years from the date of
grant. Additional details relating to previously granted stock
options under the 2004 Incentive Plan are included in
Outstanding Equity Awards at 2007 Fiscal
Year-End below. On May 1, 2007, employees and
directors of Targa Investments surrendered all options to
acquire shares of Preferred Stock in exchange for a cash payment
of $27.69 and ten shares of restricted stock of Targa
Investments for each option surrendered.
91
Outstanding
Equity Awards at 2007 Fiscal Year-End
Targa Investments indirectly owns all of our equity interests.
The following table and the footnotes related thereto provide
information regarding each stock option and other equity-based
awards of Targa Investments outstanding as of December 31,
2007 for each of our named executive officers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Equity Awards at 2007 Fiscal Year-End
|
|
|
|
Option Awards
|
|
|
Stock Awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Incentive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Incentive
|
|
|
Plan Awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan Awards:
|
|
|
Market or
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Payout Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Value of
|
|
|
Unearned
|
|
|
of Unearned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
|
Shares or Units
|
|
|
Shares, Units
|
|
|
Shares, Units or
|
|
|
|
|
|
|
|
|
|
Option
|
|
|
Option
|
|
|
or Units of Stock
|
|
|
of Stock That
|
|
|
or Other Rights
|
|
|
Other Rights
|
|
|
|
#
|
|
|
#
|
|
|
Exercise
|
|
|
Expiration
|
|
|
That Have Not
|
|
|
Have Not
|
|
|
That Have
|
|
|
That Have
|
|
Name
|
|
Exercisable
|
|
|
Unexercisable
|
|
|
Price
|
|
|
Date
|
|
|
Vested
|
|
|
Vested(11)
|
|
|
Not Vested(12)
|
|
|
Not Vested(13)
|
|
|
Rene R. Joyce
|
|
|
|
|
|
|
21,772
|
(1)
|
|
$
|
0.75
|
|
|
|
10/31/2015
|
|
|
|
734,199
|
(5)
|
|
$
|
2,532,987
|
|
|
|
15,000
|
|
|
$
|
444,300
|
|
|
|
|
|
|
|
|
291,376
|
(1)
|
|
$
|
3.00
|
|
|
|
10/31/2015
|
|
|
|
7,116
|
(6)
|
|
$
|
24,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
246,549
|
(1)
|
|
$
|
15.00
|
|
|
|
10/31/2015
|
|
|
|
84,110
|
(9)
|
|
$
|
290,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,006
|
(2)
|
|
$
|
3.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,559
|
(2)
|
|
$
|
15.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey J. McParland
|
|
|
|
|
|
|
21,772
|
(1)
|
|
$
|
0.75
|
|
|
|
10/31/2015
|
|
|
|
555,120
|
(5)
|
|
$
|
1,915,164
|
|
|
|
8,200
|
|
|
|
242,884
|
|
|
|
|
|
|
|
|
218,532
|
(1)
|
|
$
|
3.00
|
|
|
|
10/31/2015
|
|
|
|
5,337
|
(6)
|
|
$
|
18,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
184,912
|
(1)
|
|
$
|
15.00
|
|
|
|
10/31/2015
|
|
|
|
69,090
|
(9)
|
|
$
|
238,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,254
|
(2)
|
|
$
|
3.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,919
|
(2)
|
|
$
|
15.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joe Bob Perkins
|
|
|
|
|
|
|
21,772
|
(1)
|
|
$
|
0.75
|
|
|
|
10/31/2015
|
|
|
|
611,680
|
(5)
|
|
$
|
2,110,296
|
|
|
|
10,800
|
|
|
|
319,896
|
|
|
|
|
|
|
|
|
236,014
|
(1)
|
|
$
|
3.00
|
|
|
|
10/31/2015
|
|
|
|
5,764
|
(6)
|
|
$
|
19,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
199,705
|
(1)
|
|
$
|
15.00
|
|
|
|
10/31/2015
|
|
|
|
84,110
|
(9)
|
|
$
|
290,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,435
|
(2)
|
|
$
|
3.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,073
|
(2)
|
|
$
|
15.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James W. Whalen
|
|
|
136,365
|
|
|
|
90,908
|
(3)
|
|
$
|
3.00
|
|
|
|
11/1/2015
|
|
|
|
202,278
|
(7)
|
|
$
|
697,859
|
|
|
|
10,800
|
|
|
|
319,896
|
|
|
|
|
115,386
|
|
|
|
76,922
|
(3)
|
|
$
|
15.00
|
|
|
|
11/1/2015
|
|
|
|
2,220
|
(8)
|
|
$
|
7,659
|
|
|
|
|
|
|
|
|
|
|
|
|
1,407
|
|
|
|
937
|
(4)
|
|
$
|
3.00
|
|
|
|
12/20/2015
|
|
|
|
25,140
|
(10)
|
|
$
|
86,733
|
|
|
|
|
|
|
|
|
|
|
|
|
1,198
|
|
|
|
798
|
(4)
|
|
$
|
15.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael A. Heim
|
|
|
|
|
|
|
21,772
|
(1)
|
|
$
|
0.75
|
|
|
|
10/31/2015
|
|
|
|
611,680
|
(5)
|
|
$
|
2,110,296
|
|
|
|
10,000
|
|
|
|
296,200
|
|
|
|
|
|
|
|
|
236,014
|
(1)
|
|
$
|
3.00
|
|
|
|
10/31/2015
|
|
|
|
5,764
|
(6)
|
|
$
|
19,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
199,705
|
(1)
|
|
$
|
15.00
|
|
|
|
10/31/2015
|
|
|
|
84,110
|
(9)
|
|
$
|
290,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,435
|
(2)
|
|
$
|
3.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,073
|
(2)
|
|
$
|
15.00
|
|
|
|
12/20/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents options to purchase shares of Targa Investments
common stock awarded on October 31, 2005. These options
vest on the following schedule: 70% vest on April 30, 2008,
an additional 10% vest on October 31, 2008 and the
remaining options vest on October 31, 2009.
|
|
|
(2)
|
Represents options to purchase shares of Targa Investments
common stock awarded on December 20, 2005. These options
vest on the following schedule: 70% vest on June 20, 2008,
an additional 10% vest on December 20, 2008 and the
remaining options vest on December 20, 2009.
|
|
|
(3)
|
Represents options to purchase shares of Targa Investments
common stock awarded on November 1, 2005. These options
vest on the following schedule: 50% vest on each of
November 1, 2008 and 2009.
|
|
|
(4)
|
Represents options to purchase shares of Targa Investments
common stock awarded on December 20, 2005. These options
vest on the following schedule: 50% vest on each of
December 20, 2008 and 2009.
|
|
|
(5)
|
Represents shares of restricted common stock of Targa
Investments awarded on October 31, 2005. These shares vest
on the following schedule: 70% on April 30, 2008; an
additional 10% on October 31, 2008 and the remaining shares
on October 31, 2009.
|
|
|
(6)
|
Represents shares of restricted common stock of Targa
Investments awarded on December 20, 2005. These shares vest
on the following schedule: 70% on June 20, 2008; an
additional 10% on December 20, 2008 and the remaining
shares on December 20, 2009.
|
92
|
|
|
|
(7)
|
Represents shares of restricted common stock of Targa
Investments awarded on October 31, 2005 (2,721 shares)
and November 1, 2005 (502,975 shares). These shares
vest on the following schedule: 50% vest on each of
October 31, 2008 and 2009 (with respect to the
October 31, 2005 awards) and November 1, 2008 and 2009
(with respect to the November 1, 2005 awards).
|
|
|
(8)
|
Represents shares of restricted common stock of Targa
Investments awarded on December 20, 2005. These shares vest
on the following schedule: 50% vest on each of December 20,
2008 and 2009.
|
|
|
(9)
|
Represents shares of restricted common stock of Targa
Investments awarded on May 1, 2007 in connection with the
exchange of options relating to Targa Investments
preferred stock held by the named executive officers. These
shares vest on the following schedule: 80% vest on
January 1, 2008 and the remaining vest on April 16,
2008.
|
|
|
|
|
(10)
|
Represents shares of restricted common stock of Targa
Investments awarded on May 1, 2007 in connection with the
exchange of options relating to Targa Investments
preferred stock held by the named executive officer. These
shares vest on the following schedule: 80% vest on
January 1, 2008 and the remaining vest on May 7, 2008.
|
|
|
(11)
|
The dollar amounts shown are determined by multiplying the
number of shares or units reported in the table by $3.45 (the
value determined by an independent consultant pursuant to a
valuation of Targa Investments common stock as of
October 24, 2007, which management believes is a reasonable
approximation of the value of such stock as of December 31,
2007.
|
|
|
(12)
|
Represents the number of performance units awarded on
February 14, 2007 under the Targa Investments Long-Term
Incentive Plan. These awards vest in August of 2010 based on the
Partnerships performance over such period measured against
a peer group of companies. These awards are discussed in more
detail under the heading Compensation
Discussion & Analysis Application of
Compensation Elements Long-Term Cash
Incentives.
|
|
|
(13)
|
The dollar amounts shown are determined by multiplying the
number of units reported in the table by $29.62 (the closing
price of a common unit of the Partnership on December 31,
2007) and assume full payout under the awards at the time
of vesting.
|
Option
Exercises and Stock Vested in 2007
The following table provides the amount realized during 2007 by
each named executive officer upon the exercise of options and
upon the vesting of restricted common stock.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option Exercises and Stock Vested for 2007
|
|
|
Option Awards
|
|
Stock Awards
|
|
|
Number of Shares
|
|
|
|
|
|
|
|
|
Acquired on
|
|
Value Realized on
|
|
Number of Shares
|
|
Value Realized on
|
Name
|
|
Exercise(1)
|
|
Exercise(2)
|
|
Acquired on Vesting
|
|
Vesting(3)
|
|
Rene R. Joyce
|
|
|
84,110
|
|
|
$
|
325,422
|
|
|
|
|
|
|
|
|
|
Jeffrey J. McParland
|
|
|
69,090
|
|
|
$
|
267,309
|
|
|
|
|
|
|
|
|
|
Joe Bob Perkins
|
|
|
84,110
|
|
|
$
|
325,422
|
|
|
|
|
|
|
|
|
|
James W. Whalen
|
|
|
25,140
|
|
|
$
|
97,267
|
|
|
|
102,249
|
|
|
$
|
352,759
|
|
Michael A. Heim
|
|
|
84,110
|
|
|
$
|
325,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents shares of restricted common stock of Targa
Investments awarded on May 1, 2007 in connection with the
exchange of options relating to Targa Investments
preferred stock held by the named executive officers. At the
time of exchange, the restricted common stock had a value of
$1.10 per share. This value was determined by an independent
consultant pursuant to a valuation of Targa Investments common
stock as of December 31, 2006. The named executive officers
received 10 shares of restricted common stock of Targa
Investments for each option exchanged.
|
|
|
(2)
|
This value includes a cash payment to the named executive
officers of $27.69 per option exchanged.
|
|
|
(3)
|
On October 31, 2007 and December 20, 2007, 101,139 and
1,110 shares, respectively, vested. The value realized on
vesting used a per share price of $3.45. This value was
determined by an independent consultant pursuant to a valuation
of Targa Investments common stock as of October 24,
|
93
|
|
|
|
|
2007, which management believes is a reasonable approximation of
the value of such stock as of December 31, 2007.
|
Change in
Control and Termination Benefits
2005 Incentive Plan. If a Change of Control or
a Liquidation Event (each as defined below), or in the case of
restricted stock, certain drag-along transactions, occurs during
a named executive officers employment with us, the options
granted to him under Targa Investments form of Non-Statutory
Stock Option Agreement (the Option Agreement)
and/or the
restricted stock granted to him under Targa Investments
form of Restricted Stock Agreement (the Stock
Agreement) will fully vest and be exercisable (in the case
of options) by him so long as he remains an employee of Targa
Investments.
Options granted to a named executive officer under the Option
Agreement will terminate and cease to be exercisable upon the
termination of his employment with Targa Investments, except
that: (i) if his employment is terminated by reason of a
disability, he (or his estate or the person who acquires the
options by will or the laws of descent and distribution or
otherwise by reason of his death ) may exercise the options in
full for 180 days following such termination; (ii) if
he dies while employed by Targa Investments, his estate or the
person who acquires the options by will or the laws of descent
and distribution or otherwise by reason of his death, may
exercise the options in full for 180 days following his
death; or (iii) if he resigns or is terminated by Targa
Investments without Cause (as defined below), then he (or his
estate or the person who acquires the options by will or the
laws of descent and distribution or otherwise by reason of his
death) may exercise the options for three months following such
resignation or termination, but only as to the options he was
entitled to exercise as of the date his employment terminates.
Restricted stock granted to a named executive officer under the
Stock Agreement will fully vest if his employment is terminated
by reason of a disability or his death. If a named executive
officer resigns or he is terminated by Targa Investments without
Cause, then his unvested restricted stock is forfeited to Targa
Investments for no consideration. If a named executive officer
is terminated by Targa Investments for Cause, then all
restricted stock (both vested and unvested) granted to him under
the Stock Agreement is forfeited to Targa Investments for no
consideration. For one year following a named executive
officers termination of employment, Targa Investments has
the right to repurchase all of his restricted stock and other
Capital Stock (as defined below), after any applicable
forfeitures, at a purchase price equal to, in the case of a
termination by death, disability, resignation or without Cause,
the then fair market value of such restricted stock and Capital
Stock determined in accordance with the Stockholders Agreement,
and, in the case of a termination with Cause, the lower of the
Original Cost (as defined below) or the then Fair Market Value
(as defined below) of such Capital Stock.
The following terms have the specified meanings for purposes of
the 2005 Incentive Plan:
|
|
|
|
|
Change of Control means, in one transaction or a series
of related transactions, a consolidation, merger or any other
form of corporate reorganization involving Targa Investments or
a sale of Preferred Stock (or a sale of Targa Investments
common stock following conversion of the Preferred Stock) by
stockholders of Targa Investments with the result immediately
after such merger, consolidation, corporate reorganization or
sale that (A) a single person, together with its
affiliates, owns, if prior to any firm commitment underwritten
offering by Targa Investments of its common stock to the public
pursuant to an effective registration statement under the
Securities Act (x) for which the aggregate cash proceeds to
be received by Targa Investments from such offering (without
deducting underwriting discounts, expenses, and commissions) are
at least $35,000,000, and (y) pursuant to which Targa
Investments common stock is listed for trading on the New
York Stock Exchange or is admitted to trading and quoted on the
NASDAQ National Market System (a Qualified Public
Offering), either a greater number of shares of Targa
Investments common stock (calculated assuming that all
shares of Preferred Stock have been converted at the specified
conversion ratio) than Warburg Pincus and its affiliates then
own or, in the context of a consolidation, merger or other
corporate reorganization in which Targa Investments is not the
surviving entity, more voting stock generally entitled to elect
directors of such surviving entity (or in the case of a
triangular merger, of the parent entity of such
|
94
|
|
|
|
|
surviving entity) than Warburg Pincus and its affiliates then
own or, if on or after a Qualified Public Offering, either a
majority of Targa Investments common stock calculated on a
fully-diluted basis (i.e. on the basis that all shares of
Preferred Stock have been converted at the specified conversion
ratio, that all Management Stock is outstanding, whether vested
or not, and that all outstanding options to acquire Targa
Investments common stock had been exercised (whether then
exercisable or not)) or, in the context of a consolidation,
merger or other corporate reorganization in which Targa
Investments is not the surviving entity, a majority of the
voting stock generally entitled to elect directors of such
surviving entity (or in the case of a triangular merger, of the
parent entity of such surviving entity) calculated on a fully
diluted basis and (B) Warburg Pincus and its affiliates
collectively own less than a majority of the initial shares of
Capital Stock outstanding on October 31, 2005 owned by them
(the Initial Shares) or, in the event such Initial
Shares are converted or exchanged into other voting securities
of Targa Investment or such surviving or parent entity, less
than a majority of such voting securities Warburg Pincus and its
affiliates would have owned had they retained all such Initial
Shares;
|
|
|
|
|
|
Management Stock means the shares of Targa
Investments common stock granted pursuant to the terms of
the 2005 Incentive Plan, any such shares transferred to a
permitted transferee and any and all securities of any kind
whatsoever of Targa Investments which may be issued in respect
of, in exchange for, or upon conversion of such shares of common
stock pursuant to a merger, consolidation, stock split, stock
dividend, recapitalization of Targa Investments or otherwise;
|
|
|
|
Liquidation Event means the voluntary or involuntary
liquidation, dissolution, or winding up of the affairs of Targa
Investments; provided that neither the merger or consolidation
of Targa Investments with or into another entity, nor the merger
or consolidation of another entity with or into Targa
Investments, nor the sale of all or substantially all of the
assets of Targa Investments shall be deemed to be a Liquidation
Event;
|
|
|
|
Cause means discharge by Targa Investments based on
(A) an employees gross negligence or willful
misconduct in the performance of duties, (B) conviction of
a felony or other crime involving moral turpitude; (C) an
employees willful refusal, after fifteen days
written notice from the Targa Investments Board, to perform the
material lawful duties or responsibilities required of him;
(D) willful and material breach of any corporate policy or
code of conduct established by Targa Investments; and
(E) willfully engaging in conduct that is known or should
be known to be materially injurious to Targa Investments or any
of its subsidiaries;
|
|
|
|
Capital Stock means any and all shares of capital stock
of, or other equity interests in, Targa Investments, and any and
all warrants, options, or other rights to purchase or acquire
any of the foregoing;
|
|
|
|
Original Cost means, with respect to a particular share
of Capital Stock, the cash amount originally paid to Targa
Investments to purchase such share (or if such share was issued
in respect of other shares of Targa Investments issued in
connection with the merger of one of Targa Investments
subsidiaries with and into us, then the cash amount originally
paid to us to purchase such other shares), subject to adjustment
for subdivisions, combinations or stock dividends involving such
Capital Stock, or, if no cash amount was originally paid to
Targa Investments to purchase such share, then no consideration
(or if such share was issued in respect of other shares of Targa
Investments issued in connection with the merger of one of Targa
Investments subsidiaries with and into us and such other
shares were issued by us for no cash consideration, then no
consideration); and
|
|
|
|
Fair Market Value means the value determined by the
unanimous resolution of all directors of the Targa Investments
Board, provided that if the Targa Investments Board does not or
is unable to make such a determination, Fair Market Value means
the value determined by an investment banking firm of recognized
national standing selected by a majority of the directors of the
Targa Investments Board.
|
95
The following table reflects payments that would have been made
to each of the named executive officers under the 2005 Incentive
Plan and related agreements in the event there was a Change of
Control or their employment was terminated, each as of
December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Termination for Death
|
|
Name
|
|
Change of Control
|
|
|
or Disability
|
|
|
Rene R. Joyce
|
|
$
|
3,038,972
|
(1)
|
|
$
|
3,038,972
|
(1)
|
Jeffrey J. McParland
|
|
|
2,330,074
|
(2)
|
|
|
2,330,074
|
(2)
|
Joe Bob Perkins
|
|
|
2,586,449
|
(3)
|
|
|
2,586,449
|
(3)
|
James W. Whalen
|
|
|
833,583
|
(4)
|
|
|
833,583
|
(4)
|
Michael A. Heim
|
|
|
2,586,449
|
(5)
|
|
|
2,586,449
|
(5)
|
|
|
|
|
(1)
|
Of this amount, $2,532,987 relates to the unvested shares of
restricted stock of Targa Investments granted on
October 31, 2005; $24,549 relates to the unvested shares of
restricted stock of Targa Investments granted on
December 20, 2005; $290,180 relates to the unvested shares
of restricted stock of Targa Investments granted on May 1,
2007 in connection with the stock option exchange; $189,904
relates to the unvested options to purchase Targa Investments
common stock granted on October 31, 2005; and $1,352
relates to the unvested options to purchase Targa Investments
common stock granted on December 20, 2005.
|
|
|
(2)
|
Of this amount, $1,915,164 relates to the unvested shares of
restricted stock of Targa Investments granted on
October 31, 2005; $18,412 relates to the unvested shares of
restricted stock of Targa Investments granted on
December 20, 2005; $238,360 relates to the unvested shares
of restricted stock of Targa Investments granted on May 1,
2007 in connection with the stock option exchange; $157,124
relates to the unvested options to purchase Targa Investments
common stock granted on October 31, 2005; and $1,014
relates to the unvested options to purchase Targa Investments
common stock granted on December 20, 2005.
|
|
|
(3)
|
Of this amount, $2,110,296 relates to the unvested shares of
restricted stock of Targa Investments granted on
October 31, 2005; $19,886 relates to the unvested shares of
restricted stock of Targa Investments granted on
December 20, 2005; $290,180 relates to the unvested shares
of restricted stock of Targa Investments granted on May 1,
2007 in connection with the stock option exchange; $164,991
relates to the unvested options to purchase Targa Investments
common stock granted on October 31, 2005; and $1,096
relates to the unvested options to purchase Targa Investments
common stock granted on December 20, 2005.
|
|
|
(4)
|
Of this amount, $3,754 relates to the unvested shares of
restricted stock of Targa Investments granted on
October 31, 2005; $694,106 relates to the unvested shares
of restricted stock of Targa Investments granted on
November 1, 2005; $7,660 relates to the unvested shares of
restricted stock of Targa Investments granted on
December 20, 2005; $86,733 relates to the unvested shares
of restricted stock of Targa Investments granted on May 1,
2007 in connection with the stock option exchange; $40,908
relates to the unvested options to purchase Targa Investments
common stock granted on November 1, 2005; and $422 relates
to the unvested options to purchase Targa Investments common
stock granted on December 20, 2005.
|
|
|
(5)
|
Of this amount, $2,110,296 relates to the unvested shares of
restricted stock of Targa Investments granted on
October 31, 2005; $19,886 relates to the unvested shares of
restricted stock of Targa Investments granted on
December 20, 2005; $290,180 relates to the unvested shares
of restricted stock of Targa Investments granted on May 1,
2007 in connection with the stock option exchange; $164,991
relates to the unvested options to purchase Targa Investments
common stock granted on October 31, 2005; and $1,096
relates to the unvested options to purchase Targa Investments
common stock granted on December 20, 2005.
|
Other
Agreements
In connection with the DMS acquisition on October 31, 2005,
we entered into bonus agreements (the Bonus
Agreements) with Messrs. Heim, Joyce, McParland,
Perkins and Whalen and adopted the Targa
96
Resources, Inc. Bonus Plan (the Change of Control Bonus
Plan) applicable to eligible employees, including
Messrs. Joyce, McParland, Perkins and Heim, that provided
these named executive officers certain benefits upon a Change of
Control. In addition, on July 12, 2006, in order to ensure
managerial transition in the face of a potential transaction,
the TRII Compensation Committee approved the Targa Investments
Change of Control Executive Officer Severance Program (the
TRII Severance Program) in which all of our named
executive officers were participants.
Bonus Agreements. Under the Bonus Agreements,
following a Change of Control or a death or disability, our
named executive officers were entitled to receive the following
lump sum cash bonus amounts: Mr. Heim-$717,537;
Mr. Joyce-$717,537; Mr. McParland-$574,028;
Mr. Perkins-$717,537; and Mr. Whalen-$21,802.
Change of Control Bonus Plan. The Change of
Control Bonus Plan provided a lump sum cash bonus payment in
case there was a Change of Control or the plan was terminated.
