UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-34991
TARGA RESOURCES CORP.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
1000 Louisiana St, Suite 4300
Houston, Texas
(Address of principal executive offices)
20-3701075
(I.R.S. Employer
Identification No.)
77002
(Zip Code)
(713) 584-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
Title of Each Class
Common Stock
Name of Each Exchange on Which Registered
New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
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 No
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 No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files). Yes No .
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.
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
Smaller reporting company
Accelerated filer
Non-accelerated filer
(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 No .
As of June 30, 2010, the last day of the registrant’s most recently completed second quarter, the registrant’s common stock was not publicly
traded. As of February 21, 2011, the aggregate market value of the registrant’s common stock, $0.001 par value, held by non-affiliates of the
registrant was approximately $719.7 million (based upon the closing sale price of $31.91 per common stock on that date on The New York
Stock Exchange).
As of February 25, 2011, there were 42,349,738 shares of the registrant’s common stock, $0.001 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
TABLE OF CONTENTS
DESCRIPTION
PART I
1.
BUSINESS
1A. RISK FACTORS
1B. UNRESOLVED STAFF COMMENTS
2.
3.
4.
PROPERTIES
LEGAL PROCEEDINGS
RESERVED
PART II
5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
SELECTED FINANCIAL DATA
6.
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
8.
9.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
9A. CONTROLS AND PROCEDURE
9B. OTHER INFORMATION
PART III
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
11. EXECUTIVE COMPENSATION
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
14. PRINCIPAL ACOUNTANT FEES AND SERVICES
15. EXHBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
4
32
54
54
54
54
55
57
58
84
88
88
88
88
89
95
113
115
121
122
1
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Targa Resources Corp.’s (together with its subsidiaries, other than Targa Resources Partners LP, collectively “we,” “us,” “Targa,”
“TRC,” or the “Company”) 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.” You can typically identify
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended, 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:
• Targa Resources Partners LP (the “Partnership”) and our ability to access the debt and equity markets, which will depend
on general market conditions and the credit ratings for our debt obligations;
•
•
•
•
•
the amount of collateral required to be posted from time to time in the Partnership’s transactions;
the Partnership’s 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;
changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;
the timing and extent of changes in natural gas, natural gas liquids (“NGL”) and other commodity prices, interest rates
and demand for the Partnership’s services;
• weather and other natural phenomena;
•
•
•
•
•
•
industry changes, including the impact of consolidations and changes in competition;
the Partnership’s ability to obtain necessary licenses, permits and other approvals;
the level and success of oil and natural gas drilling around the Partnership’s assets and its success in connecting natural
gas supplies to its gathering and processing systems and NGL supplies to its logistics and marketing facilities;
the Partnership’s and our ability to grow through acquisitions or internal growth projects and the successful integration
and future performance of such assets;
general economic, market and business conditions; and
the risks described elsewhere in this Annual Report on Form 10-K (“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 in “Item 1A. Risk Factors” in this Annual Report. Except as may be required
by applicable 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.
2
As generally used in the energy industry and in this Annual Report the identified terms have the following meanings:
Bbl
BBtu
Btu
/d
gal
MBbl
Mcf
MMBbl
MMBtu
MMcf
NGL
Price Index
Definitions
IF-NGPL MC
IF-PB
IF-WAHA
NY-WTI
OPIS - MB
Barrels (equal to 42 gallons)
Billion British thermal units
British thermal units, a measure of heating value
Per day
Gallons
Thousand barrels
Thousand cubic feet
Million barrels
Million British thermal units
Million cubic feet
Natural gas liquid(s)
Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
Inside FERC Gas Market Report, Permian Basin
Inside FERC Gas Market Report, West Texas WAHA
NYMEX, West Texas Intermediate Crude Oil
Oil Price Information Service, Mont Belvieu, Texas
3
Item 1. Business
Overview
PART I
Targa Resources Corp. (NYSE:TRGP) is a publicly traded Delaware corporation formed in October 2005. With
the completion of the conveyance of all of our remaining operating assets to Targa Resources Partners LP (the
“Partnership”) in September 2010, we no longer directly own any operating assets. Our main source of future
revenue therefore is from general and limited partner interests, including incentive distribution rights (“IDRs”),
in the Partnership, a publicly traded Delaware limited partnership (NYSE: NGLS) that is a leading provider of
midstream natural gas and natural gas liquid services in the United States. The Partnership is engaged in the
business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating,
treating, transporting and selling NGLs, and NGL products.
Initial Public Offering
On December 10, 2010, we completed an initial public offering, or IPO, of common shares in the Company. In
the IPO, the selling shareholders, including a member of our senior management, sold 18,831,250 common
shares at a price of $22.00 per share. We did not receive any proceeds from the sale of shares by the selling
stock holders. On completion of the IPO, there were 42,292,348 shares outstanding.
Business of Targa Resources Corp.
Our primary business objective is to increase our cash available for dividends to our stockholders by assisting
the Partnership in executing its business strategy. We may facilitate the Partnership’s growth through various
forms of financial support, including, but not limited to, modifying the Partnership’s IDRs, exercising the
Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital
contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the
Partnership, if needed, to support its ability to make distributions. In addition, we may acquire assets that could
be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or
further development.
At February 25, 2011, our interests in the Partnership consist of the following:
1. a 2% general partner interest, which we hold through our 100% ownership interest in Targa Resources
GP LLC, the general partner of the Partnership (the ”General Partner”);
2. all of the outstanding IDRs; and
3. 11,645,659 of the 84,756,009 outstanding common units of the Partnership, representing a 13.7% limited
partnership interest.
Our cash flows are generated from the cash distributions we receive from the Partnership. The Partnership is
required to distribute all available cash at the end of each quarter after establishing reserves to provide for the
proper conduct of its business or to provide for future distributions. Our ownership of the general partner
interest entitles us to receive:
• 2% of all cash distributed in respect for that quarter.
Our ownership in respect to the IDR’s of the Partnership that we hold, entitles us to receive:
• 13% of all cash distributed in a quarter after $0.3881 has been distributed in respect of each common unit
of the Partnership for that quarter;
• 23% of all cash distributed in a quarter after $0.4219 has been distributed in respect of each common unit
of the Partnership for that quarter; and
• 48% of all cash distributed in a quarter after $0.50625 has been distributed in respect of each common
unit of the Partnership for that quarter.
4
Because we control the General Partner, under generally accepted accounting principles we must reflect our
ownership interest in the Partnership on a consolidated basis. Accordingly, our financial results are combined
with the Partnership’s financial results in our consolidated financial statements even though the distribution or
transfer of Partnership assets are limited by the terms of its partnership agreement, as well as restrictive
covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by
controlling affiliates of us are reflected in our results of operations as net income attributable to non-controlling
interests. Throughout this report we make a distinction where relevant between financial results of the
Partnership versus those of us as a standalone parent.
Business of Targa Resources Partners LP
Overview
The Partnership is a leading provider of midstream natural gas and NGL services in the United States that we
formed on October 26, 2006 to own, operate, acquire and develop a diversified portfolio of complementary
midstream energy assets. The Partnership is engaged in the business of gathering, compressing, treating,
processing and selling natural gas and storing, fractionating, treating, transporting and selling NGLs and NGL
products. The Partnership operates in two primary divisions: (i) Natural Gas Gathering and Processing,
consisting of two segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and
(ii) NGL Logistics and Marketing consisting of two segments—(a) Logistics Assets and (b) Marketing and
Distribution.
Since the beginning of 2007, the Partnership has completed six acquisitions from us with an aggregate purchase
price of approximately $3.1 billion. The acquisitions from us are as follows:
• In February 2007, in connection with its initial public offering, the Partnership acquired approximately
3,950 miles of integrated gathering pipelines that gather and compress natural gas received from receipt
points in the Fort Worth Basin/Bend Arch in North Texas, two natural gas processing plants and a
fractionator. These assets, together with the business conducted thereby, are collectively referred to as the
“North Texas System.”
• In October 2007, the Partnership acquired natural gas gathering, processing and treating assets in the
Permian Basin of West Texas and in Southwest Louisiana. The West Texas assets, together with the
business conducted thereby, are collectively referred to as “SAOU” and the Southwest Louisiana assets,
together with the business conducted thereby, are collectively referred to as “LOU.”
• In September 2009, the Partnership acquired our NGL business consisting of fractionation facilities,
storage and terminalling facilities, low sulfur natural gasoline treating facilities, pipeline transportation
and distribution assets, propane storage, truck terminals and NGL transport assets. These assets, together
with the businesses conducted thereby, are collectively referred to as the NGL Logistics and Marketing
division or the “Downstream Business.”
• In April 2010, the Partnership acquired a natural gas straddle business consisting of the business and
operations involving the Barracuda, Lowry and Stingray plants, including the Pelican, Seahawk and
Cameron gas gathering pipeline systems, and the interests in the business and operations of the
Bluewater, Sea Robin, Calumet, N. Terrebonne, Toca and Yscloskey plants. These assets, together with
the business conducted thereby, are collectively referred to as the “Coastal Straddles.” The Partnership
also acquired certain natural gas gathering and processing systems, processing plants and related assets
including the Sand Hills processing plant and gathering system, Monahans gathering system, Puckett
gathering system, a 40% ownership interest in the West Seminole gathering system and a compressor
overhaul facility. These assets, together with the business conducted thereby, are collectively referred to
as the “Permian Business.”
• In August 2010, the Partnership acquired a 63% ownership interest in Versado Gas Processors, L.L.C.
(“Versado”), which conducts a natural gas gathering and processing business in New Mexico consisting
of the business and operations involving the Eunice, Monument and Saunders gathering and processing
systems, processing plants and related assets. These assets, together with the business conducted thereby,
are collectively referred to as “Versado.”
5
• In September, 2010, the Partnership acquired from us our 77% ownership interest in Venice Energy
Services Company, L.L.C. (“VESCO”), a joint venture in which Enterprise Gas Processing, LLC and
ONEOK VESCO Holdings, L.L.C. own the remaining ownership interests. VESCO owns and operates a
natural gas gathering and processing business in Louisiana consisting of a coastal straddle plant and the
business and operations of Venice Gathering System, L.L.C., a wholly owned subsidiary of VESCO that
owns and operates an offshore gathering system and related assets (collectively, “VESCO”).
With the above acquisitions, the Partnership has acquired all of our operating assets. In addition, the Partnership
has successfully completed both large and small organic growth projects associated with its existing assets and
expects to continue to do so in the future. These projects, some of which occurred before the Partnership
acquired its various businesses from us, have involved growth capital expenditures of approximately $312.9
million since 2005 and include:
• Low sulfur natural gasoline project: In July 2007, the Partnership completed construction of a natural
gasoline hydrotreater (the “LSNG” facility) at Mont Belvieu, Texas that removes sulfur from natural
gasoline, allowing customers to meet new, more stringent environmental standards. The facility has a
capacity of 30 MBbls/d and is supported by fee-based contracts with Marathon Petroleum Company LLC
and Koch Supply and Trading LP that have certain guaranteed volume commitments or provisions for
deficiency payments. The Partnership made capital expenditures of $39.5 million to convert idle
equipment at Mont Belvieu into the LSNG Facility.
• Operations Improvement and Efficiency Enhancement: The Partnership has historically focused on ways
to improve margins and reduce operating expenses by improving its operations. Examples include energy
saving initiatives such as building cogeneration capacity to self-generate electricity for the Partnership’s
facilities at Mont Belvieu, installing electric compression in North Texas and Versado to reduce fuel
costs, emissions and operating costs and bringing compression overhaul in-house to improve quality,
turnaround time and costs.
• Opportunistic Commercial Development Activities: The Partnership has used the extensive footprint of its
asset base to identify and pursue projects that generate strong returns on invested capital. Examples
include installing a new interconnect pipeline to the Kinder Morgan Rancho line at SAOU, developing
the Winona wholesale propane terminal in Arizona, restarting the Easton Storage Facility at LOU and
installing additional equipment to increase ethane recoveries at the Partnership’s Lowry straddle plant.
• Other Enhancements: The Partnership also has completed a number of smaller acquisitions and projects
that have enhanced its existing asset base and that can provide attractive investment returns. Examples
include the purchase of existing pipelines that expand beyond its existing asset base; installation of
pipeline interconnects to its gathering systems and consolidation of interests in joint ventures.
The Partnership believes these projects have been successful in terms of return on investment. Because the
Partnership’s assets are not easily duplicated and are located in active producing areas and near key NGL
markets and logistics centers, we expect that the Partnership will continue to focus on attractive investment
opportunities associated with its existing asset base.
Partnership Growth Drivers
We believe the Partnership’s near-term growth will be driven both by significant recently completed or pending
projects as well as strong supply and demand fundamentals for its existing businesses. Over the longer-term, we
expect the Partnership’s growth will be driven by natural gas shale opportunities, which could lead to growth in
both the Partnership’s Gathering and Processing division and the Downstream Business, organic growth projects
and potential strategic and other acquisitions related to its existing businesses.
Organic growth projects. We expect the Partnership’s near-term growth to be driven by a number of significant
projects scheduled for completion in 2011 that are supported by long-term, fee-based contracts. We believe that
organic growth projects, such as the ones listed below, often generate higher returns on investment than those
available from third-party acquisitions. Organic projects in process include:
6
Expansion Programs at Mount Belvieu
• Cedar Bayou Fractionator expansion project: The Partnership is currently constructing approximately
78 MBbl/d of additional fractionation capacity at the Partnership’s 88% owned Cedar Bayou Fractionator
(“CBF”) in Mont Belvieu for an estimated gross cost of $78 million. The fractionation expansion is
expected to be in-service in the second quarter of 2011. This expansion is supported with 10 year fee-
based contracts with ONEOK Hydrocarbons, L.P., Questar Gas Management Company and Majestic
Energy Services, LLC that have certain guaranteed volume commitments or provisions for deficiency
payments.
• Benzene treating project: A new treater is under construction which will operate in conjunction with the
Partnership’s existing LSNG facility at Mont Belvieu and is designed to reduce benzene content of
natural gasoline to meet new, more stringent environmental standards. The treater has an estimated gross
cost of approximately $33 million. The treater is anticipated to be in service in the fourth quarter of 2011
and is supported by a fee-based contract with Marathon Petroleum Company LLC that has certain
guaranteed volume commitments or provisions for deficiency payments.
• Gulf Coast Fractionators expansion project: The Partnership has announced plans by Gulf Coast
Fractionators (“GCF”), a partnership with ConocoPhillips and Devon Energy Corporation in which the
Partnership owns a 38.8% interest, to expand the capacity of its NGL fractionation facility in Mont
Belvieu by 43 MBbl/d for an estimated gross cost of $75 million (our net cost is estimated to be
approximately $29 million). ConocoPhillips, as the operator, will manage the expansion project. The
expansion is expected to be operational during the second quarter of 2012, subject to regulatory
approvals.
SAOU Expansion Program
• The Partnership has announced a $30 million capital expenditure program to expand gathering and
processing capability over the next 18 months in response to strong volume growth and new well
connects associated with producer activity particularly in the Wolfberry play as discussed below under
“— Strong supply and demand fundamentals for the Partnership’s existing businesses.” This growth
investment program includes new compression facilities and pipelines as well as expenditures to restart
the 25 MMcf/d Conger processing plant anticipated to be completed by early 2011.
North Texas Expansion Program
• The board of directors of the general partner has approved approximately $40 million of capital
expenditures to expand the gathering and processing capability of the North Texas System with certain
provisions of the approved expenditures subject to finalization of ongoing customer commercial
agreements. The expansion program is a response to strong volume growth and new well connects
associated with producer activity in “oilier” portions of the Barnett Shale natural gas play, especially in
portions of Southern Montague and Northern Wise County as discussed below under “— Strong supply
and demand fundamentals for our existing businesses.” The scope of the full expansion includes a major
pipeline to increase residue takeaway capacity, gathering system expansions, compression equipment and
other work. Certain pieces of the expansion are underway. If commercial agreements were to be
consummated in the first half of 2011, we would expect most capital investment to be completed by early
2012.
Strong supply and demand fundamentals for the Partnership’s existing businesses.
We believe that the current strength of oil, condensate and NGL prices and of forecast prices for these energy
commodities has caused producers in and around the Partnership’s natural gas gathering and processing areas of
operation to focus their drilling programs on regions rich in these forms of hydrocarbons. Liquids rich gas is
prevalent from the Wolfberry and Canyon Sands plays, which are accessible by SAOU, the Wolfberry and Bone
Springs plays, which are accessible by the Sand Hills plant and gathering system, and from “oilier” portions of
the Barnett Shale natural gas play, especially portions of Montague, Cooke, Clay and Wise counties, which are
accessible by the North Texas System. The Wolfberry, Canyon Sands, and Bone Springs plays are oil plays with
associated gas containing high liquids content ranging from approximately 7.0 to 9.5 gal/Mcf. By comparison,
the liquids content of the gas from the liquids rich portion of the Eagle Ford Shale natural gas play is expected
7
to average about 4 gal/Mcf. The Partnership has observed increased drilling permits and higher rig counts in
these areas and expects these activities to result in higher inlet volumes over the next several years.
Producer activity in areas rich in oil, condensate and NGLs is currently generating high demand for the
Partnership’s fractionation services at the Mont Belvieu market hub. As a result, fractionation volumes have
recently increased to near existing capacity. Until additional fractionation capacity comes on-line in 2011, there
will be limited incremental supply of fractionation services in the area. These strong supply and demand
fundamentals have resulted in long-term, “take-or-pay” contracts for existing capacity and support the
construction of new essentially fully committed fractionation capacity, such as the Partnership’s CBF and GCF
expansion projects. The Partnership is continuing to see rates for fractionation services increase. Existing
fractionation customers are renewing contracts at market rates that are, in most cases, substantially higher than
expiring rates for extended terms of up to ten years and with reservation fees that are paid even if customer
volumes are not fractionated to ensure access to fractionation services. A portion of the recent and future
expected increases in cash flow for the Partnership’s fractionation business is related to high utilization and
rollover of existing contracts to higher rates. The higher volumes of fractionated NGLs should also result in
increased demand for other related fee-based services provided by the Partnership’s Downstream Business.
Casinghead gas and liquids rich shale opportunities and similar oil and gas resource plays.
The Partnership is actively pursuing natural gas gathering and processing and NGL fractionation opportunities
associated with many of the active, liquids-rich natural gas and other active oil and gas resource shale plays,
such as the Permian, Wolfberry, and Bone Springs plays and certain regions of the Eagle Ford Shale. We
believe that the Partnership’s leadership position in the NGL Logistics and Marketing business, which includes
the Partnership’s fractionation services, provides the Partnership with a competitive advantage relative to other
gathering and processing companies without these capabilities. While we believe that the expected growth in the
supply of liquids-rich gas from these plays will likely require the construction of (i) additional fractionation
capacity, (ii) additional pipelines to transport the NGLs to and from major fractionation centers and (iii)
additional natural gas gathering and processing facilities, the Partnership’s active involvement in multiple
potential projects does not guarantee that it will be involved with any such capacity expansions.
Potential third-party acquisitions related to the Partnership’s existing businesses. While the Partnership’s
recent growth has been partially driven by the implementation of a focused drop drown strategy, our
management team also has a record of successful third party acquisitions. Since our formation, our strategy has
included approximately $3 billion in third party acquisitions and growth capital expenditures. This track record
includes:
• The 2004 acquisition of SAOU and LOU from ConocoPhillips Company for $248 million;
• The 2004 acquisition of a 40% interest in Bridgeline Holdings, LP for $101 million from the Enron
Corporation bankruptcy estate. Chevron Corporation, the other owner, exercised its rights under the
partnership agreement to purchase the 40% stake from us for $117 million in 2005;
• The 2005 acquisition of Dynegy Midstream Services, Limited Partnership from Dynegy, Inc. for
$2.4 billion; and
• The 2008 acquisition of Chevron Corporation’s 53.9% interest in VESCO.
We expect that third-party acquisitions will continue to be a significant focus of the Partnership’s growth
strategy.
8
Competitive Strengths and Strategies
We believe the Partnership is well positioned to execute its business strategies due to the following competitive
strengths:
Leading fractionation position.
The Partnership is one of the largest fractionators of NGLs in the Gulf Coast. Its primary fractionation assets are
located in Mont Belvieu, Texas and Lake Charles, Louisiana, which are key market centers for NGLs and are
located at the intersection of NGL infrastructure including mixed NGL supply pipelines, storage, takeaway
pipelines and other transportation infrastructure. The Partnership’s assets are also located near and connected to
key consumers of NGL products including the petrochemical and industrial markets. The location and
interconnectivity of the assets are not easily replicated, and the Partnership has sufficient additional capability to
expand their capacity. Our management has extensive experience in operating these assets and in permitting and
building new midstream assets.
Strategically located gathering and processing asset base.
The Partnership’s gathering and processing businesses are predominantly located in active and growth oriented
oil and gas producing basins. Activity in the Canyon Sands, Bone Springs, Wolfberry, and Barnett Shale plays
is driven by the economics of current favorable oil, condensate and NGL prices and the high condensate and
NGL content of the natural gas or associated natural gas streams. Increased drilling and production activities in
these areas would likely increase the volumes of natural gas available to the Partnership’s gathering and
processing systems.
Comprehensive package of midstream services.
The Partnership provides a comprehensive package of services to natural gas producers, including natural gas
gathering, compression, treating, processing and selling natural gas and storing, fractionating, treating,
transporting and selling NGLs and NGL products. These services are essential to gather, process and treat
wellhead gas to meet pipeline standards and to extract NGLs for sale into petrochemical, industrial and
commercial markets. We believe the Partnership’s ability to provide these integrated services provides an
advantage in competing for new supplies of natural gas because the Partnership can provide substantially all of
the services producers, marketers and others require for moving natural gas and NGLs from wellhead to market
on a cost-effective basis. Additionally, due to the high cost of replicating assets in key strategic positions, the
difficulty of permitting and constructing new midstream assets and the difficulty of developing the expertise
necessary to operate them, the barriers to enter the midstream natural gas sector on a scale similar to the
Partnership’s are reasonably high.
High quality and efficient assets.
The Partnership’s gathering and processing systems and logistics assets consist of high-quality, well-maintained
facilities, resulting in low-cost, efficient operations. Advanced technologies have been implemented for
processing plants (primarily cryogenic units utilizing centralized control systems), measurement (essentially all
electronic and electronically linked to a central data base) and operations and maintenance to manage work
orders and implement preventative maintenance schedules (computerized maintenance management systems).
These applications have allowed proactive management of the Partnership’s operations resulting in lower costs
and minimal downtime. The Partnership has established a reputation in the midstream industry as a reliable and
cost-effective supplier of services to its customers and has a track record of safe and efficient operation of its
facilities. The Partnership intends to continue to pursue new contracts, cost-efficiencies and operating
improvements of its assets. Such improvements in the past have included new production and acreage
commitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. The
Partnership will also continue to optimize existing plant assets to improve and maximize capacity and
throughput.
Large, diverse business mix with favorable contracts.
The Partnership maintains gathering and processing positions in strategic oil and gas producing areas across
multiple oil and gas basins and provides services under attractive contract terms to a diverse mix of customers
9
across its areas of operations. Consequently, the Partnership is not dependent on any one oil and gas basin or
customer. The gathering and processing contract portfolio has attractive rate and term characteristics. The
Partnership’s NGL Logistics and Marketing assets are typically located near key market hubs and near
important NGL customers. They also serve must-run portions of the natural gas value chain, are primarily fee-
based and have a diverse mix of customers. The logistics contract portfolio, largely fee-based, has attractive rate
and term characteristics. Given the higher rates for logistics assets contracts that are being renewed (largely
based on replacement cost economics), the new projects underway, the long-term nature of many of the renewed
and new contracts and continuing strong supply and demand fundamentals for this business, we expect an
increasing percentage of the Partnership’s cash flows to be fee-based.
Financial flexibility.
The Partnership has historically maintained strong financial metrics relative to its peer group, with leverage and
distribution coverage ratios consistently above the peer group median. The Partnership also reduces the impact
of commodity price volatility by hedging the commodity price risk associated with a portion of its expected
natural gas, NGL and condensate equity volumes. Maintaining appropriate leverage and distribution coverage
levels and mitigating commodity price volatility allow the Partnership to be flexible in its growth strategy and
enable it to pursue strategic acquisitions and large growth projects.
Experienced and long-term focused management team.
The executive management team that formed Targa in 2004 and continues to manage TRI Resources Inc. today
possesses over 200 years of combined experience working in the midstream natural gas and energy business.
Other officers and key operational, commercial and financial employees provide depth of experience in the
industry and with our assets and businesses.
Attractive Partnership Cash Flow Characteristics
We believe that the Partnership’s strategy, combined with its high-quality asset portfolio and strong industry
fundamentals, allows the Partnership to generate attractive cash flows. Geographic, business and customer
diversity enhances the Partnership’s cash flow profile. The Partnership’s Natural Gas Gathering and Processing
division has a favorable contract mix that is primarily percent-of-proceeds or hybrid which, along with its long-
term commodity hedging program, serves to mitigate the impact of commodity price movements on cash flow.
In the Partnership’s NGL Logistics and Marketing division, the majority of its revenues are derived under fee-
based contracts.
The Partnership has hedged the commodity price risk associated with a portion of its expected natural gas, NGL
and condensate equity volumes through 2014 by entering into financially settled derivative transactions
including swaps and purchased puts (or floors). The primary purpose of its commodity risk management
activities is to hedge the Partnership’s exposure to price risk and to mitigate the impact of fluctuations in
commodity prices on cash flow. The Partnership has intentionally tailored its hedges to approximate specific
NGL products and to approximate its actual NGL and residue natural gas delivery points. The Partnership
intends to continue to manage its exposure to commodity prices in the future by entering into similar hedge
transactions as market conditions permit.
The Partnership also monitors its inventory levels with a view of mitigating losses related to downward price
exposure.
The Partnership’s annual maintenance capital expenditures have averaged approximately $54.0 million per year
over the last three years. We believe that the Partnership’s assets are well maintained and anticipate that a
similar level of capital expenditures will be sufficient for it to continue to operate these assets in a prudent and
cost-effective manner.
Asset Base Well-Positioned for Organic Growth
We believe that the Partnership’s asset platform and strategic locations allow it to maintain and potentially grow
its volumes and related cash flows as its supply areas continue to benefit from exploration and development.
Generally, higher oil and gas prices result in increased domestic oil and gas drilling and workover activity to
increase production. The location of the Partnership’s assets provides it with access to stable natural gas
supplies and proximity to end-use markets and liquid market hubs while positioning it to capitalize on drilling
10
and production activity in those areas. The Partnership’s existing infrastructure has the capacity to handle
incremental increases in volumes without significant capital investments. We believe that as domestic demand
for natural gas and NGL grows over the long term, the Partnership’s infrastructure will increase in value, as
such infrastructure takes on increasing importance in meeting that demand.
While we have set forth the Partnership’s strategies and competitive strengths above, its business involves
numerous risks and uncertainties which may prevent the Partnership from executing its strategies or impact the
amount of distributions to its unitholders. These risks include the adverse impact of changes in natural gas, NGL
and condensate prices, its inability to access sufficient additional production to replace natural declines in
production and the Partnership’s dependence on a single natural gas producer for a significant portion of its
natural gas supply. For a more complete description of the risks to which we and the Partnership are subject, see
“Item 1A. Risk Factors.”
We have used the Partnership as a growth vehicle to pursue the acquisition and expansion of midstream natural
gas, NGL and other complementary energy businesses and assets as evidenced by its acquisition of businesses
from us. However, we are not prohibited from competing with the Partnership and routinely evaluate
acquisitions that do not involve the Partnership. In addition, through its relationship with us, the Partnership has
access to a significant pool of management talent, strong commercial relationships throughout the energy
industry and access to our broad operational, commercial, technical, risk management, and administrative
functions.
As of February 14, 2011, we and our management have a significant interest in the Partnership through our
combined 14.2% limited partner interest and our 2% general partnership interest in the Partnership. In addition,
we own incentive distribution rights that entitle us to receive an increasing percentage of quarterly distributions
of the Partnership’s available cash from its operating surplus after the minimum quarterly distribution and the
target distribution levels have been achieved. We are party to an Omnibus Agreement with the Partnership that
governs our relationship regarding certain reimbursement and indemnification matters. See “Item 13. Certain
Relationships and Related Transactions, and Director Independence-Omnibus Agreement.” We employ 1,020
people who support primarily the Partnership’s operations. See “-Employees.” We allocate the cost of these
employees to the Partnership in accordance with the Omnibus Agreement. Following the conveyance of all of
our remaining operating assets to the Partnership in September 2010, substantially all of our general and
administrative costs have been and will continue to be allocated to the Partnership, other than our direct costs of
being a separate public reporting company.
The Partnership’s Challenges
The Partnership faces a number of challenges in implementing its business strategy. For example:
• The Partnership has a substantial amount of indebtedness which may adversely affect its financial
position.
• The Partnership’s cash flow is affected by supply and demand for oil, natural gas and NGL products and
by natural gas and NGL prices, and decreases in these prices could adversely affect its results of
operations and financial condition.
• The Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural
gas and NGLs, which depends on certain factors beyond its control. Any decrease in supplies of natural
gas or NGLs could adversely affect the Partnership’s business and operating results.
• If the Partnership does not make acquisitions or investments in new assets on economically acceptable
terms or efficiently and effectively integrate new assets, its results of operations and financial condition
could be adversely affected.
• The Partnership is subject to regulatory, environmental, political, legal and economic risks, which could
adversely affect its results of operations and financial condition.
• The Partnership’s growth strategy requires access to new capital. Tightened capital markets or increased
competition for investment opportunities could impair its ability to grow.
11
• The Partnership’s hedging activities may not be effective in reducing the variability of its cash flows and
may, in certain circumstances, increase the variability of its cash flows.
• The Partnership’s industry is highly competitive, and increased competitive pressure could adversely
affect the Partnership’s business and operating results.
For a further discussion of these and other challenges that we and the Partnership face, please read “Item 1A.
Risk Factors.”
Partnership Business Operations
The operations of the Partnership are reported in two divisions: (i) Natural Gas Gathering and Processing,
consisting of two segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and
(ii) NGL Logistics and Marketing, consisting of two segments—(a) Logistics Assets and (b) Marketing and
Distribution.
Natural Gas Gathering and Processing Division
The Partnership’s Natural Gas Gathering and Processing Division consists of gathering, compressing,
dehydrating, treating, conditioning, processing, transporting and marketing natural gas. The gathering of natural
gas consists of aggregating natural gas produced from various wells through small diameter gathering lines to
processing plants. Natural gas has a widely varying composition, depending on the field, the formation and the
reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs
and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas,
commonly referred to as residue gas, and (ii) a stream of mixed NGLs, commonly referred to as “Mixed NGLs”
or “Y-grade.” Once processed, the residue gas is transported to markets through pipelines that are either owned
by the gatherers or processors or third parties. End users of residue gas include large commercial and industrial
customers, as well as natural gas and electric utilities serving individual consumers. The Partnership sells its
residue gas either directly to such end users or to marketers into intrastate or interstate pipelines, which are
typically located in close proximity or with ready access to its facilities.
The Partnership continually seeks new supplies of natural gas, both to offset the natural declines in production
from connected wells and to increase throughput volumes. The Partnership obtains additional natural gas supply
in its operating areas by contracting for production from new wells or by capturing existing production currently
gathered by others. Competition for new natural gas supplies is based primarily on location of assets,
commercial terms, service levels and access to markets. The commercial terms of natural gas gathering and
processing arrangements are driven, in part, by capital costs, which are impacted by the proximity of systems to
the supply source and by operating costs, which are impacted by operational efficiencies, facility design and
economies of scale.
We believe the Partnership’s extensive asset base and scope of operations in the regions in which the
Partnership operates provide the Partnership with significant opportunities to add both new and existing natural
gas production to its systems. We believe the Partnership’s size and scope gives the Partnership a strong
competitive position by placing it in close proximity to a large number of existing and new natural gas
producing wells in its areas of operations, allowing the Partnership to generate economies of scale and to
provide its customers with access to its existing facilities and to multiple end-use markets and market hubs.
Additionally, we believe the Partnership’s ability to serve its customers’ needs across the natural gas and NGL
value chain further augments the Partnership’s ability to attract new customers.
Field Gathering and Processing Segment
The Field Gathering and Processing segment gathers and processes natural gas from the Permian Basin in West
Texas and Southeast New Mexico and the Fort Worth Basin, including the Barnett Shale, in North Texas. The
natural gas processed in this segment is supplied through its gathering systems which, in aggregate, consist of
approximately 10,100 miles of natural gas pipelines. The segment’s processing plants include nine owned and
operated facilities. For the year ended December 31, 2010, the Partnership processed an average of
approximately 588 MMcf/d of natural gas and produced an average of approximately 71 MBbl/d of NGLs.
We believe the Partnership is well positioned as a gatherer and processor in the Permian and Fort Worth Basins.
The Partnership has broad geographic scope, covering portions of 40 counties and approximately 18,100 square
12
miles across these basins. We believe proximity to production and development provides the Partnership with a
competitive advantage in capturing new supplies of natural gas because of the Partnership’s competitive costs to
connect new wells and to process additional natural gas in its existing processing plants. Additionally, because
the Partnership operates all of its plants in these regions, the Partnership is often able to redirect natural gas
among two or more of its processing plants, allowing it to optimize processing efficiency and further improve
the profitability of its operations.