The bonus pool would have been $2 million if the weighted
average sale price with respect to Targa Investments
preferred stock sold by Warburg Pincus between November 1,
2005 and the change of control was equal to or greater than $100
per share. The bonus pool would have been $0 if the weighted
average sale price was equal to or less than $72.31 per
share. The bonus pool would have been a prorated amount between
$0 and $2 million if the weighted average sale price was
between $72.31 and $100 per share.
TRII Severance Program. This program provided
separation benefits to our executive officers who voluntarily
terminated their employment or whose employment was terminated
in connection with a change of control of Targa. In such event,
executive officers would have received a lump sum cash payment,
subsidized medical coverage for up to two years and minimal
transition assistance. The lump sum cash payment would have been
paid in an amount equal to (i) two multiplied by fifty
percent of the executive officers annual base pay in
effect on the date immediately preceding the change of control,
multiplied by (ii) a fraction, the numerator of which was
the number of days during the period beginning on the first day
of such fiscal year and ending on the date of such termination,
and the denominator of which was three hundred sixty-five.
Termination
of Change in Control and Termination Benefits
In connection with Targa Investments entry into a credit
facility in August 2007, which funded a distribution to Targa
Investments investors, the Targa Board elected to
terminate the Bonus Agreements and the Change of Control Bonus
Plan and to trigger the payments due under the agreements and
plan. The TRII Severance Program was terminated without any
payments to the named executive officers when the Targa
Investments Board determined the need to ensure managerial
transition in the case of a Change of Control was no longer
necessary. As a result, no payments would have been made to the
named executive officers under the Bonus Agreements, the Change
of Control Bonus Plan and the TRII Severance Program if a change
of control occurred or their employment was terminated in
connection therewith as of December 31, 2007.
Director
Compensation
The following table sets forth the compensation earned by our
non-employee directors for 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees Earned
|
|
|
|
|
|
|
|
|
or Paid
|
|
Stock
|
|
All Other
|
|
Total
|
|
|
in Cash
|
|
Awards ($)(1)
|
|
Compensation(4)
|
|
Compensation
|
|
Robert B. Evans(2)(3)
|
|
$
|
76,000
|
|
|
$
|
22,250
|
|
|
$
|
1,688
|
|
|
$
|
99,938
|
|
Chansoo Joung(2)(3)
|
|
|
46,000
|
|
|
|
22,250
|
|
|
|
1,688
|
|
|
|
69,938
|
|
Peter R. Kagan(2)(3)
|
|
|
47,500
|
|
|
|
22,250
|
|
|
|
1,688
|
|
|
|
71,438
|
|
Barry R. Pearl(2)(3)
|
|
|
96,000
|
|
|
|
22,250
|
|
|
|
1,688
|
|
|
|
119,938
|
|
William D. Sullivan(2)(3)
|
|
|
74,500
|
|
|
|
22,250
|
|
|
|
1,688
|
|
|
|
98,438
|
|
|
|
|
|
(1)
|
The amounts reported reflect the aggregate dollar amounts
recognized for stock awards for financial statement reporting
purposes with respect to fiscal year 2007 (disregarding any
estimate of forfeitures related to service-based vesting
conditions). No stock awards granted to the directors were
forfeited
|
97
|
|
|
|
|
during 2007. For a discussion of the assumptions and
methodologies used to value the awards reported in these
columns, please see the discussion of stock awards contained in
the Notes to Consolidated Financial Statements at Note 11
included in this annual report.
|
|
|
|
|
(2)
|
Messrs. Evans, Joung, Kagan, Pearl and Sullivan each
received 2,000 common units of the Partnership on
February 14, 2007 in connection with their service on the
Board of Directors of the Partnerships general partner.
The grant date fair value of the 2,000 common units granted to
each of these named individuals was $42,000, based on the
initial public offering price of the common units. During 2007,
Messrs. Joung and Kagan each received $1,690 in
distributions on the common units of the Partnership that were
awarded to them. The Partnership also recognized $22,500 of
expense for each of the stock awards held by them.
|
|
|
(3)
|
At December 31, 2007, Mr. Evans held 3,900 common
units, Mr. Joung and Kagan each held 2,000 common units,
Mr. Pearl held 4,300 common units and Mr. Sullivan
held 6,700 common units of the Partnership.
|
|
|
(4)
|
For 2007 All Other Compensation consists of the
dividends paid on common units of the Partnership from unit
awards.
|
Narrative
to Director Compensation Table
In response to market developments identified by Apogee, a
compensation consultant, the Board approved changes to director
compensation for the 2007 fiscal year. For 2007, each
independent director receives an annual cash retainer of $34,000
and the chairman of the Audit Committee receives an additional
annual retainer of $20,000. All of our independent directors
receive $1,500 for each Audit Committee and Conflicts Committee
meeting attended. No additional fees are paid for attending
board meetings. Payment of independent director fees is
generally made twice annually, at the second regularly scheduled
meeting of the Board and the final meeting of the Board for the
fiscal year. All independent directors are reimbursed for
out-of-pocket expenses incurred in attending Board and committee
meetings.
A director who is also an employee receives no additional
compensation for services as a director. Accordingly, the
Summary Compensation Table reflects total compensation received
by Messrs. Joyce and Whalen for services performed for us
and our affiliates.
Director Long-term Equity Incentives. The
Partnership made equity-based awards in February 2007 in
connection with its initial public offering to the General
Partners nonmanagement and independent directors under the
Partnerships long-term incentive plan. These awards were
determined by Targa Investments and approved by the Board. Each
of these directors received an initial award of 2,000 restricted
units, which will settle with the delivery of Partnership common
units. The Partnership has made similar grants under its
long-term incentive plan to Targas independent directors.
All of these awards are subject to three year vesting, without a
performance condition, and vest ratably on each anniversary of
the grant. The awards are intended to align the long-term
interests of executive officers and directors of the General
Partner with those of the Partnerships unitholders. The
independent and non-management directors of the General Partner
and the independent directors of Targa Investments currently
participate in the Partnerships plan.
Changes
for 2008
Director Long-term Equity Incentives. In March
2008, each of the General Partners nonmanagement and
independent directors received an award of 2,000 restricted
units under the Partnerships long-term incentive plan,
which will settle with the delivery of Partnership common units.
The Partnership has made similar grants under its long-term
incentive plan to Targas independent directors.
98
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
The following table sets forth the beneficial ownership of our
units as of March 25, 2008 held by:
|
|
|
|
|
each person who then beneficially owns 5% or more of the then
outstanding units;
|
|
|
|
all of the directors of Targa Resources GP LLC;
|
|
|
|
each named executive officer of Targa Resources GP LLC; and
|
|
|
|
all directors and officers of Targa Resources GP LLC as a group.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Targa Resources Partners LP
|
|
|
Targa Resources Investments Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
Percentage
|
|
|
|
|
|
|
Percentage
|
|
|
|
|
|
Percentage
|
|
|
of Total
|
|
|
|
|
|
|
|
|
of
|
|
|
of
|
|
|
|
|
|
|
of
|
|
|
|
|
|
of
|
|
|
Common and
|
|
|
|
|
|
|
|
|
Series B
|
|
|
Restricted
|
|
|
|
Common
|
|
|
Common
|
|
|
Subordinated
|
|
|
Subordinated
|
|
|
Subordinated
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Common
|
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
Series B
|
|
|
Restricted
|
|
|
Stock
|
|
|
Stock
|
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Preferred
|
|
|
Common
|
|
|
Beneficially
|
|
|
Beneficially
|
|
Name of Beneficial Owner(1)
|
|
Owned
|
|
|
Owned
|
|
|
Owned(6)
|
|
|
Owned
|
|
|
Owned
|
|
|
Stock
|
|
|
Stock
|
|
|
Owned
|
|
|
Owned
|
|
|
Targa Resources Investments Inc.(2)
|
|
|
|
|
|
|
*
|
|
|
|
11,528,231
|
|
|
|
100
|
%
|
|
|
24.96
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lehman Brother Holdings Inc.(3)
|
|
|
2,619,219
|
|
|
|
7.56
|
%
|
|
|
|
|
|
|
|
|
|
|
5.67
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LaBranche Structured Products LLC(4)
|
|
|
2,510,920
|
|
|
|
7.25
|
%
|
|
|
|
|
|
|
|
|
|
|
5.44
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rene R. Joyce
|
|
|
20,000
|
|
|
|
*
|
|
|
|
285,364
|
|
|
|
2.48
|
%
|
|
|
*
|
|
|
|
56,208
|
|
|
|
1,217,212
|
(7)
|
|
|
*
|
|
|
|
15.6
|
%
|
Joe Bob Perkins
|
|
|
7,100
|
|
|
|
*
|
|
|
|
240,509
|
|
|
|
2.09
|
%
|
|
|
*
|
|
|
|
47,632
|
|
|
|
1,021,798
|
(8)
|
|
|
*
|
|
|
|
13.2
|
%
|
Michael A. Heim
|
|
|
2,500
|
|
|
|
*
|
|
|
|
226,959
|
|
|
|
1.97
|
%
|
|
|
*
|
|
|
|
39,192
|
|
|
|
1,021,798
|
(9)
|
|
|
*
|
|
|
|
13.2
|
%
|
Jeffrey J. McParland
|
|
|
1,500
|
|
|
|
*
|
|
|
|
201,663
|
|
|
|
1.75
|
%
|
|
|
*
|
|
|
|
32,856
|
|
|
|
927,197
|
(10)
|
|
|
*
|
|
|
|
12.1
|
%
|
James W. Whalen
|
|
|
36,152
|
|
|
|
*
|
|
|
|
151,131
|
|
|
|
1.31
|
%
|
|
|
*
|
|
|
|
14,978
|
|
|
|
790,742
|
(11)
|
|
|
*
|
|
|
|
10.3
|
%
|
Peter R. Kagan(5)
|
|
|
4,000
|
|
|
|
*
|
|
|
|
|
|
|
|
*
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Chansoo Joung(5)
|
|
|
4,000
|
|
|
|
*
|
|
|
|
|
|
|
|
*
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Robert B. Evans
|
|
|
5,900
|
|
|
|
*
|
|
|
|
|
|
|
|
*
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Barry R. Pearl
|
|
|
6,300
|
|
|
|
*
|
|
|
|
|
|
|
|
*
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
William D. Sullivan
|
|
|
8,700
|
|
|
|
*
|
|
|
|
|
|
|
|
*
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
All directors and executive officers as a group (12 persons)
|
|
|
96,152
|
|
|
|
*
|
|
|
|
1,478,208
|
|
|
|
12.82
|
%
|
|
|
3.41
|
%
|
|
|
241,114
|
|
|
|
6,795,333
|
|
|
|
3.8
|
%
|
|
|
71.5
|
%
|
|
|
|
|
(1)
|
Unless otherwise indicated, the address for all beneficial
owners in this table is 1000 Louisiana, Suite 4300,
Houston, Texas 77002. The nature of the beneficial ownership for
all the units is sole voting and investment power.
|
|
|
(2)
|
The units attributed to Targa Resources Investments Inc. are
held by two indirect wholly-owned subsidiaries, Targa GP Inc.
and Targa LP Inc.
|
|
|
(3)
|
Lehman Brothers Holdings Inc. beneficially owns 1,775,219 common
units, of which Lehman Brothers Inc. beneficially owns 1,295,919
common units (which includes 805,919 common units directly held
by Lehman Brothers Inc. and 490,000 common units directly held
by Lehman Brothers MLP Partners LP) and Lehman Brothers MLP
Opportunity Fund LP beneficially owns 479,300 common units.
Lehman Brothers Inc. is wholly-owned by Lehman Brothers Holdings
Inc. The address for Lehman Brothers Holdings Inc. and its
affiliates is 745 Seventh Avenue, New York, NY 10019.
|
|
|
(4)
|
LaBranche Structured Products LLC beneficially owns 2,510,920
common units. The address for LaBranche Structured Products LLC
is 33 Whitehall Street, New York, N.Y. 10004.
|
|
|
(5)
|
Warburg Pincus Private Equity VIII, L.P. (WP VIII)
and Warburg Pincus Private Equity IX, L.P. (WP IX)
in the aggregate beneficially own 73.6% of Targa Resources
Investments Inc. The general partner of WP VIII is Warburg
Pincus Partners, LLC (WP Partners LLC) and the
general partner of WP IX is Warburg Pincus IX, LLC, of which WP
Partners LLC is sole member. Warburg Pincus & Co.
(WP) is the managing member of WP Partners LLC. WP
VIII and WP IX are managed by Warburg Pincus LLC (WP
LLC). The address of the Warburg Pincus entities is 466
Lexington Avenue, New York, New York 10017. Chansoo Joung and
Peter R. Kagan, two of our directors, are each a general partner
of WP and a Managing Director and Member of WP LLC.
|
99
|
|
|
|
|
Charles R. Kaye and Joseph P. Landy are each Managing General
Partners of WP and Co-Presidents and Managing Members of WP LLC
and may be deemed to control the Warburg Pincus entities.
Messrs. Joung, Kagan, Kaye and Landy disclaim beneficial
ownership of all shares held by the Warburg Pincus entities.
|
|
|
|
|
(6)
|
The subordinated units presented as being beneficially owned by
the directors and executive officers of Targa Resources GP LLC
represent the number of units held indirectly by Targa Resources
Investments Inc. that are attributable to such directors and
officers based on their ownership of equity interests in Targa
Resources Investments Inc.
|
|
|
(7)
|
Of this amount, 391,787 shares of restricted common stock
reflect options that are currently exercisable for shares of
restricted common stock.
|
|
|
(8)
|
Of this amount, 320,244 shares of restricted common stock
reflect options that are currently exercisable for shares of
restricted common stock.
|
|
|
(9)
|
Of this amount, 297,650 shares of restricted common stock
reflect options that are currently exercisable for shares of
restricted common stock.
|
|
|
|
|
(10)
|
Of this amount, 254,356 shares of restricted common stock
reflect options that are currently exercisable for shares of
restricted common stock.
|
|
|
(11)
|
Of this amount, 52,213 shares of restricted common stock
reflect options that are currently exercisable for shares of
restricted common stock.
|
100
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Our general partner and its affiliates own 11,528,231
subordinated units representing an aggregate 24.5% 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
made by us to our general partner and its affiliates in
connection with the formation of the Partnership and to be made
to us by our general partner and its affiliates in connection
with the 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.
Operational
Stage
|
|
|
Distributions of available cash to our general partner and its
affiliates
|
|
We will generally make cash distributions 98% to our limited
partner unitholders pro rata, including our general partner and
its affiliates, as the holders of 11,528,231 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 above the highest target distribution level.
|
|
|
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 $1.3 million on
their general partner units and $15.6 million on their
subordinated units.
|
Payments to our general partner and its affiliates
|
|
We reimburse Targa for the payment of certain operating expenses
and for the provision of various general and administrative
services for our benefit. Please see Omnibus
Agreement Reimbursement of Operating and General and
Administrative Expense.
|
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.
|
Liquidation
Stage
|
|
|
Liquidation
|
|
Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their respective capital account balances.
|
101
Agreements
Governing the Transactions
We and other parties entered into the various documents and
agreements that effected our initial IPO transactions in
February 2007 and the October 2007 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 the IPO and the October 2007 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 they could have
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 the IPO and the
October 2007 offering.
Purchase
and Sale Agreement
On September 18, 2007, we entered into a purchase and sale
agreement (the Purchase Agreement) with Targa
pursuant to which we acquired the SAOU and LOU Systems for
aggregate consideration of $705 million, subject to certain
adjustments, consisting of $697.6 million in cash and the
issuance to our general partner of 275,511 general partner
units, enabling our general partner to maintain its general
partner interest in us. On September 25 and 26, 2007, Targa
completed transactions that terminated certain out of the money
NGL hedges associated with the SAOU and LOU Systems and entered
into new hedges for approximately the same volume and term at
then current market prices. Pursuant to the Purchase Agreement,
these hedging transactions resulted in a $24.2 million
increase to the purchase price we paid to Targa for the SAOU and
LOU Systems. Pursuant to the Purchase Agreement, Targa agreed to
indemnify us from and against (i) all losses that we incur
arising from any breach of Targas representations,
warranties or covenants in the Purchase Agreement,
(ii) certain environmental matters and (iii) certain
litigation matters. We agreed to indemnify Targa from and
against all losses that it incurs arising from or out of
(i) the business or operations of Targa Resources Texas GP
LLC, Targa Texas, Targa Louisiana and Targa Louisiana Intrastate
LLC (whether relating to periods prior to or after the closing
of the acquisition of the SAOU and LOU Systems) to the extent
such losses are not matters for which Targa has indemnified us
or (ii) any breach of our representations, warranties or
covenants in the Purchase Agreement. Certain of Targas
indemnification obligations are subject to an aggregate
deductible of $10 million and a cap equal to
$80 million. In addition, the parties reciprocal
indemnification obligations for certain tax liability and losses
are not subject to the deductible and cap. The acquisition
closed on October 24, 2007
On November 20, 2007, after the underwriters of the October
2007 offering exercised their option to purchase additional
shares, we settled with Targa their purchase of an additional
37,062 general partner units allowing Targa to maintain its 2%
general partner interest in us. In December 2007, the
adjustments to the purchase price of the SAOU and LOU Systems
resulted in an additional $0.8 million being paid to Targa.
Omnibus
Agreement
Concurrently with the closing of the acquisition of the SAOU and
LOU Systems, we amended and restated our Omnibus Agreement (as
amended and restated, the Omnibus Agreement) with
Targa, our general partner and others that addresses the
reimbursement of our general partner for costs incurred on our
behalf, competition and indemnification matters. Any or all of
the provisions of the Omnibus Agreement, other than the
indemnification provisions described below, are terminable by
Targa at its option if our general partner is removed without
cause and units held by our general partner and its affiliates
are not voted in favor of that removal. The Omnibus Agreement
will also terminate in the event of a change of control of us or
our general partner.
Reimbursement
of Operating and General and Administrative
Expense
Under the terms of the Omnibus Agreement, we reimburse Targa for
the payment of certain operating expenses, including
compensation and benefits of operating personnel, and for the
provision of various general
102
and administrative services for our benefit. With respect to the
North Texas System, we reimburse Targa for the following
expenses:
|
|
|
|
|
general and administrative expenses, which are capped at
$5 million annually for three years, subject to increases
based on increases in the Consumer Price Index and subject to
further increases in connection with expansions of our
operations through the acquisition or construction of new assets
or businesses with the concurrence of our conflicts committee;
thereafter, our general partner will determine the general and
administrative expenses to be allocated to us in accordance with
our partnership agreement; and
|
|
|
|
operations and certain direct expenses, which are not subject to
the $5 million cap for general and administrative expenses.
|
With respect to the SAOU and LOU Systems, we will reimburse
Targa for the following expenses:
|
|
|
|
|
general and administrative expenses, which are not capped,
allocated to the SAOU and LOU Systems according to Targas
allocation practice; and
|
|
|
|
operating and certain direct expenses, which are not capped.
|
Pursuant to these arrangements, Targa performs centralized
corporate functions for us, such as legal, accounting, treasury,
insurance, risk management, health, safety and environmental,
information technology, human resources, credit, payroll,
internal audit, taxes, engineering and marketing. We reimburse
Targa for the direct expenses to provide these services as well
as other direct expenses it incurs on our behalf, such as
compensation of operational personnel performing services for
our benefit and the cost of their employee benefits, including
401(k), pension and health insurance benefits.
General and administrative costs will continue to be allocated
to the SAOU and LOU Systems according to Targas allocation
practice.
Competition
Targa is not restricted, under either our partnership agreement
or the Omnibus Agreement, from competing with us. Targa may
acquire, construct or dispose of additional midstream energy or
other assets in the future without any obligation to offer us
the opportunity to purchase or construct those assets.
Indemnification
Under the Omnibus Agreement, Targa indemnifies us until
February 14, 2010 against certain potential environmental
claims, losses and expenses associated with the operation of the
North Texas System and occurring before February 14, 2007
that are not reserved on the books of the Predecessor Business
of the North Texas System as of February 14, 2007.
Targas maximum liability for this indemnification
obligation does not exceed $10.0 million and Targa does not
have any obligation under this indemnification until our
aggregate losses exceed $250,000. We have agreed to indemnify
Targa against environmental liabilities related to the North
Texas System arising or occurring after the closing date of this
offering.
Additionally, Targa indemnifies us for losses attributable to
rights-of-way, certain consents or governmental permits,
preclosing litigation relating to the North Texas System and
income taxes attributable to pre-IPO operations that are not
reserved on the books of the Predecessor Business of the North
Texas System as of February 14, 2007. Targa does not have
any obligation under these indemnifications until our aggregate
losses exceed $250,000. We will indemnify Targa for all losses
attributable to the post-IPO operations of the North Texas
System. Targas obligations under this additional
indemnification survive until February 14, 2010, except
that the indemnification for income tax liabilities will
terminate upon the expiration of the applicable statute of
limitations.
103
Contracts
with Affiliates
NGL and Condensate Purchase Agreement for the North Texas
System. We have entered into an NGL and high
pressure condensate purchase agreement pursuant to which
(i) we are obligated to sell all volumes of NGLs (other
than high-pressure condensate) that we own or control to Targa
Liquids Marketing and Trade (TLMT) and (ii) we
have the right to sell to TLMT or third parties the volumes of
high-pressure condensate that we own or control, in each case at
a price based on the prevailing market price less
transportation, fractionation and certain other fees. This
agreement has an initial term of 15 years and automatically
extends for a term of five years, unless the agreement is
otherwise terminated by either party. Furthermore, either party
may elect to terminate the agreement if either party ceases to
be an affiliate of Targa.
NGL Purchase Agreements for the SAOU and LOU
Systems. The SAOU System has entered into an NGL
purchase agreement pursuant to which it is obligated to sell all
volumes of mixed NGLs, or raw product, that it owns or controls
to TLMT at a price based on either TLMTs sales price to
third parties or the prevailing market price, less
transportation, fractionation and certain other fees. The LOU
System also has entered into an NGL purchase agreement pursuant
to which (i) it has the right to sell to TLMT the volumes
of raw product that it owns or controls at a commercially
reasonable price agreed by the parties, and (ii) it is
obligated to sell all volumes of fractionated NGL components
that it owns or controls at a price based on TLMTs sales
price to third parties or the prevailing market price, less
transportation, fractionation and certain other fees. Both NGL
purchase agreements have an initial term of one year and
automatically extend for additional terms of one year, unless
the agreements are otherwise terminated by either party.
Natural Gas Purchase Agreements. Both the
North Texas System and the SAOU and LOU Systems have entered
into natural gas purchase agreements at a price based on Targa
Gas Marketing LLCs (TGM) sale price for such
natural gas, less TGMs costs and expenses associated
therewith. These agreements have an initial term of
15 years and automatically extend for a term of five years,
unless the agreements are otherwise terminated by either party.
Furthermore, either party may elect to terminate the agreements
if either party ceases to be an affiliate of Targa. In addition,
Targa manages the SAOU and LOU Systems natural gas sales
to third parties under contracts that remain in the name of the
SAOU and LOU Systems.
Indemnification Agreements. In February 2007,
Targa Resources GP LLC, our general partner, and the Partnership
entered into Indemnification Agreements (each, an
Indemnification Agreement) with each independent
director of Targa Resources GP LLC (each, an
Indemnitee). Each Indemnification Agreement provides
that each of the Partnership and Targa Resources GP LLC will
indemnify and hold harmless each Indemnitee against Expenses (as
defined in the Indemnification Agreement) to the fullest extent
permitted or authorized by law, including the Delaware Revised
Uniform Limited Partnership Act and the Delaware Limited
Liability Company Act in effect on the date of the agreement or
as such laws may be amended to provide more advantageous rights
to the Indemnitee. If such indemnification is unavailable as a
result of a court decision and if the Partnership or Targa
Resources GP LLC is jointly liable in the proceeding with the
Indemnitee, the Partnership and Targa Resources GP LLC will
contribute funds to the Indemnitee for his Expenses in
proportion to relative benefit and fault of the Partnership or
Targa Resources GP LLC on the one hand and Indemnitee on the
other in the transaction giving rise to the proceeding.
Each Indemnification Agreement also provides that each of the
Partnership and Targa Resources GP LLC will indemnify and hold
harmless the Indemnitee against Expenses incurred for actions
taken as a director or officer of the Partnership or Targa
Resources GP LLC, or for serving at the request of the
Partnership or Targa Resources GP LLC as a director or officer
or another position at another corporation or enterprise, as the
case may be, but only if no final and non-appealable judgment
has been entered by a court determining that, in respect of the
matter for which the Indemnitee is seeking indemnification, the
Indemnitee acted in bad faith or engaged in fraud or willful
misconduct or, in the case of a criminal proceeding, the
Indemnitee acted with knowledge that the Indemnitees
conduct was unlawful. The Indemnification Agreement also
provides that the Partnership and Targa Resources GP LLC must
advance payment of certain Expenses to the Indemnitee, including
fees of counsel, subject to receipt of an undertaking from the
Indemnitee to return such advance if it is it is ultimately
determined that the Indemnitee is not entitled to
indemnification.
104
In February 2007, Targa Resources Investments Inc., the indirect
holder of all of our subordinated units, entered into
Indemnification Agreements (each, a Parent Indemnification
Agreement) with each director and officer of Targa (each,
a Parent Indemnitee), including Messrs. Joyce,
Whalen, Kagan and Joung who serve as directors
and/or
officers of our general partner. Each Parent Indemnification
Agreement provides that Targa Resources Investments Inc. will
indemnify and hold harmless each Parent Indemnitee for Expenses
(as defined in the Parent Indemnification Agreement) to the
fullest extent permitted or authorized by law, including the
Delaware General Corporation Law, in effect on the date of the
agreement or as it may be amended to provide more advantageous
rights to the Parent Indemnitee. If such indemnification is
unavailable as a result of a court decision and if Targa
Resources Investments Inc. and the Parent Indemnitee are jointly
liable in the proceeding, Targa Resources Investments Inc. will
contribute funds to the Parent Indemnitee for his Expenses in
proportion to relative benefit and fault of Targa Resources
Investments Inc. and Parent Indemnitee in the transaction giving
rise to the proceeding.
Each Indemnification Agreement also provides that Targa
Resources Investments Inc. will indemnify the Parent Indemnitee
for monetary damages for actions taken as a director or officer
of Targa Resources Investments Inc., or for serving at
Targas request as a director or officer or another
position at another corporation or enterprise, as the case may
be but only if (i) the Parent Indemnitee acted in good
faith and, in the case of conduct in his official capacity, in a
manner he reasonably believed to be in the best interests of
Targa Resources Investments Inc. and, in all other cases, not
opposed to the best interests of Targa Resources Investments
Inc. and (ii) in the case of a criminal proceeding, the
Parent Indemnitee must have had no reasonable cause to believe
that his conduct was unlawful. The Parent Indemnification
Agreement also provides that Targa Resources Investments Inc.
must advance payment of certain Expenses to the Parent
Indemnitee, including fees of counsel, subject to receipt of an
undertaking from the Parent Indemnitee to return such advance if
it is it is ultimately determined that the Parent Indemnitee is
not entitled to indemnification.
Conflicts
of Interest
Conflicts of interest exist and may arise in the future as a
result of the relationships between our general partner and its
affiliates (including Targa) on the one hand, and our
partnership and our limited partners, on the other hand. The
directors and officers of Targa Resources GP LLC have fiduciary
duties to manage Targa and our general partner in a manner
beneficial to its owners. At the same time, our general partner
has a fiduciary duty to manage our partnership in a manner
beneficial to us and our unitholders.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us or any other partner, on the
other hand, our general partner will resolve that conflict. Our
partnership agreement contains provisions that modify and limit
our general partners fiduciary duties to our unitholders.
Our partnership agreement also restricts the remedies available
to unitholders for actions taken that, without those
limitations, might constitute breaches of fiduciary duty.
Our general partner will not be in breach of its obligations
under the partnership agreement or its duties to us or our
unitholders if the resolution of the conflict is:
|
|
|
|
|
approved by the conflicts committee, although our general
partner is not obligated to seek such approval;
|
|
|
|
approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
or any of its affiliates;
|
|
|
|
on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
|
|
|
|
fair and reasonable to us, taking into account the totality of
the relationships among the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
|
Our general partner may, but is not required to, seek the
approval of such resolution from the conflicts committee of its
board of directors. If our general partner does not seek
approval from the conflicts committee
105
and its board of directors determines that the resolution or
course of action taken with respect to the conflict of interest
satisfies either of the standards set forth in the third or
fourth bullet points above, then it will be presumed that, in
making its decision, the board of directors acted in good faith,
and in any proceeding brought by or on behalf of any limited
partner or the partnership, the person bringing or prosecuting
such proceeding will have the burden of overcoming such
presumption. Unless the resolution of a conflict is specifically
provided for in our partnership agreement, our general partner
or the conflicts committee may consider any factors it
determines in good faith to consider when resolving a conflict.
When our partnership agreement provides that someone act in good
faith, it requires that person to believe he is acting in the
best interests of the partnership.
|
|
Item 14.
|
Principal
Accountant Fees and Services
|
We have engaged PricewaterhouseCoopers LLP as our principal
accountant. The following table summarizes fees we have paid
PricewaterhouseCoopers for independent auditing, tax and related
services for each of the last two fiscal years (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Audit Fees(1)
|
|
$
|
2,224.7
|
|
|
$
|
820.7
|
|
Audit-Related Fees(2)
|
|
|
|
|
|
|
|
|
Tax Fees(3)
|
|
|
177.4
|
|
|
|
|
|
All Other Fees(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Audit fees represent amounts billed for each of the years
presented for professional services rendered in connection with
(i) the audit of our annual financial statements,
(ii) the review of our quarterly financial statements or
(iii) those services normally provided in connection with
statutory and regulatory filings or engagements including
comfort letters, consents and other services related to SEC
matters. This information is presented as of the latest
practicable date for this annual report on
Form 10-K.
|
|
|
(2)
|
Audit-related fees represent amounts we were billed in each of
the years presented for assurance and related services that are
reasonably related to the performance of the annual audit or
quarterly reviews. This category primarily includes services
relating to internal control assessments and accounting-related
consulting.
|
|
|
(3)
|
Tax fees represent amounts we were billed in each of the years
presented for professional services rendered in connection with
tax compliance, tax advice, and tax planning. This category
primarily includes services relating to the preparation of
unitholder annual K-1 statements.
|
|
|
(4)
|
All other fees represent amounts we were billed in each of the
years presented for services not classifiable under the other
categories listed in the table above. No such services were
rendered by PricewaterhouseCoopers during the last two years.
|
All services provided by our independent auditor are subject to
pre-approval by our audit committee. The Audit Committee is
informed of each engagement of the independent auditor to
provide services under the policy. The Audit Committee of our
general partner has approved the use of PricewaterhouseCoopers
as our independent principal accountant.
106
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules
|
(a)(1) Financial Statements
Our consolidated financial statements are included under
Part II, Item 8 of this annual report. For a listing
of these statements and accompanying footnotes, please see
Index to Financial Statements on
page F-1
of this annual report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not
applicable, not required or the information called for therein
appears in the consolidated financial statements or notes
thereto.
(a)(3) Exhibits
|
|
|
|
|
|
|
|
2
|
.1**
|
|
|
|
Purchase and Sale Agreement, dated as of September 18,
2007, by and between Targa Resources Holdings LP and Targa
Resources Partners LP (incorporated by reference to
Exhibit 2.1 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed September 21, 2007 (File
No. 001-33303)).
|
|
2
|
.2
|
|
|
|
Amendment to Purchase and Sale Agreement, dated October 1,
2007, by and between Targa Resources Holdings LP and Targa
Resources Partners LP (incorporated by reference to
Exhibit 2.2 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
3
|
.1
|
|
|
|
Certificate of Limited Partnership of Targa Resources Partners
LP (incorporated by reference to Exhibit 3.2 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed November 16, 2006 (File
No. 333-138747)).
|
|
3
|
.2
|
|
|
|
Certificate of Formation of Targa Resources GP LLC (incorporated
by reference to Exhibit 3.3 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed January 19, 2007 (File
No. 333-138747)).
|
|
3
|
.3
|
|
|
|
Agreement of Limited Partnership of Targa Resources Partners LP
(incorporated by reference to Exhibit 3.3 to Targa
Resources Partners LPs Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
3
|
.4
|
|
|
|
First Amended and Restated Agreement of Limited Partnership of
Targa Resources Partners LP (incorporated by reference to
Exhibit 3.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed February 16, 2007 (File
No. 001-33303)).
|
|
3
|
.5
|
|
|
|
Limited Liability Company Agreement of Targa Resources GP LLC
(incorporated by reference to Exhibit 3.4 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed January 19, 2007 (File
No. 333-138747)).
|
|
4
|
.1
|
|
|
|
Specimen Unit Certificate representing common units
(incorporated by reference to Exhibit 4.1 to Targa
Resources Partners LPs Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
10
|
.1
|
|
|
|
Credit Agreement, dated February 14, 2007, by and among
Targa Resources Partners LP, as Borrower, Bank of America, N.A.,
as Administrative Agent, Wachovia Bank, N.A., as Syndication
Agent, Merrill Lynch Capital, Royal Bank of Canada and The Royal
Bank of Scotland PLC, as Co-Documentation Agents, and the other
lenders party thereto (incorporated by reference to
Exhibit 10.1 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed February 16, 2007 (File
No. 001-33303)).
|
|
10
|
.2
|
|
|
|
Commitment Increase Supplement, dated October 24, 2007, by
and among Targa Resources Partners LP, Bank of America, N.A. and
the parties signatory thereto as the Increasing Lenders and the
New Lenders (incorporate by reference to Exhibit 10.2 to
Targa Resources Partners LPs Current Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
10
|
.3
|
|
|
|
First Amendment to Credit Agreement, dated October 24,
2007, by and among Targa Resources Partners LP, Bank of America,
N.A. and each Lender party thereto (incorporated by reference to
Exhibit 10.3 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
107
|
|
|
|
|
|
|
|
10
|
.4
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa
Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa
Regulated Holdings LLC, Targa North Texas GP LLC and Targa North
Texas LP (incorporated by reference to Exhibit 10.2 to
Targa Resources Partners LPs Current Report on
Form 8-K
filed February 16, 2007 (File
No. 001-33303)).
|
|
10
|
.5
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
October 24, 2007, by and among Targa Resources Partners LP,
Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa
LA LLC, Targa LA PS LP and Targa North Texas GP LLC
(incorporated by reference to Exhibit 10.4 to Targa
Resources Partners LPs Current Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
10
|
.6
|
|
|
|
Amended and Restated Omnibus Agreement, dated October 24,
2007, by and among Targa Resources Partners LP, Targa Resources,
Inc., Targa Resources LLC and Targa Resources GP LLC
(incorporated by reference to Exhibit 10.5 to Targa
Resources Partners LPs Current Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
10
|
.7+
|
|
|
|
Targa Resources Partners Long-Term Incentive Plan (incorporated
by reference to Exhibit 10.2 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed February 1, 2007 (File
No. 333-138747)).
|
|
10
|
.8+
|
|
|
|
Targa Resources Investments Inc. Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.9 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed February 1, 2007 (File
No. 333-138747)).
|
|
10
|
.9+
|
|
|
|
Form of Restricted Unit Grant Agreement (incorporated by
reference to Exhibit 10.2 to Targa Resources Partners
LPs Current Report on
Form 8-K
filed February 13, 2007 (File
No. 001-33303)).
|
|
10
|
.10+
|
|
|
|
Form of Performance Unit Grant Agreement (incorporated by
reference to Exhibit 10.2 to Targa Resources Partners
LPs Current Report on
Form 8-K
filed January 22, 2008 (File
No. 001-33303)).
|
|
10
|
.11
|
|
|
|
Gas Gathering and Purchase Agreement by and between Burlington
Resources Oil & Gas Company LP, Burlington Resources
Trading Inc. and Targa Midstream Services Limited Partnership
(portions of this exhibit have been omitted and filed separately
with the Securities and Exchange Commission pursuant to a
request for confidential treatment) (incorporated by reference
to Exhibit 10.5 to Targa Resources Partners LPs
Registration Statement on
Form S-1/A
filed February 8, 2007 (File
No. 333-138747)).
|
|
10
|
.12
|
|
|
|
Natural Gas Purchase Agreement, effective January 1, 2007,
by and between Targa Gas Marketing LLC (Buyer) and Targa North
Texas LP (Seller) (incorporated by reference to
Exhibit 10.11 to Targa Resources Partners LPs
Registration Statement on
Form S-1
filed October 1, 2007 (File
No. 333-146436)).
|
|
10
|
.13
|
|
|
|
NGL and Condensate Purchase Agreement, effective January 1,
2007, by and between Targa North Texas LP (Seller) and Targa
Liquids Marketing and Trade (Buyer) (incorporated by reference
to Exhibit 10.12 to Targa Resources Partners LPs
Registration Statement on
Form S-1
filed October 1, 2007 (File
No. 333-146436)).
|
|
10
|
.14
|
|
|
|
Product Purchase Agreement, effective January 1, 2007, by
and between Targa Louisiana Field Services LLC (Seller) and
Targa Liquids Marketing and Trade (Buyer) (incorporated by
reference to Exhibit 10.13 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.15
|
|
|
|
Raw Product Purchase Agreement, effective January 1, 2007,
by and between Targa Texas Field Services LP (Seller) and Targa
Liquids Marketing and Trade (Buyer) (incorporated by reference
to Exhibit 10.14 to Targa Resources Partners LPs
Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.16
|
|
|
|
Amended and Restated Natural Gas Sales Agreement, effective
December 1, 2005, by and between Targa Louisiana Field
Services LLC (Buyer) and Targa Gas Marketing LLC (Seller)
(incorporated by reference to Exhibit 10.15 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
108
|
|
|
|
|
|
|
|
10
|
.17
|
|
|
|
Amended and Restated Natural Gas Purchase Agreement, effective
December 1, 2005, by and between Targa Gas Marketing LLC
(Buyer) and Targa Louisiana Field Services LLC (Seller)
(incorporated by reference to Exhibit 10.16 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.18
|
|
|
|
Amended and Restated Natural Gas Purchase Agreement, effective
December 1, 2005, by and between Targa Gas Marketing LLC
(Buyer) and Targa Texas Field Services LP (Seller) (incorporated
by reference to Exhibit 10.17 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.19+
|
|
|
|
Targa Resources Partners LP Indemnification Agreement for Barry
R. Pearl dated February 14, 2007 (incorporated by reference
to Exhibit 10.11 to Targa Resources Partners LPs
Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
10
|
.20+
|
|
|
|
Targa Resources Partners LP Indemnification Agreement for Robert
B. Evans dated February 14, 2007 (incorporated by reference
to Exhibit 10.12 to Targa Resources Partners LPs
Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
10
|
.21+
|
|
|
|
Targa Resources Partners LP Indemnification Agreement for
Williams D. Sullivan dated February 14, 2007 (incorporated
by reference to Exhibit 10.13 to Targa Resources Partners
LPs Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
21
|
.1
|
|
|
|
Subsidiaries of Targa Resources Partners LP.*
|
|
23
|
.1
|
|
|
|
Consent of Independent Registered Public Accounting Firm*
|
|
31
|
.1
|
|
|
|
Certification of the Chief Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*
|
|
31
|
.2
|
|
|
|
Certification of the Chief Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*.
|
|
32
|
.1
|
|
|
|
Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.*
|
|
32
|
.2
|
|
|
|
Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.*
|
|
|
|
* |
|
Filed herewith |
|
** |
|
Pursuant to Item 601(b)(2) of
Regulation S-K,
the Partnership agrees to furnish supplementally a copy of any
omitted exhibit or Schedule to the SEC upon request. |
|
+ |
|
Management contract or compensatory plan or arrangement. |
109
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.
Targa Resources Partners LP
(Registrant)
By: Targa Resources GP LLC, its general partner
|
|
|
|
By:
|
/s/ John
Robert Sparger
|
John Robert Sparger
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
Date: March 31, 2008
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities indicated on
March 31, 2008.
|
|
|
|
|
Signature
|
|
Title (Position with Targa Resources GP LLC)
|
|
|
|
|
/s/ Rene
R. Joyce
Rene
R. Joyce
|
|
Chief Executive Officer and Director (Principal Executive
Officer)
|
|
|
|
/s/ Jeffrey
J. McParland
Jeffrey
J. McParland
|
|
Executive Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
|
|
|
/s/ John
Robert Sparger
John
Robert Sparger
|
|
Senior Vice President and Chief Accounting Officer (Principal
Accounting Officer)
|
|
|
|
/s/ James
W. Whalen
James
W. Whalen
|
|
President Finance and Administration and Director
|
|
|
|
/s/ Peter
R. Kagan
Peter
R. Kagan
|
|
Director
|
|
|
|
/s/ Chansoo
Joung
Chansoo
Joung
|
|
Director
|
|
|
|
/s/ Barry
R. Pearl
Barry
R. Pearl
|
|
Director
|
|
|
|
/s/ Robert
B. Evans
Robert
B. Evans
|
|
Director
|
|
|
|
/s/ William
D. Sullivan
William
D. Sullivan
|
|
Director
|
110
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
TARGA RESOURCES PARTNERS LP AUDITED COMBINED CONSOLIDATED
FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
|
|
|
F-8
|
|
F-1
Report of
Independent Registered Public Accounting Firm
To the Partners of Targa Resources Partners LP:
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of operations, of
comprehensive income (loss), of changes in partners
capital/net parent investment and of cash flows present fairly,
in all material respects, the financial position of Targa
Resources Partners LP and its subsidiaries (the
Partnership) at December 31, 2007 and 2006 and
the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2007 in
conformity with accounting principles generally accepted in the
United States of America. These financial statements are the
responsibility of the Partnerships management. Our
responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these
statements 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. An audit 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, and
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our
opinion.
As discussed in Note 7 to the consolidated financial
statements, the Partnership has engaged in significant
transactions with other subsidiaries of its parent company,
Targa Resources, Inc., a related party.