The Field Gathering and Processing segment’s operations consist of the Permian Business, Versado, SAOU and
the North Texas System, each as described below.
Permian Business. The Permian Business consists of the Sand Hills gathering and processing system and the
West Seminole and Puckett gathering systems. These systems consist of approximately 1,300 miles of natural
gas gathering pipelines. These gathering systems are low-pressure gathering systems with significant
compression assets. The Sand Hills refrigerated cryogenic processing plant has a gross processing capacity of
150 MMcf/d and residue gas connections to pipelines owned by affiliates of Enterprise Products Partners L.P.,
ONEOK, Inc. and El Paso Corporation (“El Paso”).
Versado. Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering
systems in Southeastern New Mexico. The gathering systems consist of approximately 3,200 miles of natural
gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenic processing plants have
aggregate processing capacity of 280 MMcf/d (176 MMcf/d, net to the Partnership’s ownership interest). These
plants have residue gas connections to pipelines owned by affiliates of El Paso, MidAmerican Energy Company
and Kinder Morgan Energy Partners, L.P. The Partnership’s ownership in the Versado System is held through
Versado Gas Processors, L.L.C., a joint venture that is 63% owned by the Partnership and 37% owned by
Chevron U.S.A. Inc.
SAOU. Covering portions of 10 counties and approximately 4,000 square miles in West Texas, SAOU includes
approximately 1,500 miles of pipelines in the Permian Basin that gather natural gas to the Mertzon and Sterling
processing plants. SAOU is connected to numerous producing wells and central delivery points. SAOU has
approximately 1,000 miles of low-pressure gathering systems and approximately 500 miles of high-pressure
gathering pipelines to deliver the natural gas to the Partnership’s processing plants. The gathering system has
numerous compressor stations to inject low-pressure gas into the high-pressure pipelines. SAOU’s processing
facilities include two currently operating refrigerated cryogenic processing plants—the Mertzon plant and the
Sterling plant—which have an aggregate processing capacity of approximately 110 MMcf/d. The system also
includes the Conger cryogenic plant with a capacity of approximately 25 MMcf/d. The Partnership is in the
process of restarting the Conger plant and anticipates completion by early 2011 and for it to provide for rapidly
increasing volumes in SAOU.
North Texas System. The North Texas System includes two interconnected gathering systems with
approximately 4,100 miles of pipelines, covering portions of 12 counties and approximately 5,700 square miles,
gathering wellhead natural gas for the Chico and Shackelford natural gas processing facilities.
The Chico Gathering System consists of approximately 2,000 miles of primarily low-pressure gathering
pipelines. Wellhead natural gas is either gathered for the Chico plant located in Wise County, Texas, and then
compressed for processing, or it is compressed in the field at numerous compressor stations and then moved via
one of several high-pressure gathering pipelines to the Chico plant. The Shackelford Gathering System consists
of approximately 2,100 miles of intermediate-pressure gathering pipelines which gather wellhead natural gas
largely for the Shackelford plant in Albany, Texas. Natural gas gathered from the northern and eastern portions
of the Shackelford Gathering System is typically compressed in the field at numerous compressor stations and
then transported to the Chico plant for processing.
13
The following table lists the Field Gathering and Processing segment’s natural gas processing plants and related
volumes for the year ended December 31, 2010:
Gross
Gross Plant
Processing
Natural Gas
Facility
% Owned
Location
(MMcf/d)
Volume (MMcf/d)
Production
Type (4)
Non-Operated
Capacity
Inlet Throughput
Gross NGL
Process
Operated/
Permian Business
Sand Hills
Other Permian (1)
Versado
Saunders (2)
Eunice (2)
Monument (2)
SAOU
Mertzon
Sterling
Conger (3)
North Texas System
Chico (4)
Shackelford
100 Crane, TX
150.0
116.5
12.3
14.4 Cryo
Operated
0.4
63 Lea, NM
63 Lea, NM
63 Lea, NM
Area Total
100 Irion, TX
100 Sterling, TX
100 Sterling, TX
Area Total
100 Wise, TX
100 Shackelford, TX
Area Total
Segment System Total
70.0
120.0
90.0
280.0
48.0
62.0
25.0
135.0
265.0
13.0
278.0
843.0
Cryo
Cryo
Cryo
Operated
Operated
Operated
178.7
20.4
Cryo
Cryo
Cryo
Operated
Operated
Operated
99.8
20.7
Cryo
Cryo
Operated
Operated
180.4
587.7
15.3
71.2
_________
(1)
(2) These plants are part of our Versado joint venture, of which we own a 63%, capacity and volumes represent 100% of ownership
Other Permian includes throughput other than plant inlet, primarily from compressor stations.
interest.
(3) The Partnership is in the process of restarting the Conger plant, which we anticipate occurring in early 2011, to provide for rapidly increasing volumes in
SAOU.
(4) The Chico plant has fractionation capacity of approximately 15 MBbl/d.
(5) Cryo—Cryogenic Processing.
Coastal Gathering and Processing Segment
The Partnership’s Coastal Gathering and Processing segment assets are located in the onshore region of the
Louisiana Gulf Coast and the Gulf of Mexico. With the strategic location of its assets in Louisiana, the
Partnership has access to the Henry Hub, the largest natural gas hub in the U.S., and a substantial NGL
distribution system with access to markets throughout Louisiana and the southeast U.S. The Coastal Gathering
and Processing segment’s assets consist of the Coastal Straddles, VESCO and LOU, each as described below.
For the year ended December 31, 2010, the Partnership processed an average of approximately 1,680 MMcf/d of
plant natural gas inlet and produced an average of approximately 50 MBbl/d of NGLs.
Coastal Straddles. Coastal Straddles consists of three wholly owned and operated gas processing plants and six
partially owned plants, some of which are operated by the Partnership. The plants are generally situated on
mainline natural gas pipelines near the coastline and process volumes of natural gas collected from multiple
offshore gathering systems and pipelines throughout the Gulf of Mexico. Coastal Straddles also has ownership
in three offshore gathering systems that are operated by the Partnership. The Pelican and Seahawk pipeline
systems are non-FERC regulated gathering systems that have a combined length of approximately 175 miles
and a combined capacity of approximately 230 MMcf per day. These systems gather natural gas from shallow
waters of the central Gulf of Mexico and supply a portion of the natural gas delivered to the Barracuda and
Lowry processing facilities.
Coastal Straddles process natural gas produced from shallow water central and western Gulf of Mexico natural
gas wells and from deep shelf and deepwater Gulf of Mexico production via connections to third-party pipelines
14
or through pipelines owned by the Partnership. Coastal Straddles has access to markets across the U.S. through
the interstate natural gas pipelines to which it is interconnected. Through the Partnership’s 77% ownership
interest in VESCO, the Partnership operates the Venice Gathering System (“VGS”), an offshore gathering
system regulated as an interstate pipeline by the Federal Energy Regulatory Commission (“FERC”). VGS is
approximately 150 miles in length and has a nominal capacity of 320 MMcf per day. VGS gathers natural gas
from the shallow waters of eastern Gulf of Mexico and supplies a portion of the natural gas to the Venice gas
plant.
LOU. LOU consists of approximately 850 miles of gathering system pipelines, covering approximately 3,800
square miles in Southwest Louisiana. The gathering system is connected to numerous 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. The processing facilities include the Gillis and Acadia processing plants, both of which
are cryogenic plants. These processing plants have an aggregate processing capacity of approximately 260
MMcf/d. In addition, the Gillis plant has integrated fractionation with operating capacity of approximately 13
MBbl/d.
The following table lists the Coastal Gathering and Processing segment’s natural gas processing plants for the
year ended December 31, 2010:
Approximate
Gross
Gross Plant
Processing
Natural Gas
Capacity
Inlet Throughput
Facility
% Owned
Location
(MMcf/d)
Volume (MMcf/d)
Coastal Straddles (1)
Barracuda
Lowry
Stingray
Calumet (2)
Yscloskey (2)
Bluewater (2)
Terrebonne (2)
Toca (2)
Iowa
Sea Robin
VESCO
Other
LOU
Gillis (3)
Acadia
100 Cameron, LA
100 Cameron, LA
100 Cameron, LA
32.4 St. Mary, LA
25.3 St. Bernard, LA
21.8 Acadia, LA
4.8 Terrebonne, LA
10.7 St. Bernard, LA
100 Jeff Davis, LA
0.8 Vermillion, LA
76.8 Plaquemines, LA
Area Total
100 Calcasieu, LA
100 Acadia, LA
Area Total
Consolidated System Total
190
265
300
1,650
1,850
425
950
1,150
500
700
750
8,730
180
80
260
8,990
138.0
110.8
269.3
128.2
290.3
-
22.4
50.8
-
25.4
427.3
33.2
1,495.7
184.6
1,680.3
Gross NGL
Production
Process Operated/
Type (4) Non-operated
Operated
Operated
Operated
Non-operated
Operated
Non-operated
Non-operated
Non-operated
Operated
Non-operated
Operated
3.3 Cryo
2.8 Cryo
4.7 RA
2.9 RA
2.1 RA
- Cryo
0.9 RA
1.3 Cryo/RA
- Cryo
0.6 Cryo
23.2 Cryo
1.1
42.9
Cryo
Cryo
7.2
50.1
_________
(1) Coastal Straddles also includes three offshore gathering systems which have a combined length of approximately 325 miles.
(2) Our ownership is adjustable and subject to annual redetermination.
(3) The Gillis plant has fractionation capacity of approximately 13 MBbl/d.
(4) Cryo—Cryogenic Processing; RA—Refrigerated Absorption Processing.
NGL Logistics and Marketing Division
The NGL Logistics and Marketing division is also referred to as the Downstream Business. It includes the
activities necessary to convert mixed NGLs into NGL products, market the NGL products and provides certain
value added services such as the fractionation, storage, terminalling, transportation, distribution and marketing
of NGLs, as well as certain natural gas supply and marketing activities in support of our other businesses.
Through fractionation, mixed NGLs are separated into its component parts (ethane, propane, butanes and natural
gasoline). These component parts are delivered to end-users through pipelines, barges, trucks and rail cars. End-
users of component NGLs include petrochemical and refining companies and propane markets for heating,
cooking or crop drying applications. Retail distributors often sell to end-use propane customers.
15
Logistics Assets Segment
This segment uses its platform of integrated assets to fractionate, store, treat and transport NGLs typically under
fee-based and margin-based arrangements. For NGLs to be used by refineries, petrochemical manufacturers,
propane distributors and other industrial end-users, they must be fractionated into their component products and
delivered to various points throughout the U.S. The Partnership’s logistics assets are generally connected to and
supplied, in part, by its Natural Gas Gathering and Processing assets and are primarily located at Mont Belvieu
and Galena Park near Houston, Texas and in Lake Charles, Louisiana.
Fractionation. After being extracted in the field, mixed NGLs, sometimes referred to as “Y-grade” or “raw
NGL mix,” are typically transported to a centralized facility for fractionation where the mixed NGLs are
separated into discrete NGL products: ethane, propane, butanes and natural gasoline. Mixed NGLs delivered
from the Partnership’s Field and Coastal Gathering and Processing segments represent the largest source of
volumes processed by the Partnership’s NGL fractionators.
The Partnership’s fractionation assets include ownership interests in three stand-alone fractionation facilities
that are located on the Gulf Coast, two of which it operates, one at Mont Belvieu, Texas, and the other at Lake
Charles, Louisiana. It also has an equity investment in a third fractionator, GCF, also located at Mont Belvieu.
The Partnership is subject to a consent decree with the Federal Trade Commission, issued December 12, 1996,
that, among other things, prevents it from participating in commercial decisions regarding rates paid by third
parties for fractionation services at GCF. This restriction on the Partnership activity at GCF will terminate on
December 12, 2016, twenty years after the date the consent order was issued. In addition to the three stand-alone
facilities in the Logistics Assets segment, see the description of fractionation assets in the North Texas System
and LOU in our Natural Gas Gathering and Processing division.
The majority of the Partnership’s NGL fractionation business is under fee-based arrangements. These fees are
subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results
of the Partnership’s NGL fractionation business are dependent upon the volume of mixed NGLs fractionated
and the level of fractionation fees charged.
We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable
quantities for the foreseeable future due to increases in NGL production expected from shale plays in areas of
the U.S. that include North Texas, South Texas, Oklahoma and the Rockies and certain other basins accessed by
pipelines to Mont Belvieu, as well as from continued production of NGLs in areas such as the Permian Basin,
Mid-Continent, East Texas, South Louisiana and shelf and deepwater Gulf of Mexico. Dew point specifications
implemented by individual pipelines and the policy statement enacted by FERC should result in volumes of
mixed NGLs being available for fractionation because natural gas requires processing or conditioning to meet
pipeline quality specifications. These requirements establish a base volume of mixed NGLs during periods when
it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes
of mixed NGLs are contractually committed to the Partnership’s NGL fractionation facilities.
Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of
an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor.
This ability is a function of the existence of storage infrastructure and supply and market connectivity necessary
to conduct such operations. We believe that the location, scope and capability of the Partnership’s logistics
assets, including its transportation and distribution systems, give the Partnership access to both substantial
sources of mixed NGLs and a large number of end-use markets.
The Partnership also has a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural
gasoline, allowing customers to meet new, more stringent environmental standards. The facility has a capacity
of 30 MBbls/d and is supported by fee-based contracts with Marathon Petroleum Company LLC and Koch
Supply and Trading LP that have certain guaranteed volume commitments or provisions for deficiency
payments.
16
The following table details the Logistics Assets segment’s fractionation and treating facilities:
Facility
Operated Facilities:
Lake Charles Fractionator (Lake Charles, LA)
Cedar Bayou Fractionator (Mont Belvieu, TX) (1)
LSNG Hydrotreater (Mont Belvieu, TX)
Equity Fractionation Facilities (non-operated):
Gulf Coast Fractionator (Mont Belvieu, TX)
_______
(1)
Includes ownership through 88% interest in Downstream Energy Ventures Co, LLC.
Maximum Gross Capacity
% Owned
(MBbls/d)
Gross Throughput for the
Year Ended
December 31, 2010
(MBbls/d)
100.0
88.0
100.0
38.8
55.0
215.0
30.0
109.0
39.1
187.1
18.0
98.9
Storage and Terminalling. In general, the Partnership’s storage assets provide warehousing of mixed NGLs,
NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal
of such products at various times in order to meet demand cycles. Similarly, the Partnership’s terminalling
operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and
petrochemical products in above-ground storage tanks. The Partnership’s underground storage and terminalling
facilities serve single markets, such as propane, as well as multiple products and markets. For example, the
Mont Belvieu and Galena Park facilities have extensive pipeline connections for mixed NGL supply and
delivery of component NGLs. In addition, some of these facilities are connected to marine, rail and truck
loading and unloading facilities that provide services and products to the Partnership’s customers. The
Partnership provides long and short term storage and terminalling services and throughput capability to third
party customers for a fee.
The Partnership owns or operates a total of 39 storage wells at its facilities with a net storage capacity of
approximately 64.5 MMBbl, the usage of which may be limited by brine handling capacity, which is utilized to
displace NGLs from storage.
The Partnership operates its storage and terminalling facilities based on the needs and requirements of its
customers in the NGL, petrochemical, refining, propane distribution and other related industries. The
Partnership usually experiences an increase in demand for storage and terminalling of mixed NGLs during the
summer months when gas plants typically reach peak NGL production, refineries have excess NGL products
and LPG imports are often highest. Demand for storage and terminalling at the Partnership’s propane facilities
typically peaks during fall, winter and early spring.
The Partnership’s fractionation, storage and terminalling business is supported by approximately 800 miles of
company-owned pipelines to transport mixed NGLs and specification products.
Logistics Assets NGL storage facilities at December 31, 2010:
Facility
Hackberry Storage (Lake Charles)
Mont Belvieu Storage
Easton Storage
% Owned County/Parish, State
100 Cameron, LA
100 Chambers, TX
100 Evangeline, LA
NGL Storage Facilities
Number of
Permitted Wells
Gross Storage
Capacity (MMBbl)
12 (1)
20 (2)
1
20.0
41.4
0.8
_______
(1) Four of twelve owned wells leased to CITGO under long-term leases; one of twelve currently in service.
(2) The Partnership owns 20 wells and operates 6 wells owned by Chevron Phillips Chemical Company LLC.
17
Logistics Assets Terminal Facilities for the year ended December 31, 2010:
Throughput
% Owned County/Parish, State
Facility
Galena Park Terminal (1)
Mont Belvieu Terminal (2)
Hackberry Terminal
__________
(1) Volumes reflect total import and export across the dock/terminal.
(2) Volumes reflect total transport and terminal throughput volumes.
Harris, TX
Chambers, TX
Cameron, LA
100
100
100
Description
NGL import/export terminal
Transport and storage terminal
Storage terminal
for 2010
(Million gallons)
916.8
2,406.0
289.7
Usable Storage
Capacity
(MMBbl)
0.7
48.9
17.8
Marketing and Distribution Segment
The Marketing and Distribution segment transports, distributes and markets NGLs via terminals and
transportation assets across the U.S. The Partnership owns or commercially manages terminal facilities in a
number of states, including Texas, Louisiana, Arizona, Nevada, California, Florida, Alabama, Mississippi,
Tennessee, Kentucky and New Jersey. The geographic diversity of the Partnership’s assets provides it direct
access to many NGL customers as well as markets via trucks, barges, rail cars and open-access regulated NGL
pipelines owned by third parties. The Marketing and Distribution segment consists of (i) NGL Distribution and
Marketing, (ii) Wholesale Marketing, (iii) Refinery Services, and (iv) Commercial Transportation, each as
described below.
NGL Distribution and Marketing. The Partnership markets its own NGL production and also purchases
component NGL products from other NGL producers and marketers for resale. During the year ended December
31, 2010, the Partnership’s distribution and marketing services business sold an average of approximately
247 MBbl/d of NGLs.
The Partnership generally purchases mixed NGLs from producers at a monthly pricing index less applicable
fractionation, transportation and marketing fees and resells these products to petrochemical manufacturers,
refineries and other marketing and retail companies. This is primarily a physical settlement business in which
the Partnership earns margins from purchasing and selling NGL products from producers under contract. The
Partnership earns margins by purchasing and reselling NGL products in the spot and forward physical markets.
To effectively serve its Distribution and Marketing customers, the Partnership contracts for and uses many of
the assets included in its Logistics Assets segment. The Partnership also markets natural gas available from its
Gathering and Processing segments, and purchases and resells natural gas in selected United States markets.
Wholesale Marketing. The Partnership’s wholesale propane marketing operations primarily sells propane and
related logistics services to major multi-state retailers, independent retailers and other end-users. The
Partnership’s propane supply primarily originates from both its refinery/gas supply contracts and its other
owned or managed logistics and marketing assets. The Partnership generally sells propane at a fixed or posted
price at the time of delivery and, in some circumstances, the Partnership earns margin on a net-back basis.
The wholesale propane marketing business is significantly impacted by weather-driven demand, particularly in
the winter, which can impact the price of propane in the markets it serves and impact the ability to deliver
propane to satisfy peak demand.
Refinery Services. In its refinery services business, the Partnership typically provides NGL balancing services
via contractual arrangements with refiners to purchase and/or market propane and to supply butanes. The
Partnership uses its commercial transportation assets (discussed below) and contracts for and uses the storage,
transportation and distribution assets included in its Logistics Assets segment to assist refinery customers in
managing their NGL product demand and production schedules. This includes both feedstocks consumed in
refinery processes and the excess NGLs produced by those same refining processes. Under typical net-back
purchase contracts, the Partnership generally retains a portion of the resale price of NGL sales or receives a
fixed minimum fee per gallon on products sold. Under net-back sales contracts, fees are earned for locating and
supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a
minimum fee per gallon.
Key factors impacting the results of the Partnership’s refinery services business include production volumes,
prices of propane and butanes, as well as its ability to perform receipt, delivery and transportation services in
order to meet refinery demand.
18
Commercial Transportation. The Partnership’s NGL transportation and distribution infrastructure includes a
wide range of assets supporting both third party customers and the delivery requirements of its marketing and
asset management business. The Partnership provides fee-based transportation services to refineries and
petrochemical companies throughout the Gulf Coast area. The Partnership’s assets are also deployed to serve its
wholesale distribution terminals, fractionation facilities, underground storage facilities and pipeline injection
terminals. These distribution assets provide a variety of ways to transport products to and from its customers.
The Partnership’s transportation assets, as of December 31, 2010, include:
• approximately 760 railcars that the Partnership leases and manages;
• approximately 70 owned and leased transport tractors and approximately 100 company-owned tank
trailers; and
• 21 company-owned pressurized NGL barges.
Natural Gas Marketing. The Partnership also markets natural gas available to the Partnership from the
Gathering and Processing segments, and purchases and resells natural gas in selected United States markets.
The following table details the Marketing and Distribution segment’s Terminal Facilities:
Facility
% Owned
County/Parish,
State
Description
Throughput for
Year Ended
Usable Storage
December 31, 2010
( Million gallons) (1)
Capacity
( Million gallons)
100
100
100
100
100
100
100
100
100
100
50
100
Calvert City Terminal
Greenville Terminal
Port Everglades Terminal
Tyler Terminal
Abilene Transport (2)
Bridgeport Transport (2)
Gladewater Transport (2)
Hammond Transport
Chattanooga Terminal
Sparta Terminal
Hattiesburg Terminal (3)
Winona Terminal
_______
(1) Throughputs include volumes related to exchange agreements and third party storage agreements.
(2) Volumes reflect total transport and injection volumes.
(3) Throughput volume is based on 100% ownership.
Propane terminal
Marine propane terminal
Marine propane terminal
Propane terminal
Raw NGL transport terminal
Raw NGL transport terminal
Raw NGL transport terminal
Transport terminal
Propane terminal
Propane terminal
Propane terminal
Propane terminal
Marshall, KY
Washington, MS
Broward, FL
Smith, TX
Taylor, TX
Jack, TX
Gregg, TX
Tangipahoa, LA
Hamilton, TN
Sparta, NJ
Forrest, MS
Flagstaff, AZ
47.2
23.1
23.8
9.3
12.4
49.6
20.5
31.6
18.3
10.7
264.8
4.4
0.1
1.7
1.7
0.2
Less than 0.1
0.1
0.4
No storage
1.0
0.2
269.6
0.3
Operational Risks and Insurance
The Partnership is subject to all risks inherent in the midstream natural gas business. These risks include, but are
not limited to, explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and
inadequate maintenance of rights-of-way and could result in damage to or destruction of operating assets and
other property, or could result in personal injury, loss of life or polluting the environment, as well as curtailment
or suspension of operations at the affected facility. We maintain, on behalf of ourselves and our subsidiaries,
including the Partnership, general public liability, property, boiler and machinery and business interruption
insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles
that we consider reasonable and not excessive given the current insurance market environment. The costs
associated with these insurance coverages increased significantly following Hurricanes Katrina and Rita in
2005. Insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were
generally less favorable than terms that were obtained prior to those hurricanes. Insurance market conditions
worsened again as a result of industry losses including those sustained from Hurricanes Gustav and Ike in
September 2008, and as a result of volatile conditions in the financial markets. As a result, in 2009, the
Partnership experienced further increases in deductibles and premiums, and further reductions in coverage and
limits. During 2010, it saw the insurance market conditions improve slightly.
19
The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its
indemnification obligations, could materially and adversely affect the Partnership’s operations and financial
condition. While we currently maintain levels and types of insurance that we believe to be prudent under current
insurance industry market conditions, our inability to secure these levels and types of insurance in the future
could negatively impact the Partnership’s business operations and financial stability, particularly if an uninsured
loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the
future at rates considered commercially reasonable, particularly named windstorm coverage and contingent
business interruption coverage for the Partnership’s onshore operations.
Significant Customers
The following table lists the percentage of the Partnership’s consolidated sales and consolidated product
purchases with the Partnership’s significant customers and suppliers:
% of consolidated revenues
Chevron Phillips Chemical Company LLC
% of consolidated product purchases
Louis Dreyfus Energy Services L.P.
2010
2009
2008
10%
15%
19%
10%
11%
9%
No other customer or supplier accounted for more than 10% of the Partnership’s consolidated revenues or
consolidated product purchases during these periods.
The Partnership has agreements with Chevron Phillips Chemical Company LLC (“CPC”), a separate joint
venture affiliate of Chevron, pursuant to which the Partnership supplies a significant portion of CPC’s NGL
feedstock needs for petrochemical plants in the Texas Gulf Coast area and a related services agreement,
pursuant to which the Partnership provides storage and logistical services to CPC for feed stocks and products
produced from the petrochemical plants. The services contract was renegotiated in 2008 with key components
having a 10 year term. In September 2009, CPC executed contracts to replace the previously terminated
agreement with a new feedstock and storage agreement effective for a term of 5 years, which will renew
annually following the end of the five year term unless terminated by either party. We believe that the
Partnership is well positioned to retain CPC as a customer based on the Partnership’s long-standing history of
customer service, the criticality of the service provided, the integrated nature of facilities and the difficulty and
high cost associated with replicating the Partnership’s assets. In addition to these two agreements, The
Partnership has fractionation agreements in place with CPC for Y-grade streams and butanes.
Competition
The Partnership faces strong competition in acquiring new natural gas supplies. Competition for natural gas
supplies is primarily based on the location of gathering and processing facilities, pricing arrangements,
reputation, efficiency, flexibility, reliability and access to end-use markets or liquid marketing hubs.
Competitors to the Partnership’s gathering and processing operations include other natural gas gatherers and
processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and
gas producers. The Partnership’s major competitors for natural gas supplies in its current operating regions
include Atlas Gas Pipeline Company, Copano Energy, L.L.C. (“Copano”), WTG Gas Processing, L.P.
(“WTG”), DCP Midstream Partners LP (“DCP”), Devon Energy Corp (“Devon”), Enbridge Inc., GulfSouth
Pipeline Company, LP, Hanlon Gas Processing, Ltd., J W Operating Company, Louisiana Intrastate Gas and
several other interstate pipeline companies. Many of its competitors have greater financial resources than the
Partnership possesses.
The Partnership also competes for NGL products to market through its NGL Logistics and Marketing division.
The Partnership’s competitors include major oil and gas producers who market NGL products for their own
account and for others. Additionally, the Partnership competes with several other NGL marketing companies,
including Enterprise Products Partners L.P., DCP, ONEOK and BP p.l.c.
Additionally, the Partnership faces competition for mixed NGLs supplies at its fractionation facilities. Its
competitors include large oil, natural gas and petrochemical companies. The fractionators in which the
Partnership owns an interest in the Mont Belvieu region compete for volumes of mixed NGLs with other
fractionators also located at Mont Belvieu. Among the primary competitors are Enterprise Products Partners
20
L.P. and ONEOK, Inc. In addition, certain producers fractionate mixed NGLs for their own account in captive
facilities. The Mont Belvieu fractionators also compete on a more limited basis with fractionators in Conway,
Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. The
Partnership’s other fractionation facilities compete for mixed NGLs with the fractionators at Mont Belvieu as
well as other fractionation facilities located in Louisiana. The Partnership’s customers who are significant
producers of mixed NGLs and NGL products or consumers of NGL products may develop their own
fractionation facilities in lieu of using the Partnerships’ services.
Regulation of Operations
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may
affect certain aspects of the Partnership’s business and the market for its products and services.
Regulation of Interstate Natural Gas Pipelines
The VGS is regulated by FERC under the Natural Gas Act of 1938 (“NGA”), and the Natural Gas Policy Act of
1978 (“NGPA”). VGS operates under a FERC approved, open-access tariff that establishes rates and terms and
conditions under which the system provides services to its customers. Pursuant to FERC’s jurisdiction, existing
pipeline rates and/or terms and conditions of service may be challenged by customer complaint or by FERC and
proposed rate changes or changes in the terms and conditions of service may be challenged by protest.
Generally, FERC’s authority extends to: transportation of natural gas; rates and charges for natural gas
transportation; certification and construction of new facilities; extension or abandonment of services and
facilities; maintenance of accounts and records; commercial relationships and communications between
pipelines and certain affiliates; terms and conditions of service and service contracts with customers;
depreciation and amortization policies; and acquisition and disposition of facilities.
VGS holds a certificate of public convenience and necessity issued by FERC permitting the construction,
ownership, and operation of its interstate natural gas pipeline facilities and the provision of transportation
services. This certificate authorization requires VGS to provide on a nondiscriminatory basis open-access
services to all customers who qualify under its FERC gas tariff. FERC has the power to prescribe the accounting
treatment of items for regulatory purposes. Thus, the books and records of VGS may be periodically audited by
FERC.
The maximum recourse rates that may be charged by VGS for its services are established through FERC’s
ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of
service including recovery of and a return on the pipeline’s investment. Key determinants in the ratemaking
process are costs of providing service, allowed rate of return and volume throughput and contractual capacity
commitment assumptions. VGS is permitted to discount its firm and interruptible rates without further FERC
authorization down to the variable cost of performing service, provided they do not “unduly discriminate.” The
applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC approved
tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability.
Gathering Pipeline Regulation
The Partnership’s natural gas gathering operations are typically subject to ratable take and common purchaser
statutes in the states in which it operates. The common purchaser statutes generally require 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 or one source of supply over another. The
regulations under these statutes can have the effect of imposing some restrictions on the Partnership’s ability as
an owner of gathering facilities to decide with whom it contracts to gather natural gas. The states in which the
Partnership operates 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 the Partnership charges for gathering are deemed
just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed
against the Partnership 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 NGA exempts natural gas gathering facilities from regulation as a natural gas company by
FERC under the NGA. We believe that the natural gas pipelines in the Partnership’s gathering systems meet the
traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural
21
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 the Partnership’s 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. The Partnership’s 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. 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 the Partnership’s operations, but the industry could be required to
incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
In 2007, Texas enacted new laws regarding rates, competition and confidentiality for natural gas gathering and
transmission pipelines (“Competition Statute”) and new informal complaint procedures for challenging
determinations of lost and unaccounted for gas by gas gatherers, processors and transporters (“LUG Statute”).
The Competition Statute gives the Railroad Commission of Texas (“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. This statute 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 Statute modifies the
informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. Such
statute also 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. We cannot predict what effect, if any, these statutes
might have on the Partnership’s future operations in Texas.
Intrastate Pipeline Regulation
Though the Partnership’s natural gas intrastate pipelines are not subject to regulation by FERC as natural gas
companies under the NGA, the Partnership’s intrastate pipelines may be subject to certain FERC-imposed daily
scheduled flow and capacity posting requirements depending on the volume of flows in a given period and the
design capacity of the pipelines’ receipt and delivery meters. See “—Other Federal Laws and Regulation
Affecting Our Industry—FERC Market Transparency Rules.”
The Partnership’s intrastate pipelines located in Texas are regulated by the RRC. The Partnership’s Texas
intrastate pipeline, Targa Intrastate Pipeline LLC (“Targa Intrastate”), owns the intrastate pipeline that transports
natural gas from the Partnership’s Shackelford processing plant to an interconnect with Atmos Pipeline-Texas
that in turn delivers gas to the West Texas Utilities Company’s 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 is a gas utility subject to regulation by
the RRC and has a tariff on file with such agency. The Partnership notes that the RRC is subject to a sunset
condition. If
the RRC will be
abolished effective September 1, 2011, and will begin a one-year wind-down process. The Sunset Advisory
Commission has recommended certain organizational changes be made to the RRC. The Partnership cannot tell
what, if any, changes will be made to the RRC as a result of the pending regular session or any called sessions
of the Texas Legislature in 2011, but the Partnership does not believe that any such changes would affect its
business in a way that would be materially different from the way such changes would affect its competitors.
the Texas Legislature does not
to continue
take action
the RRC,
The Partnership’s Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC (“TLI”) 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 pipeline’s
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 full FERC regulation.
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 the Partnership charges for intrastate
transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such
22
a complaint will be filed against the Partnership in the future. Failure to comply with state regulations can result
in the imposition of administrative, civil and criminal penalties.
Regulation of NGL intrastate pipelines
The Partnership’s intrastate NGL pipelines in Louisiana gather mixed NGLs streams that the Partnership owns
from processing plants in Louisiana and deliver such streams to the Gillis fractionator in Lake Charles,
Louisiana, where the mixed NGLs streams are fractionated into various products. The Partnership delivers such
refined products (ethane, propane, butanes and natural gasoline) out of its fractionator to and from Targa-owned
storage, to other third-party facilities and to various third-party pipelines in Louisiana. These pipelines are not
subject to FERC regulation or rate regulation by the DNR, but are regulated by United States Department of
Transportation (“DOT”) safety regulations.
Natural Gas Processing
The Partnership’s natural gas gathering and processing operations are not presently subject to FERC regulation.
However, starting in May 2009 the Partnership was required to report to FERC information regarding natural
gas sale and purchase transactions for some of its operations depending on the volume of natural gas transacted
during the prior calendar year. See “—Other Federal Laws and Regulation Affecting Our Industry—FERC
Market Transparency Rules.” There can be no assurance that the Partnership’s processing operations will
continue to be exempt from other FERC regulation in the future.