/s/ PricewaterhouseCoopers
LLP
Houston, Texas
March 26, 2008
F-2
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
50,994
|
|
|
$
|
|
|
Receivables from third parties
|
|
|
59,346
|
|
|
|
61,559
|
|
Receivables from affiliated companies
|
|
|
87,547
|
|
|
|
|
|
Inventory
|
|
|
1,624
|
|
|
|
958
|
|
Assets from risk management activities
|
|
|
8,695
|
|
|
|
25,683
|
|
Other
|
|
|
269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
208,475
|
|
|
|
88,200
|
|
Property, plant and equipment, at cost
|
|
|
1,433,955
|
|
|
|
1,391,644
|
|
Accumulated depreciation
|
|
|
(174,361
|
)
|
|
|
(103,073
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
1,259,594
|
|
|
|
1,288,571
|
|
Debt issue costs
|
|
|
6,588
|
|
|
|
|
|
Debt issue costs allocated from Parent
|
|
|
|
|
|
|
21,353
|
|
Long-term assets from risk management activities
|
|
|
3,040
|
|
|
|
15,851
|
|
Other long-term assets
|
|
|
2,275
|
|
|
|
2,396
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,479,972
|
|
|
$
|
1,416,371
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
5,693
|
|
|
$
|
3,773
|
|
Accrued liabilities
|
|
|
142,836
|
|
|
|
109,337
|
|
Current maturities of debt allocated from Parent
|
|
|
|
|
|
|
340,747
|
|
Liabilities from risk management activities
|
|
|
44,003
|
|
|
|
3,296
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
192,532
|
|
|
|
457,153
|
|
|
|
|
|
|
|
|
|
|
Long-term debt allocated from Parent
|
|
|
|
|
|
|
706,597
|
|
Long-term debt
|
|
|
626,300
|
|
|
|
|
|
Long-term liabilities from risk management activities
|
|
|
43,109
|
|
|
|
551
|
|
Other long-term liabilities
|
|
|
3,266
|
|
|
|
2,919
|
|
Deferred income tax liability
|
|
|
559
|
|
|
|
3,238
|
|
Commitments and contingencies (Note 11)
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
Common unitholders (34,636,000 units issued and outstanding
at
December 31, 2007)
|
|
|
770,207
|
|
|
|
|
|
Subordinated unitholders (11,528,231 units issued and
outstanding at December 31, 2007)
|
|
|
(84,999
|
)
|
|
|
|
|
General partner (942,128 units issued and outstanding at
December, 2007)
|
|
|
4,234
|
|
|
|
|
|
Accumulated other comprehensive income (loss)
|
|
|
(75,236
|
)
|
|
|
30,964
|
|
Net parent investment
|
|
|
|
|
|
|
214,949
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
614,206
|
|
|
|
245,913
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
1,479,972
|
|
|
$
|
1,416,371
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-3
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in thousands, except per unit amounts)
|
|
|
Revenues from third parties
|
|
$
|
630,773
|
|
|
$
|
951,936
|
|
|
$
|
1,110,911
|
|
Revenues from affiliates
|
|
|
1,030,696
|
|
|
|
786,589
|
|
|
|
61,539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,661,469
|
|
|
|
1,738,525
|
|
|
|
1,172,450
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
1,215,733
|
|
|
|
1,194,751
|
|
|
|
1,041,686
|
|
Product purchases from affiliates
|
|
|
191,064
|
|
|
|
322,917
|
|
|
|
19,998
|
|
Operating expenses
|
|
|
50,931
|
|
|
|
49,075
|
|
|
|
24,394
|
|
Depreciation and amortization expense
|
|
|
71,756
|
|
|
|
69,957
|
|
|
|
23,069
|
|
General and administrative expense
|
|
|
18,927
|
|
|
|
16,063
|
|
|
|
16,721
|
|
Other
|
|
|
(296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,548,115
|
|
|
|
1,652,763
|
|
|
|
1,125,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
113,354
|
|
|
|
85,762
|
|
|
|
46,582
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
21,998
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
19,436
|
|
|
|
88,025
|
|
|
|
21,177
|
|
Loss/(gain) on
mark-to-market
derivative contracts
|
|
|
30,221
|
|
|
|
(16,756
|
)
|
|
|
11,973
|
|
Loss on debt extinguishment
|
|
|
|
|
|
|
|
|
|
|
3,701
|
|
Other
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
41,729
|
|
|
|
14,493
|
|
|
|
9,731
|
|
Deferred income tax expense
|
|
|
1,479
|
|
|
|
2,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
40,250
|
|
|
$
|
11,567
|
|
|
$
|
9,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less net income (loss) attributable to predecessor operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the period January 1, 2007 to February 13, 2007
for North Texas
|
|
|
(6,861
|
)
|
|
|
|
|
|
|
|
|
For the period January 1, 2007 to October 23, 2007 for
SAOU/LOU
|
|
|
19,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
12,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocable to partners
|
|
|
28,066
|
|
|
|
|
|
|
|
|
|
General partner interest in net income for the period
|
|
|
561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common and subordinated unitholders
|
|
$
|
27,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common and subordinated unit
|
|
$
|
0.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common and subordinated unit
|
|
$
|
0.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic average number of common and subordinated units outstanding
|
|
|
33,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted average number of common and subordinated units
outstanding
|
|
|
33,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-4
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in thousands)
|
|
|
Net income
|
|
$
|
40,250
|
|
|
$
|
11,567
|
|
|
$
|
9,731
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of commodity hedges
|
|
|
(105,584
|
)
|
|
|
36,937
|
|
|
|
(16,870
|
)
|
Reclassification adjustment for settled periods
|
|
|
993
|
|
|
|
(822
|
)
|
|
|
10,436
|
|
Related income taxes
|
|
|
312
|
|
|
|
(312
|
)
|
|
|
|
|
Interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of interest rate swaps
|
|
|
(1,689
|
)
|
|
|
1,267
|
|
|
|
(120
|
)
|
Reclassification adjustment for settled periods
|
|
|
(232
|
)
|
|
|
(488
|
)
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
|
(106,200
|
)
|
|
|
36,582
|
|
|
|
(6,515
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(65,950
|
)
|
|
$
|
48,149
|
|
|
$
|
3,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-5
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
STATEMENT OF CHANGES IN PARTNERS
CAPITAL/NET PARENT INVESTMENT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Partners Capital
|
|
|
|
|
|
|
Net Parent
|
|
|
Comprehensive
|
|
|
Limited Partners
|
|
|
General
|
|
|
|
|
|
|
Investment
|
|
|
Income (Loss)
|
|
|
Common
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Total
|
|
|
|
(in thousands)
|
|
|
Balance at December 31, 2004
|
|
$
|
138,326
|
|
|
$
|
897
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
139,223
|
|
Initial contribution North Texas System
|
|
|
219,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
219,879
|
|
Distributions to Parent
|
|
|
(81,095
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(81,095
|
)
|
Net income
|
|
|
9,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,731
|
|
Other comprehensive loss
|
|
|
|
|
|
|
(6,515
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,515
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
|
286,841
|
|
|
|
(5,618
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
281,223
|
|
Distributions to Parent
|
|
|
(83,459
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(83,459
|
)
|
Net income
|
|
|
11,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,567
|
|
Other comprehensive income
|
|
|
|
|
|
|
36,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
214,949
|
|
|
|
30,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
245,913
|
|
Net income attributable to predecessor operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the period January 1, 2007 to February 13, 2007
for North Texas
|
|
|
(6,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,861
|
)
|
For the period January 1, 2007 to October 23, 2007
for SAOU/LOU
|
|
|
19,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,045
|
|
Net income attributable to post MLP ownership
|
|
|
|
|
|
|
|
|
|
|
19,063
|
|
|
|
8,442
|
|
|
|
561
|
|
|
|
28,066
|
|
Other contributions associated with North Texas System
|
|
|
218,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218,993
|
|
Other contributions associated with SAOU/LOU System
|
|
|
195,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
195,960
|
|
Book value of net assets contributed by
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Targa Resources, Inc. to the Partnership
|
|
|
(396,905
|
)
|
|
|
|
|
|
|
|
|
|
|
376,351
|
|
|
|
20,554
|
|
|
|
|
|
Book value of net assets transferred via common control from
Targa Resources, Inc. to the Partnership
|
|
|
(245,181
|
)
|
|
|
|
|
|
|
|
|
|
|
232,420
|
|
|
|
12,761
|
|
|
|
|
|
Distribution to Targa for assets transferred under common control
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(692,486
|
)
|
|
|
(37,416
|
)
|
|
|
(729,902
|
)
|
Issuance of units to public (including underwriter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
over-allotment), net of offering and other costs
|
|
|
|
|
|
|
|
|
|
|
771,835
|
|
|
|
|
|
|
|
8,398
|
|
|
|
780,233
|
|
Contribution of non-cash compensation
|
|
|
|
|
|
|
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
|
180
|
|
Other comprehensive loss
|
|
|
|
|
|
|
(106,200
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(106,200
|
)
|
Distributions to unitholders
|
|
|
|
|
|
|
|
|
|
|
(20,871
|
)
|
|
|
(9,726
|
)
|
|
|
(624
|
)
|
|
|
(31,221
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
$
|
|
|
|
$
|
(75,236
|
)
|
|
$
|
770,207
|
|
|
$
|
(84,999
|
)
|
|
$
|
4,234
|
|
|
$
|
614,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-6
TARGA
RESOURCES PARTNERS LP
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in thousands)
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40,250
|
|
|
$
|
11,567
|
|
|
$
|
9,731
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
71,632
|
|
|
|
69,832
|
|
|
|
22,945
|
|
Accretion of asset retirement obligations
|
|
|
342
|
|
|
|
245
|
|
|
|
94
|
|
Amortization of intangibles
|
|
|
124
|
|
|
|
125
|
|
|
|
124
|
|
Amortization of debt issue costs
|
|
|
1,805
|
|
|
|
6,246
|
|
|
|
4,723
|
|
Noncash compensation
|
|
|
180
|
|
|
|
|
|
|
|
|
|
Gain on sale of assets
|
|
|
(296
|
)
|
|
|
|
|
|
|
|
|
Deferred income tax expense
|
|
|
1,479
|
|
|
|
2,926
|
|
|
|
|
|
(Gain) loss on
mark-to-market
derivative contracts
|
|
|
30,221
|
|
|
|
(16,756
|
)
|
|
|
11,973
|
|
Risk management activities
|
|
|
530
|
|
|
|
(1,541
|
)
|
|
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
89,760
|
|
|
|
78,467
|
|
|
|
(61,826
|
)
|
Inventory
|
|
|
(666
|
)
|
|
|
1,373
|
|
|
|
(1,950
|
)
|
Other
|
|
|
(273
|
)
|
|
|
1,106
|
|
|
|
10
|
|
Accounts payable
|
|
|
1,920
|
|
|
|
(13,748
|
)
|
|
|
11,439
|
|
Accrued liabilities
|
|
|
33,472
|
|
|
|
(15,408
|
)
|
|
|
13,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
270,480
|
|
|
|
124,434
|
|
|
|
10,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of property, plant and equipment
|
|
|
(41,088
|
)
|
|
|
(32,575
|
)
|
|
|
(7,197
|
)
|
Other
|
|
|
372
|
|
|
|
(317
|
)
|
|
|
422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(40,716
|
)
|
|
|
(32,892
|
)
|
|
|
(6,775
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from equity offerings
|
|
|
777,471
|
|
|
|
|
|
|
|
|
|
Costs incurred in connection with public offerings
|
|
|
(4,640
|
)
|
|
|
|
|
|
|
|
|
Distributions to unit holders
|
|
|
(31,221
|
)
|
|
|
|
|
|
|
|
|
Proceeds from borrowings under credit facility
|
|
|
721,300
|
|
|
|
|
|
|
|
|
|
Costs incurred in connection with financing arrangements
|
|
|
(7,491
|
)
|
|
|
|
|
|
|
|
|
Repayments of loans:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated
|
|
|
(665,692
|
)
|
|
|
|
|
|
|
|
|
Credit facility
|
|
|
(95,000
|
)
|
|
|
|
|
|
|
|
|
Distributions to Parent
|
|
|
(873,497
|
)
|
|
|
(91,542
|
)
|
|
|
(3,742
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(178,770
|
)
|
|
|
(91,542
|
)
|
|
|
(3,742
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
50,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
50,994
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
15,453
|
|
|
$
|
|
|
|
$
|
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution of the North Texas System
|
|
|
|
|
|
|
|
|
|
|
219,879
|
|
Debt issue costs allocated from Parent
|
|
|
|
|
|
|
5,903
|
|
|
|
6,229
|
|
Long-term debt allocated from Parent
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowing
|
|
|
|
|
|
|
|
|
|
|
(227,106
|
)
|
Repayment
|
|
|
59,400
|
|
|
|
5,979
|
|
|
|
146,907
|
|
Net settlement of allocated indebtedness and debt issue costs
|
|
|
301,801
|
|
|
|
330
|
|
|
|
|
|
Net contribution of affiliated receivables
|
|
|
184,462
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
F-7
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1
|
Organization
and Operations
|
Targa Resources Partners LP (TRP LP) is a
growth-oriented Delaware limited partnership formed on
October 26, 2006 by Targa Resources, Inc.
(Targa or Parent), a leading provider of
midstream natural gas and NGL services in the United States, to
own, operate, acquire and develop a diversified portfolio of
complementary midstream energy assets. We are engaged in the
business of gathering, compressing, treating, processing and
selling natural gas and fractionating and selling natural gas
liquids (NGLs) and NGL products. We currently
operate in the Fort Worth Basin/Bend Arch in north Texas
(the Fort Worth Basin), the Permian Basin of
west Texas and in southwest Louisiana.
Initial
Public Offering
On February 14, 2007, Targa Resources Partners LP, together
with its subsidiaries (we, us,
our or the Partnership) completed its
initial public offering (IPO) of common units
representing limited partner interests in the Partnership. In
the IPO, we issued 19,320,000 common units at a price of $21.00
per unit. We used the net proceeds of the IPO (including
2,520,000 common units sold pursuant to the full exercise by the
underwriters of their option to purchase additional common
units) to pay expenses related to the IPO and our new credit
facility and to repay approximately $371.2 million of our
outstanding allocated indebtedness. Concurrent with the IPO,
Targa contributed its interest in Targa North Texas GP LLC and
Targa North Texas LP (collectively the North Texas
System) to us. Targa indirectly received a 2% general
partnership interest in us (629,555 general partner units),
incentive distribution rights, and a limited partnership
interest in us (represented by 11,528,231 subordinated units).
Our common units are listed on The NASDAQ Stock Market LLC under
the symbol NGLS.
Acquisition
of the SAOU and LOU Systems
On October 24, 2007, we completed the purchase from Targa
of its ownership interests in Targa Texas Field Services LP,
(the SAOU System), and Targa Louisiana Field
Services LLC (the LOU System). This acquisition
consisted of the SAOU Systems natural gas gathering and
processing businesses located in the Permian Basin of west Texas
and the LOU Systems natural gas gathering and processing
businesses located in southwest Louisiana. The total value of
the transaction was approximately $706 million. In
addition, we paid approximately $24.2 million to Targa for
the termination of certain hedge transactions. Concurrent with
our acquisition we sold 13,500,000 common units representing
limited partnership interests in us at a price of $26.87 per
common unit ($25.796 per common unit after the underwriting
discount). Total consideration paid by us to Targa consisted of
cash of approximately $722.5 million and 312,246 general
partner units issued to Targa to allow it to maintain its 2%
general partner interest in us.
On November 20, 2007, the underwriters exercised their
option to purchase an additional 1,800,000 common units at the
same $26.87 price per common unit. The net proceeds from the
underwriters exercise were used to reduce borrowings under our
credit facility by approximately $47 million.
|
|
Note 2
|
Basis of
Presentation
|
Our acquisition of the SAOU and LOU Systems from Targa has been
accounted for as a transfer of assets between entities under
common control in accordance with Statement of Financial
Accounting Standards (SFAS) 141, Business
Combinations. Targas conveyance of the North
Texas System to us in 2007 has also been accounted for as a
transfer of assets between entities under common control. The
SAOU and LOU Systems are the accounting predecessor because they
were the first entities controlled by the common parent entity.
Under common control accounting, the SAOU and LOU Systems assets
and liabilities are recorded at their book value with the
balance of the acquisition proceeds recorded as an adjustment to
parent equity. As a result, the previously reported amounts have
been restated as discussed below, and as further detail in
Note 4.
F-8
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The accompanying consolidated financial statements and related
notes reflect the historical financial data of the SAOU and LOU
Systems acquired by Targa on April 16, 2004 combined with
the results of operations for the North Texas System contributed
to us by Targa from the date of its acquisition by Targa on
October 31, 2005. The historical financial information is
derived from the audited financial statements of Targa. The
accompanying financial statements and related notes for the
years ended December 31, 2007 and 2006 are presented
combining the results of operations of the SAOU and LOU Systems
with the operations of the North Texas System and present the
results of operations, cash flows and changes in partners
capital/net parent investment for those periods. The
accompanying financial statements and related notes for the year
ended December 31, 2005 combine the results of operations
for the SAOU and LOU Systems for the year then ended and the
results of operations, cash flows and changes in partners
capital reflected in the audited historical financial statements
of the North Texas System for the two-months after its
acquisition by Targa.
Prior to the acquisition of the SAOU and LOU Systems and the
contribution of the North Texas System, our Parent provided cash
management services to us through a centralized treasury system.
As a result, all of our charges and cost allocations covered by
the centralized treasury system were deemed to have been paid to
the Parent in cash, during the period in which the cost was
recorded in the combined financial statements. In addition, cash
receipts advanced by the Parent in excess/deficit of charges and
cash allocations are reflected as contributions
from/distributions to the Parent in our statements of
partners capital/net parent equity and our statements of
cash flows. As a result of this accounting treatment, our
working capital does not reflect any affiliate accounts
receivable for intercompany commodity sales or any affiliate
accounts payable for personnel and services and for intercompany
product purchases prior to the acquisition and contribution.
Consequently, we had negative working capital balances of
369.0 million at December 31, 2006. Despite the
negative working capital balance, we generated operating cash
flows of $124.4 million for the year ended
December 31, 2006. Investing cash flows of
$32.9 million for the year ended December 31, 2006 as
well as distributions to Targa of $91.5 million were funded
with operating cash flows.
We have been allocated general and administrative expenses
incurred by the Parent in order to present financial statements
on a stand-alone basis. See Note 7 for a discussion of the
amounts and method of allocation. All of the allocations are not
necessarily indicative of the costs and expenses that would have
resulted had we been operated as stand-alone entities.
|
|
Note 3
|
Significant
Accounting Policies
|
Asset Retirement Obligations. The Partnership
accounts for asset retirement obligations (AROs)
using SFAS 143, Accounting for Asset Retirement
Obligations, as interpreted by Financial
Interpretation FIN 47, Accounting for
Conditional Asset Retirement Obligations. Asset
retirement obligations are legal obligations associated with the
retirement of tangible long-lived assets that result from the
assets acquisition, construction, development
and/or
normal operation. An ARO is initially measured at its estimated
fair value. Upon initial recognition of an ARO, an entity
records an increase to the carrying amount of the related
long-lived asset and an offsetting ARO liability. The
consolidated cost of the asset and the capitalized asset
retirement obligation is depreciated using a systematic and
rational allocation method over the period during which the
long-lived asset is expected to provide benefits. After the
initial period of ARO recognition, the ARO will change as a
result of either the passage of time or revisions to the
original estimates of either the amounts of estimated cash flows
or their timing. Changes due to the passage of time increase the
carrying amount of the liability because there are fewer periods
remaining from the initial measurement date until the settlement
date; therefore, the present values of the discounted future
settlement amount increases. These changes are recorded as a
period cost called accretion expense. Upon settlement, AROs will
be extinguished by the entity at either the recorded amount or
the entity will recognize a gain or loss on the difference
between the recorded amount and the actual settlement cost.
F-9
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The changes in our aggregate asset retirement obligations are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in thousands)
|
|
|
Beginning of period
|
|
$
|
2,888
|
|
|
$
|
2,644
|
|
|
$
|
630
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
2,054
|
|
Change in estimate
|
|
|
32
|
|
|
|
(1
|
)
|
|
|
(134
|
)
|
Accretion expense
|
|
|
342
|
|
|
|
245
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
3,262
|
|
|
$
|
2,888
|
|
|
$
|
2,644
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents. We define cash
equivalents as all highly liquid short-term investments with
original maturities of three months or less. Targa operates a
centralized cash management system whereby excess cash from most
of its subsidiaries, held in separate bank accounts, is swept to
a centralized account. See centralized cash management in
Note 7 Related Party Transactions.
Comprehensive Income. Comprehensive income
includes net income and other comprehensive income, which
includes unrealized gains and losses on derivative instruments
that are designated as hedges.
Concentration of Credit Risk. Financial
instruments which potentially subject Targa to concentrations of
credit risk consist primarily of trade accounts receivable and
derivative instruments. Management believes the risk is limited,
as our customers represent a broad and diverse group of energy
marketers and end users.
We extend credit to customers and other parties in the normal
course of business. We have established various procedures to
manage our credit exposure, including initial credit approvals,
credit limits and terms, letters of credit, and rights of
offset. We also use prepayments and guarantees to limit credit
risk to ensure that our established credit criteria are met.
Estimated losses on accounts receivable are provided through an
allowance for doubtful accounts. In evaluating the level of
established reserves, we make judgments regarding each
partys ability to make required payments, economic events
and other factors. As the financial condition of any party
changes, circumstances develop or additional information becomes
available, adjustments to the allowance for doubtful accounts
may be required.
Debt Issue Costs. Costs incurred in connection
with the issuance of long-term debt are capitalized and charged
to interest expense over the term of the related debt on a
straight-line basis, which approximates the interest method.
Environmental Liabilities. Liabilities for
loss contingencies, including environmental remediation costs
arising from claims, assessments, litigation, fines, and
penalties and other sources are charged to expense when it is
probable that a liability has been incurred and the amount of
the assessment
and/or
remediation can be reasonably estimated.
Impairment of Long-Lived Assets. Management
reviews property, plant and equipment for impairment whenever
events or changes in circumstances indicate that the carrying
amount of such assets may not be recoverable. The carrying
amount is deemed not recoverable if it exceeds the undiscounted
sum of the cash flows expected to result from the use and
eventual disposition of the asset. Estimates of expected future
cash flows represent managements best estimate based on
reasonable and supportable assumptions. If the carrying amount
is not recoverable, the impairment loss is measured as the
excess of the assets carrying value over its fair value.
Management assesses the fair value of long-lived assets using
commonly accepted techniques, and may use more than one method,
including, but not limited to, recent third party comparable
sales, internally developed discounted cash flow analysis and
analysis from outside advisors.
F-10
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Income Taxes. The Partnership is not subject
to federal income taxes. As a result, our earnings or losses for
federal income tax purposes are included in the tax returns of
our individual partners. In May 2006, Texas adopted a margin
tax, consisting generally of a 1% tax on the amount by which
total revenues exceed cost of goods sold, as apportioned to
Texas. Accordingly, we have estimated our liability for this tax
and it is presently recorded as a deferred tax liability.
We adopted the provisions of FIN 48 Accounting for
Uncertainty in Income Taxes on January 1, 2007.
FIN 48 prescribes a recognition threshold and measurement
attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return. Based on our evaluation, we have determined that
there are no significant uncertain tax positions requiring
recognition in our financial statements at the date of adoption
or December 31, 2007. There are no unrecognized tax
benefits that, if recognized, would affect the effective rate,
and there are no unrecognized tax benefits that are reasonably
expected to increase or decrease in the next twelve months. We
file tax returns in the United States Federal and State of Texas
jurisdictions, and are open to federal and state income tax
examinations for years 2006 forward. Presently, no income tax
examinations are underway, and none have been announced. No
potential interest or penalties were recognized at
December 31, 2007.
Inventory Imbalance. Quantities of natural gas
and/or NGLs
over-delivered or under-delivered related to operational
balancing agreements are recorded monthly as inventory or as a
payable using weighted average prices at the time the imbalance
was created. Monthly, inventory imbalances receivable are valued
at the lower of cost or market; inventory imbalances payable are
valued at replacement cost. These imbalances are typically
settled in the following month with deliveries of natural gas or
NGLs. Certain contracts require cash settlement of imbalances on
a current basis. Under these contracts, imbalance cash-outs are
recorded as a sale or purchase of natural gas, as appropriate.
Net Income per Limited Partner Unit. Emerging
Issues Task Force (EITF) Issue
03-6,
Participating Securities and the Two-Class Method
Under FASB Statement No. 128 addresses the
computation of earnings per share by entities that have issued
securities other than common stock that contractually entitle
the holder to participate in dividends and earnings of the
entity when, and if, it declares dividends on its securities.
EITF 03-6
requires that securities that meet the definition of a
participating security be considered for inclusion in the
computation of basic earnings per unit using the two-class
method. Under the two-class method, earnings per unit is
calculated as if all of the earnings for the period were
distributed under the terms of the partnership agreement,
regardless of whether the general partner has discretion over
the amount of distributions to be made in any particular period,
whether those earnings would actually be distributed during a
particular period from an economic or practical perspective, or
whether the general partner has other legal or contractual
limitations on its ability to pay distributions that would
prevent it from distributing all of the earnings for a
particular period.
EITF 03-6
does not impact the Partnerships overall net income or
other financial results; however, in periods in which aggregate
net income exceeds the Partnerships aggregate
distributions for such period, it will have the impact of
reducing net income per limited partner unit. This result occurs
as a larger portion of the Partnerships aggregate
earnings, as if distributed, is allocated to the incentive
distribution rights of the general partner, even though the
Partnership makes distributions on the basis of available cash
and not earnings. In periods in which the Partnerships
aggregate net income does not exceed its aggregate distributions
for such period,
EITF 03-6
does not have any impact on the Partnerships calculation
of earnings per limited partner unit.
Price Risk Management (Hedging). The
Partnership accounts for derivative instruments in accordance
with SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, as amended. Under
SFAS 133, all derivative instruments not qualifying for the
normal purchases and normal sales exception are recorded on the
balance sheet at fair value. If a derivative does not qualify as
a hedge or is not designated as a
F-11
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
hedge, the gain or loss on the derivative is recognized
currently in earnings. If a derivative qualifies for hedge
accounting and is designated as a cash flow hedge, the effective
portion of the unrealized gain or loss on the derivative is
deferred in accumulated other comprehensive income
(OCI), a component of partners capital, and
reclassified to earnings when the forecasted transaction occurs.
Cash flows from a derivative instrument designated as a hedge
are classified in the same category as the cash flows from the
item being hedged.
The relationship between the hedging instrument and the hedged
item must be highly effective in achieving the offset of changes
in cash flows attributable to the hedged risk both at the
inception of the contract and on an ongoing basis. Hedge
accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in OCI related to
cash flow hedges for which hedge accounting has been
discontinued remain deferred until the forecasted transaction
occurs. If it is probable that a hedged forecasted transaction
will not occur, deferred gains or losses on the hedging
instrument are reclassified to earnings immediately.
The Partnerships policy is to formally document all
relationships between hedging instruments and hedged items, as
well as its risk management objectives and strategy for
undertaking the hedge. This process includes specific
identification of the hedging instrument and the hedged item,
the nature of the risk being hedged and the manner in which the
hedging instruments effectiveness will be assessed. At the
inception of the hedge and on an ongoing basis, the Partnership
assesses whether the derivatives used in hedging transactions
are highly effective in offsetting changes in cash flows of
hedged items. Hedge effectiveness is measured on a quarterly
basis. Any ineffective portion of the unrealized gain or loss is
reclassified to earnings in the current period.
Property, Plant and Equipment. Property, plant
and equipment are stated at cost less accumulated depreciation.
Depreciation is computed using the straight-line method over the
estimated useful lives of the assets. The estimated service
lives of the Partnerships functional asset groups are as
follows:
|
|
|
|
|
Range of
|
Asset Group
|
|
Years
|
|
Natural gas gathering systems and processing facilities
|
|
15 to 25
|
Office and miscellaneous equipment
|
|
3 to 7
|
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures to refurbish assets that extend the
useful lives or prevent environmental contamination are
capitalized and depreciated over the remaining useful life of
the asset. Upon disposition or retirement of property, plant,
and equipment, any gain or loss is charged to operations.
Revenue Recognition. The Partnerships
primary types of sales and service activities reported as
operating revenues include:
|
|
|
|
|
sales of natural gas, NGLs and condensate; and
|
|
|
|
natural gas processing, from which we generate revenues through
the compression, gathering, treating, and processing of natural
gas.
|
The Partnership recognizes revenues when all of the following
criteria are met: (1) persuasive evidence of an exchange
arrangement exists, if applicable, (2) delivery has
occurred or services have been rendered, (3) the price is
fixed or determinable and (4) collectibility is reasonably
assured.
For processing services, the Partnership receives either fees or
a percentage of commodities as payment for these services,
depending on the type of contract. Under
percent-of-proceeds
contracts, we receive either an agreed upon percentage of the
actual proceeds that we receive from our sales of the residue
natural gas and NGLs or an agreed upon percentage based on index
related prices for the natural gas and NGLs.
Percent-of-value
and
percent-of-liquids
contracts are variations on this arrangement. Under keep-whole
F-12
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
contracts, we keep the NGLs extracted and return the processed
natural gas or value of the natural gas to the producer. Natural
gas or NGLs that the Partnership receives for services or
purchase for resale are in turn sold and recognized in
accordance with the criteria outlined above. Under fee-based
contracts, the Partnership receives a fee based on throughput
volumes.
The Partnership generally reports revenues gross in the
consolidated statements of operations, in accordance with
EITF 99-19,
Reporting Revenue Gross as a Principal versus Net as an
Agent. Except for fee-based contracts, the Partnership
acts as the principal in the transactions where we receive
commodities, take title to the natural gas and NGLs, and incur
the risks and rewards of ownership.
Segment Information. SFAS 131,
Disclosures about Segments of an Enterprise and Related
Information, establishes standards for reporting
information about operating segments. The Partnership operates
in one segment only, the natural gas gathering and processing
segment.
Share-Based Employee Compensation. Targa
Investments and the Partnership have stock-based compensation
plans covering our employees and their respective Boards of
Directors. We account for awards under these plans utilizing the
fair value recognition provisions of SFAS 123R,
Share-Based Payment. Please see Note 11.
Use of Estimates. The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the period.
Estimates and judgments are based on information available at
the time such estimates and judgments are made. Adjustments made
with respect to the use of these estimates and judgments often
relate to information not previously available. Uncertainties
with respect to such estimates and judgments are inherent in the
preparation of financial statements. Estimates and judgments are
used in, among other things, (1) estimating unbilled
revenues and operating and general and administrative costs
(2) developing fair value assumptions, including estimates
of future cash flows and discount rates, (3) analyzing
tangible and intangible assets for possible impairment,
(4) estimating the useful lives of assets and
(5) determining amounts to accrue for contingencies,
guarantees and indemnifications. Actual results could differ
materially from estimated amounts.
Recent
Accounting Pronouncements.
In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157, Fair
Value Measurements (SFAS 157) which
establishes a framework for measuring fair value, and expands
disclosures about fair value measurements. The FASB partially
deferred the effective date of SFAS 157 for nonfinancial
assets and liabilities that are recognized or disclosed at fair
value in the financial statements on a nonrecurring basis while
the effective date for nonfinancial and financial assets and
liabilities that are recognized on a recurring basis is
effective beginning January 1, 2008. The Company has
determined that the adoption of SFAS 157 will not have a
material impact on its consolidated financial statements.
In February 2007, the FASB issued SFAS 159, The
Fair Value Option for Financial Assets and Financial
Liabilities, including an amendment of FASB Statement
No. 115, which is effective for fiscal years
beginning after November 15, 2007, with early adoption
permitted. SFAS 159 expands opportunities to use fair value
measurements in financial reporting and permits entities to
choose to measure many financial instruments and certain other
items at fair value. We are currently reviewing this new
accounting standard and the impact, if any; it will have on our
financial statements.
In December 2007, the FASB issued SFAS 160,
Noncontrolling Interests in Consolidated Financial
Statements An Amendment of ARB No. 51.
SFAS 160 establishes new accounting and reporting
standard for the noncontrolling interest in a subsidiary and for
the deconsolidation of a subsidiary. SFAS 160 is effective
for fiscal periods, and interim periods within those fiscal
years, beginning on or after December 15,
F-13
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2008. We are currently reviewing this new accounting standard
and the impact, if any, it will have on our financial statements.
In December 2007, the FASB issued SFAS No. 141
(revised 2007), Business Combinations
(SFAS 141R). SFAS 141R establishes
principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed, any noncontrolling interest
in the acquiree and the goodwill acquired. SFAS 141R also
establishes disclosure requirements to enable the evaluation of
the nature and financial effects of the business combination.
SFAS 141R is effective as of the beginning of an
entitys fiscal year that begins after December 15,
2008. We are currently reviewing this new accounting standard
and the impact, if any, it will have on our financial statements.
On February 14, 2007, we had Targas ownership
interests in the North Texas System contributed to us. On
October 24, 2007, we acquired Targas ownership
interests in Targa Texas Field Services LP (the SAOU
System) and Targa Louisiana Field Services LLC (the
LOU System). As required by SFAS 141, we
accounted for these transactions as transfers of net assets
between entities under common control. For combinations of
entities under common control, the purchase cost provisions (as
they relate to purchase business combinations involving
unrelated entities) of SFAS 141 explicitly do not apply;
instead the method of accounting prescribed by SFAS 141 for
such transfers is similar to the
pooling-of-interests
method of accounting. Under this method, the carrying amount of
net assets recognized in the balance sheets of each combining
entity are carried forward to the balance sheet of the combined
entity, and no other assets or liabilities are recognized as a
result of the combination (that is, no recognition is made for a
purchase premium or discount representing any difference between
the cash consideration paid and the book value of the net assets
acquired).
The predecessor entity for us is considered to be the net assets
of the SAOU and LOU Systems as these were the first assets
acquired by Targa on April 16, 2004. Therefore, following
our acquisition of the North Texas System from Targa on
February 14, 2007, we recognized the assets and liabilities
acquired at their carrying amounts (historical cost) in the
accounts of the SAOU and LOU Systems (the predecessor entity) at
the date of transfer. The accounting treatment for combinations
of entities under common control is consistent with the concept
of poolings as combinations of common shareholder (or
unitholder) interests, as all of the North Texas Systems
equity accounts were also carried forward intact initially, and
subsequently adjusted due to the cash consideration we paid for
the acquired net assets.
In addition to requiring that assets and liabilities be carried
forward at historical costs, SFAS 141 also prescribes that
for transfers of net assets between entities under common
control, all income statements presented be combined as of the
date of common control. Accordingly, our consolidated financial
statements and all other financial information included in this
report have been restated to assume that the transfer of the
North Texas System net assets from Targa to us had occurred at
the date when both the North Texas System and the SAOU and LOU
Systems met the accounting requirements for entities under
common control (October 31, 2005). As a result, financial
statements and financial information presented for prior periods
in this report have been restated.
F-14
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the impact on our consolidated
financial position at December 31, 2006, adjusted for the
acquisition of the SAOU and LOU Systems from Targa.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade receivables
|
|
$
|
60,249
|
|
|
$
|
1,310
|
|
|
$
|
61,559
|
|
Assets from risk management activities
|
|
|
8,433
|
|
|
|
17,250
|
|
|
|
25,683
|
|
Other
|
|
|
958
|
|
|
|
|
|
|
|
958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
69,640
|
|
|
|
18,560
|
|
|
|
88,200
|
|
Property, plant, and equipment, net
|
|
|
224,463
|
|
|
|
1,064,108
|
|
|
|
1,288,571
|
|
Debt issue costs allocated from Parent
|
|
|
3,741
|
|
|
|
17,612
|
|
|
|
21,353
|
|
Long-term assets from risk management activities
|
|
|
310
|
|
|
|
15,541
|
|
|
|
15,851
|
|
Other long-term assets
|
|
|
2,396
|
|
|
|
|
|
|
|
2,396
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
300,550
|
|
|
$
|
1,115,821
|
|
|
$
|
1,416,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and other liabilities
|
|
$
|
81,489
|
|
|
$
|
31,621
|
|
|
$
|
113,110
|
|
Current maturities of debt allocated from Parent
|
|
|
59,664
|
|
|
|
281,083
|
|
|
|
340,747
|
|
Liabilities from risk management activities
|
|
|
3,296
|
|
|
|
|
|
|
|
3,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
144,449
|
|
|
|
312,704
|
|
|
|
457,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt allocated from Parent
|
|
|
123,720
|
|
|
|
582,877
|
|
|
|
706,597
|
|
Long-term liabilities from risk management activities
|
|
|
455
|
|
|
|
96
|
|
|
|
551
|
|
Other long-term liabilities
|
|
|
1,629
|
|
|
|
4,528
|
|
|
|
6,157
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net parent investment
|
|
|
30,176
|
|
|
|
184,773
|
|
|
|
214,949
|
|
Other comprehensive income
|
|
|
121
|
|
|
|
30,843
|
|
|
|
30,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
30,297
|
|
|
|
215,616
|
|
|
|
245,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
300,550
|
|
|
$
|
1,115,821
|
|
|
$
|
1,416,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-15
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables present the impact on the consolidated
statements of operations, adjusted for the acquisition of the
SAOU and LOU Systems from Targa, for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ending December 31, 2006
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Targa Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
Revenues from third parties
|
|
$
|
936,712
|
|
|
$
|
15,224
|
|
|
$
|
951,936
|
|
Revenues from affiliates
|
|
|
416,984
|
|
|
|
369,605
|
|
|
|
786,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,353,696
|
|
|
|
384,829
|
|
|
|
1,738,525
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
926,264
|
|
|
|
268,487
|
|
|
|
1,194,751
|
|
Product purchases from affiliates
|
|
|
322,071
|
|
|
|
846
|
|
|
|
322,917
|
|
Operating expenses
|
|
|
24,973
|
|
|
|
24,102
|
|
|
|
49,075
|
|
Depreciation and amortization expense
|
|
|
13,999
|
|
|
|
55,958
|
|
|
|
69,957
|
|
General and administrative expense
|
|
|
9,159
|
|
|
|
6,904
|
|
|
|
16,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,296,466
|
|
|
|
356,297
|
|
|
|
1,652,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
57,230
|
|
|
|
28,532
|
|
|
|
85,762
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
15,115
|
|
|
|
72,910
|
|
|
|
88,025
|
|
Gain on
mark-to-market
derivative contracts
|
|
|
(16,756
|
)
|
|
|
|
|
|
|
(16,756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
58,871
|
|
|
|
(44,378
|
)
|
|
|
14,493
|
|
Deferred income tax expense
|
|
|
394
|
|
|
|
2,532
|
|
|
|
2,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
58,477
|
|
|
$
|
(46,910
|
)
|
|
$
|
11,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Targa Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
For The Year
|
|
|
For the Two
|
|
|
|
|
|
|
Ended
|
|
|
Months Ended
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
|
2005
|
|
|
2005
|
|
|
Total
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
Revenues from third parties
|
|
$
|
1,088,719
|
|
|
$
|
22,192
|
|
|
$
|
1,110,911
|
|
Revenues from affiliates
|
|
|
8,587
|
|
|
|
52,952
|
|
|
|
61,539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,097,306
|
|
|
|
75,144
|
|
|
|
1,172,450
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
986,705
|
|
|
|
54,981
|
|
|
|
1,041,686
|
|
Product purchases from affiliates
|
|
|
19,987
|
|
|
|
11
|
|
|
|
19,998
|
|
Operating expenses
|
|
|
20,900
|
|
|
|
3,494
|
|
|
|
24,394
|
|
Depreciation and amortization expense
|
|
|
13,919
|
|
|
|
9,150
|
|
|
|
23,069
|
|
General and administrative expense
|
|
|
15,658
|
|
|
|
1,063
|
|
|
|
16,721
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,057,169
|
|
|
|
68,699
|
|
|
|
1,125,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
40,137
|
|
|
|
6,445
|
|
|
|
46,582
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
9,635
|
|
|
|
11,542
|
|
|
|
21,177
|
|
Loss on
mark-to-market
derivative contracts
|
|
|
11,973
|
|
|
|
|
|
|
|
11,973
|
|
Loss on debt extinguishment
|
|
|
3,701
|
|
|
|
|
|
|
|
3,701
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
14,828
|
|
|
|
(5,097
|
)
|
|
|
9,731
|
|
Deferred income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14,828
|
|
|
$
|
(5,097
|
)
|
|
$
|
9,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-16
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 5
|
Partnership
Equity and Distributions
|
General. The partnership agreement requires
that, within 45 days after the end of each quarter, we
distribute all of our Available Cash (defined below) to
unitholders of record on the applicable record date, as
determined by the general partner.
Definition of Available Cash. Available Cash,
for any quarter, consists of all cash and cash equivalents on
hand on the date of determination of available cash for that
quarter:
|
|
|
|
|
less the amount of cash reserves established by the general
partner to:
|
|
|
|
provide for the proper conduct of our business;
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distributions to the unitholders and to the
general partner for any one or more of the next four quarters.
|
General Partner Interest and Incentive Distribution
Rights. The general partner is currently entitled
to approximately 2% of all quarterly distributions that we make
prior to our liquidation. The general partner has the right, but
not the obligation, to contribute a proportionate amount of
capital to us to maintain its current general partner interest.
The general partners 2% interest in these distributions
will be reduced if we issue additional units in the future and
the general partner does not contribute a proportionate amount
of capital to us to maintain its 2% general partner interest.
The incentive distribution rights held by the general partner
entitle it to receive an increasing share of Available Cash when
pre-defined distribution targets are achieved. The general
partners incentive distribution rights are not reduced if
we issue additional units in the future and the general partner
does not contribute a proportionate amount of capital to us to
maintain its 2% general partner interest. Please read
Distributions of Available Cash during the Subordination
Period and Distributions of Available Cash after the
Subordination Period below for more details about the
distribution targets and their impact on the general
partners incentive distribution rights.
Subordinated Units. All of the subordinated
units are held by Targa GP Inc. and Targa LP Inc. The
partnership agreement provides that, during the subordination
period, the common units have the right to receive distributions
of Available Cash each quarter in an amount equal to $0.3375 per
common unit, or the Minimum Quarterly Distribution,
plus any arrearages in the payment of the Minimum Quarterly
Distribution on the common units from prior quarters, before any
distributions of Available Cash may be made on the subordinated
units. These units are deemed subordinated because
for a period of time, referred to as the subordination period,
the subordinated units will not be entitled to receive any
distributions until the common units have received the Minimum
Quarterly Distribution plus any arrearages from prior quarters.
Furthermore, no arrearages will be paid on the subordinated
units. The practical effect of the subordinated units is to
increase the likelihood that during the subordination period
there will be Available Cash to be distributed on the common
units. The subordination period will end, and the subordinated
units will convert to common units, on a one for one basis, when
certain distribution requirements, as defined in the partnership
agreement, have been met. The earliest date at which the
subordination period may end is April 2008.
Distributions of Available Cash during the Subordination
Period. Based on the general partners
initial 2% ownership percentage, the partnership agreement
requires that we make distributions of Available Cash from
operating surplus for any quarter during the subordination
period in the following manner:
|
|
|
|
|
first, 98% to the common unitholders, pro rata, and 2% to
the general partner, until we distribute for each outstanding
common unit an amount equal to the Minimum Quarterly
Distribution for that quarter;
|
F-17
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
second, 98% to the common unitholders, pro rata, and 2%
to the general partner, until we distribute for each outstanding
common unit an amount equal to any arrearages in payment of the
Minimum Quarterly Distribution on the common units for any prior
quarters during the subordination period;
|
|
|
|
third, 98% to the subordinated unitholders, pro rata, and
2% to the general partner, until we distribute for each
subordinated unit an amount equal to the Minimum Quarterly
Distribution for that quarter;
|
|
|
|
fourth, 98% to all unitholders, pro rata, and 2% to the
general partner, until each unitholder receives a total of
$0.3881 per unit for that quarter (the First Target
Distribution);
|
|
|
|
fifth, 85% to all unitholders, 2% to the general partner
and 13% to the holders of the Incentive Distribution Rights, pro
rata, until each unitholder receives a total of $0.4219 per unit
for that quarter (the Second Target Distribution);
|
|
|
|
sixth, 75% to all unitholders, 2% to the general partner
and 23% to the holders of the Incentive Distribution Rights, pro
rata, until each unitholder receives a total of $0.50625 per
unit for that quarter (the Third Target Distribution); and
|
|
|
|
thereafter, 50% to all unitholders, 2% to the general
partner and 48% to the holders of the Incentive Distribution
Rights, pro rata, (the Fourth Target Distribution).
|
Distributions of Available Cash after the Subordination
Period. The partnership agreement requires that
we make distributions of Available Cash from operating surplus
for any quarter after the subordination period in the following
manner:
|
|
|
|
|
first, 98% to all unitholders, pro rata, and 2% to the
general partner, until each unitholder receives a total of
$0.3881 per unit for that quarter;
|
|
|
|
second, 85% to all unitholders, pro rata, 2% to the
general partner and 13% to the holders of the Incentive
Distribution Rights, until each unitholder receives a total of
$0.4219 per unit for that quarter;
|
|
|
|
third, 75% to all unitholders, pro rata, 2% to the
general partner and 23% to the holders of the Incentive
Distribution Rights, until each unitholder receives a total of
$0.50625 per unit for that quarter; and
|
|
|
|
thereafter, 50% to all unitholders, pro rata, 2% to the
general partner and 48% to the holders of the Incentive
Distribution Rights.
|
|
|
Note 6
|
Net
Income per Limited Partner Unit
|
The Partnerships net income is allocated to the general
partner and the limited partners, including the holders of the
subordinated units, in accordance with their respective
ownership percentages, after giving effect to incentive
distributions paid to the general partner. Basic and diluted net
income per limited partner unit is calculated by dividing
limited partners interest in net income, less general
partner incentive distributions, by the weighted average number
of outstanding limited partner units during the period.
Basic earnings per unit is computed by dividing net earnings
attributable to unitholders by the weighted average number of
units outstanding during each period. Diluted earnings per unit
reflects the potential dilution of common equivalent units that
could occur if securities or other contracts to issue common
units were exercised or converted into common units.
Due to the timing of our IPO, a pro-rated distribution for the
first quarter of 2007 of $0.16875 per unit (approximately
$5.3 million) was declared by the Board of Directors of our
general partner on April 23, 2007 and paid on May 15,
2007. A distribution for the second quarter of 2007 of $0.3375
per unit (approximately $10.6 million) was declared on
July 23, 2007 and paid on August 14, 2007 to
unitholders of record as of the close of business on
August 2, 2007. A distribution of $0.3375 per unit
(approximately $10.6 million) was declared on
October 24, 2007 and paid on November 14, 2007. A
distribution of $0.3975 (approximately $18.7 million) for
the fourth quarter of 2007 was declared on January 24, 2008
and was paid on February 14, 2008.
F-18
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table illustrates our calculation of net income
per limited and subordinated partner unit for the year ended
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU/LOU System
|
|
|
North Texas System
|
|
|
|
|
|
|
Targa Resources
|
|
|
|
|
|
Targa Resources
|
|
|
Targa North
|
|
|
|
|
|
|
Partners LP
|
|
|
SAOU/LOU
|
|
|
Partners LP
|
|
|
Texas LP
|
|
|
|
Year Ended
|
|
|
Oct. 24, 2007 to
|
|
|
Jan. 1, 2007 to
|
|
|
Feb. 14, 2007 to
|
|
|
Jan. 1, 2007 to
|
|
|
|
December 31, 2007
|
|
|
Dec. 31, 2007
|
|
|
Oct. 23, 2007
|
|
|
Dec. 31, 2007
|
|
|
Feb. 13, 2007
|
|
|
|
(in thousands, except unit and per unit information)
|
|
|
Revenues from third parties
|
|
$
|
630,773
|
|
|
$
|
129,916
|
|
|
$
|
483,766
|
|
|
$
|
13,156
|
|
|
$
|
3,935
|
|
Revenues from affiliates
|
|
|
1,030,696
|
|
|
|
139,616
|
|
|
|
472,746
|
|
|
|
380,165
|
|
|
|
38,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,661,469
|
|
|
|
269,532
|
|
|
|
956,512
|
|
|
|
393,321
|
|
|
|
42,104
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases
|
|
|
1,406,797
|
|
|
|
242,214
|
|
|
|
858,007
|
|
|
|
277,881
|
|
|
|
28,695
|
|
Operating expenses, excluding DD&A
|
|
|
50,931
|
|
|
|
6,837
|
|
|
|
19,270
|
|
|
|
22,008
|
|
|
|
2,816
|
|
Depreciation and amortization expense
|
|
|
71,756
|
|
|
|
2,747
|
|
|
|
11,663
|
|
|
|
50,421
|
|
|
|
6,925
|
|
General and administrative expense
|
|
|
18,927
|
|
|
|
965
|
|
|
|
9,018
|
|
|
|
8,242
|
|
|
|
702
|
|
Loss (gain) on sale of assets
|
|
|
(296
|
)
|
|
|
|
|
|
|
(298
|
)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,548,115
|
|
|
|
252,763
|
|
|
|
897,660
|
|
|
|
358,554
|
|
|
|
39,138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
113,354
|
|
|
|
16,769
|
|
|
|
58,852
|
|
|
|
34,767
|
|
|
|
2,966
|
|
Other expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
21,998
|
|
|
|
4,261
|
|
|
|
|
|
|
|
17,737
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
19,436
|
|
|
|
|
|
|
|
9,609
|
|
|
|
|
|
|
|
9,827
|
|
Loss/(gain) on
mark-to-market
derivative contracts
|
|
|
30,221
|
|
|
|
|
|
|
|
30,221
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(30
|
)
|
|
|
(7
|
)
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
41,729
|
|
|
|
12,515
|
|
|
|
19,045
|
|
|
|
17,030
|
|
|
|
(6,861
|
)
|
Deferred income tax expense
|
|
|
1,479
|
|
|
|
99
|
|
|
|
|
|
|
|
1,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
40,250
|
|
|
|
12,416
|
|
|
|
19,045
|
|
|
|
15,650
|
|
|
|
(6,861
|
)
|
Less: Net income attributable to predecessor operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the period 1/1-2/13/2007 for North Texas
|
|
|
(6,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,861
|
)
|
For the period 1/1-10/23/2007 for SAOU/LOU
|
|
|
19,045
|
|
|
|
|
|
|
|
19,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
12,184
|
|
|
|
|
|
|
$
|
19,045
|
|
|
|
|
|
|
$
|
(6,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocable to partners
|
|
|
28,066
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest in net income
|
|
|
561
|
|
|
|
248
|
|
|
|
|
|
|
|
313
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common and subordinated unitholders
|
|
$
|
27,505
|
|
|
$
|
12,168
|
|
|
|
|
|
|
$
|
15,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common and subordinated unit
|
|
$
|
0.81
|
|
|
$
|
0.36
|
|
|
|
|
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common and subordinated unit
|
|
$
|
0.81
|
|
|
$
|
0.36
|
|
|
|
|
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic average number of common and subordinated units outstanding
|
|
|
33,986
|
|
|
|
33,986
|
|
|
|
|
|
|
|
33,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted average number of common and subordinated units
outstanding
|
|
|
33,994
|
|
|
|
33,994
|
|
|
|
|
|
|
|
33,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-19
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The calculation of basic and diluted net income per common and
subordinated unit are the same for all periods presented as
distributable cash flow was greater than net income for those
periods and distributions to the subordinated unitholders have
been equivalent to the distribution to the common unitholders
for all quarters.