Availability, Terms and Cost of Pipeline Transportation
The Partnership’s processing facilities and marketing of natural gas and NGLs are affected by the availability,
terms and cost of pipeline transportation. 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 the Partnership’s processing operations and its natural gas and NGL marketing
operations. We do not believe that the Partnership would be affected by any such FERC action materially
differently than other natural gas processors and natural gas and NGL marketers with whom it competes.
The ability of the Partnership’s 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. In 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 (“NGC+ Work Group”), or to explain how and
why their tariff provisions differ. We do not believe that the adoption of the NGC+ Work Group’s gas quality
interim guidelines by a pipeline that either directly or indirectly interconnects with the Partnership’s facilities
would materially affect the Partnership’s operations. We have no way to predict, however, whether FERC will
approve of gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for
such an interconnecting pipeline.
Sales of Natural Gas and NGLs
The price at which the Partnership buys and sells natural gas and NGLs is currently not subject to federal rate
regulation and, for the most part, is not subject to state regulation. However, with regard to the Partnership’s
physical purchases and sales of these energy commodities and any related hedging activities that it undertakes,
the Partnership is required to observe anti-market manipulation laws and related regulations enforced by FERC
and/or the Commodities Futures Trading Commission (“CFTC”). See “—Other Federal Laws and Regulation
Affecting Our Industry—Energy Policy Act of 2005.” Starting May 1, 2009, the Partnership was required to
report to FERC information regarding natural gas sale and purchase transactions for some of its operations
depending on the volume of natural gas transacted during the prior calendar year. See “—Other Federal Laws
and Regulation Affecting Our Industry—FERC Market Transparency Rules.” Should the Partnership violate the
anti-market manipulation laws and regulations, it could also be subject to related third-party damage claims by,
among others, market participants, sellers, royalty owners and taxing authorities.
23
Other State and Local Regulation of Operations
The Partnership’s 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 the Partnership’s
business, see “Risk Factors—Risks Related to Our Business.”
Interstate Common Carrier Liquids Pipeline Regulation
As part of the Downstream Business acquired from Targa on September 24, 2009, the Partnership acquired
Targa NGL Pipeline Company LLC (“Targa NGL”). Targa NGL is an interstate NGL common carrier subject to
regulation by FERC under the ICA. Targa NGL owns a twelve inch diameter pipeline that runs between Lake
Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGLs and purity NGL products.
Targa NGL also owns an eight inch diameter pipeline and a 20 inch diameter pipeline, each of which run
between Mont Belvieu, Texas and Galena Park, Texas. The eight inch and the 20 inch pipelines are part of an
extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic
and foreign import and export customers. The ICA requires that the Partnership maintain tariffs on file with
FERC for each of these pipelines. Those tariffs set forth the rates the Partnership charges for providing
transportation services as well as the rules and regulations governing these services. The ICA requires, among
other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory.
All shippers on this pipeline are Partnership subsidiaries.
Other Federal Laws and Regulation Affecting Our Industry
Energy Policy Act of 2005(“EPA Act of 2005”)
The EPA Act of 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, EPA Act of 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 EPA Act of 2005 provides FERC with the power to
assess civil penalties of up to $1 million per day for violations of the NGA and $1 million per violation per day
for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of
natural gas for resale in interstate commerce, including VGS. In 2006, FERC issued Order 670 to implement the
anti-market manipulation provision of EPA Act of 2005. Order 670 makes 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 any 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. Order 670 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, which now includes the
annual reporting requirements under a final rule on the annual natural gas transaction reporting requirements, as
amended by subsequent orders on rehearing (Order 704), the daily schedule flow and capacity posting
requirements under Order 720, and the quarterly reporting requirement under Order 735. The anti-market
manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement
authority.
FERC Standards of Conduct for Transmission Providers
On October 16, 2008, FERC issued new standards of conduct for transmission providers (Order 717) to regulate
the manner in which interstate natural gas pipelines may interact with their marketing affiliates based on an
employee separation approach. A “Transmission Provider” includes an interstate natural gas pipeline that
provides open access transportation pursuant to FERC’s regulations. Under these rules, a Transmission
Provider’s transmission function employees (including the transmission function employees of any of its
affiliates) must function independently from the Transmission Provider’s marketing function employees
(including the marketing function employees of any of its affiliates). FERC clarified on October 15, 2009 in a
24
rehearing order, Order 717-A, however, that if a Hinshaw pipeline affiliated with a Transmission Provider
engages in off-system sales of gas that has been transported on the Transmission Provider’s affiliated pipeline,
then the Transmission Provider and the Hinshaw pipeline (which is engaging in marketing functions) will be
required to observe the Standards of Conduct by, among other things, having the marketing function employees
function independently from the transmission function employees. The Partnership’s only Hinshaw pipeline,
TLI, does not engage in any off-system sales of gas that have been transported on an affiliated Transmission
Provider, and we do not believe that the Partnership’s operations will be affected by the new standards of
conduct. FERC further clarified Order 717-A in a rehearing order, Order 717-B, on November 16, 2009 and in
Order 717-C, on April 16, 2010. However, Orders 717-B and 717-C did not substantively alter the rules
promulgated under Orders 717 and 717-A. Requests for rehearing of Order 717-C have been filed and are
currently pending before FERC. Our only Transmission Provider, VGS, does not engage in any transactions
with marketing affiliates, and we do not believe that our operations will be affected by the new standards of
conduct. We have no way to predict with certainty whether and to what extent FERC will revise the new
standards of conduct in response to those requests for rehearing.
FERC Market Transparency Rules
In 2007, FERC issued Order 704, whereby wholesale buyers and sellers of more than 2.2 BBtu of physical
natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas
gatherers, natural gas processors and natural gas marketers, 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 to
the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the
responsibility of the reporting entity to determine which transactions should be reported based on the guidance
of Order 704 as clarified in orders on clarification and rehearing.
On November 20, 2008, FERC issued a final rule on daily scheduled flows and capacity posting requirements
(Order 720). Under Order 720, as clarified in orders on clarification and rehearing certain non-interstate
pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous
three calendar years, are required to post daily certain information regarding the pipeline’s capacity and
scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000
MMBtu/d and interstate pipelines are required to post information regarding the provision of no-notice service.
The Partnership takes the position that, at this time, all of its entities are exempt from this rule as currently
written.
On May 20, 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation
services under Section 311 of the NGPA and “Hinshaw” pipelines operating under Section 1(c) of the NGA to
report on a quarterly basis more detailed transportation and storage transaction information, including: rates
charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each
contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the
contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735
further requires that such information must be supplied through a new electronic reporting system and will be
posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged.
The FERC promulgated this Rule after determining that such transactional information would help shippers
make more informed purchasing decisions and would improve the ability of both shippers and the FERC to
monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends
the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years.
Order No. 735 becomes effective on April 1, 2011. On December 16, 2010, the Commission issued Order No.
735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring section 311 and
Hinshaw pipelines to report on a quarterly basis storage and transportation transactions containing specific
information for each transaction, aggregated by contract. Order No. 735-A did grant rehearing of three requests,
including removing the requirement that the quarterly reports include the contract end-date for interruptible
transactions, eliminating the increased per-customer revenue reporting requirements, and extending the deadline
for submitting the quarterly reports from 30 days to 60 days following the quarter end date. As currently written,
this rule does not apply to the Partnership’s Hinshaw pipelines. We will continue to monitor developments with
respect to this rulemaking.
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 or the above regulatory changes to the
Partnership’s natural gas operations. We do not believe that the Partnership would be affected by any such
FERC action materially differently than other midstream natural gas companies with whom it competes.
25
Environmental, Health and Safety Matters
General
The Partnership’s operations are subject to stringent and complex federal, state and local laws and regulations
pertaining to health, safety and the environment. As with the industry generally, compliance with current and
anticipated environmental laws and regulations increases the Partnership’s overall cost of business, including its
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 the Partnership can handle or dispose of
its wastes; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness areas or areas
inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker
protection, require investigatory and remedial action to mitigate pollution conditions caused by the Partnership’s
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 the
Partnership’s activities.
The Partnership has implemented programs and policies designed to keep its 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 or reinterpretation of enforcement policies that result in more
stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a
material adverse effect on the Partnership’s operations and financial position. The Partnership may be unable to
pass on such increased compliance costs to its customers. Moreover, accidental releases or spills may occur in
the course of the Partnership’s operations and we cannot assure you that the Partnership will not incur
significant costs and liabilities as a result of such releases or spills, including any third party claims for damage
to property, natural resources or persons. While we believe that the Partnership is in substantial compliance with
existing environmental laws and regulations and that continued compliance with current requirements would not
have a material adverse effect on the Partnership, there is no assurance that the current conditions will continue
in the future.
The following is a summary of the more significant existing environmental, health and safety laws and
regulations to which the Partnership’s business operations are subject and for which compliance may have a
material adverse impact on its capital expenditures, results of operations or financial position.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) 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 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 Environmental Protection Agency (“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. The Partnership generates materials in
the course of its 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 or such statutes for all or part of the costs
required to clean up sites at which these hazardous substances have been released into the environment.
The Partnership also generates solid wastes, including hazardous wastes that are subject to the requirements of
Resource Conservation and Recovery Act (“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. In the course of its operations, the Partnership generates petroleum product
26
wastes and ordinary industrial wastes such as paint wastes, waste solvents and waste compressor oils that are
regulated as hazardous wastes. Certain materials generated in the exploration, development or production of
crude oil and natural gas are excluded from the RCRA hazardous waste regulations. However, it is possible that
future changes in law or regulation could result in these wastes, including wastes currently generated during the
Partnership’s operations, being designated as “hazardous wastes” and therefore subject to more rigorous and
costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect
on the Partnership’s capital expenditures and operating expenses as well as those of the oil and gas industry in
general.
The Partnership currently owns or leases and has in the past owned or leased, properties that for many years
have been used for midstream natural gas and NGL activities. Although the Partnership has utilized operating
and disposal practices that were standard in the industry at the time, hydrocarbons or 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
wastes was not under the Partnership’s control. These properties and wastes disposed thereon may be subject to
CERCLA, RCRA and analogous state laws. Under these laws, the Partnership 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) and 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 the Partnership’s 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 the Partnership 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. The Partnership is currently reviewing the air emissions monitoring systems
at certain of its facilities. The Partnership 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 or non-ambient storage tanks as a result of its review or in connection with maintaining,
amending or obtaining operating permits and approvals for air emissions. We currently believe, however, that
such requirements will not have a material adverse affect on the Partnership’s operations.
Climate Change
There is increasing attention in the United States and worldwide concerning the issue of climate change and the
effect of Green House Gasses (“GHGs”). In December 2009, the EPA published its findings that emissions of
carbon dioxide, methane and other GHGs present an endangerment to public health and the environment
because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere
and other climatic changes. These findings allow the EPA to proceed with the adoption and implementation of
regulations restricting emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA
already has adopted two sets of regulations regarding possible future regulation of GHG emissions under the
Clean Air Act, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which
would regulate emissions of GHGs from large stationary sources of emissions, such as power plants or
industrial facilities, effective January 2, 2011. In June 2010, EPA published its final rule to address permitting
of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration
(“PSD”) and Title V permitting programs. The final rule tailors the PSD and Title V permitting programs to
apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first
subject to permitting. The EPA’s rules relating to emissions of GHGs from large stationary sources of
emissions are currently subject to a number of legal challenges but the federal courts have thus far declined to
issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to
implement the rules. Moreover, on October 30, 2009, the EPA published a final rule requiring the reporting of
GHG emissions from specified large GHG emission sources in the U.S., on an annual basis beginning in 2011
for emissions occurring in 2010. On November 8, 2010, the EPA adopted amendments to this GHG reporting
rule, expanding the monitoring and reporting obligations to include onshore and offshore oil and natural gas
production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities
on an annual basis, beginning in 2012 for emissions occurring in 2011.
27
In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and
almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the
planned development of GHG emission inventories and/or regional GHG 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 and NGL fractionation plants, to acquire and surrender emission
allowances. The number of allowances available for purchase is reduced each year until the overall GHG
emission reduction goal is achieved. The adoption and implementation of any regulations imposing GHG
reporting or permitting obligations on, or limiting emissions of GHGs from, the Partnership’s equipment and
operations could require the Partnership to incur costs to reduce emissions of GHGs associated with its
operations, could adversely affect its performance of operations in the absence of any permits that may be
required to regulate emission of greenhouse gases, or could adversely affect demand for its natural gas and NGL
processing services.
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse
gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as
increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects
were to occur, they could have in adverse effect on the Partnership’s assets and operations.
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 U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the
terms of the permit issued by the 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 the
Partnership to monitor and sample the storm water runoff. The CWA and analogous state laws can impose
substantial civil and criminal penalties for non-compliance including spills and other nonauthorized discharges.
It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing,
combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and
chemical additives under pressure into rock formations to stimulate gas production. The process is typically
regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority
over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (“SDWA”)
Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this
newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At
the same time, the EPA has commenced a study of the potential adverse impact of hydraulic fracturing
activities, with results of the study expected to be available in late 2012, and a committee of the U.S. House of
Representatives is conducting an investigation of hydraulic fracturing practices. Also, legislation was
introduced in the recently completed session of Congress to amend the SDWA to subject hydraulic fracturing
operations to regulation under the Act and to require the disclosure of chemicals used by the oil and natural gas
industry, and such legislation could be introduced in the current session of Congress. Moreover, some states
have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in
certain circumstances. Adoption of legislation or of any implementing regulations placing restrictions on
hydraulic fracturing activities could impose operational delays, increased operating costs and additional
regulatory burdens on exploration and production operators, which could reduce their production of natural gas
and, in turn, adversely affect our revenues and results of operation by decreasing the volumes of natural gas that
the Partnership gathers, processes and fractionates.
The Oil Pollution Act of 1990, as amended (“OPA”), which amends the CWA, 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 onshore facilities, such as the Partnership’s plants, and the Partnership’s pipelines. Under OPA,
owners and operators of 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
28
related to an oil spill for which such parties could be statutorily responsible. We believe that the Partnership is in
substantial compliance with the CWA, SDWA, 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 the Partnership’s facilities may be located in areas that are
designated as habitat for endangered or threatened species, we believe that the Partnership is in substantial
compliance with the ESA. However, the designation of previously unidentified endangered or threatened species
could cause the Partnership to incur additional costs or become subject to operating restrictions or bans in the
affected areas.
Pipeline Safety
The pipelines used by the Partnership to gather and transport natural gas and transport NGLs are subject to
regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with
respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“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. Pursuant to
these acts, the DOT has promulgated regulations governing pipeline wall thickness, design pressures, maximum
operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency
procedures, as well as other matters intended to ensure adequate protection for the public and to prevent
accidents and failures. 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 the Partnership’s pipeline operations are in substantial compliance with applicable 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.
The Partnership’s pipelines are also subject to regulation by the DOT under the Pipeline Safety Improvement
Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006
(“PIPES Act”). The DOT, through the Pipeline and Hazardous Materials Safety Administration (“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.
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 $2.2 million for years 2011 through 2013 to perform necessary integrity management
program testing on the Partnership’s 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 the Partnership’s financial condition or results of operations.
More recently, on December 3, 2009, the PHMSA issued a final rule mandated by the PIPES Act focusing on
how human interactions of control room personnel, such as avoidance of error or the performance of mitigating
actions, may impact pipeline system integrity. Among other things, the final rule requires operators of hazardous
liquid and gas pipelines to amend their existing written operations and maintenance procedures, operator
qualification programs and emergency plans to take into account such items as specificity of the responsibilities
and roles of control room personnel; listing of planned pipeline-related occurrences during a particular shift that
may be easily shared with other controllers during a shift turnover; establishment of appropriate shift rotations
to protect against controller fatigue; and development of appropriate communications between controllers,
management and field personnel when planning and implementing changes to pipeline equipment or operations.
We do not anticipate that the rule, as issued in final form, will result in substantial costs with respect to the
Partnership’s operations.
29
Employee Health and Safety
We and the Partnership 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 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 the Partnership’s operations and that this
information be provided to employees, state and local government authorities and citizens. The Partnership and
the entities in which it owns 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. The
Partnership has an internal program of inspection designed to monitor and enforce compliance with worker
safety requirements. We believe that the Partnership is in substantial compliance with all applicable laws and
regulations relating to worker health and safety.
Title to Properties and Rights-of-Way
The Partnership’s real property falls into two categories: (1) parcels that it owns in fee and (2) parcels in which
its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental
authorities permitting the use of such land for its operations. Portions of the land on which the Partnership’s
plants and other major facilities are located are owned by the Partnership in fee title, and we believe that the
Partnership has satisfactory title to these lands. The remainder of the land on which the Partnership’s plant sites
and major facilities are located is held by the Partnership pursuant to ground leases between the Partnership, as
lessee, and the fee owner of the lands, as lessors. The Partnership, or its predecessors, has leased these lands for
many years without any material challenge known to us relating to the title to the land upon which the assets are
located, and we believe that the Partnership has satisfactory leasehold estates to such lands. We have no
knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or
license held by the Partnership and we believe that the Partnership has satisfactory title to all of its material
leases, easements, rights-of-way, permits and licenses.
We 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 obtained prior
to transfer. Such consents and approvals would include those required by federal and state agencies or political
subdivisions. In some cases, we 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, causing us 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 our holding of title to any part of such assets subject to future conveyance or as our nominee.
Employees
Through our subsidiaries, we employ 1,020 people who primarily support the Partnership’s operations. None of
these employees are covered by collective bargaining agreements. We consider our employee relations to be
good.
Financial Information by Segment
See “Segment Information” included under Note 21 to our “Consolidated Financial Statements” beginning on
page F-1 of this Annual Report for a presentation of financial results by segment and see “Management’s
Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of the
Partnership – By Segment” for a discussion of our financial results by segment.
30
Available Information
those
reports. We make
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
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 SEC’s 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.
available
free of
charge
filings
such
31
Item 1A. Risk Factors
The nature of our business activities subjects 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. If any of the following
risks were actually to occur, then our business, financial condition, cash flows and results of operations could
be materially adversely affected.
Risks Related to Our Business
Our cash flow is dependent upon the ability of the Partnership to make cash distributions to us.
Our cash flow consists of cash distributions from the Partnership. The amount of cash that the Partnership will
be able to distribute to its partners, including us, each quarter principally depends upon the amount of cash it
generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash
that the Partnership generates from its business, please read “—Risks Inherent in the Partnership’s Business”
and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors That
Significantly Affect Our Results.” The Partnership may not have sufficient available cash each quarter to
continue paying distributions at their current level or at all. If the Partnership reduces its per unit distribution,
because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less
cash available for distribution and would probably be required to reduce the dividend per share of common
stock. The amount of cash the Partnership has available for distribution depends primarily upon the
Partnership’s cash flow, including cash flow from the release of reserves as well as borrowings, and is not solely
a function of profitability, which will be affected by non-cash items. As a result, the Partnership may make cash
distributions during periods when it records losses and may not make cash distributions during periods when it
records profits.
Once we receive cash from the Partnership and the General Partner, our ability to distribute the cash received to
our stockholders is limited by a number of factors, including:
• our obligation to (i) satisfy tax obligations associated with previous sales of assets to the Partnership, (ii)
reimburse the Partnership for certain capital expenditures related to Versado and (iii) provide the
Partnership with limited quarterly distribution support through 2011, all as described in more detail in
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity
and Capital Resources;”
• interest expense and principal payments on any indebtedness we incur;
• restrictions on distributions contained in any existing or future debt agreements;
• our general and administrative expenses, including expenses we incur as a result of being a public
company as well as other operating expenses;
• expenses of the General Partner;
• income taxes;
• reserves we establish in order for us to maintain our 2% general partner interest in the Partnership upon
the issuance of additional partnership securities by the Partnership; and
• reserves our board of directors establishes for the proper conduct of our business, to comply with
applicable law or any agreement binding on us or our subsidiaries or to provide for future dividends by
us.
The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors,
many of which are beyond our control.
32
A reduction in the Partnership’s distributions will disproportionately affect the amount of cash distributions
to which we are entitled.
Our ownership of the IDRs in the Partnership entitles us to receive specified percentages of the amount of cash
distributions made by the Partnership to its limited partners only in the event that the Partnership distributes
more than $0.3881 per unit for such quarter. As a result, the holders of the Partnership’s common units have a
priority over our IDRs to the extent of cash distributions by the Partnership up to and including $0.3881 per unit
for any quarter.
Our IDRs entitle us to receive increasing percentages, up to 48%, of all cash distributed by the Partnership.
Because the Partnership’s distribution rate is currently above the maximum target cash distribution level on the
IDRs, future growth in distributions we receive from the Partnership will not result from an increase in the
target cash distribution level associated with the IDRs. Furthermore, a decrease in the amount of distributions by
the Partnership to less than $0.50625 per unit per quarter would reduce the General Partner’s percentage of the
incremental cash distributions above $0.3881 per common unit per quarter from 48% to 23%. As a result, any
such reduction in quarterly cash distributions from the Partnership would have the effect of disproportionately
reducing the distributions that we receive from the Partnership based on our IDRs as compared to distributions
we receive from the Partnership with respect to our 2% general partner interest and our common units.
If the Partnership’s unitholders remove the General Partner, we would lose our general partner interest and
IDRs in the Partnership and the ability to manage the Partnership.
We currently manage our investment in the Partnership through our ownership interest in the General Partner.
The Partnership’s partnership agreement, however, gives unitholders of the Partnership the right to remove the
General Partner upon the affirmative vote of holders of 66⅔% of the Partnership’s outstanding units. If the
General Partner were removed as general partner of the Partnership, it would receive cash or common units in
exchange for its 2% general partner interest and the IDRs and would also lose its ability to manage the
Partnership. While the cash or common units the General Partner would receive are intended under the terms of
the Partnership’s partnership agreement to fully compensate us in the event such an exchange is required, the
value of the investments we make with the cash or the common units may not over time be equivalent to the
value of the general partner interest and the IDRs had the General Partner retained them.
In addition, if the General Partner is removed as general partner of the Partnership, we would face an increased
risk of being deemed an investment company. Please read “—If in the future we cease to manage and control
the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.”
The Partnership, without our stockholders’ consent, may issue additional common units or other equity
securities, which may increase the risk that the Partnership will not have sufficient available cash to
maintain or increase its cash distribution level per common unit.
Because the Partnership distributes to its partners most of the cash generated by its operations, it relies primarily
upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion
capital expenditures. Accordingly, the Partnership has wide latitude to issue additional common units on the
terms and conditions established by its general partner. We receive cash distributions from the Partnership on
the general partner interest, IDRs and common units that we own. Because a significant portion of the cash we
receive from the Partnership is attributable to our ownership of the IDRs, payment of distributions on additional
Partnership common units may increase the risk that the Partnership will be unable to maintain or increase its
quarterly cash distribution per unit, which in turn may reduce the amount of distributions we receive attributable
to our common units, general partner interest and IDRs and the available cash that we have to pay as dividends
to our stockholders.
33
The General Partner, with our consent but without the consent of our stockholders, may limit or modify the
incentive distributions we are entitled to receive, which may reduce cash dividends to you.
We own the General Partner, which owns the IDRs in the Partnership that entitle us to receive increasing
percentages, up to a maximum of 48% of any cash distributed by the Partnership as certain target distribution
levels are reached in excess of $0.3881 per common unit in any quarter. A substantial portion of the cash flow
we receive from the Partnership is provided by these IDRs. Because of the high percentage of the Partnership’s
incremental cash flow that is distributed to the IDRs, certain potential acquisitions might not increase cash
available for distribution per Partnership unit. In order to facilitate acquisitions by the Partnership or for other
reasons, the board of directors of the General Partner may elect to reduce the IDRs payable to us with our
consent. These reductions may be permanent reductions in the IDRs or may be reductions with respect to cash
flows from the potential acquisition. If distributions on the IDRs were reduced for the benefit of the Partnership
units, the total amount of cash distributions we would receive from the Partnership, and therefore the amount of
cash dividends we could pay to our stockholders, would be reduced.
In the future, we may not have sufficient cash to pay estimated dividends.
Because our only source of operating cash flow consists of cash distributions from the Partnership, the amount
of dividends we are able to pay to our stockholders may fluctuate based on the level of distributions the
Partnership makes to its partners, including us. The Partnership may not continue to make quarterly distributions
at the 2010 fourth quarter distribution level of $0.5475 per common unit, or may not distribute any other
amount, or increase its quarterly distributions in the future. In addition, while we would expect to increase or
decrease dividends to our stockholders if the Partnership increases or decreases distributions to us, the timing
and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount
of any changes in dividends made by us. Factors such as reserves established by our board of directors for our
estimated general and administrative expenses of being a public company as well as other operating expenses,
reserves to satisfy our debt service requirements, if any, and reserves for future dividends by us may affect the
dividends we make to our stockholders. The actual amount of cash that is available for dividends to our
stockholders will depend on numerous factors, many of which are beyond our control.
Our cash dividend policy limits our ability to grow.
Because we plan on distributing a substantial amount of our cash flow, our growth may not be as fast as the
growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because our only
cash-generating assets are direct and indirect partnership interests in the Partnership, our growth will be
substantially dependent upon the Partnership. If we issue additional shares of common stock or we were to incur
debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we
will be unable to maintain or increase our cash dividend levels.
Our rate of growth may be reduced to the extent we purchase additional units from the Partnership, which
will reduce the relative percentage of the cash we receive from the IDRs.
Our business strategy includes, where appropriate, supporting the growth of the Partnership by purchasing the
Partnership’s units or lending funds or providing other forms of financial support to the Partnership to provide
funding for the acquisition of a business or asset or for a growth project. To the extent we purchase common
units or securities not entitled to a current distribution from the Partnership, the rate of our distribution growth
may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of
IDRs, whose distributions increase at a faster rate than those of our other securities.
We have a credit facility that contains various restrictions on our ability to pay dividends to our stockholders,
borrow additional funds or capitalize on business opportunities.
We have a credit facility that contains various operating and financial restrictions and covenants. Our ability to
comply with these restrictions and covenants may be affected by events beyond our control, including prevailing
economic, financial and industry conditions. If we are unable to comply with these restrictions and covenants,
any future indebtedness under this credit facility may become immediately due and payable and our lenders’
commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds
to make these accelerated payments.
34
Our credit facility limits our ability to pay dividends to our stockholders during an event of default or if an event
of default would result from such dividend. In addition, any future borrowings may:
• adversely affect our ability to obtain additional financing for future operations or capital needs;
• limit our ability to pursue acquisitions and other business opportunities;
• make our results of operations more susceptible to adverse economic or operating conditions; or
• limit our ability to pay dividends.
Our payment of any principal and interest will reduce our cash available for dividends to holders of common
stock. In addition, we are able to incur substantial additional indebtedness in the future. If we incur additional
debt, the risks associated with our leverage would increase. For more information regarding our credit facility,
please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—
Liquidity and Capital Resources.”
If dividends on our shares of common stock are not paid with respect to any fiscal quarter, including those at
the anticipated initial dividend rate, our stockholders will not be entitled to receive that quarter’s payments in
the future.
Dividends to our stockholders will not be cumulative. Consequently, if dividends on our shares of common
stock are not paid with respect to any fiscal quarter, including those at the anticipated initial dividend rate, our
stockholders will not be entitled to receive that quarter’s payments in the future.
The Partnership’s practice of distributing all of its available cash may limit its ability to grow, which could
impact distributions to us and the available cash that we have to dividend to our stockholders.
Because our only cash-generating assets are common units and general partner interests in the Partnership,
including the IDRs, our growth will be dependent upon the Partnership’s ability to increase its quarterly cash
distributions. The Partnership has historically distributed to its partners most of the cash generated by its
operations. As a result, it relies primarily upon external financing sources, including debt and equity issuances,
to fund its acquisitions and expansion capital expenditures. Accordingly, to the extent the Partnership is unable
to finance growth externally; its ability to grow will be impaired because it distributes substantially all of its
available cash. Also, if the Partnership incurs additional indebtedness to finance its growth, the increased
interest expense associated with such indebtedness may reduce the amount of available cash that we can
distribute to you. In addition, to the extent the Partnership issues additional units in connection with any
acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase
the risk that the Partnership will be unable to maintain or increase its per unit distribution level, which in turn
may impact the cash available for dividends to our stockholders.
Restrictions in the Partnership’s senior secured credit facility and indentures could limit its ability to make
distributions to us.
The Partnership’s senior secured credit facility and indentures contain covenants limiting its ability to incur
indebtedness, grant liens and make distributions. The Partnership’s senior secured credit facility also contains
covenants requiring the Partnership to maintain certain financial ratios. The Partnership is prohibited from
making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a
covenant under its senior secured credit facility or the indentures.
If in the future we cease to manage and control the Partnership, we may be deemed to be an investment
company under the Investment Company Act of 1940.
If we cease to manage and control the Partnership and are deemed to be an investment company under the
Investment Company Act of 1940, we would either have to register as an investment company under the
Investment Company Act of 1940, obtain an exemption from the SEC or modify our organizational structure or
our contractual rights to fall outside the definition of an investment company. Registering as an investment
company could, among other things, materially limit our ability to engage in transactions with the Partnership,
including the purchase and sale of certain securities or other property to or from the Partnership, restrict our
35
ability to borrow funds or engage in other transactions involving leverage and require us to add additional
directors who are independent of us and the Partnership, and adversely affect the price of our common stock.
Our historical financial information may not be representative of our future performance.
The historical financial information included in this annual report is derived from our historical financial
statements for periods including prior to our initial public offering in December 2010. Our audited historical
financial statements were prepared in accordance with GAAP. Accordingly, the historical financial information
included in this annual report does not reflect what our results of operations and financial condition would have
been had we been a public entity during the periods presented, or what our results of operations and financial
condition will be in the future.
If we lose any of our named executive officers, our business may be adversely affected.
Our success is dependent upon the efforts of the named executive officers. Our named executive officers are
responsible for executing the Partnership’s business strategy and, when appropriate to our primary business
objective, facilitating the Partnership’s growth through various forms of financial support provided by us,
including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision
contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or
non-yielding equity interests or providing other financial support to the Partnership. There is substantial
competition for qualified personnel in the midstream natural gas industry. We may not be able to retain our
existing named executive officers or fill new positions or vacancies created by expansion or turnover. We have
not entered into employment agreements with any of our named executive officers. In addition, we do not
maintain “key man” life insurance on the lives of any of our named executive officers. A loss of one or more of
our named executive officers could harm our and the Partnership’s business and prevent us from implementing
our and the Partnership’s business strategy.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our
financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to
revise our financial results and disclosure in the future.
Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively
prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and
operating results would be harmed. We continue to enhance our internal controls and financial reporting
capabilities. These enhancements require a significant commitment of resources, personnel and the development
and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting.
Our efforts to update and maintain our internal controls may not be successful, and we may be unable to
maintain adequate controls over our financial processes and reporting in the future, including future compliance
with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective
controls, or difficulties encountered in the effective improvement of our internal controls could prevent us from
timely and reliably reporting our financial results and may harm our operating results. Ineffective internal
controls could also cause investors to lose confidence in our reported financial information. In addition, the
Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how
we or the Partnership are required to record revenues, expenses, assets and liabilities. Any significant change in
accounting standards or disclosure requirements could have a material effect on our business, results of
operations, financial condition and ability to service our and our subsidiaries’ debt obligations.
An increase in interest rates may cause the market price of our common stock to decline.
Like all equity investments, an investment in our common stock is subject to certain risks. In exchange for
accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable
from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-
adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in
demand for riskier investments generally, including yield-based equity investments. Reduced demand for our
common stock resulting from investors seeking other more favorable investment opportunities may cause the
trading price of our common stock to decline.
36
The requirements of being a public company, including compliance with the reporting requirements of the
Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs
and distract management; and we may be unable to comply with these requirements in a timely or cost-
effective manner.
As a public company with listed equity securities, we must comply with new laws, regulations and
requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of
the SEC and the requirements of the New York Stock Exchange, or NYSE, with which we were not required to
comply as a private company. Complying with these statutes, regulations and requirements will occupy a
significant amount of time of our board of directors and management and will significantly increase our costs
and expenses. These new laws and regulations require us to:
• institute a more comprehensive compliance function;
• design, establish, evaluate and maintain an additional system of internal controls over financial reporting
in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related
rules and regulations of the SEC and the Public Company Accounting Oversight Board;
• comply with rules promulgated by the NYSE;
• prepare and distribute periodic public reports in compliance with our obligations under the federal
securities laws;
• establish new internal policies, such as those relating to disclosure controls and procedures and insider
trading;
• involve and retain to a greater degree outside counsel and accountants in the above activities; and
• augment our investor relations function.
In addition, we also expect that being a public company could require us to accept less director and officer
liability insurance coverage than we desire or to incur additional costs to maintain coverage. These factors could
also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to
serve on our Audit Committee, and qualified executive officers.
Future sales of our common stock in the public market could lower our stock price, and any additional
capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
We or our stockholders may sell shares of common stock in subsequent public offerings. We may also issue
additional shares of common stock or convertible securities. As of December 31, 2010 we have 42,292,348
outstanding shares of common stock. This number consists of 18,831,250 shares that the selling stockholders
sold in our initial public offering. Following our initial public offering, the existing shareholders owned
approximately 23.5 million shares, or approximately 55.5% of our total outstanding shares. All such shares may
be sold into the market in the future. Certain of our existing stockholders are party to a registration rights
agreement with us which requires us to affect the registration of their shares in certain circumstances no earlier
than the expiration of the lock-up period contained in the underwriting agreement of our initial public offering.