The calculation of net income per limited and subordinated
partner unit for the year ended December 31, 2006 and prior
is not presented as the Partnership did not have any outstanding
units until we completed our IPO on February 14, 2007.
|
|
Note 7
|
Related-Party
Transactions
|
Targa
Resources, Inc.
On February 14, 2007, we entered into an Omnibus Agreement
with Targa, our general partner and others that addressed the
reimbursement of our general partner for costs incurred on our
behalf and indemnification matters. Any or all of the provisions
of the Omnibus Agreement, other than the indemnification
provisions described in Note 13, are terminable by Targa at
its option if our general partner is removed without cause and
units held by our general partner and its affiliates are not
voted in favor of that removal. The Omnibus Agreement will also
terminate in the event of a change of control of us or our
general partner.
Concurrently with the closing of the acquisition of the SAOU and
LOU Systems, we amended and restated our Omnibus Agreement (as
amended and restated, the Omnibus Agreement) with
Targa, our general partner and others that addresses the
reimbursement of our general partner for costs incurred on our
behalf, competition and indemnification matters. Any or all of
the provisions of the Omnibus Agreement, other than the
indemnification provisions described below, are terminable by
Targa at its option if our general partner is removed without
cause and units held by our general partner and its affiliates
are not voted in favor of that removal. The Omnibus Agreement
will also terminate in the event of a change of control of us or
our general partner.
Reimbursement
of Operating and General and Administrative
Expense
Under the Omnibus Agreement, we reimburse Targa for the payment
of certain operating expenses, including compensation and
benefits of operating personnel, and for the provision of
various general and administrative services for our benefit.
With respect to the North Texas System, we reimburse Targa for
the following expenses:
|
|
|
|
|
general and administrative expenses, which are capped at
$5 million annually for three years, subject to increases
based on increases in the Consumer Price Index and subject to
further increases in connection with expansions of our
operations through the acquisition or construction of new assets
or businesses with the concurrence of our conflicts committee;
thereafter, our general partner will determine the general and
administrative expenses to be allocated to us in accordance with
our partnership agreement, and
|
|
|
|
operations and certain direct general and administrative
expenses, which are not subject to the $5 million cap for
general and administrative expenses.
|
With respect to the SAOU and LOU Systems, we will reimburse
Targa for the following expenses:
|
|
|
|
|
General and administrative expenses, which are not capped,
allocated to the SAOU and LOU Systems according to Targas
allocation practice; and
|
|
|
|
Operating and certain direct expenses, which are not capped.
|
Pursuant to these arrangements, Targa performs centralized
corporate functions for us, such as legal, accounting, treasury,
insurance, risk management, health, safety and environmental,
information technology,
F-20
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
human resources, credit, payroll, internal audit, taxes,
engineering and marketing. We reimburse Targa for the direct
expenses to provide these services as well as other direct
expenses it incurs on our behalf, such as compensation of
operational personnel performing services for our benefit and
the cost of their employee benefits, including 401(k), pension
and health insurance benefits.
Contracts
with Affiliates
Sales to and purchases from affiliates. The
Partnership routinely conducts business with other subsidiaries
of Targa. The related party transactions result primarily from
purchases and sales of natural gas and NGLs. Prior to
February 14, 2007, all of the Partnerships
expenditures were paid through Targa, resulting in inter-company
transactions. Prior to February 14, 2007, settlement of
these inter-company transactions was through adjustments to
partners capital accounts. Effective February 14,
2007, all of the North Texas Systems transactions were settled
monthly in cash. Effective October 23, 2007, all of the
SAOU and LOU Systems transactions were settled in cash.
NGL and Condensate Purchase Agreement for the North Texas
System. During 2007, we entered into an NGL and
high pressure condensate purchase agreement with Targa Liquids
Marketing and Trade (TLMT) for our North Texas
System, which has an initial term of 15 years and will
automatically extend for a term of five years, unless the
agreement is otherwise terminated by either party, pursuant to
which (i) we are obligated to sell all volumes of NGLs
(other than high-pressure condensate) that we own or control to
TLMT and (ii) we have the right to sell to TLMT or third
parties the volumes of high-pressure condensate that we own or
control, in each case at a price based on the prevailing market
price less transportation, fractionation and certain other fees.
Furthermore, either party may elect to terminate the agreement
if either party ceases to be an affiliate of Targa.
NGL Purchase Agreements for the SAOU and LOU
Systems. During 2007, the SAOU System entered
into an NGL purchase agreement pursuant to which it is obligated
to sell all volumes of mixed NGLs, or raw product, that it owns
or controls to TLMT at a price based on either TLMTs sales
price to third parties or the prevailing market price, less
transportation, fractionation and certain other fees. The LOU
System also has entered into an NGL purchase agreement pursuant
to which (i) it has the right to sell to TLMT the volumes
of raw product that it owns or controls at a commercially
reasonable price agreed by the parties, and (ii) it is
obligated to sell all volumes of fractionated NGL components
that it owns or controls at a price based on TLMTs sales
price to third parties or the prevailing market price, less
transportation, fractionation and certain other fees. Both NGL
purchase agreements have an initial term of one year and
automatically extend for additional terms of one year, unless
the agreements are otherwise terminated by either party.
Natural Gas Purchase Agreements. During 2007,
the North Texas, SAOU and LOU Systems entered into natural gas
purchase agreements at a price based on Targa Gas Marketing
LLCs (TGM) sale price for such natural gas,
less TGMs costs and expenses associated therewith. These
agreements have an initial term of 15 years and
automatically extend for a term of five years, unless the
agreements are otherwise terminated by either party.
Furthermore, either party may elect to terminate the agreements
if either party ceases to be an affiliate of Targa. In addition,
Targa manages the SAOU and LOU Systems natural gas sales
to third parties under contracts that remain in the name of the
SAOU and LOU Systems.
Allocations
Allocation of costs. The employees supporting
the Partnerships operations are employees of Targa. The
Partnerships financial statements include costs allocated
to it by Targa for centralized general and administrative
services performed by Targa, as well as depreciation of assets
utilized by Targas centralized general and administrative
functions. Costs allocated to the Partnership were based on
identification of Targas resources which directly benefit
the Partnership and its proportionate share of costs based on
the Partnerships estimated usage of shared resources and
functions. All of the allocations are based on assumptions that
management
F-21
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
believes are reasonable; however, these allocations are not
necessarily indicative of the costs and expenses that would have
resulted if the Partnership had been operated as a stand-alone
entity. Prior to the initial IPO and the subsequent acquisition
of the SAOU and LOU Systems these allocations were not settled
in cash, but were settled through an adjustment to
partners capital accounts. Effective February 14,
2007, all of the North Texas Systems allocations were settled
monthly in cash. Effective October 23, 2007, all of the
SAOU and LOU Systems allocations were settled in cash.
Allocations of long-term debt, debt issue costs, interest
rate swaps and interest expense. Prior to
January 1, 2007, the Partnerships financial
statements included long-term debt, debt issue costs, interest
rate swaps and interest expense allocated from Targa. The
allocations were calculated in a manner similar to Targas
purchase price allocation related to its acquisition of the SAOU
and LOU Systems and were based on the fair value of acquired
tangible assets plus related net working capital and
unconsolidated equity interests. These allocations were not
settled in cash. Settlement of these allocations occurred
through adjustments to partners capital. The allocated
debt, debt issue costs and interest rate swaps for the North
Texas System, were settled through a deemed partner contribution
of $846.3 million on January 1, 2007. The allocated
debt, debt issue costs and interest rate swaps related to the
SAOU and LOU Systems were settled through a deemed partner
contribution of $179.6 million.
F-22
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the sales to and purchases from
affiliates of Targa, payments made or received by Targa on
behalf of the Partnership and allocations of costs from Targa
which were settled through adjustments to partners
capital. Management believes these transactions are executed on
terms that are fair and reasonable.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU/LOU System
|
|
|
North Texas System
|
|
|
|
|
|
|
|
|
|
|
|
|
Targa Resources
|
|
|
|
|
|
Targa Resources
|
|
|
Targa North
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Partners LP
|
|
|
SAOU/LOU
|
|
|
Partners LP
|
|
|
Texas LP
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
Oct. 24, 2007 to
|
|
|
Jan 1, 2007 to
|
|
|
Feb. 14, 2007 to
|
|
|
Jan. 1, 2007 to
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
Dec. 31, 2007
|
|
|
Oct. 23, 2007
|
|
|
Dec. 31, 2007
|
|
|
Feb 13, 2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in thousands)
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to affiliates
|
|
$
|
(1,030,696
|
)
|
|
$
|
(139,616
|
)
|
|
$
|
(472,746
|
)
|
|
$
|
(380,165
|
)
|
|
$
|
(38,169
|
)
|
|
$
|
(786,589
|
)
|
|
$
|
(61,539
|
)
|
Purchases from affiliates
|
|
|
191,064
|
|
|
|
51,031
|
|
|
|
139,108
|
|
|
|
848
|
|
|
|
77
|
|
|
|
322,917
|
|
|
|
19,998
|
|
Allocations of general & administrative
expenses pre IPO
|
|
|
8,831
|
|
|
|
|
|
|
|
8,129
|
|
|
|
|
|
|
|
702
|
|
|
|
16,062
|
|
|
|
16,721
|
|
Allocations of general & administrative expenses under
Omnibus Agreement
|
|
|
5,095
|
|
|
|
746
|
|
|
|
|
|
|
|
4,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated interest
|
|
|
19,436
|
|
|
|
|
|
|
|
9,598
|
|
|
|
|
|
|
|
9,838
|
|
|
|
88,025
|
|
|
|
21,177
|
|
Receivable from affiliates to be settled in cash
|
|
|
87,547
|
|
|
|
65,477
|
|
|
|
|
|
|
|
22,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receipts (Payments) made by the Parent
|
|
|
584,561
|
|
|
|
22,362
|
|
|
|
182,268
|
|
|
|
352,898
|
|
|
|
27,033
|
|
|
|
268,043
|
|
|
|
(99
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(134,162
|
)
|
|
$
|
|
|
|
|
(133,643
|
)
|
|
$
|
|
|
|
$
|
(519
|
)
|
|
$
|
(91,542
|
)
|
|
$
|
(3,742
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Initial contribution by Parent
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
219,879
|
|
Allocation of Parent debt repayments
|
|
|
|
|
|
|
|
|
|
|
59,400
|
|
|
|
|
|
|
|
|
|
|
|
5,979
|
|
|
|
146,907
|
|
Allocation of Parent incremental debt borrowings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(227,106
|
)
|
Net settlement of allocated indebtedness and debt issue costs
|
|
|
|
|
|
|
|
|
|
|
121,145
|
|
|
|
|
|
|
|
180,656
|
|
|
|
5,903
|
|
|
|
6,229
|
|
Net contribution of affiliated receivables
|
|
|
|
|
|
|
|
|
|
|
145,606
|
|
|
|
|
|
|
|
38,856
|
|
|
|
|
|
|
|
|
|
Parent settlement of risk management activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,774
|
|
|
|
(3,384
|
)
|
Other
|
|
|
|
|
|
|
|
|
|
|
3,452
|
|
|
|
|
|
|
|
|
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
329,603
|
|
|
|
|
|
|
|
219,512
|
|
|
|
13,928
|
|
|
|
142,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
195,960
|
|
|
|
|
|
|
$
|
218,993
|
|
|
$
|
(77,614
|
)
|
|
$
|
138,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Centralized
Cash Management
Prior to the contribution of the assets of the North Texas, SAOU
and LOU Systems, Targa operated a cash management system whereby
the excess cash from these subsidiaries was held in separate
bank accounts and swept to a centralized corporate account.
After the contribution of the assets from these systems, the
Partnership maintained its own centralized cash management
system.
F-23
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For the North Texas System, prior to February 14, 2007,
cash distributions are deemed to have occurred through
partners capital and are reflected as an adjustment to
partners capital. Prior to February 14, 2007, the
cash accounts of the Partnership were part of Targas
centralized cash management system. After this date, the
Partnership maintains its own cash management system. For the
period from January 1, 2007 through February 13, 2007,
deemed net capital distributions from the Partnership were
$0.5 million.
For the SAOU and LOU Systems, the same centralized cash
management system was also maintained until October 23,
2007. After this date, the SAOU and LOU Systems transactions
were cleared as part of the Partnerships cash management
system. For the period from January 1, 2007 though
October 23, 2007, deemed net capital distributions from the
Partnership were $133.6 million.
Other
Commodity hedges. We have entered into various
commodity derivative transactions with Merrill Lynch Commodities
Inc. (MLCI), an affiliate of Merrill Lynch, Pierce,
Fenner & Smith Incorporated (Merrill
Lynch). Merrill Lynch holds an equity interest in the
holding company that indirectly owns our general partner. Under
the terms of these various commodity derivative transactions,
MLCI has agreed to pay us specified fixed prices in relation to
specified notional quantities of natural gas and condensate over
periods ending in 2010, and we have agreed to pay MLCI floating
prices based on published index prices of such commodities for
delivery at specified locations. The following table shows our
open commodity derivatives with MLCI as of December 31,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Commodity
|
|
Instrument Type
|
|
Daily Volumes
|
|
Average Price
|
|
|
Index
|
|
Jan 2008 Mar 2008
|
|
Natural gas
|
|
Swap
|
|
1,650 MMBtu
|
|
$
|
8.47 per MMBtu
|
|
|
NY-HH
|
Jan 2008 Dec 2008
|
|
Natural gas
|
|
Swap
|
|
3,847 MMBtu
|
|
|
8.76 per MMBtu
|
|
|
IF-Waha
|
Jan 2009 Dec 2009
|
|
Natural gas
|
|
Swap
|
|
3,556 MMBtu
|
|
|
8.07 per MMBtu
|
|
|
IF-Waha
|
Jan 2010 Dec 2010
|
|
Natural gas
|
|
Swap
|
|
3,289 MMBtu
|
|
|
7.39 per MMBtu
|
|
|
IF-Waha
|
Jan 2008 Mar 2008
|
|
NGL
|
|
Swap
|
|
470 Bbl
|
|
|
1.39 per gallon
|
|
|
OPIS-MB
|
Jan 2008 Dec 2008
|
|
NGL
|
|
Swap
|
|
3,175 Bbl
|
|
|
1.06 per gallon
|
|
|
OPIS-MB
|
Jan 2009 Dec 2009
|
|
NGL
|
|
Swap
|
|
3,000 Bbl
|
|
|
0.98 per gallon
|
|
|
OPIS-MB
|
Jan 2008 Dec 2008
|
|
Condensate
|
|
Swap
|
|
264 Bbl
|
|
|
72.66 per barrel
|
|
|
NY-WTI
|
Jan 2009 Dec 2009
|
|
Condensate
|
|
Swap
|
|
202 Bbl
|
|
|
70.60 per barrel
|
|
|
NY-WTI
|
Jan 2010 Dec 2010
|
|
Condensate
|
|
Swap
|
|
181 Bbl
|
|
|
69.28 per barrel
|
|
|
NY-WTI
|
At December 31, 2007, the fair value of all these open
positions is a liability of $25.6 million. During 2007, we
paid MLCI $1.9 million to settle payments due under hedge
transactions. During 2006, Merrill Lynch paid us
$4.2 million in commodity derivative settlements. There
were no commodity derivative settlements with Merrill Lynch
prior to 2006.
F-24
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 8
|
Property,
Plant, and Equipment
|
Property, plant, and equipment and accumulated depreciation were
as follows at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(in thousands)
|
|
|
Gathering and processing systems
|
|
$
|
1,363,791
|
|
|
$
|
1,362,980
|
|
Other property and equipment
|
|
|
70,164
|
|
|
|
28,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,433,955
|
|
|
|
1,391,644
|
|
Accumulated depreciation
|
|
|
(174,361
|
)
|
|
|
(103,073
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,259,594
|
|
|
$
|
1,288,571
|
|
|
|
|
|
|
|
|
|
|
Pre-IPO Indebtedness. In April 2004, Targa
acquired the SAOU and LOU Systems from ConocoPhillips for
$247 million of which $124 million of the acquisition
costs was borrowed and allocated to the SAOU and LOU Systems.
The entities holding the SAOU and LOU Systems provided a
guarantee of this indebtedness. This indebtedness was also
secured by a collateral interest in both the equity of the
entities holding the SAOU and LOU Systems as well as their
assets.
In October 2005, Targa completed the DMS acquisition, which
included the North Texas System. A substantial portion of the
acquisition was financed through borrowings. Following the
acquisition, a significant portion of Targas acquisition
borrowings were allocated to the North Texas System, resulting
in approximately $870.1 million of allocated indebtedness
and corresponding levels of interest expense. The entity holding
the North Texas System provided a guarantee of this
indebtedness. This indebtedness was also secured by a collateral
interest in both the equity of the entity holding the North
Texas System as well as its assets.
On January 1, 2007, Targa contributed to us affiliated
indebtedness related to the North Texas System of approximately
$904.5 million (including accrued interest of
$88.3 million computed at 10% per anum). We recorded
approximately $9.8 million in interest expense associated
with this affiliated debt for the period from January 1,
2007 through February 13, 2007. On February 14, 2007,
Targa contributed its interest in Targa North Texas GP LLC and
Targa North Texas LP to us.
The stated 10% interest rate in the formal debt arrangement is
not indicative of prevailing external rates of interest
including that incurred under our credit facility which is
secured by substantially all of our assets. On a pro forma
basis, at prevailing interest rates the affiliated interest
expense for the period from January 1, 2007 to
February 13, 2007 would have been reduced by
$3.0 million. The pro forma interest expense adjustment has
been calculated by applying the weighted average rate of 6.9%
that we incurred under our revolving credit facility to the
affiliate debt balance for the period from January 1, 2007
to February 13, 2007.
Post-IPO Indebtedness. On February 14,
2007, we entered into a credit agreement which provides for a
five-year $500 million revolving credit facility with a
syndicate of financial institutions. The revolving credit
facility bears interest at the Partnerships option, at the
higher of the lenders prime rate or the federal funds rate
plus 0.5%, plus an applicable margin ranging from 0% to 1.25%
dependent on the Partnerships total leverage ratio, or
LIBOR plus an applicable margin ranging from 1.0% to 2.25%
dependent on the Partnerships total leverage ratio. The
Partnership initially borrowed $342.5 million under its
credit facility, and concurrently repaid $48.0 million
under its credit facility with the proceeds from the 2,520,000
common units sold pursuant to the full exercise by the
underwriters of their option to purchase additional common
units. The net proceeds of $294.5 million from this
borrowing, together with approximately $371.2 million of
available cash from the IPO (after payment of offering and debt
issue costs and necessary operating cash reserve balances), were
used to repay approximately $665.7 million of affiliate
indebtedness. In connection
F-25
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
with our IPO, the guarantee of indebtedness from the entity
holding the North Texas System was terminated, the related
collateral interest was released and the remaining affiliate
indebtedness was retired and treated as a capital contribution
to the Partnership. Our credit facility is secured by
substantially all of our assets. Our weighted average interest
rate on outstanding borrowings under our credit facility for the
period from February 14, 2007 to December 31, 2007 was
6.7%.
On October 24, 2007, we completed the acquisition of the
SAOU and LOU Systems from Targa. As part of the acquisition of
the SAOU and LOU Systems, the allocated indebtedness was settled
with Targa through an adjustment to parent equity and the
collateralization of the assets was released.
Concurrent with the acquisition of the SAOU and LOU Systems, we
entered into a Commitment Increase Supplement (the
Supplement) to our existing five-year
$500 million senior secured revolving credit facility to
increase the credit facility. The Supplement increased the
aggregate commitments under the Credit Agreement by
$250 million to an aggregate $750 million. We paid for
our acquisition of the SAOU and LOU Systems with the proceeds
from our offering of common units and approximately
$378.9 million in incremental borrowings under the
increased senior secured revolving credit facility.
Substantially all of the assets of the Partnership (North Texas,
SAOU and LOU Systems) are currently pledged as collateral on our
$750 million credit facility.
On October 24, 2007, we entered into the First Amendment to
Credit Agreement (the Amendment). The Amendment
increased by $250 million the maximum amount of increases
to the aggregate commitments that may be requested by us. The
Amendment allows us to request commitments under the Credit
Agreement, as supplemented and amended, up to $1 billion.
The credit agreement restricts our ability to make distributions
of available cash to unitholders if we are in any default or an
event of default (as defined in the credit agreement) exists.
The credit agreement requires us to maintain a leverage ratio
(the ratio of consolidated indebtedness to our consolidated
EBITDA, as defined in the credit agreement) of no more than 5.00
to 1.00 on the last day of any fiscal quarter ending on or after
September 30, 2007. The credit agreement also requires us
to maintain an interest coverage ratio (the ratio of our
consolidated EBITDA to our consolidated interest expense, as
defined in the credit agreement) of no less than 2.25 to 1.00
determined as of the last day of each quarter for the
four-fiscal quarter period ending on the date of determination.
In addition, the credit agreement contains various covenants
that may limit, among other things, our ability to:
|
|
|
|
|
incur indebtedness;
|
|
|
|
grant liens; and
|
|
|
|
engage in transactions with affiliates.
|
The credit facility matures on February 14, 2012, at which
time all unpaid principal and interest is due.
As of December 31, 2007, we had approximately
$97.8 million available under our revolving credit
facility, after giving effect to our outstanding borrowings of
$626.3 million and the issuance of $25.9 million of
letters of credit.
|
|
Note 10
|
Derivative
Instruments and Hedging Activities
|
At December 31, 2007 and 2006, OCI included
$74.0 million of unrealized net losses and
$30.5 million ($30.2 million, net of tax) of
unrealized net gains, respectively, on commodity hedges.
For the years ended December 31, 2007, 2006 and 2005
deferred net gains/(losses) on commodity hedges of
$1.0 million, ($0.8) million and $10.4 million
were reclassified from OCI to revenues, respectively. There were
no adjustments for hedge ineffectiveness for the years ended
December 31, 2007, 2006 or 2005.
F-26
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2007, OCI also included $1.2 million
of unrealized losses on interest rate hedges. At
December 31, 2006, OCI also included $0.6 million of
unrealized gains on interest rate hedges allocated from Targa.
In connection with our IPO, all allocated debt was repaid or
retired, and the associated allocated interest rate swaps were
also retired.
For the years ended December 31, 2007, 2006 and 2005,
deferred net gain/(losses) on interest rate hedges of
($0.2) million, ($0.5) million and $0.1 million
were reclassified from OCI to net interest expense,
respectively. There were no adjustments for hedge
ineffectiveness for the years ended December 31, 2007, 2006
or 2005.
At December 31, 2007, deferred net losses of
$36.4 million on commodity hedges and $0.3 million on
interest rate hedges recorded in OCI are expected to be
reclassified to expense during the next twelve months.