We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances
and sales of shares of our common stock will have on the market price of our common stock. Sales of
substantial amounts of our common stock (including shares issued in connection with an acquisition), or the
perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware
law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely
affect the market price of our common stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock
without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult
for a third party to acquire us. In addition, some provisions of our amended and restated certificate of
37
incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control
of us, even if the change of control would be beneficial to our stockholders, including:
• a classified board of directors, so that only approximately one-third of our directors are elected each year;
• limitations on the removal of directors; and
• limitations on the ability of our stockholders to call special meetings and establish advance notice
provisions for stockholder proposals and nominations for elections to the board of directors to be acted
upon at meetings of stockholders.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,”
meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a
period of three years from the date this person became an interested stockholder, unless various conditions are
met, such as approval of the transaction by our board of directors. We anticipate opting out of this provision of
Delaware law until such time as Warburg Pincus and certain transferees; do not beneficially own at least 15% of
our common stock. Please read “Description of Our Capital Stock—Anti-Takeover Effects of Provisions of Our
Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law.”
We have a significant stockholder, which will limit other stockholders’ ability to influence corporate matters
and may give rise to conflicts of interest.
Affiliates of Warburg Pincus beneficially own approximately 32.2% of our outstanding common stock.
Accordingly, Warburg Pincus can exert significant influence over us and any action requiring the approval of
the holders of our stock, including the election of directors and approval of significant corporate transactions.
Warburg’s concentrated ownership makes it less likely that any other holder or group of holders of common
stock will be able to affect the way we are managed or the direction of our business. These factors also may
delay or prevent a change in our management or voting control.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and
its affiliates, on the other hand, concerning among other things, potential competitive business activities,
business opportunities, the issuance of additional securities, the payment of dividends by us and other matters.
Warburg Pincus is a private equity firm that has invested, among other things, in companies in the energy
industry. As a result, Warburg Pincus’ existing and future portfolio companies which it controls may compete
with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
In our amended and restated certificate of incorporation, we have renounced business opportunities that may
be pursued by the Partnership or by affiliated stockholders that currently hold a significant amount of our
common stock.
In our restated charter and in accordance with Delaware law, we have renounced any interest or expectancy we
may have in, or being offered an opportunity to participate in, any business opportunities, including any
opportunities within those classes of opportunity currently pursued by the Partnership, presented to Warburg
Pincus or any private fund that it manages or advises, their affiliates (other than us and our subsidiaries), their
officers, directors, partners, employees or other agents who serve as one of our directors, Merrill Lynch
Ventures L.P. 2001, its affiliates (other than us and our subsidiaries) and any portfolio company in which such
entities or persons has an equity investment (other than us and our subsidiaries) participates or desires or seeks
to participate in and that involves any aspect of the energy business or industry.
The duties of our officers and directors may conflict with those owed to the Partnership and these officers
and directors may face conflicts of interest in the allocation of administrative time among our business and
the Partnership’s business.
We anticipate that substantially all of our officers and certain members of our board of directors will be officers
or directors of the General Partner and, as a result, will have separate duties that govern their management of the
Partnership’s business. These officers and directors may encounter situations in which their obligations to us, on
the one hand, and the Partnership, on the other hand, are in conflict. The resolution of these conflicts may not
always be in our best interest or that of our stockholders.
38
In addition, our officers who also serve as officers of the General Partner may face conflicts in allocating their
time spent on our behalf and on behalf of the Partnership. These time allocations may adversely affect our or the
Partnership’s results of operations, cash flows, and financial condition.
Risks Inherent in the Partnership’s Business
Because we are directly dependent on the distributions we receive from the Partnership, risks to the
Partnership’s operations are also risks to us. We have set forth below risks to the Partnership’s business and
operations, the occurrence of which could negatively impact the Partnership’s financial performance and
decrease the amount of cash it is able to distribute to us.
The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.
The Partnership has a substantial amount of indebtedness. As of December 31, 2010, the Partnership had
approximately $765.3 million of borrowings outstanding under its senior secured credit facility, approximately
$101.3 million of letters of credit outstanding and approximately $233.4 million of additional borrowing
capacity under its senior secured credit facility. The partnership’s $1.1 billion senior secured revolving credit
facility allows us to request increases in commitments up to an additional $300.0 million. For the years ended
December 31, 2010, 2009 and 2008, the Partnership’s consolidated interest expense was $110.8 million, $159.8
million and $156.1 million.
This substantial level of indebtedness increases the possibility that the Partnership may be unable to generate
cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness.
This substantial indebtedness, combined with the Partnership’s lease and other financial obligations and
contractual commitments, could have other important consequences to us, including the following:
• the Partnership’s 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;
• satisfying the Partnership’s obligations with respect to indebtedness may be more difficult and any failure
to comply with the obligations of any debt instruments could result in an event of default under the
agreements governing such indebtedness;
• the Partnership will need a portion of cash flow to make interest payments on debt, reducing the funds
that would otherwise be available for operations and future business opportunities;
• the Partnership’s debt level will make it more vulnerable to competitive pressures or a downturn in its
business or the economy generally; and
• the Partnership’s debt level may limit flexibility in planning for, or responding to, changing business and
economic conditions.
The Partnership’s ability to service its debt will depend upon, among other things, its 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 its control. If the Partnership’s operating results are not
sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or
delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or
refinancing debt, or seeking additional equity capital and may adversely affect the Partnership’s ability to make
cash distributions. The Partnership may not be able to affect any of these actions on satisfactory terms, or at all.
Increases in interest rates could adversely affect the Partnership’s business.
The Partnership has significant exposure to increases in interest rates. As of December 31, 2010, its total
indebtedness was $1,445.4 million, of which $680.1 million was at fixed interest rates and $765.3 million was at
variable interest rates. After giving effect to interest rate swaps with a notional amount of $300 million, a one
percentage point increase in the interest rate on the Partnership’s variable interest rate debt would have
increased its consolidated annual interest expense by approximately $4.7 million. As a result of this significant
amount of variable interest rate debt, the Partnership’s financial condition could be adversely affected by
significant increases in interest rates.
39
Despite current indebtedness levels, the Partnership may still be able to incur substantially more debt. This
could increase the risks associated with its substantial leverage.
The Partnership may be able to incur substantial additional indebtedness in the future. As of December
31, 2010, the Partnership had approximately $765.3 million of borrowings outstanding under its senior secured
credit facility, approximately $101.3 million of letters of credit outstanding and approximately $233.4 million of
additional borrowing capacity under its senior secured credit facility. The Partnership may be able to incur an
additional $300 million of debt under its senior secured credit facility if it requests and is able to obtain
commitments for the additional $300 million available under its senior secured credit facility. Although the
Partnership’s senior secured credit facility contains restrictions on the incurrence of additional indebtedness,
these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness
incurred in compliance with these restrictions could be substantial. If the Partnership incurs additional debt, the
risks associated with its substantial leverage would increase.
The terms of the Partnership’s senior secured credit facility and indentures may restrict its current and
future operations, particularly its ability to respond to changes in business or to take certain actions.
The credit agreement governing the Partnership’s senior secured credit facility and the indentures governing the
Partnership’s senior notes (other than its 11¼% senior notes due 2017) contain, and any future indebtedness the
Partnership incurs will likely contain, a number of restrictive covenants that impose significant operating and
financial restrictions, including restrictions on its ability to engage in acts that may be in its best long-term
interests. These agreements include covenants that, among other things, restrict the Partnership’s ability to:
• incur or guarantee additional indebtedness or issue preferred stock;
• pay distributions on its equity securities or redeem, repurchase or retire its equity securities or
subordinated indebtedness;
• make investments;
• create restrictions on the payment of distributions to its equity holders;
• sell assets, including equity securities of its subsidiaries;
• engage in affiliate transactions,
• consolidate or merge;
• incur liens;
• prepay, redeem and repurchase certain debt, other than loans under the senior secured credit facility;
• make certain acquisitions;
• transfer assets;
• enter into sale and lease back transactions;
• make capital expenditures;
• amend debt and other material agreements; and
• change business activities conducted by it.
In addition, the Partnership’s senior secured credit facility requires it to satisfy and maintain specified financial
ratios and other financial condition tests. The Partnership’s ability to meet those financial ratios and tests can be
affected by events beyond its control, and we cannot assure you that the Partnership will meet those ratios and
tests.
40
A breach of any of these covenants could result in an event of default under the Partnership’s senior secured
credit facility and indentures, as applicable. Upon the occurrence of such an event of default, all amounts
outstanding under the applicable debt agreements could be declared to be immediately due and payable and all
applicable commitments to extend further credit could be terminated. If the Partnership is unable to repay the
accelerated debt under its senior secured credit facility, the lenders under senior secured credit facility could
proceed against the collateral granted to them to secure that indebtedness. The Partnership has pledged
substantially all of its assets as collateral under its senior secured credit facility. If the Partnership indebtedness
under its senior secured credit facility or indentures is accelerated, we cannot assure you that the Partnership
will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in
these debt agreements and any future financing agreements may adversely affect the Partnership’s ability to
finance future operations or capital needs or to engage in other business activities.
The Partnership’s cash flow is affected by supply and demand for natural gas and NGL products and by
natural gas and NGL prices, and decreases in these prices could adversely affect its results of operations and
financial condition.
The Partnership’s operations can be affected by the level of natural gas and NGL prices and the relationship
between these prices. The prices of oil, natural gas and NGLs have been volatile and we expect this volatility to
continue. The Partnership’s future cash flow may be materially adversely affected if it experiences significant,
prolonged pricing deterioration. The markets and prices for natural gas and NGLs depend upon factors beyond
the Partnership’s 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 and economic conditions impacting the Partnership’s primary markets;
• the economic conditions of the Partnership’s customers;
• the level of domestic crude oil and natural gas production and consumption;
• the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;
• actions taken by foreign oil and gas producing nations;
• the availability of local, intrastate and interstate transportation systems and storage for residue natural gas
and NGLs;
• the availability and marketing of competitive fuels and/or feedstocks;
• the impact of energy conservation efforts; and
• the extent of governmental regulation and taxation.
The Partnership’s primary natural gas gathering and processing arrangements that expose it to commodity price
risk are its percent-of-proceeds arrangements. For the year ended December 31, 2010 and 2009, its percent-of-
proceeds arrangements accounted for approximately 37% and 48% of its gathered natural gas volume. Under
these arrangements, the Partnership generally processes natural gas from producers and remits 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 its processing facilities. In some percent-of-
proceeds arrangements, the Partnership remits to the producer a percentage of an index-based 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, the Partnership’s revenues and its cash flows increase or decrease,
whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. Please see “Management’s
Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative
Disclosures about Market Risk.”
41
Because of the natural decline in production in the Partnership’s operating regions and in other regions
from which it sources NGL supplies, the Partnership’s long-term success depends on its ability to obtain new
sources of supplies of natural gas and NGLs, which depends on certain factors beyond its control. Any
decrease in supplies of natural gas or NGLs could adversely affect the Partnership’s business and operating
results.
The Partnership’s gathering systems are connected to oil and natural gas wells from which production will
naturally decline over time, which means that its cash flows associated with these sources of natural gas will
likely also decline over time. The Partnership’s logistics assets are similarly impacted by declines in NGL
supplies in the regions in which the Partnership operates as well as other regions from which it sources NGLs.
To maintain or increase throughput levels on its gathering systems and the utilization rate at its processing
plants and its treating and fractionation facilities, the Partnership must continually obtain new natural gas and
NGL supplies. A material decrease in natural gas production from producing areas on which the Partnership
relies, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural
gas that it processes and NGL products delivered to its fractionation facilities. The Partnership’s ability to obtain
additional sources of natural gas and NGLs depends, in part, on the level of successful drilling and production
activity near its gathering systems and, in part, on the level of successful drilling and production in other areas
from which it sources NGL supplies. The Partnership has no control over the level of such activity in the areas
of its operations, the amount of reserves associated with the wells or the rate at which production from a well
will decline. In addition, the Partnership has 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, 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 and production activity generally decreases as oil and
natural gas prices decrease. Prices of oil and natural gas have been historically volatile, and the Partnership
expects this volatility to continue. Consequently, even if new natural gas reserves are discovered in areas served
by the Partnership’s assets, producers may choose not to develop those reserves. Reductions in exploration and
production activity, competitor actions or shut-ins by producers in the areas in which the Partnership operates
may prevent it from obtaining supplies of natural gas to replace the natural decline in volumes from existing
wells, which could result in reduced volumes through its facilities, and reduced utilization of its gathering,
treating, processing and fractionation assets.
If the Partnership does not make acquisitions on economically acceptable terms or efficiently and effectively
integrate the acquired assets with its asset base, its future growth will be limited.
The Partnership’s ability to grow depends, in part, on its ability to make acquisitions that result in an increase in
cash generated from operations per unit. The Partnership is unable to acquire businesses from us in order to
grow because our only assets are the interests in the Partnership that we own. As a result, it will need to focus on
third-party acquisitions and organic growth. If the Partnership is unable to make these accretive acquisitions
either because the Partnership is (1) unable to identify attractive acquisition candidates or negotiate acceptable
purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable
terms or (3) outbid by competitors, then its future growth and ability to increase distributions will be limited.
Any acquisition involves potential risks, including, among other things:
• 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 volumes, revenues, profitability or growth;
• the failure to realize any expected synergies and cost savings;
• coordinating geographically disparate organizations, systems and facilities.
42
• 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 management’s and employees’ attention from other business concerns; and
• customer or key employee losses at the acquired businesses.
If these risks materialize, the acquired assets may inhibit the Partnership’s growth, fail to deliver expected
benefits and add further unexpected costs. Challenges may arise whenever businesses with different operations
or management are combined and the Partnership may experience unanticipated delays in realizing the benefits
of an acquisition. If the Partnership consummates any future acquisition, its 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 the Partnership will consider in evaluating future acquisitions.
The Partnership’s acquisition strategy is based, in part, on its expectation of ongoing divestitures of energy
assets by industry participants. A material decrease in such divestitures would limit its opportunities for future
acquisitions and could adversely affect its operations and cash flows available for distribution to its unit holders.
Acquisitions may significantly increase the Partnership’s size and diversify the geographic areas in which it
operates. The Partnership may not achieve the desired affect from any future acquisitions.
The Partnership’s 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 its results of operations and
financial condition.
One of the ways the Partnership intends to grow its business is through the construction of new midstream
assets. The construction of additions or modifications to the Partnership’s existing systems and the construction
of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond
the Partnership’s control and may require the expenditure of significant amounts of capital. If the Partnership
undertakes these projects, they may not be completed on schedule or at the budgeted cost or at all. Moreover,
the Partnership’s revenues may not increase immediately upon the expenditure of funds on a particular project.
For instance, if the Partnership builds a new pipeline, the construction may occur over an extended period of
time and it will not receive any material increases in revenues until the project is completed. Moreover, it may
construct facilities to capture anticipated future growth in production in a region in which such growth does not
materialize. Since the Partnership is not engaged in the exploration for and development of natural gas and oil
reserves, it does not possess reserve expertise and it often does not have access to third-party estimates of
potential reserves in an area prior to constructing facilities in such area. To the extent the Partnership relies on
estimates of future production in its decision to construct additions to its 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 the Partnership’s expected
investment return, which could adversely affect its results of operations and financial condition. In addition, the
construction of additions to the Partnership’s existing gathering and transportation assets may require it to
obtain new rights-of-way prior to constructing new pipelines. The Partnership may be unable to obtain such
rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive
expansion opportunities. Additionally, it may become more expensive for the Partnership 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, the
Partnership’s cash flows could be adversely affected.
The Partnership’s acquisition strategy requires access to new capital. Tightened capital markets or increased
competition for investment opportunities could impair its ability to grow through acquisitions.
The Partnership continuously considers and enters into discussions regarding potential acquisitions. Any
limitations on its access to capital will impair its ability to execute this strategy. If the cost of such capital
becomes too expensive, its ability to develop or acquire strategic and accretive assets will be limited. The
Partnership may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that
influence the Partnership’s initial cost of equity include market conditions, fees it pays to underwriters and other
43
offering costs, which include amounts it pays for legal and accounting services. The primary factors influencing
the Partnership’s cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan
origination fees and similar charges it pays to lenders.
Current weak economic conditions and the volatility and disruption in the weak financial markets have
increased the cost of raising money in the debt and equity capital markets substantially while diminishing the
availability of funds from those markets. Also, as a result of concerns about the stability of financial markets
generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets
generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter
lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and
reduced and, in some cases, ceased to provide funding to borrowers. These factors may impair the Partnership’s
ability to execute its acquisition strategy.
In addition, the Partnership is experiencing increased competition for the types of assets it contemplates
purchasing. Weak economic conditions and competition for asset purchases could limit the Partnership’s ability
to fully execute its growth strategy.
Demand for propane is seasonal and requires increases in the partnership’s inventory to meet seasonal
demand.
Weather conditions have a significant impact on the demand for propane because end-users depend on propane
principally for heating purposes. Warmer-than-normal temperatures in one or more regions in which the
Partnership operates can significantly decrease the total volume of propane it sells. Lack of consumer demand
for propane may also adversely affect the retailers the Partnership transacts within its wholesale propane
marketing operations, exposing it to their inability to satisfy their contractual obligations to the Partnership.
If the Partnership fails to balance its purchases of natural gas and its sales of residue gas and NGLs, its
exposure to commodity price risk will increase.
The Partnership may not be successful in balancing its purchases of natural gas and its sales of residue gas and
NGLs. In addition, a producer could fail to deliver promised volumes to the Partnership 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 the Partnership’s purchases and sales. If the Partnership’s purchases and sales are
not balanced, it will face increased exposure to commodity price risks and could have increased volatility in its
operating income.
The Partnership’s hedging activities may not be effective in reducing the variability of its cash flows and
may, in certain circumstances, increase the variability of its cash flows. Moreover, the Partnership’s hedges
may not fully protect it against volatility in basis differentials. Finally, the percentage of the Partnership’s
expected equity commodity volumes that are hedged decreases substantially over time.
The Partnership has entered into derivative transactions related to only a portion of its equity volumes. As a
result, it will continue to have direct commodity price risk to the unhedged portion. The Partnership’s actual
future volumes may be significantly higher or lower than it estimated at the time it entered into the derivative
transactions for that period. If the actual amount is higher than it estimated, it will have greater commodity price
risk than it intended. If the actual amount is lower than the amount that is subject to its derivative financial
instruments, it might be forced to satisfy all or a portion of its derivative transactions without the benefit of the
cash flow from its sale of the underlying physical commodity. The percentages of the Partnership’s expected
equity volumes that are covered by its hedges decrease over time. To the extent the Partnership hedges its
commodity price risk, it may forego the benefits it would otherwise experience if commodity prices were to
change in its favor. The derivative instruments the Partnership utilizes for these hedges are based on posted
market prices, which may be higher or lower than the actual natural gas, NGLs and condensate prices that it
realizes in its operations. These pricing differentials may be substantial and could materially impact the prices
the Partnership ultimately realizes. In addition, current market and economic conditions may adversely affect
the Partnership’s hedge counterparties’ ability to meet their obligations. Given the current volatility in the
financial and commodity markets, the Partnership may experience defaults by its hedge counterparties in the
future. As a result of these and other factors, the Partnership’s hedging activities may not be as effective as it
intends in reducing the variability of its cash flows, and in certain circumstances may actually increase the
variability of its cash flows. Please see “Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”
44
If third-party pipelines and other facilities interconnected to the Partnership’s natural gas pipelines and
processing facilities become partially or fully unavailable to transport natural gas and NGLs, the
Partnership’s revenues could be adversely affected.
The Partnership depends upon third-party pipelines, storage and other facilities that provide delivery options to
and from its pipelines and processing facilities. Since it does not own or operate these pipelines or other
facilities, their continuing operation in their current manner is not within the Partnership’s control. If any of
these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities
change so as to restrict the Partnership’s ability to utilize them, its revenues could be adversely affected.
The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect
the Partnership’s business and operating results.
The Partnership competes with similar enterprises in its respective areas of operation. Some of its competitors
are large oil, natural gas and natural gas liquid companies that have greater financial resources and access to
supplies of natural gas and NGLs than it does. Some of these competitors may expand or construct gathering,
processing and transportation systems that would create additional competition for the services the Partnership
provides to its customers. In addition, its customers who are significant producers of natural gas may develop
their own gathering, processing and transportation systems in lieu of using the Partnership’s. The Partnership’s
ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues
and cash flows could be adversely affected by the activities of its competitors and its customers. All of these
competitive pressures could have a material adverse effect on the Partnership’s business, results of operations,
and financial condition.
The Partnership typically does not obtain independent evaluations of natural gas reserves dedicated to its
gathering pipeline systems; therefore, volumes of natural gas on the Partnership’s systems in the future
could be less than it anticipates.
The Partnership typically does not obtain independent evaluations of natural gas reserves connected to its
gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of
such evaluations. Accordingly, the Partnership does not have independent estimates of total reserves dedicated
to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the
reserves connected to its gathering systems is less than it anticipates and the Partnership is unable to secure
additional sources of natural gas, then the volumes of natural gas transported on its gathering systems in the
future could be less than it anticipates. A decline in the volumes of natural gas on the Partnership’s systems
could have a material adverse effect on its business, results of operations, and financial condition.
A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel
markets, or a significant increase in NGL product supply relative to this demand, could materially adversely
affect the Partnership’s business, results of operations and financial condition.
The NGL products the Partnership produces 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 or industry specific economic conditions, new government regulations, global competition, reduced
demand by consumers for products made with NGL products (for example, reduced petrochemical demand
observed due to lower activity in the automobile and construction industries), increased competition from
petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other
reasons, could result in a decline in the volume of NGL products the Partnership handles or reduce the fees it
charges for its services. Also, increased supply of NGL products could reduce the value of NGLs handled by the
Partnership and reduce the margins realized. The Partnership’s 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 processors to leave the ethane in the natural
gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing.
45
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 the Partnership’s 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, changes in feedstocks,
products and economics, 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 mandated composition of motor
gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could adversely
affect demand for natural gasoline.
NGLs and products produced from NGLs also compete with products from global markets. Any reduced
demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets the
Partnership’s accesses for any of the reasons stated above could adversely affect demand for the services it
provides as well as NGL prices, which would negatively impact the Partnership’s results of operations and
financial condition.
The Partnership has significant relationships with Chevron Phillips Chemical Company LLC as a customer
for its marketing and refinery services. In some cases, these agreements are subject to renegotiation and
termination rights.
For the years ended December 31, 2010, and 2009, approximately 10% and 15% of the Partnership’s
consolidated revenues were derived from transactions with CPC. Under many of the Partnership’s CPC
contracts where it purchases or markets NGLs on CPC’s behalf, CPC may elect to terminate the contracts or
renegotiate the price terms. To the extent CPC reduces the volumes of NGLs that it purchases from the
Partnership or reduces the volumes of NGLs that the Partnership markets on its behalf or to the extent the
economic terms of such contracts are changed, the Partnership’s revenues and cash available for debt service
could decline.
The tax treatment of the Partnership depends on its status as a partnership for federal income tax purposes
as well as its not being subject to a material amount of entity-level taxation by individual states. If the
Internal Revenue Service (“IRS”) were to treat the Partnership as a corporation for federal income tax
purposes or the Partnership becomes subject to a material amount of entity-level taxation for state tax
purposes, then its cash available for distribution to its unitholders, including us, would be substantially
reduced.
We currently own an approximate 13.7% limited partner interest, a 2% general partner interest and the IDRs in
the Partnership. The anticipated after-tax economic benefit of our investment in the Partnership depends largely
on its being treated as a partnership for federal income tax purposes. In order to maintain its status as a
partnership for United States federal income tax purposes, 90 percent or more of the gross income of the
Partnership for every taxable year must be “qualifying income” under section 7704 of the Internal Revenue
Code of 1986, as amended. The Partnership has not requested and does not plan to request a ruling from the IRS
with respect to its treatment as a partnership for federal income tax purposes. Despite the fact that the
Partnership is a limited partnership under Delaware law, it is possible, under certain circumstances for an entity
such as the Partnership to be treated as a corporation for federal income tax purposes.
Although the Partnership does not believe based upon its current operations that it is so treated, a change in the
Partnership’s business could cause it to be treated as a corporation for federal income tax purposes or otherwise
subject it to federal income taxation as an entity. If the Partnership were treated as a corporation for federal
46
income tax purposes, it would pay federal income tax on its 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 the
Partnership’s unitholders, including us, would generally be taxed again as corporate distributions and no
income, gains, losses or deductions would flow through to the Partnership’s unitholders, including us. If such
tax was imposed upon the Partnership as a corporation, its cash available for distribution would be substantially
reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the
anticipated cash flow and after-tax return to the Partnership’s unitholders, including us, and would likely cause a
substantial reduction in the value of our investment in the Partnership.
In addition, current law may change so as to cause the Partnership to be treated as a corporation for federal
income tax purposes or otherwise subject the Partnership to entity-level taxation for state or local income tax
purposes. At the federal level, members of Congress have recently considered legislative changes that would
affect the tax treatment of certain publicly traded partnerships. Although the considered legislation would not
appear to have affected the Partnership’s treatment as a partnership, we are unable to predict whether any of
these changes or other proposals will be reintroduced or 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 the Partnership’s 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, the Partnership is required to pay Texas franchise tax at a maximum effective rate of
0.7% of its gross income apportioned to Texas in the prior year. Imposition of any similar tax on the Partnership
by additional states would reduce the cash available for distribution to Partnership unitholders, including us.
The Partnership’s partnership agreement provides that if a law is enacted or existing law is modified or
interpreted in a manner that subjects it to taxation as a corporation or otherwise subjects it to entity-level
taxation for federal, state or local income tax purposes, the minimum quarterly distribution and the target
distribution amounts may be adjusted to reflect the impact of that law on the Partnership.
The Partnership does not own most of the land on which its pipelines and compression facilities are located,
which could disrupt its operations.
The Partnership does not own most of the land on which its pipelines and compression facilities are located, and
the Partnership is therefore subject to the possibility of more onerous terms and/or increased costs to retain
necessary land use if it does not have valid rights-of-way or leases or if such rights-of-way or leases lapse or
terminate. The Partnership sometimes obtains the rights to land owned by third parties and governmental
agencies for a specific period of time. The Partnership’s loss of these rights, through its inability to renew right-
of-way contracts, leases or otherwise, could cause it to cease operations on the affected land, increase costs
related to continuing operations elsewhere, and reduce its revenue.
The Partnership may be unable to cause its majority-owned joint ventures to take or not to take certain
actions unless some or all of its joint venture participants agree.
The Partnership participates in several majority-owned joint ventures whose corporate governance structures
require at least a majority in interest vote to authorize many basic activities and require a greater voting interest
(sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities
are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money
or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant,
litigation and transactions not in the ordinary course of business, among others. Without the concurrence of joint
venture participants with enough voting interests, the Partnership may be unable to cause any of its joint
ventures to take or not take certain actions, even though taking or preventing those actions may be in the best
interest of the Partnership or the particular joint venture.
In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its
ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners.
Any such transaction could result in the Partnership partnering with different or additional parties.
47
Weather may limit the Partnership’s ability to operate its business and could adversely affect its operating
results.
The weather in the areas in which the Partnership operates can cause disruptions and in some cases suspension
of its operations. For example, unseasonably wet weather, extended periods of below freezing weather or
hurricanes may cause disruptions or suspensions of the Partnership’s operations, which could adversely affect
its operating results.
The Partnership’s business involves many hazards and operational risks, some of which may not be insured
or fully covered by insurance. If a significant accident or event occurs that is not fully insured, if the
Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it
is insured, or if it fails to rebuild facilities damaged by such accidents or events, its operations and financial
results could be adversely affected.
The Partnership’s operations are subject to many hazards inherent in gathering, compressing, treating,
processing and selling natural gas and the storing, fractionation, treating, transportation and selling of 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, 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 the Partnership’s related operations. A natural disaster or other hazard affecting the
areas in which the Partnership operates could have a material adverse effect on its operations. For example,
Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines
along the Gulf Coast, including certain of the Partnership’s facilities. These hurricanes disrupted the operations
of the Partnership’s customers in August and September 2005, which curtailed or suspended the operations of
various energy companies with assets in the region. The Louisiana and Texas Gulf Coast was similarly impacted
in September 2008 as a result of Hurricanes Gustav and Ike. The Partnership is not fully insured against all
risks inherent to its business. The Partnership is not insured against all environmental accidents that might occur
which may include toxic tort claims, other than incidents considered to be sudden and accidental. If a significant
accident or event occurs that is not fully insured, if the Partnership fails to recover all anticipated insurance
proceeds for significant accidents or events for which it is insured, or if it fails to rebuild facilities damaged by
such accidents or events, its operations and financial condition could be adversely affected. In addition, the
Partnership may not be able to maintain or obtain insurance of the type and amount it desires at reasonable rates.
As a result of market conditions, premiums and deductibles for certain of the Partnership’s 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 were
generally less favorable than terms that could be obtained prior to such hurricanes. Insurance market conditions
worsened as a result of the losses sustained from Hurricanes Gustav and Ike in September 2008. As a result, the
Partnership experienced further increases in deductibles and premiums, and further reductions in coverage and
limits, with some coverages unavailable at any cost.
The Partnership 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
Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through the 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
48
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;
• repair and remediate the pipeline as necessary; and
• implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and
transmission lines. The Partnership currently estimates that it will incur an aggregate cost of approximately $6.6
million between 2011 and 2012 to implement pipeline integrity management program testing along certain
segments of its 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, the Partnership cannot predict the ultimate cost of
compliance with applicable pipeline integrity management regulations, 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. The Partnership will continue its pipeline integrity testing programs to assess and maintain the integrity
of its pipelines. The results of these tests could cause the Partnership to incur significant and unanticipated
capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and
reliable operations of its pipelines.
Unexpected volume changes due to production variability or to gathering, plant or pipeline system
disruptions may increase the Partnership’s exposure to commodity price movements.
The Partnership sells processed natural gas to third parties at plant tailgates or at pipeline pooling points. Sales
made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the
system. The Partnership attempts to balance sales with volumes supplied from processing operations, but
unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions
may expose the Partnership to volume imbalances which, in conjunction with movements in commodity prices,
could materially impact the Partnership’s income from operations and cash flow.
The Partnership requires a significant amount of cash to service its indebtedness. The Partnership’s ability to
generate cash depends on many factors beyond its control.
The Partnership’s ability to make payments on and to refinance its indebtedness and to fund planned capital
expenditures depends on its ability to generate cash in the future. This, to a certain extent, is subject to general
economic, financial, competitive, legislative, regulatory and other factors that are beyond its control. We cannot
assure you that the Partnership will generate sufficient cash flow from operations or that future borrowings will
be available to it under its credit agreement or otherwise in an amount sufficient to enable it to pay its
indebtedness or to fund its other liquidity needs. The Partnership may need to refinance all or a portion of its
indebtedness at or before maturity. The Partnership cannot assure you that it will be able to refinance any of its
indebtedness on commercially reasonable terms or at all.
Failure to comply with existing or new environmental laws or regulations or an accidental release of
hazardous substances, hydrocarbons or wastes into the environment may cause the Partnership to incur
significant costs and liabilities.
The Partnership’s 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. 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,
as amended, (“RCRA”) and comparable state laws that impose requirements for the handling, storage, treatment
or disposal of solid and hazardous waste from the Partnership’s facilities, (3) the Federal Comprehensive
49
Environmental Response, Compensation and Liability Act of 1980, as amended, (“CERCLA” or the
“Superfund” law) 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 the
Partnership’s hazardous substances have been transported for recycling or disposal and (4) the Clean Water Act
and comparable state laws that regulate discharges of wastewater from the Partnership’s 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 or other sanctions, the imposition of remedial obligations 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, hydrocarbons or waste products 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 noise, odor or the release of
hazardous substances, hydrocarbons or waste products into the environment.
There is inherent risk of incurring environmental costs and liabilities in connection with the Partnership’s
operations due to its handling of natural gas, NGLs and other petroleum products, because of air emissions and
water discharges related to its operations, and as a result of historical industry operations and waste disposal
practices. For example, an accidental release from one of the Partnership’s facilities could subject it 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, stricter laws, regulations or enforcement policies could significantly increase the Partnership’s
operational or compliance costs and the cost of any remediation that may become necessary. For instance, since
August 2009, the Texas Commission on Environmental Quality (“TCEQ”) has conducted a comprehensive
analysis of air emissions in the Barnett Shale area in response to reported concerns about high concentrations of
benzene in the air near drilling sites and natural gas processing facilities. Partially in response to its
investigation, the TCEQ has proposed new air permitting requirements for oil and gas facilities in the state,
which will first become applicable to facilities located in the Barnett Shale area on April 1, 2011. These new
requirements could require the Partnership to incur increased capital or operating costs. Moreover, the agency’s
investigations could lead to additional, more stringent air permitting requirements, increased regulation, and
possible enforcement actions against producers and midstream operators in the Barnett Shale area. The
Partnership is also conducting its own evaluation of air emissions at certain of its facilities in the Barnett Shale
area and, as necessary, plans to conduct corrective actions at such facilities. Additionally, environmental groups
have advocated increased regulation and a moratorium on the issuance of drilling permits for new natural gas
wells in the Barnett Shale area. The adoption of any laws, regulations or other legally enforceable mandates that
result in more stringent air emission limitations or that restrict or prohibit the drilling of new natural gas wells
for any extended period of time could increase the Partnership’s operating and compliance costs as well as
reduce the rate of production of natural gas operators with whom the Partnership has a business relationship,
which could have a material adverse effect on the Partnership’s results of operations and cash flows.
Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing
new oil and natural gas wells, which could adversely impact the Partnership’s revenues by decreasing the
volumes of natural gas that the Partnership gathers, processes and fractionates.
Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of
certain oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface
formations to stimulate gas and, to a lesser extent, oil production. The process is typically regulated by state oil
and gas commissions. However, the U.S. Environmental Protection Agency (“EPA”) recently asserted federal
regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s
(“SDWA”) Underground Injection Control Program. While the EPA has yet to take any action to enforce or
implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent
decision. At the same time, the EPA has commenced a study of the potential adverse impact of hydraulic
fracturing activities, with results of the study expected to be available in late 2012, and a committee of the U.S.
House of Representatives is conducting an investigation of hydraulic fracturing practices. Also, legislation was
introduced in the recently completed session of Congress to amend the SDWA to subject hydraulic fracturing
operations to regulation under the Act and to require the disclosure of chemicals used by the oil and natural gas
industry, and such legislation could be introduced in the current session of Congress. Moreover, some states
have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in
50
certain circumstances. Adoption of legislation or of any implementing regulations placing restrictions on
hydraulic fracturing activities could impose operational delays, increased operating costs and additional
regulatory burdens on exploration and production operators, which could reduce their production of natural gas
and, in turn, adversely affect the Partnership’s revenues and results of operations by decreasing the volumes of
natural gas that it gathers, processes and fractionates.
A change in the jurisdictional characterization of some of the Partnership’s assets by federal, state or local
regulatory agencies or a change in policy by those agencies may result in increased regulation of the
Partnership’s assets, which may cause its revenues to decline and operating expenses to increase.
Venice Gathering System, L.L.C. (“VGS”) is a wholly owned subsidiary of VESCO engaged in the business of
transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of
FERC under the NGA. VGS owns and operates a natural gas gathering system extending from South Timbalier
Block 135 to an onshore interconnection to a natural gas processing plant owned by VESCO. With the
exception of our interest in VGS, our operations are generally exempt from FERC regulation under the NGA,
but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived
from these businesses. The NGA exempts natural gas gathering facilities from regulation by FERC as a natural
gas company under the NGA. The Partnership believes that the natural gas pipelines in its gathering systems
meet the traditional tests FERC has used to establish a pipeline’s 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 the Partnership’s gathering facilities are subject to change based on future determinations by
FERC, the courts or Congress. In addition, the courts have determined that certain pipelines that would
otherwise be subject to the ICA are exempt from regulation by FERC under the ICA as proprietary lines. The
classification of a line as a proprietary line is a fact-based determination subject to FERC and court review.
Accordingly, the classification and regulation of some of the Partnership’s gathering facilities and transportation
pipelines may be subject to change based on future determinations by FERC, the courts, or Congress.
While the Partnerships’ natural gas gathering operations are generally exempt from FERC regulation under the
NGA, its gas gathering operations may be subject to certain FERC reporting and posting requirements in a given
year. FERC has issued a final rule (as amended by orders on rehearing and clarification), Order 704, requiring
certain participants in the natural gas market, including intrastate pipelines, natural gas gatherers, natural gas
marketers and natural gas processors, that engage in a minimum level of natural gas sales or purchases to submit
annual reports regarding those transactions to FERC. It is the responsibility of the reporting entity to determine
which individual transactions should be reported based on the guidance of Order No. 704. 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 FERC’s policy statement on price reporting.
In addition, FERC has issued a final rule, (as amended by orders on rehearing and clarification), Order 720,
requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual
basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, to post daily
certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point
that has design capacity equal to or greater than 15,000 MMBtu/d and requiring interstate pipelines to post
information regarding the provision of no-notice service. The Partnership takes the position that at this time it
and its subsidiaries are exempt from this rule. A petition for review of Order 720 is currently pending before the
Court of Appeals for the Fifth Circuit, and the Partnership has no way to predict with certainty whether and to
what extent Order 720 will be modified in response to the petition for review.
In addition, FERC recently issued an order extending certain of the open-access requirements including the
prohibition on buy/sell arrangements and shipper-must-have-title provisions to include Hinshaw pipelines to the
extent such pipelines provide interstate service. However, FERC issued a Notice of Inquiry on October 21,
2010, effectively suspending the recent ruling and requesting comments on whether and how holders of firm
capacity on Section 311 and Hinshaw pipelines should be permitted to allow others to make use of their firm
interstate capacity, including to what extent buy/sell transactions should be permitted.
Other FERC regulations may indirectly impact the Partnership’s businesses and the markets for products
derived from these businesses. FERC’s 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
51
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 Targa’s operations, see “Item 1. Business—Regulation of Operations.”
Should the Partnership fail to comply with all applicable FERC administered statutes, rules, regulations and
orders, it could be subject to substantial penalties and fines.
Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act 2005”), which is applicable to VGS, 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 the Partnership’s systems
have not been regulated by FERC as a natural gas companies under the NGA, FERC has adopted regulations
that may subject certain of its otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily
scheduled flow and capacity 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 the Partnership to civil penalty liability. For more information regarding regulation of
Targa’s operations, see “Item 1. Business—Regulation of Operations.”
The adoption of climate change legislation or regulations restricting emissions of GHGs could result in
increased operating costs and reduced demand for the products and services we provide.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases
(“GHGs”) present an endangerment to public health and the environment because emissions of such gases are,
according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on
these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under
existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating GHG
emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor
vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective
January 2, 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are
currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any
injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the
rules. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG
emission sources in the United States, on an annual basis, beginning in 2011 for emissions occurring after
January 1, 2010, as well as certain onshore and offshore oil and natural gas production facilities and onshore oil
and natural gas processing, transmission, storage and distribution facilities on an annual basis, beginning in
2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation to reduce
emissions of GHGs and almost half of the states have already taken legal measures to reduce emissions of
GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and
trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as
electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and
surrender emission allowances. The number of allowances available for purchase is reduced each year in an
effort to achieve the overall GHG emission reduction goal. The adoption of legislation or regulatory programs
to reduce emissions of GHGs could require the Partnership to incur increased operating costs, such as costs to
purchase and operate emissions control systems, to acquire emissions allowances or comply with new
regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost
of consuming, and thereby reduce demand for, the natural gas and NGLs the Partnership processes or
fractionates. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an
adverse effect on the Partnership’s business, financial condition and results of operations. Finally, it should be
noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere
may produce climate changes that have significant physical effects, such as increased frequency and severity of
storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an
adverse effect on the Partnership’s financial condition and results of operations.
The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on
the Partnership’s ability to use derivative instruments to reduce the effect of commodity price, interest rate
and other risks associated with its business.
The United States Congress recently adopted comprehensive financial reform legislation that establishes federal
oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that
52
participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer
Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the CFTC and
the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of
enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain
futures and option contracts in the major energy markets and for swaps that are their economic equivalents.
Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible
at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also
require the Partnership to comply with margin requirements and with certain clearing and trade-execution
requirements in connection with its derivative activities, although the application of those provisions to the
Partnership is uncertain at this time. The financial reform legislation may also require counterparties to the
Partnership’s derivative instruments to spin off some of their derivatives activities to a separate entity, which
may not be as creditworthy as the current counterparty. The new legislation and any new regulations could
significantly increase the cost of derivative contracts (including through requirements to post collateral which
could adversely affect the Partnership’s available liquidity), materially alter the terms of derivative contracts,
reduce the availability of derivatives to protect against risks the Partnership encounters, reduce the Partnership’s
ability to monetize or restructure its existing derivative contracts, and increase the Partnership’s exposure to less
creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the legislation and
regulations, its results of operations may become more volatile and its cash flows may be less predictable, which
could adversely affect its ability to plan for and fund capital expenditures. Finally, the legislation was intended,
in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative
trading in derivatives and commodity instruments related to oil and natural gas. The Partnership’s revenues
could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity
prices. Any of these consequences could have a material adverse effect on the Partnership, its financial
condition, and its results of operations.
The Partnership’s interstate common carrier liquids pipeline is regulated by the Federal Energy Regulatory
Commission.
Targa NGL Pipeline Company LLC (“Targa NGL”), one of the Partnership’s subsidiaries, is an interstate NGL
common carrier subject to regulation by FERC under the ICA. Targa NGL owns a twelve inch diameter pipeline
that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGL and
purity NGL products. Targa NGL also owns an eight inch diameter pipeline and a 20 inch diameter pipeline
each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight inch and the 20 inch
pipelines are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides
services to domestic and foreign import and export customers. The Interstate Commerce Act (“ICA”) requires
that the Partnership maintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the
rates the Partnership charges for providing transportation services as well as the rules and regulations governing
these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just
and reasonable” and nondiscriminatory. All shippers on these pipelines are the Partnership’s subsidiaries.
Recent events in the Gulf of Mexico may adversely affect the operations of the Partnership.
On April 20, 2010, the Transocean Deepwater Horizon drilling rig exploded and subsequently sank 130 miles
south of New Orleans, Louisiana, and the resulting release of crude oil into the Gulf of Mexico was declared a
Spill of National Significance by the United States Department of Homeland Security. The Partnership cannot
predict with any certainty the impact of this oil spill, the extent of cleanup activities associated with this spill, or
possible changes in laws or regulations that may be enacted in response to this spill, but this event and its
aftermath could adversely affect the Partnership’s operations. It is possible that the direct results of the spill and
clean-up efforts could interrupt certain offshore production processed by our facilities. Furthermore, additional
governmental regulation of, or delays in issuance of permits for, the offshore exploration and production
industry may negatively impact current or future volumes being gathered or processed by the Partnership’s
facilities, and may potentially reduce volumes in its Downstream logistics and marketing business.
Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to the Partnership’s
business. Continued hostilities in the Middle East or other sustained military campaigns may adversely
impact the Partnership’s results of operations.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat
of future terrorist attacks on the Partnership’s industry in general and on it in particular is not known at this
53
time. However, resulting regulatory requirements and/or related business decisions associated with security are
likely to increase the Partnership’s costs.
Increased security measures taken by the Partnership as a precaution against possible terrorist attacks have
resulted in increased costs to its business. Uncertainty surrounding continued hostilities in the Middle East or
other sustained military campaigns may affect the Partnership’s operations in unpredictable ways, including
disruptions of crude oil supplies and markets for its products, and the possibility that infrastructure facilities
could be direct targets, 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 the Partnership to obtain. Moreover, the insurance that may be available to the Partnership may be
significantly more expensive than its existing insurance coverage. Instability in the financial markets as a result
of terrorism or war could also affect the Partnership’s ability to raise capital.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A description of our properties is contained in “Item 1. Business” 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 filed suit in the 333rd District Court of Harris County, Texas against several
defendants, including Targa and two 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, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley,
tortiously interfered with (i) a contract WTG claims to have had to purchase SAOU from ConocoPhillips and
(ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s
competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. In
October 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. In
February 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in
its entirety. In January 2011, the Texas Supreme Court denied the WTG’s petition for review of the lower
courts’ judgment and WTG filed a motion for rehearing with the Texas Supreme Court requesting the court
reconsider its denial to review WTG’s appeal. We have agreed to indemnify the Partnership for any claim or
liability arising out of the WTG suit.
Except as provided above, neither we nor the Partnership is a party to any other legal proceedings other than
legal proceedings arising in the ordinary course of our business. The Partnership is a party to various
administrative and regulatory proceedings that have arisen in the ordinary course of our business. See “Item 1.
Business — Regulation of Operations” and “Item 1. Business — Environmental, Health and Safety Matters.”
Item 4. Removed and Reserved
54
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Market Information
Our common stock has been listed on the New York Stock Exchange since December 7, 2010 under the symbol
“TRGP.” The following table sets forth the high and low sales prices of the common stock, as reported by The
New York Stock Exchange (“NYSE”) through December 31, 2010.
Quarter Ended
Stock Prices
High
Low
Dividends
Declared
December 31, 2010
$
28.40 $
23.50 $
0.06
As of February 22, 2011, there were approximately 224 stockholders of record of our common stock. This
number does not include stockholders whose shares are held in trust by other entities. The actual number of
stockholders is greater than the number of holders of record.
Overview of Distributions
During the past three fiscal years, our stockholders have received dividends from us on a pro rata basis. Holders
of our previously outstanding preferred stock received their pro rata share of (i) an $18 million dividend paid on
November 22, 2010; (ii) a $220 million extraordinary dividend paid in April 2010; (iii) a $200 million
extraordinary dividend paid on the common stock (treating the preferred stock on a common stock equivalent
basis) in April 2010; and (iv) a $445 million dividend paid in 2007. Holders of our common stock received their
pro rata share of the $200 million extraordinary dividend paid in April 2010 (treating the preferred stock on a
common stock equivalent basis).
Our Dividend Policy
We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our
Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:
• Federal income taxes, which we are required to pay because we are taxed as a corporation;
•
•
•
•
•
•
the expenses of being a public company;
other general and administrative expenses;
general and administrative reimbursements to the Partnership;
capital contributions to the Partnership upon the issuance by it of additional partnership securities if we
choose to maintain the General Partner’s 2.0% interest;
reserves our board of directors believes prudent to maintain;
our obligation to (i) satisfy tax obligations associated with previous sales of assets to the Partnership,
(ii) reimburse the Partnership for certain capital expenditures related to Versado and (iii) provide the
Partnership with limited quarterly distribution support through 2011, all as described in more detail in
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity
and Capital Resources;” and
•
interest expense or principal payments on any indebtedness we incur.
On February 21, 2011, we paid a cash dividend of $0.0616 per share of common stock, or $2.6 million in total,
to holders of our outstanding common stock. This dividend was pro-rated to give effect to a partial quarter
following our IPO. If the Partnership is successful in implementing its business strategy and increasing
distributions to its partners, we would generally expect to increase dividends to our stockholders, although the
55
timing and amount of any such increased dividends will not necessarily be comparable to the increased
Partnership distributions. We cannot assure you that any dividends will be declared or paid in the future.
The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to
be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our
capital expenditures, future business prospects and any other matters that our board of directors deems relevant.
The Partnership’s debt agreements contain restrictions on the payment of distributions and prohibit the payment
of distributions if the Partnership is in default. If the Partnership cannot make incentive distributions to the
general partner or limited partner distributions to us, we will be unable to pay dividends on our common stock.
The Partnership’s Cash Distribution Policy
Under the Partnership’s partnership agreement, available cash is defined to generally mean, for each fiscal
quarter, all cash on hand at 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 the Partnership’s business, to
comply with applicable law or any agreement binding on the Partnership and its subsidiaries and to provide for
future distributions to the Partnership’s unitholders for any one or more of the upcoming four quarters. The
determination of available cash takes into account the possibility of establishing cash reserves in some quarterly
periods that the Partnership may use to pay cash distributions in other quarterly periods, thereby enabling it to
maintain relatively consistent cash distribution levels even if the Partnership’s business experiences fluctuations
in its cash from operations due to seasonal and cyclical factors. The General Partner’s determination of available
cash also allows the Partnership to maintain reserves to provide funding for its growth opportunities. The
Partnership makes its quarterly distributions from cash generated from its operations, and those distributions
have grown over time as its business has grown, primarily as a result of numerous acquisitions and organic
expansion projects that have been funded through external financing sources and cash from operations.
The actual cash distributions paid by the Partnership to its partners occur within 45 days after the end of each
quarter. Since second quarter 2007, the Partnership has increased its quarterly cash distribution 7 times. During
that time period, the Partnership has increased its quarterly distribution by 62% from $0.3375 per common unit,
or $1.35 on an annualized basis, to $0.5475 per common unit, or $2.19 on an annualized basis.
Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit
Facilities and Long-Term Debt” and Note 9 to our consolidated financial statements for a discussion of
restrictions on our and our subsidiaries’ ability to pay dividends or make distributions.
Recent Sales of Unregistered Stock
None
Repurchase of Equity by Targa Resources Corp.
None
56
Item 6. Selected Financial Data
The following table presents selected historical consolidated financial and operating data of Targa Resources
Corp. for the periods and as of the dates indicated. We derived this information from our historical consolidated
financial statements and accompanying notes. This information should be read together with, and is qualified in
its entirety, by reference to those financial statements and notes, which for the years 2010, 2009 and 2008
begins on page F-1 of this Form 10-K.
Revenues(1)
Income from operations
Net income
Net income (loss) attributable to Targa Resources Corp.
Dividends on Series B preferred stock
Net income (loss) available to common shareholders
Net loss per common share - Basic and diluted
Balance Sheet Data (at end of period)
Year Ended December 31,
2010
2009
2008
2007
2006
(In millions, except per share amounts)
$
5,469.2
$
4,536.0
$
7,998.9
$
7,297.2
$
6,132.9
196.1
63.3
(15.0)
(9.5)
(202.3)
(30.94)
217.2
79.1
29.3
(17.8)
-
-
234.5
134.4
37.3
(16.8)
-
-
280.3
104.2
56.1
(31.6)
-
-
237.1
50.2
24.2
(39.7)
(15.5)
(2.53)
Total assets
$
3,393.8
$
3,367.5
$
3,641.8
$
3,795.1
$
3,458.0
Long-term debt
Convertible cumulative participating Series B
preferred stock
Total owners' equity
Other:
Dividends declared per share
Dividends paid on Series B preferred shares
_________
(1)
1,534.7
1,593.5
1,976.5
1,867.8
1,471.9
-
308.4
290.6
273.8
1,036.1
754.9
822.0
574.1
687.2
(71.5)
$
$
0.0616
NA
NA
NA
NA
238.0
$
-
$
-
$
445.1
$
-
Includes business interruption insurance revenues of $6.0 million, $21.5 million, $32.9 million, and $7.3 million, for the years ended
2010, 2009, 2008 and 2007. We received no business interruption proceeds during 2006.
57
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discusses and analyzes our financial condition and results of operations. You should read the
following discussion in conjunction with our historical financial statements and notes included in Part IV of this
Annual Report. Also, the Partnership files a separate Annual Report on Form 10-K with the SEC.
Overview
Financial Presentation
An indirect subsidiary of ours is the sole member of the General Partner. Because we control the General
Partner, under generally accepted accounting principles we must reflect our ownership interest in the Partnership
on a consolidated basis. Accordingly, our financial results are combined with the Partnership’s financial results
in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited
by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending
agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of
operations as net income attributable to non-controlling interests. Therefore, throughout this discussion, we
make a distinction where relevant between financial results of the Partnership versus those of us as a standalone
parent including our non-Partnership subsidiaries.
The Partnership is a leading provider of midstream natural gas and NGL services in the United States. The
Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas and
storing, fractionating, treating, transporting and selling NGLs and NGL products. It operates through two
divisions: the Natural Gas Gathering and Processing division and the NGL Logistics and Marketing division.
As a result of the conveyance of all of our remaining operating assets to the Partnership in September 2010, we
have no separate, direct operating activities apart from those conducted by the Partnership. As such, our cash
inflows will primarily consist of cash distributions from our interests in the Partnership. The Partnership is
required to distribute all available cash at the end of each quarter after establishing reserves to provide for the
proper conduct of its business or to provide for future distributions.
The Partnership files its own separate Annual Report. The results of operations included in our consolidated
financial statements will differ from the results of operations of the Partnership primarily due to the financial
effects of: non-controlling interests in the Partnership, our separate debt obligations, certain general and
administrative costs applicable to us as a separate public company, and certain non-operating assets and
liabilities that we retained and were not included in the asset conveyances to the Partnership.
Factors That Significantly Affect Our Results
Our cash flow and resulting ability to pay dividends will be dependent upon the Partnership’s ability to make
distributions to its partners, including us. The actual amount of cash that the Partnership will have available for
distributions will depend primarily on the amount of cash that it generates from its operations.
As of February 25, 2011, our interests in the Partnership consist of the following:
• a 2% general partner interest, which we hold through our 100% ownership interest in the general partner
of the Partnership;
• all IDRs; and
• 11,645,659 of the 84,756,009 outstanding common units of the Partnership, representing a 13.7% limited
partnership interest.
Cash Distributions
The following table sets forth the historical distributions that the Partnership has paid in respect of our 2%
general partner interest, the associated IDRs and actual common units that we held during the periods indicated.
The amount of these Partnership distributions available for distribution to us and the Partnership’s shareholders
58
will be after reserves are established for the Partnership’s capital contributions, debt service requirements,
general, administrative and other expenses, future distributions and other miscellaneous uses of cash.
Cash
Distribution
Per Limited
Partner Unit
Limited
Partner
Units
Outstanding
Actual Cash Distributions
Total
Limited
Partners
Units
General
Partner
Interest
(In millions, except per unit amounts)
Distributions
to Targa
Resources
Corp. (1)
IDRs
2010
Fourth Quarter
Third Quarter
Second Quarter
First Quarter
2009
Fourth Quarter
Third Quarter
Second Quarter
First Quarter
2008
Fourth Quarter
Third Quarter
Second Quarter
First Quarter
2007
$ 0.54750
0.53750
0.52750
0.51750
$ 0.51750
0.51750
0.51750
0.51750
$ 0.51750
0.51750
0.51250
0.41750
75.5 $
75.5
68.0
68.0
68.0 $
61.6
46.2
46.2
46.2 $
46.2
46.2
46.2
53.5 $
46.1
40.2
38.8
38.8 $
35.2
26.4
26.3
26.4 $
26.3
25.9
19.9
46.4 $
40.6
35.9
35.2
35.2 $
31.9
23.9
23.9
24.0 $
23.9
23.7
19.3
1.1 $
0.9
0.8
0.8
0.8 $
0.7
0.5
0.5
0.5 $
0.5
0.5
0.4
6.0 $
4.6
3.5
2.8
2.8 $
2.6
2.0
1.9
1.9 $
1.9
1.7
0.2
13.4
11.8
10.4
9.6
14.0
13.7
8.5
8.4
8.4
8.4
8.2
5.5
Fourth Quarter
Third Quarter
Second Quarter
First Quarter
________
(1) Distributions to Targa are comprised of amounts attributable to Targa’s (i) Limited Partner Units, (ii) General Partner Units, and (iii)
$ 0.39750
0.33750
0.33750
0.16875
18.9 $
15.3
10.6
5.3
46.2 $
44.4
30.9
30.9
18.4 $
15.0
10.4
5.2
0.4 $
0.3
0.2
0.1
0.1 $
-
-
-
5.1
4.2
4.1
2.1
IDRs.
Factors That Significantly Affect the Partnership’s Results
The Partnership’s results of operations are substantially impacted by the volumes that move through its
gathering and processing and logistics assets, its contract terms and changes in commodity prices.
Volumes. In the Partnership’s gathering and processing operations, plant inlet volumes and capacity utilization
rates generally are driven by wellhead production, its competitive and contractual position on a regional basis
and more broadly by the impact of prices for oil, natural gas and NGLs on exploration and production activity in
the areas of its operations. The factors that impact the gathering and processing volumes also impact the total
volumes that flow to the Partnership’s Downstream Business. In addition, fractionation volumes are also
affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to the
Partnership’s fractionators, and the Partnership’s competitive and contractual position relative to other
fractionators.
59
Contract Terms and Contract Mix and the Impact of Commodity Prices. Because of the significant volatility of
natural gas and NGL prices, the contract mix of the Partnership’s natural gas gathering and processing segment
can also have a significant impact on its profitability, especially those that create exposure to changes in energy
prices. Set forth below is a table summarizing the contract mix of the Partnership’s natural gas gathering and
processing division for 2010 and the potential impacts of commodity prices on operating margins:
Contract Type
Percent-of-Proceeds/Percent-of-Liquids
Fee-Based
Wellhead Purchases/Keep-whole
Hybrid
Percent of
Throughput
38%
7%
17%
38%
Impact of Commodity Prices
Decreases in natural gas and or NGL prices generate decreases
in operating margins.
No direct impact from commodity price movements
Increases in natural gas prices relative to NGL prices generate
decreases in operating margin.
In periods of favorable processing economics (1), similar to
percent-of-liquids or to wellhead purchases/keep-whole in some
circumstances, if economically advantageous to the processor.
In periods of unfavorable processing economics, similar to fee-
based.
______
(1) Favorable processing economics typically occur when processed NGLs can be sold, after allowing for processing costs, at a higher
value than natural gas on a Btu equivalent basis.
The Partnership generally prefers to enter into contracts with less commodity price sensitivity including fee-
based and percent-of-proceeds arrangements. However, negotiated contract terms are based upon a variety of
factors, including natural gas quality, geographic location, the competitive commodity and pricing environment
at the time the contract is executed, and customer requirements. The gathering and processing contract mix and,
accordingly, the 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, the Partnership’s
expansion into regions where different types of contracts are more common as well as other market factors.
The contract terms and contract mix of the Downstream Business can also have a significant impact on its
results of operations. During periods of low relative demand for available fractionation capacity, rates were low
and take-or-pay contracts were not readily available. Currently, demand for fractionation services is relatively
high, rates have increased, contract terms or lengths have increased and reservation fees are required. These
fractionation contracts in the logistics assets segment are primarily fee-based arrangements while the marketing
and distribution segment includes both fee-based and percent-of-proceeds contracts.
Impact of the Partnership’s Commodity Price Hedging Activities. In an effort to reduce the variability of its cash
flows, the Partnership has hedged the commodity price associated with a portion of its expected natural gas,
NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including
swaps and purchased puts (or floors). With these arrangements, the Partnership has attempted to mitigate its
exposure to commodity price movements with respect to its forecasted volumes for these periods. The
Partnership actively manages the Downstream Business product inventory and other working capital levels to
reduce exposure to changing NGL prices. For additional information regarding the Partnership’s hedging
activities, see “Quantitative and Qualitative Disclosures About Market Risk— Commodity Price Risk.”
General Trends and Outlook
We expect the midstream energy business environment to continue to be affected by the following key trends:
demand for our services, significant relationships, commodity prices, volatile capital markets and increased
regulation. These 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.
Demand for Services. Fluctuations in energy prices can affect production rates and investments by third parties
in the development of oil and natural gas reserves. Generally, drilling and production activity will increase as
energy prices increase. We believe that the current strength of oil, condensate and NGL prices compared to
natural gas prices has caused producers in and around the Partnership’s natural gas gathering and processing
areas of operation to focus their drilling programs on regions rich in liquid forms of hydrocarbons. This focus is
reflected in increased drilling permits and higher rig counts in these areas, and we expect these activities to lead
to higher inlet volumes in the Field Gathering and Processing segment over the next several years. Producer
60
activity in areas rich in oil, condensate and NGLs is currently generating increased demand for the Partnership’s
fractionation services and for related fee-based services provided by its Downstream Business. While we expect
development activity to remain robust with respect to oil and liquids rich gas development and production,
currently depressed natural gas prices have resulted in reduced activity levels surrounding comparatively dry
natural gas reserves, whether conventional or unconventional.
Significant Relationships. The following table lists the counterparties that account for more than 10% of the
Partnership’s consolidated sales and consolidated product purchases.
% of consolidated revenues
Chevron Phillips Chemical Company LLC
% of consolidated purchases
Year Ended December 31,
2010
2009
2008
10%
15%
19%
Louis Dreyfus Energy Services L.P.
10%
11%
9%
Commodity Prices. Current forward commodity prices for the January 2011 through December 2011 period
show natural gas and crude oil prices strengthening while NGL prices weaken on an absolute price basis and as
a percentage of crude oil. Various industry commodity price forecasts based on fundamental analysis may differ
significantly from forward market prices. Both are subject to change due to multiple factors. There has been and
we believe there will continue to be significant volatility in commodity prices and in the relationships among
NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and
NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to
the Partnership’s systems.
The Partnership’s operating income generally improves in an environment of higher natural gas, NGL and
condensate prices, primarily as a result of its percent-of-proceeds contracts. The Partnership’s processing
profitability is largely dependent upon pricing, the supply of and market demand for natural gas, NGLs and
condensate, which are beyond its control and have been volatile. Recent weak economic conditions have
negatively affected the pricing and market demand for natural gas, NGLs and condensate, which caused a
reduction in profitability of the Partnership’s processing operations. In a declining commodity price
environment, without taking into account the Partnership’s hedges, it will realize a reduction in cash flows under
its percent-of-proceeds contracts proportionate to average price declines. The Partnership has attempted to
mitigate its exposure to commodity price movements by entering into hedging arrangements. For additional
information regarding hedging activities, see “Quantitative and Qualitative Disclosures about Market Risk—
Commodity Price Risk.”
Volatile Capital Markets. We and the Partnership are dependent on our abilities to access equity and debt capital
markets in order to fund acquisitions and expansion expenditures. Global financial markets have been, and are
expected to continue to be, volatile and disrupted and weak economic conditions may cause a significant decline
in commodity prices. As a result, we and the Partnership may be unable to raise equity or debt capital on
satisfactory terms, or at all, which may negatively impact the timing and extent to which we and the Partnership
execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our
and the Partnership’s ability or willingness to enter into new hedges, fund organic growth, connect to new
supplies of natural gas, execute acquisitions or implement expansion capital expenditures.
Increased Regulation. Additional regulation in various areas has the potential to materially impact the
Partnership’s operations and financial condition. For example, increased regulation of hydraulic fracturing used
by producers may cause reductions in supplies of natural gas and of NGLs from producers. Please read “Risk
Factors—Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and
completing new oil and natural gas wells, which could adversely impact the Partnership’s revenues by
decreasing the volumes of natural gas that it gathers, processes and fractionates.” Similarly, the forthcoming
rules and regulations of the CFTC may limit the Partnership’s ability or increase the cost to use derivatives,
which could create more volatility and less predictability in its results of operations. Please read “Risk Factors—
the recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the
Partnership’s ability to hedge risks associated with its business.”
61
How We Evaluate Our Operations
Our consolidated operations include the operations of the Partnership due to our ownership and control of the
General Partner. As a result of our conveyances of all of our remaining operating assets to the Partnership we
have no separate, direct operating activities from those conducted by the Partnership. Our financial results differ
from the Partnership’s due to the financial effects of non-controlling interests in the Partnership, our separate
debt obligations, certain non-operating costs associated with assets and liabilities that we retained and were not
included in the asset conveyances to the Partnership, and certain general and administrative costs applicable to
us as a separate public company.
How We Evaluate the Partnership’s Operations
The Partnership’s profitability is a function of the difference between the revenues it receives from our
operations, including revenues from the natural gas, NGLs and condensate it sells, and the costs associated with
conducting its operations, including the costs of wellhead natural gas and mixed NGLs that it purchases as well
as operating and general and administrative costs, and the impact of the Partnership’s commodity hedging
activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases
in the Partnership’s revenues alone are not necessarily indicative of increases or decreases in its profitability.
The Partnership’s contract portfolio, the prevailing pricing environment for natural gas and NGLs, and the
volume of natural gas and NGL throughput on its systems are important factors in determining its profitability.
The Partnership’s profitability is also affected by the NGL content in gathered wellhead natural gas, supply and
demand for its products and services and changes in its customer mix.
Management uses a variety of financial and operational measurements to analyze the Partnership’s performance.
These measurements include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating
expenses and (3) the following non-GAAP measures—gross margin, operating margin and adjusted EBITDA.
Throughput Volumes, Facility Efficiencies and Fuel Consumption. The Partnership’s profitability is impacted by
its 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 its gathering and processing systems. This is achieved by connecting new wells
and adding new volumes in existing areas of production as well as by capturing natural gas supplies currently
gathered by third parties. Similarly, the Partnership’s profitability is impacted by its ability to add new sources
of mixed NGL supply, typically connected by third-party transportation, to its Downstream Business’
fractionation facilities. The Partnership fractionates NGLs generated by its gathering and processing plants as
well as by contracting for mixed NGL supply from third-party gathering or fractionation facilities.
In addition, the Partnership seeks to increase operating margins by limiting volume losses and reducing fuel
consumption by increasing compression efficiency. With its gathering systems’ extensive use of remote
monitoring capabilities, the Partnership monitors the volumes of natural gas received at the wellhead or central
delivery points along its gathering systems, the volume of natural gas received at its processing plant inlets and
the volumes of NGLs and residue natural gas recovered by its processing plants. The Partnership also monitors
the volumes of NGLs received, stored, fractionated, and delivered across its logistics assets. This information is
tracked through its processing plants and Downstream Business facilities to determine customer settlements for
sales and volume-related fees for service, which helps the Partnership increase efficiency and reduce fuel
consumption.
As part of monitoring the efficiency of its operations, the Partnership measures the difference between the
volume of natural gas received at the wellhead or central delivery points on its gathering systems and the
volume received at the inlet of its processing plants as an indicator of fuel consumption and line loss. The
Partnership also tracks 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 plant to monitor the fuel consumption and
recoveries of the facilities. Similar tracking is performed for its logistics assets. These volume, recovery and fuel
consumption measurements are an important part of the Partnership’s operational efficiency analysis.
Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Labor, ad
valorem taxes, repair and maintenance, utilities and contract services comprise the most significant portion of
the Partnership’s operating expenses. These expenses generally remain relatively stable and independent of the
volumes through its systems but fluctuate depending on the scope of the activities performed during a specific
period.
62
Gross Margin. Gross margin is defined as revenue less purchases. It is impacted by volumes and commodity
prices as well as the Partnership’s contract mix and hedging programs. We define Natural Gas Gathering and
Processing division gross margin as total operating revenues from the sales of natural gas and NGLs plus
service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas
purchases. Logistics Assets gross margin consists primarily of service fee revenue. Marketing and Distribution
gross margin equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily
of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash
flow hedge settlements are reported in Other.
Operating Margin. Operating margin is an important performance measure of the core profitability of the
Partnership’s operations. We define operating margin as gross margin less operating expenses. Natural gas and
NGL sales revenue includes settlement gains and losses on commodity hedges.
Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to
gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to
GAAP net income and have important limitations as analytical tools. You should not consider gross margin and
operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because
gross margin and operating margin exclude some, but not all, items that affect net income and are defined
differently by different companies in our industry, our definition of gross margin and operating margin may not
be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Targa senior management reviews business segment gross margin and operating margin monthly as a core
internal management process. We believe that investors benefit from having access to the same financial
measures that our management uses in evaluating our operating results. Gross Margin and Operating Margin
provide useful information to investors because they are used as supplemental financial measures by us and by
external users of our financial statements, including such investors, commercial banks and others, to assess:
• the financial performance of the Partnership’s assets without regard to financing methods, capital
structure or historical cost basis;
• the Partnership’s 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.
63
The Partnership’s management compensates for the limitations of gross margin and operating margin as
analytical tools by reviewing the comparable GAAP measure, understanding the differences between the
measures and incorporating these insights into its decision-making processes.
Reconciliation of gross margin and operating
(In millions)
Year Ended December 31,
2010
2009
2008
margin to net income (loss):
Gross margin
Operating expenses
Operating margin
Depreciation and amortization expenses
General and administrative expenses
Other operating income (loss)
Interest expense, net
Income tax expense
Gain (loss) on sale of assets
Gain (loss) on debt repurchases
Risk management activities
Equity in earnings of unconsolidated investments
Gain on insurance claims
Other, net
Partnership net income
$
772.2 $
710.9 $
(259.5)
512.7
(176.2)
(122.4)
3.3
(110.8)
(4.0)
-
-
26.0
5.4
-
-
(234.4)
476.5
(166.7)
(118.5)
3.7
(159.8)
(1.2)
(0.1)
(1.5)
(30.9)
5.0
-
0.7
812.9
(274.3)
538.6
(156.8)
(97.3)
(19.3)
(156.1)
(2.9)
5.9
13.1
76.4
14.0
18.5
1.1
$
134.0 $
7.2 $
235.2
Adjusted EBITDA. The Partnership defines Adjusted EBITDA as net income before interest, income taxes,
depreciation and amortization, gains or losses on debt repurchases and non-cash income or loss related to
derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by
external users of our financial statements such as investors, commercial banks and others.
The economic substance behind the Partnership’s use of Adjusted EBITDA is to measure the ability of its assets
to generate cash sufficient to pay interest costs, support its indebtedness and make distributions to its investors.
The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating
activities and net income. 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.
The Partnership 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 its decision-making processes.
64
Year Ended December 31,
2010
2009
2008
Reconciliation of Targa Resources Partners LP net cash provided
(In millions)
by operating activities to Adjusted EBITDA:
Net cash provided by operating activities
Net income attributable to noncontrolling interest
Interest expense, net (1)
Gain (loss) on debt repurchases
Termination of commodity derivatives
Current income tax expense
Other (2)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets
Accounts payable and other liabilities
$
371.2 $
422.9 $
550.2
(24.9)
(19.3)
(33.1)
74.8
-
-
2.8
44.8
(1.5)
-
0.3
(14.7)
(10.6)
34.7
13.1
87.4
0.8
3.4
71.2
57.0
(890.8)
(84.3)
(93.0)
655.3
Partnership adjusted EBITDA
_________
(1) Net of amortization of debt issuance costs of $6.6 million, $3.9 million and $2.1 million and amortization of discount and premium
included in interest expense of $0.1 million, $3.4 million and $2.1 million for 2010, 2009 and 2008. Excludes affiliate and allocated
interest expense.
Includes non-controlling interest percentage of our consolidated investment’s depreciation, interest expense and maintenance capital
expenditures , equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset
retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets.
400.6 $
396.1 $
421.0
$
(2)
Reconciliation of net income (loss) attributable to
Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP
Add:
Interest expense, net (1)
Income tax expense
Depreciation and amortization expenses
Risk management activities
Noncontrolling interest adjustment
Partnership adjusted EBITDA
________
(1)
Includes affiliate and allocated interest expense.
Consolidated Results of Operations
Year Ended December 31,
2010
2009
2008
(In millions)
$
109.1 $
(12.1) $
202.1
110.8
159.8
156.1
4.0
1.2
2.9
176.2
166.7
156.8
6.4
95.5
(10.4)
(10.5)
(85.4)
(11.5)
$
396.1 $
400.6 $
421.0
Our management uses a variety of financial and operational measurements to analyze our performance. These
measurements include both measures for the Partnership activities and measures for the Parent. Partnership
measures include gross margin, operating margin, operating expenses, plant inlet, gross NGL production,
adjusted EBITDA and distributable cash flow, among others. For a discussion of these measures, see
“Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate
Partnership Operations.”
65
The following table and discussion is a summary of our consolidated results of operations for the three years
ended December 31, 2010, 2009 and 2008 (In millions, except operating and price amounts).
Revenues (1)
Product purchases
Gross margin
Operating expenses
Operating margin
Depreciation and amortization expenses
General and administrative expenses
Other
Income from operations
Interest expense, net
Gain on insurance claims
Equity in earnings of unconsolidated investments
Gain(loss) on debt repurchases
Gain on early debt extinguishment
Gain (loss) on mark-to-market derivative instruments
Other
Income tax expense
Net income
Less: Net income attributable to noncontrolling interest
Net income attributable to Targa Resources Corp.
Year Ended December 31,
2010 vs. 2009
2009 vs. 2008
2010
2009
2008
$ Change % Change $ Change
% Change
Variance
$
$
5,469.2
4,536.0 $
7,998.9 $
933.2
$
20.57%
(3,462.9)
(43.3%)
4,687.7
3,791.1
7,218.5
896.6
23.65%
(3,427.4)
(47.5%)
781.5
260.2
744.9
235.0
780.4
275.2
$
521.3 $
509.9 $
505.2 $
185.5
144.4
(4.7)
170.3
120.4
2.0
160.9
96.4
13.4
36.6
25.2
11.4
15.2
24.0
4.91%
(35.5)
(4.5%)
10.72%
(40.2)
(14.6%)
2.24% $
8.93%
4.7
9.4
19.93%
24.0
0.93%
5.84%
24.9%
(6.7)
(335.0%)
(11.4)
(85.1%)
196.1
217.2
234.5
(21.1)
(9.7%)
(17.3)
(7.4%)
(110.9)
(132.1)
(141.2)
21.2
(16.0%)
9.1
(6.4%)
-
5.4
(17.4)
12.5
(0.4)
0.5
-
5.0
(1.5)
9.7
0.3
1.2
18.5
14.0
25.6
3.6
-
0.4
*
(18.5)
(100.0%)
8%
(9.0)
(64.3%)
(15.9)
1,060%
(27.1)
(105.9%)
2.8
28.87%
6.1
169.44%
(1.3)
(0.7)
(233.3%)
1.6
(123.1%)
-
(0.7)
(1.8)
(58.3%)
8.7%
1.2
(1.4)
*
7.25%
(22.5)
(20.7)
(19.3)
63.3
78.3
(15.0)
79.1
49.8
29.3
134.4
(15.8)
(20.0%)
(55.3)
(41.1%)
97.1
37.3
28.5
57.23%
(47.3)
(48.7%)
(44.3)
(151.2%)
(8.0)
(21.4%)
Dividends on Series B preferred stock
(9.5)
(17.8)
(16.8)
8.3
(46.6%)
(1.0)
5.95%
Less:
Undistributed earnings attributable to
preferred shareholders
Dividends to common equivalents
Net income (loss) available to common shareholders
$
(202.3) $
-
(11.5)
(20.5)
11.5
(100.0%)
9.0
(43.9%)
(177.8)
-
- $
-
(177.8)
- $
(202.3)
-
- $
-
-
-
-
Operating statistics:
Plant natural gas inlet, MMcf/d (2) (3)
2,268.0
2,139.8
1,846.4
128.2
Gross NGL production, MBbl/d
Natural gas sales, BBtu/d (3)
NGL sales, MBbl/d
Condensate sales, MBbl/d
Average realized prices: (4)
Natural Gas, $/MMBtu
NGL, $/gal
Condensate, $/Bbl
Balance Sheet Data (at end of period)
121.2
685.1
251.5
3.5
118.3
598.4
279.7
4.7
101.9
532.1
286.9
5.99%
2.45%
2.9
86.7
14.49%
(28.2)
(10.1%)
293.4
16.4
66.3
(7.2)
0.9
15.9%
16.1%
12.5%
(3%)
23.7%
3.8
(1.2)
(25.5%)
$
4.43 $
1.06
3.96 $
0.79
8.20 $
1.38
0.48
0.27
73.68
56.32
91.28
17.37
12% $
(4.24)
(51.8%)
34.7%
30.8%
(0.59)
(34.96)
(43%)
(38%)
Property, plant and equipment, net
$
2,509.0 $
$
2,548.1
2,617.4 $
(39.1)
(2%) $
(69.3)
Total assets
3,393.8
3,367.5
3,641.8
22.7
.7%
(274.3)
(3%)
(8%)
Long-term debt less current maturities
1,534.7
1,593.5
1,976.5
(58.8)
(4%)
(383.0)
(19%)
Convertible cumulative participating Series B
preferred stock
Total owners' equity
Cash Flow Data:
Net cash provided by (used in)
Operating activities
Investing activities
Financing activities
-
1,036.1
308.4
754.9
290.6
(308.4)
(100%)
822.0
288.1
38.2%
17.8
(67.1)
6.1%
(8%)
$
208.5 $
335.8 $
390.7 $
(127.3)
(37.9%) $
(54.9)
(14.1%)
(134.6)
(59.3)
(206.7)
(75.3)
127.0%
147.4
(71.3%)
(137.9)
(386.9)
0.9
249.0
(64.4%)
(387.8) (43,089%)
66
_________
(1)
Includes business interruption insurance proceeds of $6.0 million, $21.5 million, and $32.9 million for the years ended December 31,
2010, 2009, and 2008.
(2) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing
plant.
(3) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
(4) Average realized prices include the impact of hedging activities.
* Not meaningful
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Revenue increased $933.2 million due to higher realized commodity prices ($1,200.9 million) offset by lower
sales volumes ($247.6 million), lower fee-based and other revenues ($5.5 million) and lower business
interruption insurance proceeds ($15.5 million)
The $36.6 million increase in gross margin reflects higher revenues ($933.2 million) offset by higher product
purchase costs ($896.7 million). For additional information regarding the period to period changes in our gross
margins, see “— Results of Operations —By Segment.”
The $25.2 million increase in operating expenses was primarily attributable to increased compensation and
benefits expense ($14.6 million), increased maintenance costs and utility costs of ($14.5 million), partially offset
by lower contract services and professional fees of $6.1 million. See “— Results of Operations—By Segment”
for additional discussion regarding changes in operating expenses.
The increase in depreciation and amortization expenses of $15.2 million is attributable to a $10.8 million
impairment charge related to idled terminal and processing assets as well as assets acquired in 2009 that have a
full period of depreciation in 2010 and capital expenditures in 2010 of $147.2 million.
General and administrative expenses increased $24.0 million reflecting increased professional services and
special compensation expense related to our December IPO.
Other operating items were an overall gain of $4.7 million during 2010 versus an overall loss of $2.0 million
during 2009. This improvement primarily reflects lower project abandonment costs during 2010. Both years
included income related to favorable outcomes on hurricane repair outlays and insurance recoveries.
The decrease in interest expense of $21.2 million is due to reductions in our total outstanding indebtedness
primarily funded by equity issuances by the Partnership. See “— Liquidity and Capital Resources” for
information regarding our outstanding debt obligations.
The effects of an overall net loss on debt retirements lowered pre-tax earnings by $13.1 million.
Net income attributable to noncontrolling interests increased from $49.8 million for the twelve months ended
December 31, 2009 to $78.3 million for the twelve months ended December 31, 2010. $5.5 million of the
increase was due to increased net income subject to noncontrolling interest for CBF, Versado and VESCO. In
addition, net income subject to noncontrolling interest for the Partnership increased in 2010, primarily due to the
impact of the full year ownership of the Downstream Business by the Partnership, as well as the partial year
impact of the 2010 dropdowns of assets into the Partnership. In addition, our ownership interest in the
Partnership decreased in 2010 due to the impact of the secondary sales of our units to the public in April 2010,
as well as the Partnership’s sales of common units in January and August 2010. At December 31, 2010 our
ownership in the Partnership was 17.1% versus 33.9% at year-end 2009. After adjusting for the impact of the
incentive distribution rights, our weighted average percentages of net income were 35.5% in 2010 and 40.5% in
2009.
Dividends were paid to our Series B Preferred shareholders in April 2010 and November 2010, which reduced
the accretive value of these shares. At our IPO, the outstanding Series B Preferred shares converted to common
shares.
67
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Revenue decreased $3,462.9 million due to lower commodity prices ($3,516.5 million), lower NGL sales
volumes ($169.4 million) and lower business interruption insurance proceeds of ($11.4 million) offset by higher
natural gas and condensate sales volumes ($222.1 million) and higher fee-based and other revenues
($12.3 million).
The $35.5 million decrease in gross margin reflects lower revenue ($3,462.9 million) offset by a reduction in
product purchase costs ($3,427.4) million. For additional information regarding the period to period changes in
our gross margins, see “— Results of Operations —By Segment.”
The decrease in operating expenses was primarily due to lower fuel, utilities and catalyst expenses ($20.6
million), lower maintenance and supplies expenses ($20.6 million), and lower contract labor costs ($7.8
million), partially offset by a lower level of cost recovery billings to others ($6.5 million). Year over year
comparisons of operating expenses are affected by the consolidation of VESCO starting August 1, 2008,
following our acquisition of majority ownership in this operation. Had VESCO been consolidated for all of
2008, operating expenses would have been $17.1 million higher for 2008. See “— Results of Operations — By
Segment” for additional discussion regarding changes in operating expenses.
The increase in depreciation and amortization expenses is primarily attributable to assets acquired in 2008 that
had a full period of depreciation and capital expenditures in 2009 of $170.3 million.
The increase in general and administrative expenses was primarily due to higher compensation related expenses
($17.0 million) and increased insurance expenses ($6.0 million), reflecting higher property casualty premiums
following significant 2008 Gulf Coast hurricane activity.
Other operating items were an overall loss of $2.0 million during 2009 versus a loss of $13.4 million during
2008, when we recorded a $19.3 million loss provision for property damage from Hurricanes Gustav and Ike net
of expected insurance recoveries. During 2009 the loss provision was reduced by $3.7 million. A $5.9 million
gain from a like-kind exchange of pipeline assets was also realized during 2008.
The decrease in interest expense is due to reduction of debt levels due to our sale of certain of our assets to the
Partnership coupled with sales of Partnership equity and increased debt at the Partnership. See “— Liquidity and
Capital Resources” for information regarding our outstanding debt obligations.
The decrease in equity in earnings of unconsolidated investments is due to our acquisition of majority ownership
in and consolidation of VESCO beginning August 1, 2008.
The net decrease in gains from debt transactions includes a $27.1 million decrease in gain on debt repurchases
partially offset by a $6.1 million increase in gain on debt extinguishment. See “— Liquidity and Capital
Resources” for information regarding our outstanding debt obligations.
The increase in gain on mark-to-market derivative instruments was due to favorable changes in commodity
prices and our adjusting $1.6 million in fair value of certain contracts with Lehman Brothers Commodity
Services Inc. to zero as a result of the Lehman Brothers bankruptcy filing.
Net income attributable to noncontrolling interests decreased from $97.1 million for the twelve months ended
December 31, 2008 to $49.8 million for the twelve months ended December 31, 2009. $20.0 million of the
decrease was due to decreased net income subject to noncontrolling interest for CBF and Versado, partially
offset by an increase of $6.2 million for VESCO due to the purchase of Chevron’s interest in August 2008. In
addition, net income subject to noncontrolling interest for the Partnership decreased in 2009, partially offset by
the September 2009 dropdown of the Downstream Business into the Partnership. In addition, our ownership in
the Partnership increased in 2009 to 33.9% versus 26.5% at the prior year-end due to the impact of the
Downstream dropdown, partially offset by the Partnership sales of common units in August 2009. After
adjusting for the impact of the IDRs, our weighted average percentages of net income were 40.5% in 2009 and
30.1 % in 2008.
68
Consolidating Results of Operations – Partnership versus Non-Partnership
The following table breaks down the consolidated results of operations for the three years ended December 31,
2010, 2009 and 2008 into Partnership and our standalone (“TRC Non-Partnership”) financial results.
Partnership results are presented on a common control accounting basis – the same basis reported in the separate
Partnership 10-K. A discussion of the Non-Partnership financial results follows this table.
2010
2009
2008
Targa
Resources
Corp.
Consolidated
Targa
Resources
Partners,
LP
TRC - Non-
partnership
Targa
Resources
Corp.
Consolidated
Targa
Resources
Partners,
LP
(In millions)
Targa
Resources
Corp.
Consolidated
Targa
Resources
Partners,
LP
TRC - Non-
partnership
TRC - Non-
partnership
$
5,469.2 $
5,460.2 $
9.0 $
4,536.0 $
4,503.8 $
32.2 $
7,998.9 $
8,030.1 $
(31.2)
4,687.7
260.2
4,688.0
259.5
185.5
144.4
(4.7)
176.2
122.4
(3.3)
5,273.1
5,242.8
(0.3)
0.7
9.3
22.0
(1.4)
30.3
3,791.1
235.0
3,792.9
234.4
(1.8)
0.6
7,218.5
275.2
7,217.2
274.3
170.3
120.4
2.0
166.7
118.5
(3.6)
4,318.8
4,308.9
3.6
1.9
5.6
9.9
160.9
96.4
13.4
156.8
97.3
13.4
7,764.4
7,759.0
1.3
0.9
4.1
(0.9)
-
5.4
196.1
217.4
(21.3)
217.2
194.9
22.3
234.5
271.1
(36.6)
(110.9)
(81.4)
(29.5)
(132.1)
(52.1)
(80.0)
(141.2)
(38.9)
(102.3)
-
(29.4)
29.4
-
(107.7)
107.7
-
(117.2)
117.2
5.4
5.4
-
5.0
5.0
(17.4)
12.5
-
(0.4)
0.5
85.8
10.6
(33.1)
(22.5)
-
-
-
26.0
-
138.0
(2.8)
(1.2)
(4.0)
(17.4)
(1.5)
(1.5)
12.5
-
(26.4)
0.5
(52.2)
13.4
(31.9)
(18.5)
(70.7)
9.7
-
0.3
1.2
99.8
(1.6)
(19.1)
(20.7)
79.1
-
-
(30.9)
0.7
8.4
(0.3)
(0.9)
(1.2)
7.2
-
-
9.7
-
31.2
0.5
91.4
(1.3)
(18.2)
(19.5)
71.9
14.0
14.0
-
13.1
18.5
76.4
1.1
29.2
18.5
(1.3)
-
153.7
238.1
(1.3)
(18.0)
(19.3)
(0.8)
(2.1)
(2.9)
-
-
16.1
-
(77.7)
(1.1)
(84.4)
(0.5)
(15.9)
(16.4)
134.4
235.2
(100.8)
Revenues
Costs and Expenses:
Product purchases
Operating expenses
Depreciation and
amortization
General and administrative
Other
Income from operations
Other income (expense):
Interest expense, net - Third
Party
Interest expense -
Intercompany
Equity in earnings of
unconsolidated investments
Gain (loss) on debt
repurchases
Gain (loss) on debt
extinguishment
Gain on insurance claims
Gain (loss) on mark-to-market
derivative instruments
Other income (expense)
Income before income taxes
Income tax (expense) benefit
Current
Deferred
Net income (loss)
63.3
134.0
Less: Net income attributable to
noncontrolling interest
Net income (loss) attributable
to TRC
$
78.3
24.9
53.4
49.8
19.3
30.5
97.1
33.1
64.0
(15.0) $
109.1 $
(124.1) $
29.3 $
(12.1) $
41.4 $
37.3 $
202.1 $
(164.8)
69
The following table provides details of explanations the TRC Non-Partnership results displayed in the table
above:
Revenues
Business interruption revenues (post dropdown) retained by TRC Non-Partnership
$
6.0 $
8.2 $
-
Settlements on pre-dropdown derivatives not qualifying for hedge treatment in separate
Partnership financial statements
3.0
24.0
(31.2)
2010
2009
2008
Costs & Expenses
Product purchases for assets excluded from dropdown transactions
Operating expenses for assets excluded from dropdown transactions
Depreciation on excluded and corporate assets
G&A expenses retained by TRC Non-Partnership
Project abandonments and loss (gain) on property retirements and sales related to
excluded assets
Other income (expense)
Interest expense on TRC Non-Partnership debt
Interest income on intercompany debt
(0.3)
(1.8)
0.7
9.3
22.0
0.6
3.6
1.9
1.3
0.9
4.1
(0.9)
(1.4)
5.6
-
(29.5)
(80.0)
(102.3)
29.4
107.7
117.2
Gain (loss) on purchases and extinguishments of TRC Non-Partnership debt obligations
(4.9)
9.7
16.1
Reversal of Partnership mark-to-market derivatives gain (losses) qualifying for hedge
accounting by Parent
Other
Income tax expense (benefit) related to profits and losses taxed at the TRC Non-
Partnership level and impact of dropdown transactions
Net income attributable to noncontrolling interest in the Partnership
(26.4)
31.2
(77.7)
0.5
0.5
(1.1)
(18.5)
53.4
(19.5)
30.5
(16.4)
64.0
Results of Operations—By Segment
We have segregated the following segment operating margin between Partnership and Non-partnership
activities. Partnership activities have been presented on a common control accounting basis which reflects the
dropdown transactions as if they occurred in prior periods. Non-Partnership results include certain assets and
liabilities contractually excluded from the dropdown transactions and certain historical hedge activities that
could not be reflected as such under GAAP in the Partnership common control results.
Partnership
Field
Gathering
and
Processing
Coastal
Gathering
and
Processing
Logistics
Assets
Year Ended
Marketing
and
Distribution Other
TRC Non-
Partnership
Consolidated
Operating
Margin
December 31, 2010
$
236.6 $
107.8 $
83.8 $
80.5 $
4.0 $
8.6 $
December 31, 2009
183.2
89.7
December 31, 2008
385.4
105.4
74.3
40.1
83.0
46.3
41.3
(33.6)
33.4
(33.4)
521.3
509.9
505.2
A discussion of the Partnership segment results follows.
70
Results of Operations of the Partnership – By Segment
Natural Gas Gathering and Processing
Field Gathering and Processing
Year Ended December 31,
2010 vs. 2009
2009 vs. 2008
2010
2009
($ in millions)
2008
$ Change
% Change $ Change
% Change
Gross margin
Operating expenses
Operating margin
$
$
338.8 $
268.3 $
489.5 $
102.2
85.1
104.1
236.6 $
183.2 $
385.4 $
70.5
17.1
53.4
26% $
(221.2)
20%
(19.0)
29% $
(202.2)
(45%)
(18%)
(52%)
1%
5.8
69.8
68.0
71.2
219.6
581.9
584.1
258.6
587.7
Operating statistics:
Plant natural gas inlet, MMcf/d
Gross NGL production, MBbl/d
Natural gas sales, BBtu/d (1)
NGL sales, MBbl/d (1)
Condensate sales, MBbl/d (1)
Average realized prices:
Natural gas, $/MMBtu
NGL, $/gal
Condensate, $/Bbl
________
(1) Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation.
For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of
calendar days during the year.
75.48
55.84
0.93
4.11
0.69
3.69
(30.67)
86.51
296.2
19.64
(0.52)
(76.6)
(3.86)
(9%)
56.6
54.1
56.2
1.21
7.55
39.0
0.24
0.42
(2.2)
(0.3)
(0.3)
35%
35%
18%
11%
2.9
3.5
3.2
1.8
2.1
0.4
1.4
2%
1%
(%)
3%
(26%)
4%
(9%)
(51%)
(43%)
(35%)
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $70.5 million increase in gross margin for 2010 was primarily due to higher commodity sales prices
($303.9 million) and higher natural gas and NGL sales volumes ($22.6 million) offset by lower condensate sales
volumes ($6.8 million), higher fee based and other revenue ($4.5 million) and higher product purchases
($253.6 million.) The increased natural gas and NGL sales volumes were due primarily to higher natural gas and
NGL production.
The increase in operating expenses was primarily due to higher system maintenance expenses ($8.2 million),
higher compensation and benefit costs ($4.7 million) and higher contract and professional service expenses
($2.0 million).
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $221.2 million decrease in gross margin for 2009 was due to lower commodity sales prices ($853.9) million
and lower natural gas and condensate sales volumes ($157.2 million) offset by higher NGL sales volumes
($36.1 million), higher fee based and other revenue ($0.1 million) and lower product purchases ($753.8 million).
The increased NGL sales volumes were due primarily to higher NGL production.
The decrease in operating expenses was primarily due to lower maintenance and supplies expenses ($8.4
million), lower contract services and professional fees ($4.4 million), and lower fuel, utilities and catalysts
expenses ($3.2 million).
71
Coastal Gathering and Processing
Year Ended December 31,
2010 vs. 2009
2009 vs. 2008
2010
2009
($ in millions)
2008
$ Change
% Change $ Change
% Change
Gross margin
Operating expenses
Operating margin
$
$
151.2 $
132.7 $
136.5 $
43.4
43.0
31.1
107.8 $
89.7 $
105.4 $
18.5
0.4
18.1
14% $
1%
(3.8)
11.9
(3%)
38%
20% $
(15.7)
(15%)
8%
122.5
48.5
50.1
33.9
258.4
293.6
1,557.8
1,262.4
1,680.3
Operating statistics:
Plant natural gas inlet, MMcf/d (2)
Gross NGL production, MBbl/d
Natural gas sales, Bbtu/d (1)
NGL sales, MBbl/d (1)
Condensate sales, MBbl/d (1)
Average realized prices:
Natural gas, $/MMBtu
NGL, $/gal
Condensate, $/Bbl
__________
(1) Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation.
For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of
calendar days during the year.
(36.79)
78.82
239.4
90.10
53.31
(69%)
295.4
(0.57)
(5.00)
43.7
31.7
4.00
1.34
9.00
40.6
4.48
1.03
0.77
25.51
14.6
19.0
1.5
34%
12%
1.6
14%
48%
0.5
35.2
0.26
0.48
(1.1)
8.9
0.1
3%
8%
1.6
3.1
23%
43%
8%
28%
7%
(56%)
(43%)
(41%)
(2) The majority of the Partnership’s straddle plant volumes are gathered on third party offshore pipeline systems and delivered to the
plant inlets.
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $18.5 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices
($230.3 million) and an increase in natural gas and NGL sales volumes ($88.3 million) offset by decreases in
condensate sales volumes ($21.8 million) and fee-based and other revenues ($11.3 million) and an increase in
commodity sales purchases ($266.8 million). Natural gas sales volumes increased due to increased sales to other
segments for resale partially offset by a small decrease in demand from the Partnership’s industrial customers.
NGL, natural gas and inlet sales volumes increased primarily because the straddle plants were recovering
operations in the first two quarters of 2009 after Hurricanes Gustav and Ike disrupted operations in 2008.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $3.8 million decrease in gross margin for 2009 is primarily due to lower commodity realization prices
($847.7 million) and lower business interruption proceeds ($3.4 million) offset by higher commodity sales
volumes ($246.0 million) as a result of the recovery of operations after Hurricanes Gustav and Ike, reduced
product purchase costs ($596.7 million) and higher fee-based and other income ($4.6 million). VESCO has been
consolidated in our financials since we purchased Chevron’s interest in August 2008, giving us a controlling
interest from that date forward. Had VESCO been consolidated for the entire period, gross margin for 2008
would have been $43.6 million.
The increase in operating expenses was primarily due to a full year of operating expenses from VESCO in 2009,
as compared with five months of operating expenses from VESCO in 2008 due to the Partnership’s acquisition
of majority ownership in and consolidation of VESCO on August 1, 2008. Had VESCO been consolidated for
the entire period, operating expenses for 2008 would have been $17.8 million higher and our Coastal Gathering
and Processing segment would have reported reductions in aggregate operating expense levels during 2009 as
was the case with the Partnership’s other segments.
72
NGL Logistics and Marketing Division
Logistics Assets
Gross margin
Operating expenses
Operating margin
Operating statistics:
Fractionation volumes, MBbl/d
LSNG Treating volumes, MBbl/d
Year Ended December 31,
2010 vs. 2009
2009 vs. 2008
2010
2009
($ in millions)
2008
$ Change
% Change $ Change
% Change
$
$
172.3 $
156.2 $
172.5 $
16.1
10% $
(16.3)
(9%)
88.5
81.9
132.4
83.8 $
74.3 $
40.1 $
6.6
9.5
8%
(50.5)
(38%)
13% $
34.2
85%
230.8
217.2
212.2
18.0
21.9
20.7
13.6
(3.9)
6%
(18%)
5.0
1.2
2%
6%
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $16.1 million increase in gross margin reflects higher fractionation and treating fees ($20.4 million) and
higher terminalling and storage revenue ($2.6 million), offset by lower fee-based and other revenues ($6.9
million). The increase in fractionation volumes is as result of the Partnership’s capacity in its fractionating
facilities being at or near capacity. The Partnership is expanding its fractionation capacity at the Cedar Bayou
and Gulf Coast Fractionating plants to meet increased market demand.
The $6.6 million increase in operating expenses was primarily due to higher compensation costs ($5.0 million)
and higher general maintenance supplies ($3.0 million).
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $16.3 million decrease in gross margin for 2009 was due to lower fractionation and treating revenue ($20.9
million) due to lower fees offset by higher other fee-based and other revenue ($4.6 million).
The decrease in operating expenses was primarily due to lower fuel and utilities expenses ($43.2 million), lower
maintenance and supplies expenses ($4.7 million) and lower outside services ($9.4 million), offset by higher
compensation expense ($1.1 million) and system product losses ($2.5 million).
Marketing and Distribution
Gross margin
Operating expenses
Operating margin
Operating statistics:
Natural gas sales, BBtu/d
NGL sales, MBbl/d
Average realized prices:
Natural gas, $/MMBtu
NGL realized price, $/gal
Year Ended December 31,
2010 vs. 2009
2009 vs. 2008
2010
2009
($ in millions)
2008
$ Change
% Change $ Change
% Change
$
$
125.4 $
128.9 $
44.9
45.9
98.8 $
57.5
80.5 $
83.0 $
41.3 $
(3.5)
(1.0)
(2.5)
(3%) $
30.1
30%
(2%)
(11.6)
(20%)
(3%) $
41.7
101%
634.9
510.3
417.4
124.6
24%
246.7
276.1
284.0
(29.4)
(11%)
92.9
(7.9)
22%
(3%)
4.31
1.10
3.65
0.80
7.81
1.40
0.66
0.30
18%
38%
(4.16)
(0.60)
(53%)
(43%)
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
The $3.5 million decrease in gross margin was due to increased commodity prices of $1,287.9 million and
higher natural gas volumes of $166.2 million offset by lower NGL volumes of $359.8 million, lower fee-based
and other revenues of $20.4 million, and increased product purchases of $1,077.2 million. Lower 2010 margins
at inventory locations were primarily due to the 2009 impact of higher margins on forward sales agreements that
were fixed at relatively high 2008 prices, along with spot fractionation volumes and associated fees. These items
73
were partially offset by higher marketing fees on contract purchase volumes due to overall higher 2010 market
prices. Margin on transportation activity decreased due to expiration of a barge contract partially offset by
increased truck activity.
Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are lower due to
a change in contract terms with a petrochemical supplier that had a minimal impact to gross margin.
Operating expenses were essentially flat.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
The $30.1 million increase in gross margin for 2009 was due to higher natural gas sales volumes of $261.8
million, lower product purchase costs of $3,312.4 million and a $33.0 million decrease in lower of cost or
market adjustment, offset by lower realized commodity prices of $3,334.9 million, and lower NGL sales
volumes of $188.2 million, lower fee-based and other revenues of $37.6 million and lower business interruption
proceeds of $16.3 million.
Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are lower
beginning in the third quarter of 2009 due to a change in contract terms with a petrochemical supplier that had a
minimal impact to gross margin.
The $11.6 million decrease in operating expenses was primarily due to a decrease in fuel and utilities expense of
$5.8 million, a decrease in maintenance and supplies expenses of $4.2 million and a decrease in outside services
of $1.0 million. Factors contributing to the decrease included the expiration of a barge contract, partially offset
by increased truck utilization.