At December 31, 2007, we had the following hedge
arrangements which will settle during the years ended
December 31, 2008 thru 2012:
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
MMBtu per Day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
$/MMBtu
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Natural Gas Purchases
|
Swap
|
|
NY-HH
|
|
|
8.34
|
|
|
|
1,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(341
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(341
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales
|
Swap
|
|
IF-HSC
|
|
|
8.09
|
|
|
|
2,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
513
|
|
Swap
|
|
IF-HSC
|
|
|
7.39
|
|
|
|
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(551
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,328
|
|
|
|
1,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.43
|
|
|
|
6,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,475
|
|
Swap
|
|
IF-NGPL MC
|
|
|
8.02
|
|
|
|
|
|
|
|
6,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,110
|
|
Swap
|
|
IF-NGPL MC
|
|
|
7.43
|
|
|
|
|
|
|
|
|
|
|
|
5,685
|
|
|
|
|
|
|
|
|
|
|
|
(667
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
|
|
|
|
(387
|
)
|
Swap
|
|
IF-NGPL MC
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,750
|
|
|
|
(435
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,964
|
|
|
|
6,256
|
|
|
|
5,685
|
|
|
|
2,750
|
|
|
|
2,750
|
|
|
|
4,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
IF-Waha
|
|
|
8.20
|
|
|
|
7,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,000
|
|
Swap
|
|
IF-Waha
|
|
|
7.61
|
|
|
|
|
|
|
|
6,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(618
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.38
|
|
|
|
|
|
|
|
|
|
|
|
5,709
|
|
|
|
|
|
|
|
|
|
|
|
(1,288
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
|
|
|
|
(709
|
)
|
Swap
|
|
IF-Waha
|
|
|
7.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,250
|
|
|
|
(789
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,389
|
|
|
|
6,936
|
|
|
|
5,709
|
|
|
|
3,250
|
|
|
|
3,250
|
|
|
|
(404
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
16,681
|
|
|
|
15,158
|
|
|
|
11,394
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
3,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218
|
|
Floor
|
|
IF-NGPL MC
|
|
|
6.55
|
|
|
|
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
IF-Waha
|
|
|
6.85
|
|
|
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
140
|
|
Floor
|
|
IF-Waha
|
|
|
6.55
|
|
|
|
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
670
|
|
|
|
565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
1,670
|
|
|
|
1,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap Jan 2008 Rec IF-HH minus $0.01, pay GD-HH,
403,000 MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-27
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
NGLs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/gal
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
NGL Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
OPIS-MB
|
|
|
|
1.02
|
|
|
|
7,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(40,051
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.96
|
|
|
|
|
|
|
|
6,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,573
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.91
|
|
|
|
|
|
|
|
|
|
|
|
4,809
|
|
|
|
|
|
|
|
|
|
|
|
(5,506
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,400
|
|
|
|
|
|
|
|
(3,210
|
)
|
Swap
|
|
|
OPIS-MB
|
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,700
|
|
|
|
(2,030
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,127
|
|
|
|
6,248
|
|
|
|
4,809
|
|
|
|
3,400
|
|
|
|
2,700
|
|
|
$
|
(71,370
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg. Price
|
|
|
Barrels per day
|
|
|
|
|
Instrument Type
|
|
Index
|
|
|
$/Bbl
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Condensate Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
NY-WTI
|
|
|
|
70.68
|
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,013
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
69.00
|
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,008
|
)
|
Swap
|
|
|
NY-WTI
|
|
|
|
68.10
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(1,705
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
|
|
|
|
|
384
|
|
|
|
322
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
(6,726
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.50
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Floor
|
|
|
NY-WTI
|
|
|
|
60.00
|
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Floors
|
|
|
|
|
|
|
|
|
|
|
55
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
439
|
|
|
|
372
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
$
|
(6,715
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
Hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Commodity
|
|
|
Instrument Type
|
|
Daily Volume
|
|
|
Average Price
|
|
|
Index
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 June 2008
|
|
|
Natural gas
|
|
|
Swap
|
|
|
8,440 MMBtu
|
|
|
|
7.23 per MMBtu
|
|
|
|
NY-HH
|
|
|
$
|
8
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2008 June 2008
|
|
|
Natural gas
|
|
|
Fixed price sale
|
|
|
8,440 MMBtu
|
|
|
|
7.23 per MMBtu
|
|
|
|
NY-HH
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of derivative instruments, depending on the type
of instrument, was determined by the use of present value
methods or standard option valuation models with assumptions
about commodity prices based on those observed in underlying
markets. These contracts may expose us to the risk of financial
loss in certain circumstances. Our hedging arrangements provide
us protection on the hedged volumes if prices decline below the
prices at which these hedges are set. If prices rise above the
prices at which we have hedged, we will receive less revenue on
the hedged volumes than we would receive in the absence of
hedges.
Our earnings are also affected by use of the
mark-to-market
method of accounting as required under SFAS 133 for
derivative financial instruments that do not qualify for hedge
accounting. The changes in fair value of these instruments are
recorded on the balance sheet and through earnings (i.e., using
the
F-28
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
mark-to-market
method) rather than being deferred until the anticipated
transaction affects earnings. The use of
mark-to-market
accounting for financial instruments can cause non-cash earnings
volatility due to changes in the underlying commodity price
indices. During 2007, 2006 and 2005, we recorded
mark-to-market
gains /(losses) of ($30.2) million, $16.8 million
and ($12.0) million, respectively. At December 31,
2007, all of our derivative financial instruments qualify for
hedge accounting.
In December 2007, we entered into interest rate swaps with a
notional amount of $200 million. At December 31, 2007,
we had the following open interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective Date
|
|
|
Expiration Date
|
|
|
Notional Amount
|
|
|
Index
|
|
|
Fixed Rate
|
|
|
|
12/13/2007
|
|
|
|
1/24/2011
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.0775
|
%
|
|
12/18/2007
|
|
|
|
1/24/2011
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.2100
|
%
|
|
12/21/2007
|
|
|
|
1/24/2012
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.0750
|
%
|
|
12/21/2007
|
|
|
|
1/24/2012
|
|
|
$
|
50,000,000
|
|
|
|
3 Month USD LIBOR
|
|
|
|
4.0750
|
%
|
Each of these interest rate swaps have been designated as cash
flow hedges of variable rate interest payments on
$50 million in borrowings under our revolving credit
facility. At December 31, 2007, the fair value of our
interest rate swaps was $1.2 million.
|
|
Note 11
|
Share-Based Compensation
|
Our general partner has adopted a long-term incentive plan
(the Plan) for employees, consultants and directors
of the general partner and its affiliates who perform services
for us. We account for awards under the Plan utilizing the fair
value recognition provisions of SFAS 123R,
Share-Based Payment.
Non-Employee
Director Grants
In connection with our IPO, our general partner made
equity-based awards of 16,000 restricted common units of the
Partnership (2,000 restricted common units in the Partnership to
each of the Partnerships and Targa Investments
non-management directors) under the Plan. The awards will settle
with the delivery of common units and are subject to three-year
vesting, without a performance condition, and will vest ratably
on each anniversary of the grant date.
Compensation expense on the restricted common units is
recognized on a straight-line basis over the vesting period. The
fair value of an award of restricted common units is measured on
the grant date using the market price of a common unit on such
date. During 2007, we recognized compensation expense of
$180,000 related to these awards. We estimate that the remaining
fair value of $156,000 will be recognized in expense over the
next 26 months.
We are not a taxable entity for United States Federal income tax
purposes. Taxes on our net income are generally borne by our
unitholders through allocations of taxable income pursuant to
the partnership agreement. In May 2006, Texas substantially
revised its tax rules and imposed a new tax based on modified
gross margin, beginning in 2007. Pursuant to the guidance of
SFAS 109, Accounting for Income Taxes,
we have accounted for this tax as an income tax. Our income
tax expense of $1.5 million for the year ended
December 31, 2007, was computed by applying a 1.0% state
income tax rate to taxable margin, as defined in the Texas
statute.
F-29
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 13
|
Commitments
and Contingencies
|
Contractual obligations pertain to a natural gas pipeline
capacity agreement on certain interstate pipelines, operating
leases and AROs. Future non-cancelable commitments related to
these obligations are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 &
|
|
Contractual Obligations
|
|
Total
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
|
(in thousands)
|
|
|
Operating lease obligations
|
|
$
|
142
|
|
|
$
|
110
|
|
|
$
|
32
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Capacity payments
|
|
|
16,777
|
|
|
|
9,201
|
|
|
|
5,306
|
|
|
|
1,492
|
|
|
|
778
|
|
|
|
|
|
|
|
|
|
Right of way
|
|
|
4,947
|
|
|
|
310
|
|
|
|
269
|
|
|
|
255
|
|
|
|
255
|
|
|
|
252
|
|
|
|
3,606
|
|
Asset retirement obligation
|
|
|
3,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
25,129
|
|
|
$
|
9,621
|
|
|
$
|
5,607
|
|
|
$
|
1,747
|
|
|
$
|
1,033
|
|
|
$
|
252
|
|
|
$
|
6,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses related to operating lease obligations, capacity
payments and right-of-way payments were $5.7 million,
$3.2 million, and $0.5 million for the years ended
December 31, 2007, 2006 and 2005, respectively.
Environmental
For environmental matters, the Partnership records liabilities
when remedial efforts are probable and the costs are reasonably
estimated in accordance with the American Institute of Certified
Public Accountants Statement of Position
96-1,
Environmental Remediation Liabilities.
Environmental reserves do not reflect managements
assessment of the insurance coverage that may be applicable to
the matters at issue. Management has assessed each of the
matters based on current information and made a judgment
concerning its potential outcome, considering the nature of the
claim, the amount and nature of damages sought and the
probability of success. This liability was transferred as part
of the assets contributed to us at the time of our IPO.
Our environmental liability was $0.3 million at
December 31, 2007, primarily for ground water assessment
and remediation.
Under the Omnibus Agreement described in Note 7, Targa has
indemnified us for three years from February 14, 2007,
against certain potential environmental claims, losses and
expenses associated with the operation of the North Texas System
and occurring before such date that were not reserved on the
books of the North Texas System. Targas maximum liability
for this indemnification obligation will not exceed
$10.0 million and Targa will not have any obligation under
this indemnification until our aggregate losses exceed $250,000.
We have indemnified Targa against environmental liabilities
related to the North Texas System arising or occurring after
February 14, 2007.
Litigation
On December 8, 2005, WTG Gas Processing (WTG)
filed suit in the 333rd District Court of Harris County,
Texas against several defendants, including Targa Resources,
Inc., and three other Targa entities and private equity funds
affiliated with Warburg Pincus LLC, seeking damages from the
defendants. The suit alleges that Targa and private equity funds
affiliated with Warburg Pincus LLC, along with ConocoPhillips
Company (ConocoPhillips) and Morgan Stanley,
tortiously interfered with (i) a contract WTG claims to
have had to purchase certain ConocoPhillips assets, and
(ii) prospective business relations of WTG. WTG claims the
alleged interference resulted from Targas competition to
purchase the ConocoPhillips assets and its successful
acquisition of those assets in 2004. On October 2, 2007,
the District Court granted defendants
F-30
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
motions for summary judgment on all of WTGs claims. Targa
has agreed to indemnify us for any claim or liability arising
out of the WTG suit. WTGs motion to reconsider and for a
new trial was overruled. On January 2, 2008, WTG filed a
notice of appeal. Targa will contest any appeal filed by WTG,
but can give no assurances regarding the outcome of the
proceeding.
|
|
Note 14
|
Significant
Risks and Uncertainties
|
Nature
of Operations in Midstream Energy Industry
We operate in the midstream energy industry. Its business
activities include gathering, transporting and processing of
natural gas, NGLs and crude oil. As such, its results of
operations, cash flows and financial condition may be affected
by (i) changes in the commodity prices of these hydrocarbon
products and (ii) changes in the relative price levels
among these hydrocarbon products. In general, the prices of
natural gas, NGLs, crude oil and other hydrocarbon products are
subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond
our control.
Our profitability could be impacted by a decline in the volume
of natural gas, NGLs and crude oil transported, gathered or
processed at its facilities. A material decrease in natural gas
or crude oil production or crude oil refining, as a result of
depressed commodity prices, a decrease in exploration and
development activities or otherwise, could result in a decline
in the volume of natural gas, NGLs and crude oil handled by our
facilities.
A reduction in demand for NGL products by the petrochemical,
refining or heating industries, whether because of
(i) general economic conditions, (ii) reduced demand
by consumers for the end products made with NGL products,
(iii) increased competition from petroleum-based products
due to the pricing differences, (iv) adverse weather
conditions, (v) government regulations affecting commodity
prices and production levels of hydrocarbons or the content of
motor gasoline or (vi) other reasons, could also adversely
affect our results of operations, cash flows and financial
position.
Counterparty
Risk with Respect to Financial Instruments
Where we are exposed to credit risk in its financial instrument
transactions, management analyzes the counterpartys
financial condition prior to entering into an agreement,
establishes credit
and/or
margin limits and monitors the appropriateness of these limits
on an ongoing basis. Generally, management does not require
collateral and does not anticipate nonperformance by our
counterparties.
Casualty
or Other Risks
Targa maintains coverage in various insurance programs on our
behalf, which provides us with property damage, business
interruption and other coverages which are customary for the
nature and scope of our operations.
Management believes that Targa has adequate insurance coverage,
although insurance will not cover every type of interruption
that might occur. As a result of insurance market conditions,
premiums and deductibles for certain insurance policies have
increased substantially, and in some instances, certain
insurance may become unavailable, or available for only reduced
amounts of coverage. As a result, Targa may not be able to renew
existing insurance policies or procure other desirable insurance
on commercially reasonable terms, if at all.
If we were to incur a significant liability for which we were
not fully insured, it could have a material impact on our
consolidated financial position and results of operations. In
addition, the proceeds of any such insurance may not be paid in
a timely manner and may be insufficient if such an event were to
occur. Any event that interrupts the revenues generated by us,
or which causes us to make significant expenditures not covered
by insurance, could reduce our ability to meet our financial
obligations.
F-31
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A portion of the insurance costs described above is allocated to
us by Targa through the allocation methodology as prescribed in
the Omnibus Agreement described in Note 7.
Under the Omnibus Agreement, Targa has also indemnified us for
losses attributable to rights-of-way, certain consents or
governmental permits, pre-closing litigation relating to the
North Texas System and income taxes attributable to pre-closing
operations that were not reserved on the books of the North
Texas System as of February 14, 2007. Targa does not have
any obligation under these indemnifications until our aggregate
losses exceed $250,000. We have indemnified Targa for all losses
attributable to the post-closing operations of the North Texas
System. Targas obligations under this additional
indemnification will survive for three years from
February 14, 2007, except that the indemnification for
income tax liabilities will terminate upon the expiration of the
applicable statutes of limitations.
|
|
Note 15
|
Selected
Quarterly Financial Data (Unaudited)
|
The Partnerships results of operations by quarter for the
years ended December 31, 2007 and 2006, as adjusted to
reflect the consideration of common control accounting and
change in predecessor entities as discussed in Note 4, were
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Total
|
|
|
|
(Dollars in thousands, except per unit amounts)
|
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
348,781
|
|
|
$
|
433,615
|
|
|
$
|
405,038
|
|
|
$
|
474,035
|
|
|
$
|
1,661,469
|
|
Operating income
|
|
|
20,739
|
|
|
|
28,183
|
|
|
|
29,965
|
|
|
|
34,467
|
|
|
|
113,354
|
|
Net income (loss)
|
|
|
(10,627
|
)
|
|
|
13,811
|
|
|
|
14,392
|
|
|
|
22,674
|
|
|
|
40,250
|
|
less: net income (loss) attributable to predecessor operations
|
|
|
(12,780
|
)
|
|
|
9,771
|
|
|
|
10,523
|
|
|
|
4,670
|
|
|
|
12,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to partners
|
|
|
2,153
|
|
|
|
4,040
|
|
|
|
3,869
|
|
|
|
18,004
|
|
|
|
28,066
|
|
General partner interest in net income
|
|
|
43
|
|
|
|
81
|
|
|
|
77
|
|
|
|
360
|
|
|
|
561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common and subordinated unitholders
|
|
$
|
2,110
|
|
|
$
|
3,959
|
|
|
$
|
3,792
|
|
|
$
|
17,644
|
|
|
$
|
27,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income per limited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
partner unit
|
|
$
|
0.07
|
|
|
$
|
0.13
|
|
|
$
|
0.12
|
|
|
$
|
0.42
|
|
|
$
|
0.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic number of units
|
|
|
30,848
|
|
|
|
30,848
|
|
|
|
30,848
|
|
|
|
41,795
|
|
|
|
33,986
|
|
Diluted number of units
|
|
|
30,852
|
|
|
|
30,856
|
|
|
|
30,857
|
|
|
|
41,805
|
|
|
|
33,994
|
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
523,858
|
|
|
$
|
453,721
|
|
|
$
|
401,267
|
|
|
$
|
359,679
|
|
|
$
|
1,738,525
|
|
Operating income
|
|
|
24,789
|
|
|
|
22,983
|
|
|
|
22,869
|
|
|
|
15,121
|
|
|
|
85,762
|
|
Net income (loss)
|
|
|
14,925
|
|
|
|
(3,681
|
)
|
|
|
8,241
|
|
|
|
(7,918
|
)
|
|
|
11,567
|
|
Basic income per limited partner unit(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Total basic net income per limited partner unit was not
calculated as Partner Units were not outstanding as of
December 31, 2006.
|
F-32
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables present the impact on the condensed
consolidated statement of operation, adjusted for the
acquisition of the SAOU and LOU Systems from Targa, for the
periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, 2007
|
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
Revenues from third parties
|
|
$
|
134,106
|
|
|
$
|
6,084
|
|
|
$
|
140,190
|
|
Revenues from affiliates
|
|
|
121,082
|
|
|
|
87,509
|
|
|
|
208,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
255,188
|
|
|
|
93,593
|
|
|
|
348,781
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
190,709
|
|
|
|
63,445
|
|
|
|
254,154
|
|
Product purchases from affiliates
|
|
|
40,101
|
|
|
|
243
|
|
|
|
40,344
|
|
Operating expenses
|
|
|
6,184
|
|
|
|
5,968
|
|
|
|
12,152
|
|
Depreciation and amortization expense
|
|
|
3,843
|
|
|
|
14,195
|
|
|
|
18,038
|
|
General and administrative expense
|
|
|
1,776
|
|
|
|
1,578
|
|
|
|
3,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
242,613
|
|
|
|
85,429
|
|
|
|
328,042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
12,575
|
|
|
|
8,164
|
|
|
|
20,739
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
3,616
|
|
|
|
9,827
|
|
|
|
13,443
|
|
Interest expense, net
|
|
|
|
|
|
|
2,705
|
|
|
|
2,705
|
|
Loss on mark-to-market derivative contracts
|
|
|
14,880
|
|
|
|
|
|
|
|
14,880
|
|
Other
|
|
|
(21
|
)
|
|
|
|
|
|
|
(21
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
(5,900
|
)
|
|
|
(4,368
|
)
|
|
|
(10,268
|
)
|
Deferred income tax expense
|
|
|
21
|
|
|
|
338
|
|
|
|
359
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
(5,921
|
)
|
|
$
|
(4,706
|
)
|
|
$
|
(10,627
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-33
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ending
|
|
|
For the Six Months Ending
|
|
|
|
June 30, 2007
|
|
|
June 30, 2007
|
|
|
|
|
|
|
|
|
|
Targa
|
|
|
SAOU/LOU
|
|
|
|
|
|
Targa
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
System
|
|
|
North Texas
|
|
|
Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
(restated)a
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
Revenues from third parties
|
|
$
|
170,849
|
|
|
$
|
4,300
|
|
|
$
|
175,149
|
|
|
$
|
304,955
|
|
|
$
|
10,384
|
|
|
$
|
315,339
|
|
Revenues from affiliates
|
|
|
156,363
|
|
|
|
102,103
|
|
|
|
258,466
|
|
|
|
277,445
|
|
|
|
189,612
|
|
|
|
467,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
327,212
|
|
|
|
106,403
|
|
|
|
433,615
|
|
|
|
582,400
|
|
|
|
199,996
|
|
|
|
782,396
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
236,159
|
|
|
|
74,306
|
|
|
|
310,465
|
|
|
|
426,868
|
|
|
|
137,751
|
|
|
|
564,619
|
|
Product purchases from affiliates
|
|
|
60,965
|
|
|
|
271
|
|
|
|
61,236
|
|
|
|
101,066
|
|
|
|
514
|
|
|
|
101,580
|
|
Operating expenses
|
|
|
5,730
|
|
|
|
6,065
|
|
|
|
11,795
|
|
|
|
11,914
|
|
|
|
12,033
|
|
|
|
23,947
|
|
Depreciation and amortization expense
|
|
|
3,330
|
|
|
|
14,289
|
|
|
|
17,619
|
|
|
|
7,173
|
|
|
|
28,484
|
|
|
|
35,657
|
|
General and administrative expense
|
|
|
2,679
|
|
|
|
1,953
|
|
|
|
4,632
|
|
|
|
4,455
|
|
|
|
3,531
|
|
|
|
7,986
|
|
Loss (gain) on sale of assets
|
|
|
(315
|
)
|
|
|
|
|
|
|
(315
|
)
|
|
|
(315
|
)
|
|
|
|
|
|
|
(315
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
308,548
|
|
|
|
96,884
|
|
|
|
405,432
|
|
|
|
551,161
|
|
|
|
182,313
|
|
|
|
733,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
18,664
|
|
|
|
9,519
|
|
|
|
28,183
|
|
|
|
31,239
|
|
|
|
17,683
|
|
|
|
48,922
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
2,732
|
|
|
|
|
|
|
|
2,732
|
|
|
|
6,348
|
|
|
|
9,827
|
|
|
|
16,175
|
|
Interest expense, net
|
|
|
|
|
|
|
5,154
|
|
|
|
5,154
|
|
|
|
|
|
|
|
7,859
|
|
|
|
7,859
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
6,122
|
|
|
|
|
|
|
|
6,122
|
|
|
|
21,002
|
|
|
|
|
|
|
|
21,002
|
|
Other
|
|
|
16
|
|
|
|
|
|
|
|
16
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
9,794
|
|
|
|
4,365
|
|
|
|
14,159
|
|
|
|
3,894
|
|
|
|
(3
|
)
|
|
|
3,891
|
|
Deferred income tax expense
|
|
|
21
|
|
|
|
327
|
|
|
|
348
|
|
|
|
42
|
|
|
|
665
|
|
|
|
707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
9,773
|
|
|
$
|
4,038
|
|
|
$
|
13,811
|
|
|
$
|
3,852
|
|
|
$
|
(668
|
)
|
|
$
|
3,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
a)
|
Previously reported allocated interest expense from parent has
been adjusted to reflect an additional allocation of interest
expense of $1.5 million.