Other
Years Ended December 31,
2010 vs. 2009
2009 vs. 2008
2010
2009
2008
Change
% Change Change
% Change
($ in millions)
Gross margin
Operating margin
$
$
4.0 $
46.3 $
(33.6)
$
(42.3)
(91%) $
79.9
4.0 $
46.3 $
(33.6)
$
(42.3)
(91%) $
79.9
238%
238%
Other contains the financial effects of the cash flow hedging program on profitability. The primary purpose of
the Partnership’s commodity risk management activities is to hedge its exposure to commodity price risk and
reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. The Partnership has
hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity
volumes by entering into derivative financial instruments. The Partnership’s hedging strategy is in effect to
forward sell its equity gas and NGL volumes generated by our gas plants. As such, these hedge positions will
enhance the Partnership’s margins in periods of falling prices and decrease its margins in periods of rising
prices.
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Our cash flow hedging program decreased gross margin by $42.3 million during 2010 versus 2009, due to
higher commodity prices which resulted in lower revenues from settlements on derivative contracts, as well as
the impact of lower volumes hedged.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Our cash flow hedges increased gross margin by $79.9 million during 2009 versus 2008, as lower commodity
prices yielded higher settlement revenues on derivative contracts.
74
Insurance Update
Hurricanes Katrina and Rita affected certain of our Gulf Coast facilities in 2005. The final purchase price
allocation for our acquisition from Dynegy in October 2005 included an $81.1 million receivable for insurance
claims related to property damage caused by Hurricanes Katrina and Rita. During 2008, our cumulative receipts
exceeded such amount, and we recognized a gain of $18.5 million. During 2009, expenditures related to these
hurricanes included $0.3 million capitalized as improvements. The insurance claim process is now complete
with respect to Hurricanes Katrina and Rita for property damage and business interruption insurance.
Certain of our Louisiana and Texas facilities sustained damage and had disruptions to their operations during the
2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we
recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes.
During 2010 and 2009, the estimate was reduced by $3.3 million and $3.7 million. During 2009, expenditures
related to the hurricanes included $33.7 million for previously accrued repair costs and $7.5 million capitalized
as improvements.
Liquidity and Capital Resources
As a result of our conveyances of all of our remaining operating assets to the Partnership, we have no separate,
direct operating activities apart from those conducted by the Partnership. As such, our ability to finance our
operations, including payment of dividends to our common shareholders, funding capital expenditures and
acquisitions, or to meet our indebtedness obligations, will depend on cash inflows from future cash distributions
to us from our interests in the Partnership. The Partnership is required to distribute all available cash at the end
of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for
future distributions. See “Item 1A. Risk Factors.” As of February 25, 2011, our interests in the Partnership
consist of the following:
• a 2% general partner interest, which we hold through our 100% ownership interest in the general partner
of the Partnership;
• all of the outstanding IDRs; and
• 11,645,659 of the 84,756,009 outstanding common units of the Partnership, representing a 13.7% limited
partnership interest.
Our ownership of the general partner interest entitles us to receive:
• 2% of all cash distributed in respect for that quarter.
Our ownership in respect to the IDR’s of the Partnership that we hold, entitles us to receive:
• 13% of all cash distributed in a quarter after $0.3881 has been distributed in respect of each common unit
of the Partnership for that quarter;
• 23% of all cash distributed in a quarter after $0.4219 has been distributed in respect of each common unit
of the Partnership for that quarter; and
• 48% of all cash distributed in a quarter after $0.50625 has been distributed in respect of each common
unit of the Partnership for that quarter.
The General Partner’s Board of Directors increased the fourth quarter 2010 distribution by $0.01 per common
unit or $0.04 on an annualized basis. Based on the $2.19 annualized rate, a quarterly distribution by the
Partnership of $0.5475 per common unit will result in quarterly distributions to us of $6.4 million, or
$25.5 million on an annualized basis, in respect of our common units in the Partnership. Such distribution would
also result in quarterly distributions to us in respect of our 2% general partner interest and the IDRs of $7.1
million, or $28.4 million on an annualized basis.
We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash the Partnership distributes
to us based on our ownership of Partnership securities, less the expenses of being a public company, other
general and administrative expenses, federal income taxes, capital contributions to the Partnership and reserves
75
established by our board of directors. On February 21, 2011, based on the pro rata dividend declared for the
portion fourth quarter of 2010 following our IPO of $0.0616 per share of our common stock, we paid an
equivalent initial quarterly dividend of $0.2575 per share of our common stock, or $1.03 per share on an
annualized basis. The total dividend paid was $2.6 million.
As of December 31, 2010, we had $188.4 million of cash on hand, including $76.3 million of cash belonging to
the Partnership. We do not have access to the Partnership’s cash as it is restricted for the use of the Partnership.
We have the ability to use $112.1 million of the cash on hand and available to us to satisfy our aggregate tax
liability of approximately $88.0 million over the next ten years associated with our sales of assets to the
Partnership and related financings as well as to fund the reimbursement of certain capital expenditures to the
Partnership associated with its acquisition of Versado. In addition, we have a contingent obligation to contribute
to the Partnership limited distribution support in any quarter through 2011 if and to the extent the Partnership
has insufficient available cash to fund a distribution of $0.5175 per unit, limited to $8.0 million per quarter. We
have yet and do not currently expect to make any payments pursuant to this distribution support obligation.
Our and the Partnership’s cash generated from operations has been sufficient to finance operating expenditures
and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any
disruptive events, we believe that internally generated cash flow, primarily from distributions received from the
Partnership and borrowings available under our senior secured credit facility should provide sufficient resources
to finance our operations, non-acquisition related capital expenditures, long-term indebtedness obligations and
collateral requirements. Our future cash flows will consist of distributions to us from our interests in the
Partnership, from which we intend to make quarterly cash dividends to our shareholders from available cash. On
February 14, 2011, the Partnership paid its quarterly distribution of $0.5475 per common unit per quarter (or
$2.19 per common unit on an annualized basis) for the quarter ended December 31, 2010. Based on the
Partnership’s current capital structure, the distribution of $0.5475 per common unit resulted in a quarterly
distribution to us of $13.4 million in respect of our Partnership interests.
The impact on us of changes in the Partnership’s distribution levels will vary depending on several factors,
including the Partnership’s total outstanding partnership interests on the record date for the distribution, the
aggregate cash distributions made by the Partnership and the interests in the Partnership owned by us. If the
Partnership increases distributions to its unitholders, including us, we would expect to increase dividends to our
stockholders, although the timing and amount of such increased dividends, if any, will not necessarily be
comparable to the timing and amount of the increase in distributions made by the Partnership. In addition, the
level of distributions we receive and of dividends we pay to our stockholders may be affected by the various
risks associated with an investment in us and the underlying business of the Partnership. Please read “Item 1A.
Risk Factors” for more information about the risks that may impact your investment in us.
A significant portion of the Partnership’s capital resources are utilized in the form of cash and letters of credit to
satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade
status, as assigned to us and the Partnership by Moody’s Investors Service, Inc. and Standard & Poor’s Ratings
Service, and counterparties’ views of our financial condition and ability to satisfy our performance obligations,
as well as commodity prices and other factors. At February 14, 2011, we had no total outstanding letter of credit
postings and the Partnership had $111.8 million.
Working Capital. Working capital is the amount by which current assets exceed current liabilities. The
Partnership’s 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 the Partnership buys and
sells. In general, the Partnership’s working capital requirements increase in periods of rising commodity prices
and decrease in periods of declining commodity prices. However, the Partnership’s working capital needs do not
necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable
are impacted by the same commodity prices. In addition, the timing of payments received by the Partnership’s
customers or paid to their suppliers can also cause fluctuations in working capital because the Partnership settles
with most of their larger suppliers and customers on a monthly basis and often near the end of the month. The
Partnership expects that their future working capital requirements will be impacted by these same factors. The
Partnership’s cash flows provided by operating activities will be sufficient to meet their operating requirements
for the next twelve months.
Subsequent Events. On January 24, 2011, the Partnership completed a public offering of 8,000,000 common
units under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41
per common unit, net of underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the
76
exercise of the underwriters’ overallotment option, on February 3, 2011 the Partnership sold an additional
1,200,000 common units, providing net proceeds of $38.9 million. In addition, we contributed $6.3 million for
187,755 general partner units to maintain our 2% general partner interest in the Partnership. The Partnership
used the net proceeds from the offering to reduce borrowings under its senior secured credit facility.
On February 2, 2011, the Partnership privately placed $325.0 million in aggregate principal amount of 6⅞%
Senior Notes due 2021 (“the 6⅞% Notes”) resulting in net proceeds of $319.3 million.
On February 4, 2011 the Partnership exchanged $158.6 million under an exchange offer to holders of our 11¼%
Notes due 2017 for $158.6 million principal amount 6⅞% Notes due 2021. In conjunction with the exchange
the Partnership paid a premium in cash of $28.6 million. The debt covenants related to the remaining $72.7
million of face value 11¼% Notes due 2017 were removed as the Partnership received sufficient consents in
connection with the exchange offer to amend the indenture.
Net cash from the completion of the unit offerings, the note offering and the exchange offer was used to reduce
outstanding borrowings under the Partnership’s senior secured credit facility by $595.2 million. Taking into
account these payments, as of December 31, 2010, the Partnership’s available borrowings under its senior
secured credit facility would have been $828.6 million.
Cash Flow
The following table and discussion of the Operating Activities, Investing Activities, and Financing Activities
summarizes the consolidated cash flows of us and the Partnership provided by or used in operating activities,
investing activities and financing activities for the periods indicated:
Year Ended December 31,
2010
2009
2008
(in millions)
$
208.5 $
(134.6)
(137.9)
335.8 $
(59.3)
(386.9)
390.7
(206.7)
0.9
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Operating Activities
The changes in net cash provided by operating activities are attributable to our consolidated net income adjusted
for non-cash charges as presented in the Consolidated Statements of Cash Flows included in our historical
consolidated financial statements and related notes thereto appearing elsewhere in this Annual Report and
changes in working capital as discussed above under “—Liquidity and Capital Resources —Working Capital.”
We expect our cash flows provided by operating activities will be sufficient to meet our operating requirements
for the next twelve months.
For the year ended December 31, 2010 compared to 2009, net cash provided by operating activities decreased
by $127.3 million primarily due to the following:
• a decrease in net income of $15.9 million,
• a decrease in non-cash risk management activities of $10.3 million due to higher average future prices on
commodity valuations,
• a decrease in the change in operating assets and liabilities of $147.6 million, primarily driven by higher
payable and receivable balances in 2010, and
• offset by changes in net losses related to debt repurchases and extinguishments of $13.1 million.
The $54.9 million decrease in net cash provided by operating activities in 2009 compared to 2008 was primarily
due to the following:
77
• net cash flow from consolidated operations (excluding cash payments for interest, cash payments for
income taxes and distributions received from unconsolidated affiliates) decreased $48.3 million period-
to-period. The decrease in operating cash flow is generally due to a decrease in net income of
$55.3 million. Please see “—Results of Operations—Year Ended December 31, 2009 Compared to Year
Ended December 31, 2008” for a discussion of material items that impacted our operating cash flow, and
• cash payments for interest expense decreased $11.8 million period-to-period primarily due to a reduction
in and change in the mix of debt due to debt retirements and refinancing activities and lower effective
interest rates.
Investing Activities
Net cash used in investing activities increased by $75.3 million for the year ended December 31, 2010 compared
to the year ended 2009, primarily due to increased capital spending of $39.9 million offset by a decrease in
proceeds from property insurance claims of $35.3 million received in 2009.
Net cash used in investing activities decreased by $147.4 million to $59.3 million for 2009 compared to $206.7
million for 2008. The decrease is attributable to lower capital expenditures in 2009 and the VESCO acquisition
in 2008.
The following table lists gross additions to property, plant and equipment, cash flows used in property, plant and
equipment additions and the difference, which is primarily settled accruals and non-cash additions:
2010
Year Ended December 31,
2009
(In millions)
2008
Gross additions to property, plant and equipment
Inventory line-fill transferred to property, plant and equipment
Change in accruals and other
Purchase price adjustment related to consolidation of VESCO
$
147.2 $
(0.4)
(7.5)
-
101.9 $
(9.8)
6.6
0.7
Cash expenditures
$
139.3 $
99.4 $
147.1
(5.8)
(9.0)
-
132.3
Financing Activities
Net cash used in financing activities for the year ended 2010 compared to 2009 decreased by $249 million. The
decrease was primarily due to a $457.6 million dividend to our Series B Preferred, common stockholders and
common equivalents, partially offset by a net decrease in repayments on indebtedness of $322.9 million and
proceeds from the sale of limited partner interests in the Partnership of $542.5 million.
Net cash used in financing activities in 2009 was primarily due to net repayments on indebtedness and
distributions by the Partnership, partially offset by equity issuances.
Net cash provided by financing activities during 2008 was primarily due to net borrowings, net of repayments
on indebtedness and repurchases, partially offset by increased dividends paid to stockholders in 2008.
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 make significant
expenditures during the next year for the construction of additional natural gas gathering and processing
infrastructure and to enhance the value of our natural gas logistics and marketing assets.
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, add capabilities, reduce costs or enhance revenues.
78
Year Ended December 31,
2010
2009
2008
(In millions)
Capital expenditures
Expansion
Maintenance
$
$
93.9 $
53.3
55.4 $
46.5
74.5
72.6
147.2 $
101.9 $
147.1
The Partnership estimates that its capital expenditures for 2011 will be approximately $230 million, of which
approximately 25% will be spent on capital maintenance.
Credit Facilities and Long-Term Debt
The following table summarizes our and the Partnership’s debt as of December 31, 2010 (in millions):
Our Obligations:
TRC Holdco Loan, due February 2015
$
TRI Senior secured revolving credit facility due July 2014
Obligations of the Partnership:
Senior secured revolving credit facility, due July 2015
Senior unsecured notes, 8 1/4% fixed rate, due July 2016
Senior unsecured notes, 11 1/4% fixed rate, due July 2017
Unamortized discounts, net of premiums
Senior unsecured notes, 7 7/8% fixed rate, due July 2018
Total debt
Current maturities of debt
Total long-term debt
89.3
-
765.3
209.1
231.3
(10.3)
250.0
1,534.7
-
$
1,534.7
We consolidate the debt of the Partnership with that of our own; however, we do not have the contractual
obligation to make interest or principal payments with respect to the debt of the Partnership. We have retired all
amounts outstanding under our senior secured term loan facility due July 2016 as of December 2010. Our debt
obligations including those of Targa Resources, Inc (“TRI”) do not restrict the ability of the Partnership to make
distributions to us. TRI’s senior secured credit facility has restrictions and covenants that may limit our ability to
pay dividends to our stockholders. Please read “—TRI Senior Secured Credit Facility” for a discussion of the
restrictions and covenants in TRI’s senior secured credit facility.
As of December 31, 2010, both we and the Partnership were in compliance with the covenants contained in our
various debt agreements.
Holdco Loan
On August 9, 2007, we borrowed $450 million under this facility. Interest on borrowings under the facility are
payable, at our option, either (i) entirely in cash, (ii) entirely by increasing the principal amount of the
outstanding borrowings or (iii) 50% in cash and 50% by increasing the principal amount of the outstanding
borrowings.
We are the borrower under this facility. We have pledged TRI stock as collateral under this loan agreement.
On November 3, 2010, we amended our Holdco Loan to name our wholly-owned subsidiary, TRI, as guarantor
to our obligations under the credit agreement. The operations and assets of the Partnership continue to be
excluded as guarantors of the Holdco Loan. In conjunction with the guaranty agreement, the applicable margin
for borrowings under the facility was reduced from 5.0% to 3.75%. At our option, should we choose to pay the
79
interest on this loan in cash versus increasing the principal amount of the outstanding borrowings, the applicable
margin for borrowings would be further reduced to 3.0%.
TRI Senior Secured Credit Facility
On January 5, 2010, we entered into a senior secured credit facility providing senior secured financing of
$600 million, consisting of:
• $500 million senior secured term loan facility (fully repaid as of December 2010); and
• $100 million senior secured revolving credit facility (subsequently reduced to $75 million and undrawn
as of December 2010).
The entire amount of our credit facility is available for letters of credit and includes a limited borrowing
capacity for borrowings on same-day notice referred to as swing line loans. Our available capacity under this
facility is currently $75 million. TRI is the borrower under this facility.
Borrowings under the credit agreement bear interest at a rate equal to an applicable margin, plus at our option,
either (a) a base rate determined by reference to the higher of (1) the prime rate of Deutsche Bank, (2) the
federal funds rate plus 0.5%, and (3) solely in the case of term loans, 3%, or (b) LIBOR as determined by
reference to the higher of (1) the British Bankers Association LIBOR Rate and (2) solely in the case of term
loans, 2%.
Principal amounts outstanding under our senior secured revolving credit facility are due and payable in full on
July 5, 2014. During 2010, we used the proceeds from our sales of the Permian Business and Straddle Assets,
Versado and VESCO, as well as the secondary public offering of 8,500,000 common units of the Partnership
that we owned to fully repay the outstanding balance on the senior secured term loan.
The credit agreement is secured by a pledge of our ownership in our restricted subsidiaries and contains a
number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur
additional indebtedness (including guarantees and hedging obligations); create liens on assets; enter into sale
and leaseback transactions; engage in mergers or consolidations; sell assets; pay dividends and make
distributions or repurchase capital stock and other equity interests; make investments, loans or advances; make
capital expenditures; repay, redeem or repurchase certain indebtedness; make certain acquisitions; engage in
certain transactions with affiliates; amend certain debt and other material agreements; and change our lines of
business.
Senior Secured Revolving Credit Facility of the Partnership due 2015
On July 19, 2010, the Partnership entered into an amended and restated five-year $1.1 billion senior secured
credit facility, which allows it to request increases in commitments up to additional $300 million. The amended
and restated senior secured credit facility replaces the Partnership’s former $977.5 million senior secured
revolving credit facility due February 2012.
For the year ended December 31, 2010, the Partnership had gross borrowings under its senior secured revolving
credit facilities of $1,343.1 million, and repayments totaling $1,057.0 million, for a net increase for the year
ended December 31, 2010 of $286.1 million.
The amended and restated credit facility bears interest at LIBOR plus an applicable margin ranging from 2.25%
to 3.5% (or base rate at the borrower’s option) dependent on the Partnership’s consolidated funded indebtedness
to consolidated adjusted EBITDA ratio. The Partnership’s amended and restated senior secured credit facility is
secured by a majority of the Partnership’s assets.
The Partnership’s senior secured credit facility restricts its ability to make distributions of available cash to
unitholders if a default or an event of default (as defined in our senior secured credit agreement) has occurred
and is continuing. The senior secured credit facility requires the Partnership to maintain a consolidated funded
indebtedness to consolidated adjusted EBITDA of less than or equal to 5.50 to 1.00. The senior secured credit
facility also requires the Partnership to maintain an interest coverage ratio (the ratio of our consolidated
EBITDA to our consolidated interest expense, as defined in the senior secured credit agreement) of greater than
or equal to 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on
80
the date of determination, as well as upon the occurrence of certain events, including the incurrence of
additional permitted indebtedness.
The Partnership’s Outstanding Notes
On June 18, 2008, the Partnership privately placed $250 million in aggregate principal amount at par value of
8¼% senior notes due 2016 (the “8¼% Notes”). On July 6, 2009, the Partnership privately placed $250 million
in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were
issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million.
On August 13, 2010, the Partnership privately placed $250 million in aggregate principal amount of its 7⅞%
senior notes due 2018. These notes are unsecured senior obligations that rank pari passu in right of payment
with existing and future senior indebtedness of the Partnership, including indebtedness under its credit facility.
They are senior in right of payment to any of the Partnership’s future subordinated indebtedness.
The Partnership’s senior unsecured notes and associated indenture agreements (other than the indenture for the
11¼ Notes) restrict the Partnership’s ability to make distributions to unitholders in the event of default (as
defined in the indentures). The indentures also restrict the Partnership’s ability and the ability of certain of its
subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain
distributions on or repurchase, equity interests (only if such distributions do not meet specified conditions); (iii)
make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate
with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important
exceptions and qualifications. If at any time when the notes are rated investment grade by both Moody’s
Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indentures) has
occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will
cease to be subject to such covenants.
Off-Balance Sheet Arrangements
We currently have no off-balance sheet arrangements as defined by the Securities and Exchange Commission.
See “Contractual Obligations” below and “Commitments and Contingencies” included under Note 16 to our
“Audited Consolidated Financial Statements” beginning on page F-1 of this Annual Report for a discussion of
our commitments and contingencies, some of which are not recognized in the consolidated balance sheets under
GAAP.
Contractual Obligations
Following is a summary of our contractual cash obligations over the next several fiscal years, as of December
31, 2010:
Payments Due By Period
Less Than
More Than
Contractual Obligations
Total
1 Year
1-3 Years
4-5 Years
5 Years
Debt obligations (1)
Interest on debt obligations (2)
Operating lease and service contract obligations (3)
Capacity and terminalling payments (4)
Land site lease and right-of-way (5)
Asset retirement obligation
Commodities (6)
Purchase order commitments (7)
Commodities Purchase Commitments
Natural Gas (millions MMBtu)
NGL (millions of gallons)
$
1,534.7 $
427.8
52.0
12.9
20.4
37.5
98.1
63.5
(In millions)
- $
67.7
13.1
6.6
1.3
-
98.1
63.0
- $
189.7
16.5
6.3
2.4
-
-
0.5
854.6 $
118.8
9.7
-
2.1
-
-
-
680.1
51.6
12.7
-
14.6
37.5
-
-
$
2,246.9 $
249.8 $
215.4 $
985.2 $
796.5
9.3
56.3
9.3
56.3
-
-
-
-
-
-
81
_______
(1) Represents our scheduled future maturities of consolidated debt obligations for the periods indicated. See “Debt Obligations” included
under Note 9 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report for information regarding our
debt obligations.
(2) Represents interest expense on our debt obligations based on interest rates as of December 31, 2010 and the scheduled future
maturities of those debt obligations.
Includes minimum payments on lease obligations, service contracts, right-of-way agreement, with site leases and railcar leases.
(3)
(4) Consists of capacity payments for firm transportation contracts.
(5) Lease site and right-of-way expenses provide for surface and underground access for gathering, processing and distribution assets that
are located on property not owned by us; these agreements expire at various dates through 2099.
Includes natural gas and NGL purchase commitments.
(6)
(7) Consists of open purchase orders and Versado remediation projects.
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. See the description of our accounting policies in the notes to the financial
statements for additional information about our critical accounting policies and estimates.
Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s
cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment are depreciated
using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation
incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we
place our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop
that would cause us to change these assumptions, which would change our depreciation amounts prospectively.
Examples of such circumstances include:
• changes in energy prices;
• changes in competition;
• changes in laws and regulations that limit the estimated economic life of an asset
• changes in technology that render an asset obsolete;
• changes in expected salvage values; and
• changes in the forecast life of applicable resources basins.
As of December 31, 2010, the net book value of our property, plant and equipment was $2.5 billion and we
recorded $185.5 million in depreciation expense for the year ended December 31, 2010. The weighted average
life of our long-lived assets is approximately 20 years. 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. For
example, if the depreciable lives of our assets were reduced by 10%, we estimate that depreciation expense
would increase by $20.6 million per year, which would result in a corresponding reduction in our operating
income. In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, our
operating income would decrease by $25.1 million in the year of the impairment. There have been no material
changes impacting estimated useful lives of the assets.
Revenue Recognition. As of December 31, 2010, our balance sheet reflects total accounts receivable from third
parties of $466.6 million. We have recorded an allowance for doubtful accounts as of December 31, 2010 of
$7.9 million.
Our exposure to uncollectible accounts receivable relates to the financial health of its counterparties. We have
an active credit management process which is focused on controlling loss exposure to bankruptcies or other
liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of our
82
third-party accounts receivable, our annual operating income would decrease by $4.7 million in the year of the
assessment.
Price Risk Management (Hedging). Our net income and cash flows are subject to volatility stemming from
changes in commodity prices and interest rates. To reduce the volatility of our cash flows, the Partnership has
entered into (i) derivative financial instruments related to a portion of its equity volumes to manage the purchase
and sales prices of commodities and (ii) interest rate financial instruments to fix the interest rate on the
Partnership’s variable debt. We are exposed to the credit risk of the Partnership’s counterparties in these
derivative financial instruments. We also monitor NGL inventory levels with a view to mitigating losses related
to downward price exposure.
The Partnership’s cash flow is affected by the derivative financial instruments it enters into to the extent these
instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving
a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically
a derivative financial instrument is settled when the physical transaction that underlies the derivative financial
instrument occurs.
One of the primary factors that can affect our operating results each period is the price assumptions used to
value the Partnership’s derivative financial instruments, which are reflected at their fair values in the balance
sheet. The relationship between the derivative financial instruments 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 derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively
when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive
income 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 derivative financial instrument are reclassified to earnings immediately.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see “Significant Accounting Policies”
included under Note 4 to our “Unaudited Consolidated Financial Statements” beginning on page F-1 of this
Annual Report.
83
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The Partnership’s principal market risks are its 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. The
Partnership does not use risk sensitive instruments for trading purposes.
Commodity Price Risk. A majority of the Partnership’s revenues are derived from percent-of-proceeds contracts
under which it receives 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
hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. 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 primary purpose of the commodity risk management activities is to hedge the exposure to commodity price
risk and reduce fluctuations in the Partnership’s operating cash flow despite fluctuations in commodity prices. In
an effort to reduce the variability of the Partnership’s cash flows, as of December 31, 2010, the Partnership has
hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity
volumes that result from its percent of proceeds processing arrangements in Field Gathering and Processing, and
the LOU portion of the Coastal Gathering and Processing Operations through 2014 by entering into derivative
financial instruments including swaps and purchased puts (or floors). The percentages of expected equity
volumes that are hedged decrease over time. With swaps, the Partnership typically receive an agreed fixed price
for a specified notional quantity of natural gas or NGL and it pays the hedge counterparty a floating price for
that same quantity based upon published index prices. Since the Partnership receives from its 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, the Partnership typically limits
its use of swaps to hedge the prices of less than its expected natural gas and NGL equity volumes. The
Partnership utilizes purchased puts (or floors) to hedge additional expected equity commodity volumes without
creating volumetric risk. The Partnership intends to continue to manage its 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.
The Partnership has tailored its hedges to generally match the NGL product composition and the NGL and
natural gas delivery points to those of its physical equity volumes. The NGL hedges cover specific NGL
products 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.
The NGL hedges fair values are based on published index prices for delivery at Mont Belvieu through 2013,
except for the price of isobutane in 2012, which is based on the ending 2011 pricing. The natural gas hedges fair
values are based on published index prices for delivery at WAHA, Permian Basin and Mid-Continent, which
closely approximate the actual NGL and natural gas delivery points. A portion of the Partnership’s condensate
sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas
Intermediate light, sweet crude.
These commodity price hedging transactions are typically documented pursuant to a standard International
Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if
applicable, their guarantors) have investment grade credit ratings. The Partnership’s 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 its senior secured indebtedness that ranks equal in right of payment with liens granted
in favor of its senior secured lenders. As long as this first priority lien is in effect, the partnership expects to
have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time,
even if the counterparty’s exposure to the Partnership’s credit increases over the term of the hedge as a result of
higher commodity prices or because there has been a change in the Partnership’s creditworthiness.
For all periods presented we entered into hedging arrangements for a portion of our forecasted equity volumes.
Floor volumes and floor pricing are based solely on purchased puts (or floors). During 2010, 2009 and 2008, our
operating revenues were increased (decreased) by net hedge adjustments of $8.4 million, $69.7 million and
$(65.1) million.
84
As of December 31, 2010, our commodity derivative arrangements were as follows:
Natural Gas
Instrument
Price
MMBtu per day
Type
Index
$/MMBtu
2011
2012
2013
Fair Value
(In millions)
Swap
Swap
Swap
Total Swaps
Swap
Swap
Swap
Total Swaps
Swap
Swap
Total Swaps
IF-WAHA
IF-WAHA
IF-WAHA
IF-PB
IF-PB
IF-PB
IF-NGPL MC
IF-NGPL MC
6.29
6.61
5.59
5.42
5.54
5.54
6.87
6.82
-
-
-
-
- $
-
-
-
23,750
-
14,850
-
4,000
23,750
14,850
4,000
2,000
-
4,000
-
4,000
2,000
4,000
4,000
4,350
-
-
4,250
4,350
4,250
-
-
-
30,100
23,100
8,000
16.9
9.6
0.8
0.8
1.1
0.8
4.1
3.1
Natural Gas Basis Swaps
Basis Swaps
Various Indexes, Maturities January 2011-May 2011
$
(0.4)
36.8
Instrument
Type
Index
OPIS_MB
OPIS_MB
OPIS_MB
OPIS_MB
OPIS_MB
Swap
Swap
Swap
Total Swaps
Floor
Floor
Total Floors
Total Sales
Price
$/Gal
0.85
0.85
0.92
1.44
1.43
NGL
Barrels per day
2011
2012
2013
Fair Value
(In millions)
(18.0)
(6.6)
(4.0)
0.8
1.3
$
(26.5)
8,550
-
- $
-
6,700
-
-
-
3,400
8,550
6,700
3,400
253
-
253
-
294
294
-
-
-
8,803
6,994
3,400
85
Instrument
Type
Index
Price
$/Bbl
Condensate
Barrels per day
2011
2012
2013
2014
Fair Value
Swap
Swap
Swap
Swap
Total Sales
NY-WTI
NY-WTI
NY-WTI
NY-WTI
80.37
82.25
81.82
90.03
1,100
-
-
-
-
950
-
-
1,100
950
-
-
800
-
800
$
-
-
-
700
700
(In millions)
(5.4)
(4.0)
(3.1)
(0.6)
$
(13.1)
These contracts may expose the Partnership to the risk of financial loss in certain circumstances. Its hedging
arrangements provide 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 they have been hedged, the Partnership will receive less revenue
on the hedged volumes than it would receive in the absence of hedges.
The Partnership accounts for the fair value of our financial assets and liabilities using a three-tier fair value
hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1,
defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than
quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as
unobservable inputs in which little or no market data exists, therefore required an entity to develop its own
assumptions. The value of the NGL derivative contracts is determined utilizing a discounted cash flow model
for swaps and a standard option pricing model for options, based on inputs that are either readily available in
public markets or are quoted by counterparties to these contracts. Prior to 2009, all of the NGL contracts were
classified as Level 3 within the hierarchy. In 2009, we were able to obtain inputs from quoted prices related to
certain of these commodity derivatives for similar assets and liabilities in active markets. These inputs are
observable for the asset or liability, either directly or indirectly, for the full term of the commodity swaps and
options. For the NGL contracts that have inputs from quoted prices, the classification of these instruments
changed from Level 3 to Level 2 within the fair value hierarchy. For those NGL contracts where we were unable
to obtain quoted prices for the full term of the commodity swap and options, the NGL valuations are still
classified as Level 3 within the fair value hierarchy.
Interest Rate Risk We are exposed to changes in interest rates, primarily as a result of variable rate borrowings
under Targa and the Partnership’s senior secured revolving credit facilities. To the extent that interest rates
increase, interest expense for our revolving debt will also increase. As of December 31, 2010, we have variable
rate borrowings of $89.3 million and the Partnership has variable interest rate borrowings of $765.3 million. In
an effort to reduce the variability of our cash flows, the Partnership has entered into several interest rate swap
and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges,
the base interest rate on the specified notional amount of the Partnership’s variable rate debt is effectively fixed
for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair
values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty
for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the
interest rate swaps are recorded in accumulated other comprehensive income (“OCI”) until the interest expense
on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying
interest rate, after taking into account our interest rate swaps, would increase our consolidated interest expense
by $5.5 million.
86
As of December 31, 2010, the Partnership had the following open interest rate swaps:
Period
Fixed Rate
Notional
Amount
Fair
Value
2011
2012
2013
2014
3.52%
3.40%
3.39%
3.39%
$
($ in millions)
300 $
300
300
300
$
(7.8)
(7.5)
(4.0)
(0.8)
(20.1)
Credit Risk. The Partnership is subject to risk of losses resulting from nonpayment or nonperformance by its
counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value
of contracts with these derivative instruments being in a net asset position at the reporting date. At such times,
these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to
the agreements. Should the creditworthiness of one or more of the counterparties decline, the Partnership’s
ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination
and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a
counterparty default, the Partnership may sustain a loss and its cash receipts could be negatively impacted.
As of December 31, 2010, the Partnership had counterparty credit exposure related to commodity derivatives
with affiliates of Barclays, Credit Suisse, and BP which accounted for 62%, 13% and 12%, respectively, of the
Partnership’s counterparty credit exposure related to commodity derivative instruments. Barclays, and Credit
Suisse are major financial institutions and BP is a major oil and gas company. These entities possess investment
grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.
87
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 Annual Report.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Management, under the supervision of and with the participation of our Chief Executive Officer and Chief
Financial Officer, has evaluated the design and 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 in this Annual Report. Based on such evaluation, our Chief
Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2010 our disclosure
controls and procedures were designed at the reasonable assurance level and, as of the end of the period covered
in this Annual Report, our disclosure controls and procedures are effective at the reasonable assurance level to
provide that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i)
recorded, processed, summarized and reported within the time periods specified in the rules and forms of the
Securities and Exchange Commission and (ii) accumulated and communicated to management, including our
principal executive officer and principal financial officer, to allow for timely decisions regarding required
disclosure.