|
F-34
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ending
|
|
|
For the Nine Months Ending
|
|
|
|
September 30, 2007
|
|
|
September 30, 2007
|
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
Revenues from third parties
|
|
$
|
142,036
|
|
|
$
|
6,951
|
|
|
$
|
148,987
|
|
|
$
|
446,991
|
|
|
$
|
17,335
|
|
|
$
|
464,326
|
|
Revenues from affiliates
|
|
|
155,339
|
|
|
|
100,712
|
|
|
|
256,051
|
|
|
|
432,784
|
|
|
|
290,324
|
|
|
|
723,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
297,375
|
|
|
|
107,663
|
|
|
|
405,038
|
|
|
|
879,775
|
|
|
|
307,659
|
|
|
|
1,187,434
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
225,035
|
|
|
|
74,457
|
|
|
|
299,492
|
|
|
|
651,903
|
|
|
|
212,208
|
|
|
|
864,111
|
|
Product purchases from affiliates
|
|
|
38,042
|
|
|
|
228
|
|
|
|
38,270
|
|
|
|
139,108
|
|
|
|
742
|
|
|
|
139,850
|
|
Operating expenses
|
|
|
6,193
|
|
|
|
6,543
|
|
|
|
12,736
|
|
|
|
18,107
|
|
|
|
18,576
|
|
|
|
36,683
|
|
Depreciation and amortization expense
|
|
|
3,588
|
|
|
|
14,396
|
|
|
|
17,984
|
|
|
|
10,761
|
|
|
|
42,880
|
|
|
|
53,641
|
|
General and administrative expense
|
|
|
3,795
|
|
|
|
2,779
|
|
|
|
6,574
|
|
|
|
8,250
|
|
|
|
6,310
|
|
|
|
14,560
|
|
Loss (gain) on sale of assets
|
|
|
17
|
|
|
|
|
|
|
|
17
|
|
|
|
(298
|
)
|
|
|
|
|
|
|
(298
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
276,670
|
|
|
|
98,403
|
|
|
|
375,073
|
|
|
|
827,831
|
|
|
|
280,716
|
|
|
|
1,108,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
20,705
|
|
|
|
9,260
|
|
|
|
29,965
|
|
|
|
51,944
|
|
|
|
26,943
|
|
|
|
78,887
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
2,806
|
|
|
|
|
|
|
|
2,806
|
|
|
|
9,154
|
|
|
|
9,827
|
|
|
|
18,981
|
|
Interest expense, net
|
|
|
|
|
|
|
5,059
|
|
|
|
5,059
|
|
|
|
|
|
|
|
12,918
|
|
|
|
12,918
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
7,367
|
|
|
|
|
|
|
|
7,367
|
|
|
|
28,369
|
|
|
|
|
|
|
|
28,369
|
|
Other
|
|
|
(12
|
)
|
|
|
|
|
|
|
(12
|
)
|
|
|
(17
|
)
|
|
|
|
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
10,544
|
|
|
|
4,201
|
|
|
|
14,745
|
|
|
|
14,438
|
|
|
|
4,198
|
|
|
|
18,636
|
|
Deferred income tax expense
|
|
|
21
|
|
|
|
332
|
|
|
|
353
|
|
|
|
63
|
|
|
|
997
|
|
|
|
1,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
10,523
|
|
|
$
|
3,869
|
|
|
$
|
14,392
|
|
|
$
|
14,375
|
|
|
$
|
3,201
|
|
|
$
|
17,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-35
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ending March 31, 2006
|
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
Revenues from third parties
|
|
$
|
353,613
|
|
|
$
|
1,857
|
|
|
$
|
355,470
|
|
Revenues from affiliates
|
|
|
73,995
|
|
|
|
94,393
|
|
|
|
168,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
427,608
|
|
|
|
96,250
|
|
|
|
523,858
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
283,059
|
|
|
|
67,694
|
|
|
|
350,753
|
|
Product purchases from affiliates
|
|
|
117,567
|
|
|
|
172
|
|
|
|
117,739
|
|
Operating expenses
|
|
|
5,826
|
|
|
|
5,944
|
|
|
|
11,770
|
|
Depreciation and amortization expense
|
|
|
3,364
|
|
|
|
13,720
|
|
|
|
17,084
|
|
General and administrative expense
|
|
|
135
|
|
|
|
1,588
|
|
|
|
1,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
409,951
|
|
|
|
89,118
|
|
|
|
499,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
17,657
|
|
|
|
7,132
|
|
|
|
24,789
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
3,637
|
|
|
|
17,361
|
|
|
|
20,998
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
(11,134
|
)
|
|
|
|
|
|
|
(11,134
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
25,154
|
|
|
|
(10,229
|
)
|
|
|
14,925
|
|
Deferred income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
25,154
|
|
|
$
|
(10,229
|
)
|
|
$
|
14,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-36
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ending
|
|
|
For the Six Months Ending
|
|
|
|
June 30, 2006
|
|
|
June 30, 2006
|
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
Revenues from third parties
|
|
$
|
254,594
|
|
|
$
|
2,871
|
|
|
$
|
257,465
|
|
|
$
|
608,207
|
|
|
$
|
4,728
|
|
|
$
|
612,935
|
|
Revenues from affiliates
|
|
|
106,453
|
|
|
|
89,803
|
|
|
|
196,256
|
|
|
|
180,448
|
|
|
|
184,196
|
|
|
|
364,644
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
361,047
|
|
|
|
92,674
|
|
|
|
453,721
|
|
|
|
788,655
|
|
|
|
188,924
|
|
|
|
977,579
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
236,869
|
|
|
|
64,657
|
|
|
|
301,526
|
|
|
|
519,928
|
|
|
|
132,350
|
|
|
|
652,278
|
|
Product purchases from affiliates
|
|
|
96,223
|
|
|
|
227
|
|
|
|
96,450
|
|
|
|
213,790
|
|
|
|
400
|
|
|
|
214,190
|
|
Operating expenses
|
|
|
6,455
|
|
|
|
5,599
|
|
|
|
12,054
|
|
|
|
12,281
|
|
|
|
11,543
|
|
|
|
23,824
|
|
Depreciation and amortization expense
|
|
|
3,365
|
|
|
|
13,719
|
|
|
|
17,084
|
|
|
|
6,729
|
|
|
|
27,439
|
|
|
|
34,168
|
|
General and administrative expense
|
|
|
1,957
|
|
|
|
1,667
|
|
|
|
3,624
|
|
|
|
2,092
|
|
|
|
3,255
|
|
|
|
5,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
344,869
|
|
|
|
85,869
|
|
|
|
430,738
|
|
|
|
754,820
|
|
|
|
174,987
|
|
|
|
929,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
16,178
|
|
|
|
6,805
|
|
|
|
22,983
|
|
|
|
33,835
|
|
|
|
13,937
|
|
|
|
47,772
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
3,779
|
|
|
|
18,302
|
|
|
|
22,081
|
|
|
|
7,416
|
|
|
|
35,663
|
|
|
|
43,079
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
2,735
|
|
|
|
|
|
|
|
2,735
|
|
|
|
(8,399
|
)
|
|
|
|
|
|
|
(8,399
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
9,664
|
|
|
|
(11,497
|
)
|
|
|
(1,833
|
)
|
|
|
34,818
|
|
|
|
(21,726
|
)
|
|
|
13,092
|
|
Deferred income tax expense
|
|
|
394
|
|
|
|
1,454
|
|
|
|
1,848
|
|
|
|
394
|
|
|
|
1,454
|
|
|
|
1,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
9,270
|
|
|
$
|
(12,951
|
)
|
|
$
|
(3,681
|
)
|
|
$
|
34,424
|
|
|
$
|
(23,180
|
)
|
|
$
|
11,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-37
TARGA
RESOURCES PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ending
|
|
|
|
For the Three Months Ending September 30, 2006
|
|
|
September 30, 2006
|
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
|
|
|
|
|
Targa
|
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
SAOU/LOU
|
|
|
North Texas
|
|
|
Resources
|
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
System
|
|
|
System
|
|
|
Partners LP
|
|
|
|
(in thousands)
|
|
|
Revenues from third parties
|
|
$
|
171,241
|
|
|
$
|
3,505
|
|
|
$
|
174,746
|
|
|
$
|
779,448
|
|
|
$
|
8,233
|
|
|
$
|
787,681
|
|
Revenues from affiliates
|
|
|
128,060
|
|
|
|
98,461
|
|
|
|
226,521
|
|
|
|
308,508
|
|
|
|
282,657
|
|
|
|
591,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
299,301
|
|
|
|
101,966
|
|
|
|
401,267
|
|
|
|
1,087,956
|
|
|
|
290,890
|
|
|
|
1,378,846
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchases from third parties
|
|
|
212,981
|
|
|
|
72,182
|
|
|
|
285,163
|
|
|
|
732,909
|
|
|
|
204,532
|
|
|
|
937,441
|
|
Product purchases from affiliates
|
|
|
59,263
|
|
|
|
270
|
|
|
|
59,533
|
|
|
|
273,053
|
|
|
|
670
|
|
|
|
273,723
|
|
Operating expenses
|
|
|
5,857
|
|
|
|
6,362
|
|
|
|
12,219
|
|
|
|
18,138
|
|
|
|
17,905
|
|
|
|
36,043
|
|
Depreciation and amortization expense
|
|
|
3,397
|
|
|
|
14,274
|
|
|
|
17,671
|
|
|
|
10,126
|
|
|
|
41,713
|
|
|
|
51,839
|
|
General and administrative expense
|
|
|
1,930
|
|
|
|
1,882
|
|
|
|
3,812
|
|
|
|
4,022
|
|
|
|
5,137
|
|
|
|
9,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
283,428
|
|
|
|
94,970
|
|
|
|
378,398
|
|
|
|
1,038,248
|
|
|
|
269,957
|
|
|
|
1,308,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
15,873
|
|
|
|
6,996
|
|
|
|
22,869
|
|
|
|
49,708
|
|
|
|
20,933
|
|
|
|
70,641
|
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense allocated from Parent
|
|
|
3,761
|
|
|
|
18,706
|
|
|
|
22,467
|
|
|
|
11,177
|
|
|
|
54,369
|
|
|
|
65,546
|
|
Loss/(gain) on mark-to-market derivative contracts
|
|
|
(8,373
|
)
|
|
|
|
|
|
|
(8,373
|
)
|
|
|
(16,771
|
)
|
|
|
|
|
|
|
(16,771
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
20,485
|
|
|
|
(11,710
|
)
|
|
|
8,775
|
|
|
|
55,302
|
|
|
|
(33,436
|
)
|
|
|
21,866
|
|
Deferred income tax expense
|
|
|
|
|
|
|
534
|
|
|
|
534
|
|
|
|
394
|
|
|
|
1,988
|
|
|
|
2,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
20,485
|
|
|
$
|
(12,244
|
)
|
|
$
|
8,241
|
|
|
$
|
54,908
|
|
|
$
|
(35,424
|
)
|
|
$
|
19,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 16
|
Subsequent
Event
|
On January 24, 2008, our general partner approved a
quarterly distribution of available cash of $0.3975 per unit
(approximately $18.7 million), for the quarter ended
December 31, 2007, payable on February 14, 2008 to
unitholders of record as of the close of business on
February 4, 2008.
F-38
Index to
Exhibits
|
|
|
|
|
|
|
|
2
|
.1**
|
|
|
|
Purchase and Sale Agreement, dated as of September 18,
2007, by and between Targa Resources Holdings LP and Targa
Resources Partners LP (incorporated by reference to
Exhibit 2.1 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed September 21, 2007 (File
No. 001-33303)).
|
|
2
|
.2
|
|
|
|
Amendment to Purchase and Sale Agreement, dated October 1,
2007, by and between Targa Resources Holdings LP and Targa
Resources Partners LP (incorporated by reference to
Exhibit 2.2 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
3
|
.1
|
|
|
|
Certificate of Limited Partnership of Targa Resources Partners
LP (incorporated by reference to Exhibit 3.2 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed November 16, 2006 (File
No. 333-138747)).
|
|
3
|
.2
|
|
|
|
Certificate of Formation of Targa Resources GP LLC (incorporated
by reference to Exhibit 3.3 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed January 19, 2007
(File No. 333-138747)).
|
|
3
|
.3
|
|
|
|
Agreement of Limited Partnership of Targa Resources Partners LP
(incorporated by reference to Exhibit 3.3 to Targa
Resources Partners LPs Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
3
|
.4
|
|
|
|
First Amended and Restated Agreement of Limited Partnership of
Targa Resources Partners LP (incorporated by reference to
Exhibit 3.1 to Targa Resources Partners LPs current
report on
Form 8-K
filed February 16, 2007 (File
No. 001-33303)).
|
|
3
|
.5
|
|
|
|
Limited Liability Company Agreement of Targa Resources GP LLC
(incorporated by reference to Exhibit 3.4 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed January 19, 2007 (File
No. 333-138747)).
|
|
4
|
.1
|
|
|
|
Specimen Unit Certificate representing common units
(incorporated by reference to Exhibit 4.1 to Targa
Resources Partners LPs Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
10
|
.1
|
|
|
|
Credit Agreement, dated February 14, 2007, by and among
Targa Resources Partners LP, as Borrower, Bank of America, N.A.,
as Administrative Agent, Wachovia Bank, N.A., as Syndication
Agent, Merrill Lynch Capital, Royal Bank of Canada and The Royal
Bank of Scotland PLC, as Co-Documentation Agents, and the other
lenders party thereto (incorporated by reference to
Exhibit 10.1 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed February 16, 2007 (File
No. 001-33303)).
|
|
10
|
.2
|
|
|
|
Commitment Increase Supplement, dated October 24, 2007, by
and among Targa Resources Partners LP, Bank of America, N.A. and
the parties signatory thereto as the Increasing Lenders and the
New Lenders (incorporate by reference to Exhibit 10.2 to
Targa Resources Partners LPs Current Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
10
|
.3
|
|
|
|
First Amendment to Credit Agreement, dated October 24,
2007, by and among Targa Resources Partners LP, Bank of America,
N.A. and each Lender party thereto (incorporated by reference to
Exhibit 10.3 to Targa Resources Partners LPs Current
Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
10
|
.4
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
February 14, 2007, by and among Targa Resources Partners
LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa
Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa
Regulated Holdings LLC, Targa North Texas GP LLC and Targa North
Texas LP (incorporated by reference to Exhibit 10.2 to
Targa Resources Partners LPs Current Report on
Form 8-K
filed February 16, 2007
(File No. 001-33303)).
|
|
10
|
.5
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
October 24, 2007, by and among Targa Resources Partners LP,
Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa
LA LLC, Targa LA PS LP and Targa North Texas GP LLC
(incorporated by reference to Exhibit 10.4 to Targa
Resources Partners LPs Current Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
10
|
.6
|
|
|
|
Amended and Restated Omnibus Agreement, dated October 24,
2007, by and among Targa Resources Partners LP, Targa Resources,
Inc., Targa Resources LLC and Targa Resources GP LLC
(incorporated by reference to Exhibit 10.5 to Targa
Resources Partners LPs Current Report on
Form 8-K
filed October 24, 2007 (File
No. 001-33303)).
|
|
10
|
.7+
|
|
|
|
Targa Resources Partners Long-Term Incentive Plan (incorporated
by reference to Exhibit 10.2 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed February 1, 2007
(File No. 333-138747)).
|
|
|
|
|
|
|
|
|
10
|
.8+
|
|
|
|
Targa Resources Investments Inc. Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.9 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed February 1, 2007 (File
No. 333-138747)).
|
|
10
|
.9+
|
|
|
|
Form of Restricted Unit Grant Agreement (incorporated by
reference to Exhibit 10.2 to Targa Resources Partners
LPs Current Report on
Form 8-K
filed February 13, 2007 (File
No. 001-33303)).
|
|
10
|
.10+
|
|
|
|
Form of Performance Unit Grant Agreement (incorporated by
reference to Exhibit 10.2 to Targa Resources Partners
LPs Current Report on
Form 8-K
filed January 22, 2008 (File
No. 001-33303)).
|
|
10
|
.11
|
|
|
|
Gas Gathering and Purchase Agreement by and between Burlington
Resources Oil & Gas Company LP, Burlington Resources
Trading Inc. and Targa Midstream Services Limited Partnership
(portions of this exhibit have been omitted and filed separately
with the Securities and Exchange Commission pursuant to a
request for confidential treatment) (incorporated by reference
to Exhibit 10.5 to Targa Resources Partners LPs
Registration Statement on
Form S-1/A
filed February 8, 2007 (File
No. 333-138747)).
|
|
10
|
.12
|
|
|
|
Natural Gas Purchase Agreement, effective January 1, 2007,
by and between Targa Gas Marketing LLC (Buyer) and Targa North
Texas LP (Seller) (incorporated by reference to
Exhibit 10.11 to Targa Resources Partners LPs
Registration Statement on
Form S-1
filed October 1, 2007
(File No. 333-146436)).
|
|
10
|
.13
|
|
|
|
NGL and Condensate Purchase Agreement, effective January 1,
2007, by and between Targa North Texas LP (Seller) and Targa
Liquids Marketing and Trade (Buyer) (incorporated by reference
to Exhibit 10.12 to Targa Resources Partners LPs
Registration Statement on
Form S-1
filed October 1, 2007 (File
No. 333-146436)).
|
|
10
|
.14
|
|
|
|
Product Purchase Agreement, effective January 1, 2007, by
and between Targa Louisiana Field Services LLC (Seller) and
Targa Liquids Marketing and Trade (Buyer) (incorporated by
reference to Exhibit 10.13 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.15
|
|
|
|
Raw Product Purchase Agreement, effective January 1, 2007,
by and between Targa Texas Field Services LP (Seller) and Targa
Liquids Marketing and Trade (Buyer) (incorporated by reference
to Exhibit 10.14 to Targa Resources Partners LPs
Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.16
|
|
|
|
Amended and Restated Natural Gas Sales Agreement, effective
December 1, 2005, by and between Targa Louisiana Field
Services LLC (Buyer) and Targa Gas Marketing LLC (Seller)
(incorporated by reference to Exhibit 10.15 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.17
|
|
|
|
Amended and Restated Natural Gas Purchase Agreement, effective
December 1, 2005, by and between Targa Gas Marketing LLC
(Buyer) and Targa Louisiana Field Services LLC (Seller)
(incorporated by reference to Exhibit 10.16 to Targa
Resources Partners LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.18
|
|
|
|
Amended and Restated Natural Gas Purchase Agreement, effective
December 1, 2005, by and between Targa Gas Marketing LLC
(Buyer) and Targa Texas Field Services LP (Seller) (incorporated
by reference to Exhibit 10.17 to Targa Resources Partners
LPs Registration Statement on
Form S-1/A
filed October 12, 2007 (File
No. 333-146436)).
|
|
10
|
.19+
|
|
|
|
Targa Resources Partners LP Indemnification Agreement for Barry
R. Pearl dated February 14, 2007 (incorporated by reference
to Exhibit 10.11 to Targa Resources Partners LPs
Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
10
|
.20+
|
|
|
|
Targa Resources Partners LP Indemnification Agreement for Robert
B. Evans dated February 14, 2007 (incorporated by reference
to Exhibit 10.12 to Targa Resources Partners LPs
Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
10
|
.21+
|
|
|
|
Targa Resources Partners LP Indemnification Agreement for
Williams D. Sullivan dated February 14, 2007 (incorporated
by reference to Exhibit 10.13 to Targa Resources Partners
LPs Annual Report on
Form 10-K
filed April 2, 2007 (File
No. 001-33303)).
|
|
21
|
.1
|
|
|
|
Subsidiaries of Targa Resources Partners LP.*
|
|
23
|
.1
|
|
|
|
Consent of Independent Registered Public Accounting Firm*
|
|
31
|
.1
|
|
|
|
Certification of the Chief Executive Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*
|
|
|
|
|
|
|
|
|
31
|
.2
|
|
|
|
Certification of the Chief Financial Officer pursuant to
Rule 13a-14(a)/15d-14(a)
of the Securities Exchange Act of 1934.*
|
|
32
|
.1
|
|
|
|
Certification of the Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.*
|
|
32
|
.2
|
|
|
|
Certification of the Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.*
|
|
|
|
* |
|
Filed herewith |
|
** |
|
Pursuant to Item 601(b)(2) of
Regulation S-K,
the Partnership agrees to furnish supplementally a copy of any
omitted exhibit or Schedule to the SEC upon request. |
|
+ |
|
Management contract or compensatory plan or arrangement. |
exv21w1
Exhibit 21.1
Targa Resources Partners LP Subsidiaries
Targa Resources Operating GP LLC
Targa Resources Operating LP
Targa North Texas GP LLC
Targa North Texas LP
Targa Intrastate Pipeline LLC
Targa Resources Texas GP LLC
Targa Texas Field Services LP
Targa Louisiana Field Services LLC
Targa Louisiana Intrastate LLC
exv23w1
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on
Form S-8 (No. 333-149200) of Targa Resources Partners LP of our report dated March 26,
2008 relating to the financial statements, which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
March 26, 2008
exv31w1
Exhibit 31.1
CERTIFICATION
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Rene R. Joyce, certify that:
1. I have reviewed this Annual Report on Form 10-K of Targa Resources Partners LP;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15(d)-(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principes;
(b) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter (the registrants
fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrants internal control over financial
reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrants internal control over financial reporting.
Date:
March 31, 2008
|
|
|
|
|
By:
|
|
/s/ Rene R. Joyce
|
|
|
|
|
|
|
|
|
|
Name: Rene R. Joyce |
|
|
|
|
Title: Chief Executive Officer of Targa Resources |
|
|
|
|
GP LLC, the general partner of Targa
Resources |
|
|
|
|
Partners LP (Principal Executive
Officer) |
|
|
exv31w2
Exhibit 31.2
CERTIFICATION
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Jeffrey J. McParland, certify that:
1. I have reviewed this Annual Report on Form 10-K of Targa Resources Partners LP;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15(d)-(f))for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter (the registrants
fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrants internal control over financial
reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have
a significant role in the registrants internal control over financial reporting.
Date:
March 31, 2008
|
|
|
|
|
By:
|
|
/s/ Jeffrey J. McParland
|
|
|
|
|
|
|
|
|
|
Name: Jeffrey J. McParland |
|
|
|
|
Title: Executive Vice President, Chief Financial Officer |
|
|
|
|
and Treasurer of Targa Resources GP LLC, the general partner of Targa Resources
Partners LP |
|
|
|
|
(Principal Financial Officer) |
|
|
exv32w1
Exhibit 32.1
CERTIFICATION OF CEO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of Targa Resources Partners LP (the
Partnership) for the year ended December 31, 2007 as filed with the Securities and Exchange
Commission on the date hereof (the Report), Rene R. Joyce, as Chief Executive Officer of Targa
Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his
knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
|
|
|
|
|
By:
|
|
/s/ Rene R. Joyce
|
|
|
|
|
|
|
|
Name: Rene R. Joyce |
|
|
Title: Chief Executive Officer of Targa Resources GP LLC, |
|
|
|
|
the general partner of the Partnership |
|
|
Date:
March 31, 2008
A signed original of this written statement required by Section 906, or other document
authenticating, acknowledging, or otherwise adopting the signature that appears in typed form
within the electronic version of this written statement required by Section 906, has been provided
to the Partnership and will be retained by the Partnership and furnished to the Securities and
Exchange Commission or its staff upon request.
exv32w2
Exhibit 32.2
CERTIFICATION OF CFO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of Targa Resources Partners LP (the
Partnership) for the year ended December 31, 2007 as filed with the Securities and Exchange
Commission on the date hereof (the Report), Jeffrey J. McParland, as Chief Financial Officer of
Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that,
to his knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
|
|
|
|
|
By:
|
|
/s/ Jeffrey J. McParland
|
|
|
|
|
|
|
|
|
|
Name: Jeffrey J. McParland |
|
|
|
|
Title: Executive Vice President, Chief Financial Officer and Treasurer
of Targa Resources GP LLC, the general partner of the Partnership |
|
|
Date:
March 31, 2008
A signed original of this written statement required by Section 906, or other document
authenticating, acknowledging, or otherwise adopting the signature that appears in typed form
within the electronic version of this written statement required by Section 906, has been provided
to the Partnership and will be retained by the Partnership and furnished to the Securities and
Exchange Commission or its staff upon request.