Internal Control Over Financial Reporting
(a) Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting,
as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Management, including the Chief
Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the internal
control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, management
concluded that the internal control over financial reporting was effective as of December 31, 2010 as stated in its
report included in our consolidated financial statements on page F-2 of this Annual Report, which is
incorporated herein by reference.
(b) Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2010, there were no changes in our internal control over financial
reporting that have materially affected or are reasonably likely to materially affect, our internal control over
financial reporting.
Item 9B. Other Information
None.
88
Item 10. Directors, Executive Officers and Corporate Governance
Part III
Our executive officers listed below serve in the same capacity for the General Partner and devote their time as
needed to conduct the business and affairs of both the Company and the Partnership. Because our only cash-
generating assets are direct and indirect partnership interests in the Partnership, we expect that our executive
officers will devote a substantial majority of their time to the Partnership’s business. We expect the amount of
time that our executive officers devote to our business as opposed to the Partnership’s business in future periods
will not be substantial unless significant changes are made to the nature of our business.
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. There are
no family relationships among any of our directors or executive officers. Please read “Certain Relationships and
Related Transactions—Stockholders’ Agreement” for a discussion of arrangements among our stockholders
pursuant to which our directors were selected prior to our IPO. The following table sets forth certain information
with respect to our directors, executive officers and other officers as of February 25, 2011.
Name
Rene R. Joyce
Joe Bob Perkins
James W. Whalen
Jeffrey J. McParland
Roy E. Johnson
Michael A. Heim
Paul W. Chung
Matthew J. Meloy
John R. Sparger
Charles R. Crisp
In Seon Hwang
Peter R. Kagan
Chris Tong
Ershel C. Redd Jr.
Age
Position
63 Chief Executive Officer and Director
50 President
69 Executive Chairman and Director
56 President-Finance and Administration
66 Executive Vice President
62 Executive Vice President and Chief Operating Officer
50 Executive Vice President, General Counsel and Secretary
33 Senior Vice President and Chief Financial Officer
57 Senior Vice President and Chief Accounting Officer
63 Director
34 Director
42 Director
54 Director
63 Director
Rene R. Joyce has served as a director and Chief Executive Officer of Targa Resources Corp. (the “Company”)
since its formation on October 27, 2005, of the General Partner since October 2006 and of TRI Resources Inc.
(“TRI”) since its formation in February 2004 and was a consultant for the TRI predecessor company during
2003. 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
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. As the founding Chief Executive Officer of TRI, Mr. Joyce brings
deep experience in the midstream business, expansive knowledge of the oil and gas industry, as well as
relationships with chief executives and other senior management at peer companies, customers and other oil and
natural gas companies throughout the world. His experience and industry knowledge, complemented by an
engineering and legal educational background, enable Mr. Joyce to provide the board with executive counsel on
the full range of business, technical, and professional matters.
Joe Bob Perkins has served as President of the Company since its formation on October 27, 2005, of the
General Partner since October 2006 and of TRI since February 2004 and was a consultant for the TRI
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, of Houston Industries from 1996 to 1998. He
89
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 Executive Chairman of the Company’s board of directors since October 25,
2010 and the General Partner’s board of directors since December 15, 2010. He served as a director of the
Company since its formation on October 27, 2005, of the General Partner since February 2007 and of TRI since
2004. Mr. Whalen served as President-Finance and Administration of the Company and of TRI between January
2006 and October 25, 2010. He has served as President-Finance and Administration of the General Partner since
October 2006 and for various Targa subsidiaries since November 2005. 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 brings a breadth and
depth of experience as an executive, board member, and audit committee member across several different
companies and in energy and other industry areas. His valuable management and financial expertise includes an
understanding of the accounting and financial matters that the Partnership and industry address on a regular
basis.
Roy E. Johnson has served as Executive Vice President of the Company since its formation on October 27,
2005, of the General Partner since October 2006 and of TRI since April 2004 and was a consultant for the TRI
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 the Company since its
formation on October 27, 2005, of the General Partner since October 2006 and of TRI since April 2004 and was
a consultant for the TRI 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 Coastal’s 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 President — Finance and Administration of the Company and TRI since
October 25, 2010 and of the General Partner since December 15, 2010. He has also served as a director of TRI
since December 16, 2010. Mr. McParland served as Executive Vice President and Chief Financial Officer of the
Company between October 27, 2005 and October 25, 2010 and of TRI between April 2004 and October 25,
2010 and was a consultant for the TRI predecessor company during 2003. He served as Executive Vice
President and Chief Financial Officer of the General Partner between October 2006 and December 15, 2010 and
served as a director of the General Partner from October 2006 to February 2007. Mr. McParland served as
Treasurer of the Company from October 27, 2005 until May 2007, of the General Partner from October 2006
until May 2007 and of TRI from April 2004 until May 2007. Mr. McParland served as Secretary of TRI
between February 2004 and 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
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 the Company since
its formation on October 27, 2005, of the General Partner since October 2006 and of TRI since May 2004. Mr.
90
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.
Matthew J. Meloy has served as Senior Vice President, Chief Financial Officer and Treasurer of the Company
and TRI since October 25, 2010 and of the General Partner since December 15, 2010. Mr. Meloy served as Vice
President — Finance and Treasurer of the Company and TRI between March 2008 and October 2010, and as
Director, Corporate Development of the Company and TRI between March 2006 and March 2008 and of the
General Partner between October 2006 and March 2008. He served as Vice President — Finance and Treasurer
of the General Partner between March 2008 and December 15, 2010. Mr. Meloy was with The Royal Bank of
Scotland in the structured finance group, focusing on the energy sector from October 2003 to March 2006, most
recently serving as Assistant Vice President.
John R. Sparger has served as Senior Vice President and Chief Accounting Officer of the Company and TRI
since January 2006 and of the General Partner since October 2006. Mr. Sparger served as Vice President,
Internal Audit of the Company between October 2005 and January 2006 and of TRI between November 2004
and January 2006. Mr. Sparger served as a consultant in the energy industry from 2002 through September
2004, including TRI between February 2004 and September 2004, providing advice to various energy
companies and entities regarding processes, systems, accounting and internal controls. Prior to 2002, he worked
in various accounting and administrative positions with companies in the energy industry, audit and consulting
positions in public accounting and consulting positions with a large international consulting firm.
Charles R. Crisp has served as a director of the Company since its formation on October 27, 2005 and of TRI
between February 2004 and December 16, 2010. Mr. Crisp was President and Chief Executive Officer of Coral
Energy, LLC, a subsidiary of Shell Oil Company from 1999 until his retirement in November 2000, and was
President and Chief Operating Officer of Coral from January 1998 through February 1999. Prior to this, Mr.
Crisp served as President of the power generation group of Houston Industries and, between 1988 and 1996, as
President and Chief Operating Officer of Tejas. Mr. Crisp is also a director of AGL Resources Inc., EOG
Resources Inc. and Intercontinental Exchange, Inc. Mr. Crisp brings extensive energy experience, a vast
understanding of many aspects of our industry and experience serving on the boards of other public companies
in the energy industry. His leadership and business experience and deep knowledge of various sectors of the
energy industry bring a crucial insight to the board of directors.
In Seon Hwang has served as a director of the Company since May 2006, of TRI between May 2006 and
December 16, 2010, and of the General Partner since February 2011. Mr. Hwang is a Member and Managing
Director of Warburg Pincus LLC and a general partner of Warburg Pincus & Co., where he has been employed
since 2004, and became a partner of Warburg Pincus & Co. in 2009. Prior to joining Warburg Pincus, Mr.
Hwang worked at GSC Partners, a distressed investment firm, from 2002 until 2004, the M&A group at
Goldman Sachs from 1998 to 2000, and the Boston Consulting Group from 1997 to 1998. He is also a director
of Competitive Power Ventures and serves on the investment committee of Sheridan Production Partners LLC.
Mr. Hwang serves as a director because certain investment funds managed by Warburg Pincus LLC, for whom
Mr. Hwang is a managing director and member, control us through their ownership of securities in Targa
Resources Corp. Mr. Hwang has significant experience with energy companies and investments and broad
familiarity with the industry and related transactions and capital markets activity, which enhance his
contributions to the board of directors.
Peter R. Kagan has served as a director of the Company since its formation on October 27, 2005, of the General
Partner since February 2007 and of TRI between February 2004 and December 16, 2010. Mr. Kagan is a
member and Managing Director of Warburg Pincus LLC and a general partner of Warburg Pincus & Co., 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, Canbriam Energy, Fairfield Energy Limited, Laredo Petroleum and MEG Energy Corp. Mr. Kagan
serves as a director because certain investment funds managed by Warburg Pincus LLC, for whom Mr. Kagan is
a managing director and member, control us through their ownership of securities in Targa Resources Corp. Mr.
Kagan has significant experience with energy companies and investments and broad familiarity with the
industry and related transactions and capital markets activity, which enhance his contributions to the board of
directors.
91
Chris Tong has served as a director of the Company since January 2006 and of TRI between January 2006 and
December 16, 2010. Mr. Tong is a director of Cloud Peak Energy Inc. and Kosmos Energy Holdings. He served
as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August
2009. He also served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc.
from August 1997 until December 2004. Prior thereto, he was Senior Vice President of Finance of Tejas
Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and
Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these
positions from August 1996 until August 1997, and had served in other treasury positions with Tejas since
August 1989. Mr. Tong brings a breadth and depth of experience as a chief financial officer in the energy
industry, a financial executive, a director of another public company and member of another audit committee.
He brings significant financial, capital markets and energy industry experience to the board and in his position
as the chairman of our Audit Committee.
Ershel C. Redd Jr. has served as a director of the Company since February 2011. Mr. Redd has served as a
consultant in the energy industry since 2008 providing advice to various energy companies and investors
regarding their operations, acquisitions and dispositions. Mr. Redd was President and Chief Executive Officer of
El Paso Electric Company, a public utility company, from May 2007 until March 2008. Prior to this, Mr. Redd
served in various positions with NRG Energy, Inc., a wholesale energy company, including as Executive Vice
President – Commercial Operations from October 2002 through July 2006, as President – Western Region from
February 2004 through July 2006, and as a director between May 2003 and December 2003. On May 14, 2003,
NRG filed for protection under Chapter 11 of the Federal Bankruptcy Code. On November 24, 2003, NRG's
Chapter 11 Plan of Reorganization was confirmed. Mr. Redd served as Vice President of Business Development
for Xcel Energy Markets, a unit of Xcel Energy Inc., from 2000 through 2002, and as President and Chief
Operating Officer for New Century Energy’s (predecessor to Xcel Energy Inc.) subsidiary, Texas Ohio Gas
Company, from 1997 through 2000. Mr. Redd brings to the Company extensive energy industry experience, a
vast understanding of varied aspects of the energy industry and experience in corporate performance, marketing
and trading of natural gas and natural gas liquids, risk management, finance, acquisitions and divestitures,
business development, regulatory relations and strategic planning. His leadership and business experience and
deep knowledge of various sectors of the energy industry bring a crucial insight to the board of directors.
Board of Directors
Our board of directors consists of seven members. The board reviewed the independence of our directors using
the independence standards of the NYSE and, based on this review, determined that Messrs. Crisp, Hwang,
Kagan, Redd and Tong are independent within the meaning of the NYSE listing standards currently in effect.
Our directors are divided into three classes serving staggered three-year terms. Class I, Class II and Class III
directors will serve until our annual meetings of stockholders in 2011, 2012 and 2013, respectively. The Class I
directors are Messrs. Crisp and Whalen, the Class II directors are Messrs. Redd and Hwang and the Class III
directors are Messrs. Kagan, Tong and Joyce. At each annual meeting of stockholders, directors will be elected
to succeed the class of directors whose terms have expired. This classification of our board of directors could
have the effect of increasing the length of time necessary to change the composition of a majority of the board
of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect
a change in a majority of the members of the board of directors.
Committees of the Board of Directors
Our board of directors has four standing committees - an Audit Committee, a Compensation Committee, a
Nominating and Governance Committee and a Conflicts Committee - and may have such other committees as
the board of directors shall determine from time to time. Each of the standing committees of the board of
directors has the composition and responsibilities described below.
Audit Committee
The members of our Audit Committee are Messrs. Tong, Redd and Crisp. Mr. Tong is the Chairman of this
committee. Our board of directors has affirmatively determined that Messrs. Crisp, Redd, and Tong are
independent as described in the rules of the NYSE and the Securities Exchange Act of 1934, as amended (the
“Exchange Act”). Our board of directors has also determined that, based upon relevant experience, Mr. Tong is
an “audit committee financial expert” as defined in Item 407 of Regulation S-K of the Exchange Act. We will
rely on the phase-in rules of the SEC and NYSE with respect to the independence of our Audit Committee.
92
This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board
of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be
paid to the independent accountants, the performance of our independent accountants and our accounting
practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory
requirements. We have adopted an Audit Committee charter defining the committee’s primary duties in a
manner consistent with the rules of the SEC and NYSE or market standards.
Compensation Committee
The members of our Compensation Committee are Messrs. Kagan, Crisp and Hwang. Mr. Crisp is the Chairman
of this committee. This committee establishes salaries, incentives and other forms of compensation for officers
and other employees. Our Compensation Committee also administers our incentive compensation and benefit
plans. We have adopted a Compensation Committee charter defining the committee’s primary duties in a
manner consistent with the rules of the SEC and NYSE or market standards.
Nominating and Governance Committee
The members of our Nominating and Governance Committee are Messrs. Kagan, Redd and Tong. Mr. Kagan is
the Chairman of this committee. This committee identifies, evaluates and recommends qualified nominees to
serve on our board of directors, develops and oversees our internal corporate governance processes and
maintains a management succession plan. We have adopted a Nominating and Governance Committee charter
defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market
standards.
In evaluating the director candidates, the Nominating and Governance Committee assesses whether a candidate
possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the
board’s ability to manage and direct the affairs and business of the Company, including, when applicable, to
enhance the ability of committees of the board to fulfill their duties.
Conflicts Committee
The members of our Conflicts Committee are Messrs. Crisp, Redd and Tong. Mr. Tong is the Chairman of this
committee. This Committee reviews matters of potential conflicts of interest, as directed by our board of
directors. We adopted a Conflicts Committee charter defining the committee’s primary duties.
Code of Business Conduct and Ethics
Our board of directors has adopted a Code of Ethics For Chief Executive Officer and Senior Financial Officers
(the “Code of Ethics”), which applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting
Officer, Controller and all of our other senior financial and accounting officers, and TRI Resources Inc.’s Code
of Conduct (the “Code of Conduct”), which applies to officers, directors and employees of TRI Resources Inc.
and its subsidiaries. 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 or Code of Conduct under Item
5.05 of a current report on Form 8-K.
Available Information
We make available, free of charge within the “Corporate Governance” section of our website at
www.targaresources.com and in print to any stockholder who so requests, our Corporate Governance
Guidelines, Code of Ethics, Code of Conduct, Audit Committee Charter, Compensation Committee charter and
Nominating and Governance Committee charter. Requests for print copies may be directed to: Investor
Relations, Targa Resources Corp., 1000 Louisiana, Suite 4300, Houston, Texas 77002 or made by telephone by
calling (713) 584-1000. The information contained on or connected to, our internet website is not incorporated
by reference into this Annual Report and should not be considered part of this or any other report that we file
with or furnish to the SEC.
93
Corporate Governance Guidelines
Our board of directors has adopted corporate governance guidelines in accordance with the corporate
governance rules of the NYSE.
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 2010, all of our directors, executive officers and
beneficial owners of more than 10% of our common units complied with Section 16(a) filing requirements
applicable to them.
94
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 management’s expectations or estimates of results
or other guidance.
Overview
Prior to our initial public offering (the “IPO”) in December 2010, under the terms of our Amended and Restated
Stockholders’ Agreement, as amended (the “Stockholders’ Agreement”), that was in effect until the closing of
the IPO , compensatory arrangements with our executive officers identified in the Summary Compensation
Table (“named executive officers”) were required to be submitted to a vote of our stockholders unless such
arrangements were approved by the Compensation Committee (the “Compensation Committee”) of our board of
directors. As such, the Compensation Committee was responsible for overseeing the development of an
executive compensation philosophy, strategy, framework and individual compensation elements for our named
executive officers that were based on our business priorities.
The Stockholders’ Agreement terminated upon completion of the IPO. Compensatory arrangements with our
named executive officers remain the responsibility of our Compensation Committee.
The following Compensation Discussion and Analysis describes the material elements of compensation for our
named executive officers as determined by the Compensation Committee.
Compensation Philosophy
The Compensation Committee believes that total compensation of executives should be competitive with the
market in which we compete for executive talent which encompasses not only midstream natural gas companies,
but also other energy industry companies as described in “The Role of Peer Groups and Benchmarking” below.
The following compensation objectives guide the 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;
• provide compensation for performance that reflects individual and company performance both in
absolute terms and relative to 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.
Consistent with this philosophy and compensation objectives, 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 President — Finance and Administration (collectively,
“Senior Management”) review compensation practices at peer companies, as well as broader industry
compensation practices, at a general level and by individual position to ensure that our total compensation is
reasonably comparable to industry practice and meets our compensation objectives. In addition, when evaluating
compensation levels for each named executive officer, the Compensation Committee reviews publicly available
95
compensation data for executives in our peer group, compensation surveys and compensation levels for each
named executive officer with respect to their roles and levels of responsibility, accountability and decision-
making authority. Although Senior Management and the Compensation Committee consider compensation data
from other companies, they do not attempt to set compensation components to meet specific benchmarks, such
as salaries “above the median” or total compensation “at the 50th percentile.” The peer company data that is
reviewed by Senior Management and the Compensation Committee is simply one factor out of many that is
used in connection with the establishment of the compensation for our officers. The other factors considered by
Senior Management and the Compensation Committee include, but are not limited to, (i) available
compensation data about rankings and comparisons, (ii) effort and accomplishment on a group basis,
(iii) challenges faced and challenges overcome, (iv) unique skills, (v) contribution to the management team and
(vi) the perception of both the board of directors and the Compensation Committee of performance relative to
expectations, actual market/business conditions and peer company performance. All of these factors, including
peer company data, are utilized in a subjective assessment of each year’s decisions relating to annual cash
incentives, long-term incentives and base compensation changes with a view towards total compensation and
pay-for-performance.
As part of the annual review process conducted in 2009 for 2010 compensation, Senior Management identified
peer companies in the midstream energy industry and reviewed compensation information filed by the peer
companies with the SEC. The peer group reviewed by Senior Management and the Compensation Committee
for 2010 consisted of the following companies: Atlas Pipeline Partners, L.P., Copano Energy L.L.C., Crosstex
Energy, L.P., DCP Midstream Partners LP, Enbridge Energy Partners LP, Energy Transfer Partners, LP,
Magellan Midstream Partners LP, MarkWest Energy Partners, LP, Martin Midstream Partners, NuStar Energy,
ONEOK Partners, LP, Plains All American Pipeline Partners, LP, Regency Energy Partners LP, TEPPCO
Partners and Williams Partners LP. During the second quarter of 2010, following its initial review relating to
2010 compensation, the Compensation Committee engaged BDO USA, LLP (“BDO”), a compensation
consultant, to conduct a new review of executive and key employee compensation to help it assure that
compensation goals were being met and that the most recent trends in compensation were appropriately
considered. In this additional review process, the peer companies were reassessed to determine whether the peer
groups for long-term cash incentive awards (performance units) and for compensation comparison and analysis
remained appropriate and adequately reflected the market for executive talent. As a result, the peer group used
for long-term cash incentive awards and for compensation comparison was expanded and weighted to include
energy companies other than midstream master limited partnerships (“MLPs”) to better reflect the market for
executive talent in the energy industry. Because many companies in the expanded peer group are larger than the
Company as measured by market capitalization and total assets, with the assistance of BDO, compensation data
for the peer companies was analyzed using multiple regression analysis to develop a prediction of the total
compensation that peer companies of comparable size to the Company would offer similarly-situated
executives. This regressed data was then weighted as follows to develop a reference point for judging the
adequacy of executive pay at the Company: MLPs (given a 70% weighting), exploration and production
companies (“E&Ps”) (given a 15% weighting) and utility companies (given a 15% weighting). The peer group
companies in each of the three categories are:
• MLP peer companies: Atlas Pipeline Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, LP,
DCP Midstream Partners, LP, Enbridge Energy Partners LP, Energy Transfer Partners, LP, Enterprise
Products Partners LP, Magellan Midstream Partners, LP, MarkWest Energy Partners, LP, NuStar
Energy LP, ONEOK Partners, LP, Regency Energy Partners LP and Williams Partners LP
• E&P peer companies: Cabot Oil & Gas Corp., Cimarex Energy Co., Denbury Resources Inc., EOG
Resources Inc., Murphy Oil Corp., Newfield Exploration Co., Noble Energy Inc., Penn Virginia Corp.,
Petrohawk Energy Corp., Pioneer Natural Resources Co., Southwestern Energy Co. and Ultra
Petroleum Corp.
• Utility peer companies: Centerpoint Energy Inc., El Paso Corp., Enbridge Inc., EQT Corp., National
Fuel Gas Co., NiSource Inc., ONEOK Inc., Questar Corp., Sempra Energy, Spectra Energy Co.,
Southern Union Co. and Williams Companies Inc.
Senior Management and the Compensation Committee review our compensation practices and performance
against peer companies on at least an annual basis.
96
Role of Senior Management in Establishing Compensation for Named Executive Officers
Typically, Senior Management consults with BDO, the compensation consultant engaged by the Compensation
Committee, 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 emerging conclusions and later a proposal to the chairman of the 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 Compensation
Committee reviews and discusses the proposal with Senior Management and the consultant and may discuss it
with the other members of the Compensation Committee, other board members, or the full boards of the
Company and Targa Resources GP LLC and may request that Senior Management provide him with additional
information or reconsider their proposal. The resulting recommendation is then submitted to the Compensation
Committee for consideration, which also meets separately with the compensation consultant. The final
compensation decisions are reported to the Board.
Our Senior Management has no other role in determining compensation for our named 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
Our compensation philosophy for executive officers emphasizes our executives having a significant long-term
equity stake. For this reason, in connection with TRI Resources Inc.’s formation in 2004 and with our
acquisition of Dynegy Midstream Services, Limited Partnership from Dynegy, Inc. in 2005, the named
executive officers were granted restricted stock and options to purchase restricted stock to attract, motivate and
retain our executive team. In connection with the IPO, the named executive officers were granted additional
shares of bonus stock as an additional recognition for past performance and positioning to this point in time and
restricted stock as one-time retention and incentive awards in connection with our transition from a private to a
public company. Both of these equity awards align our executive officers interests with those of stockholders.
Our executive officers have also invested a significant portion of their personal investable assets in our equity
and have made significant investments in the equity of the Partnership. With these equity interests as context,
elements of compensation for our named executive officers are the following: (i) annual base salary;
(ii) discretionary annual cash awards; (iii) performance awards under our long-term incentive plan, (iv) awards
under our new stock incentive plan; (v) contributions under our 401(k) and profit sharing plan; and
(vi) 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
Compensation Committee. The salaries are intended to provide fixed compensation based on historical salaries
paid to our named executive officers for services rendered to us, market data on compensation paid to similarly
situated executives and responsibilities and performance of our named executive officers.
Annual Cash Incentives. The discretionary annual cash awards available to our named executive officers provide
an opportunity to supplement the annual base salary of our named executive officers so that, on a combined
basis, the annual cash compensation opportunity for our named executive officers yields competitive cash
compensation levels and drives performance in support of our business strategies. It is our general policy to pay
these awards prior to the end of the first quarter of the fiscal year following the fiscal year to which they related.
The payment of individual cash bonuses to executive management, including our named executive officers, is
subject to the sole discretion of the Compensation Committee.
The discretionary annual cash awards are designed to reward our employees for contributions towards our
achievement of financial and operational business priorities (including business priorities of the Partnership)
approved by the Compensation Committee and to aid us in retaining and motivating employees. These priorities
are not objective in nature—they are subjective and performance in regard to these priorities is ultimately
evaluated by the Compensation Committee in its sole discretion. The approach taken by the Compensation
Committee in reviewing performance against the priorities is along the lines of grading a multi-faceted essay
rather than a simple true/false exam. As such, success does not depend on achieving a particular target; rather,
success is determined based on past norms, expectations and unanticipated obstacles or opportunities that arise.
For example, hurricanes and deteriorating market conditions may alter the priorities initially established by the
Compensation Committee such that certain performance that would otherwise be deemed a negative may, in
context, be a positive result. This subjectivity allows the Compensation Committee to account for the full
97
industry and economic context of our actual performance or that of our personnel. The Compensation
Committee considers all strategic priorities and reviews performance against the priorities but does not assign
specific weightings to the strategic priorities in advance.
Under plans to pay a discretionary annual cash award that have been adopted and may be adopted in subsequent
years, funding of a discretionary cash bonus pool is expected to be recommended by our Senior Management
and approved by the Compensation Committee annually based on our achievement of certain strategic, financial
and operational objectives. Such plans are and will be approved by the Compensation Committee, which
considers certain recommendations by our Senior Management. Near or following the end of each year, Senior
Management recommends to the 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 our Senior Management’s
recommendation, the Compensation Committee, in its sole discretion, determines the total amount of cash to be
allocated to the bonus pool. Additionally, the 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 our departments, groups and employees (other
than our executive officers) based on performance and on the recommendation of their supervisors, managers
and line officers.
Stock Option Grants. Under our 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 2,536,969 shares of our
restricted stock may be granted to our employees, directors and consultants. No option awards have been
granted to the named executive officers since 2005 under the 2005 Incentive Plan and option awards that were
previously granted to our named executive officers under the 2005 Incentive Plan and that were outstanding
upon the closing of the IPO were surrendered and cancelled. We will no longer make grants under the 2005
Incentive Plan.
Restricted Stock Grants. Under the 2005 Incentive Plan, up to 3,586,236 shares of our restricted stock may be
granted to our employees, directors and consultants. No restricted stock awards have been granted to the named
executive officers under the 2005 Stock Incentive Plan since 2005. We will no longer make grants under the
2005 Incentive Plan.
New Incentive Plan. In connection with the IPO, we adopted the 2010 Stock Incentive Plan (the “2010
Incentive Plan”) under which we may grant to the named executive officers, other key employees, consultants
and directors certain awards, including restricted stock and performance awards. The 2010 Incentive Plan
provides for discretionary grants of the following types of awards: (a) incentive stock options qualified as such
under U.S. federal income tax laws, (b) stock options that do not qualify as incentive stock options, (c) phantom
stock awards, (d) restricted stock awards, (e) performance awards, (f) bonus stock awards, or (g) any
combination of such awards. The maximum aggregate number of shares of our common stock that may be
granted in connection with awards under the 2010 Incentive Plan is 5 million, of which approximately 1.9
million shares were awarded in connection with our IPO. A restricted stock award is a grant of shares of
common stock subject to a risk of forfeiture, restrictions on transferability, and any other restrictions imposed by
the Compensation Committee in its discretion. Except as otherwise provided under the terms of the 2010
Incentive Plan or an award agreement, the holder of a restricted stock award may have rights as a stockholder,
including the right to vote or to receive dividends (subject to any mandatory reinvestment or other requirements
imposed by the Compensation Committee). A restricted stock award that is subject to forfeiture restrictions may
be forfeited and reacquired by us upon termination of employment or services. Common stock distributed in
connection with a stock split or stock dividend, and other property distributed as a dividend, may be subject to
the same restrictions and risk of forfeiture as the restricted stock with respect to which the distribution was
made. Bonus stock awards under the 2010 Incentive Plan are awards of our common stock. These awards are
granted on such terms and conditions and at such purchase price (if any) determined by the Compensation
Committee and need not be subject to performance criteria, objectives, or forfeiture. Additional details relating
to shares of restricted stock and bonus stock granted under the 2010 Incentive Plan are included below under
“—Application of Compensation Elements—Equity Ownership” and “—Executive Compensation Tables—
Outstanding Equity Awards at 2010 Fiscal Year-End.”
LTIP Awards. We may grant to the named executive officers and other key employees performance unit awards
linked to the performance of the Partnership’s common units, with the amounts vesting under such awards
dependent on the Partnership’s performance compared to a peer-group consisting of the Partnership and 12 other
publicly traded partnerships. These awards, which may be settled in cash or equity, are designed to further align
the interests of the named executive officers and other key employees with those of the Partnership’s equity
98
holders. Additional details relating to our peer group applicable to LTIP awards payouts are included below
under “—Application of Compensation Elements—Long-Term Cash Incentives.”
Retirement Benefits. We offer eligible employees a Section 401(k) tax-qualified, defined contribution plan (the
“401(k) Plan”) to enable employees to save for retirement through a tax-advantaged combination of employee
and 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
of 1986, as amended (the “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 employee’s eligible
compensation; and (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the
employee’s eligible compensation. We may also make discretionary contributions to the 401(k) Plan for the
benefit of employees depending on our 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 Compensation Committee’s 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 6.9 of our fully diluted equity. Based on our named executive
officers’ ownership interests in us and their direct ownership of the Partnership’s common units, they own,
directly and indirectly, approximately 0.9% of the Partnership’s limited partner interests. The Compensation
Committee believes that the elements of its compensation program fit the established overall compensation
objectives in the context of management’s substantial ownership of our equity, which allows us to provide
competitive compensation opportunities to align and drive the performance of the named executive officers in
support of our and the Partnership’s business strategies and to attract, motivate and retain high quality talent
with the skills and competencies required by us and the Partnership.
Application of Compensation Elements
Equity Ownership. Historically, we have used both stock options and restricted stock to compensate our
employees, including our named executive officers. Based on recommendations by our compensation consultant
after completing the second quarter compensation review, we currently expect the Compensation Committee’s
awards under the 2010 Incentive Plan to consist primarily of restricted stock and performance awards rather
than stock options. In addition, we expect the Compensation Committee’s awards under our long term incentive
plan to consist of performance based restricted stock and cash-settled performance units. In connection with the
IPO, our employees, including the named executive officers, were granted an aggregate of approximately
1.9 million shares of restricted stock and bonus stock under the 2010 Incentive Plan. Of these initial awards, our
named executive officers were granted shares of restricted stock and bonus stock as follows: (i) with respect to
restricted
stock: Mr. Joyce—121,125 shares; Mr. Perkins—67,980 shares; Mr. Whalen—67,980 shares;
Mr. Heim—60,885 shares; Mr. McParland—56,100 shares; and Mr. Meloy —22,425 shares and (ii) with
stock: Mr. Joyce—122,439 shares; Mr. Perkins—106,200 shares; Mr. Whalen—
respect
106,200 shares; Mr. Heim—61,825 shares; and Mr. McParland—87,642 shares. The restricted stock awards
have vesting restrictions. The restricted stock awards ((i) above) to executive officers and other key employees
were made based upon the recommendation of BDO using market-based precedent and market-based amounts
to provide a one-time retention and incentive award in connection with our transition from a private to a public
company. The awards to the executive officers were established using a market-based multiple of 3X annual
target long-term incentive compensation for each individual. BDO concluded that at the proposed 3X annual
target long-term incentive level, the awards for executive management were of lesser value than grants awarded
to senior executives in connection with other recent industry transactions over the last three years and that the
value of the overall program available to executive officers would fall in a range between the 50th and
75th percentile of the expanded peer group over the next three years. The comparable transactions included the
merger of MarkWest Hydrocarbons with MarkWest Energy Partners, L.P., the acquisition of the controlling
bonus
to
99
interest of Buckeye GP Holding by BGHGP Holdings, LLC, the merger of Inergy L.P. and Inergy LP Holdings,
the acquisition of Genesis Energy’s general partner from Denbury Resources by Quintana Energy Investor
Group and transactions involving Precision Drilling, Apache, RRI Energy, Approach Resources, Concho
Resources, Encore Energy Partners, and Vanguard Natural Resources. The bonus stock awards ((ii) above) were
fully vested on the date of grant. Both of these awards are intended to align the interests of key employees
(including our named executive officers) with those of our stockholders. Therefore, participants (including our
named executive officers) did not pay any consideration for the common stock they received with respect to
these awards, and we did not receive any cash remuneration for the common stock delivered with respect to
these awards. Partially as a result of the overall award structure, our named executive officers, as well as all
other holders, of outstanding out-of-the-money options that were granted under the 2005 Incentive Plan
cancelled those options.
The Compensation Committee also made cash bonus awards to our executive officers, including our named
executive officers, in connection with the IPO in the aggregate amount of $3 million. After the internal
reallocation described below, the cash awards to our named executive officers were as follows: Mr. Heim—
$732,000.
The bonus stock awards and the cash bonus awards were granted to the seven-person executive management
team to provide (i) a higher “carry” of their equity interests and (ii) additional discretionary compensation, in
each case in recognition of our executive management team’s efforts in bringing us to this point in our
successful history. The initial allocation among the seven persons of the 1.9 million shares of discretionary
bonus and restricted stock awards and $3 million cash bonus awarded to the executive team was initially based
on the relative current base compensation of each individual. Our board of directors and the Compensation
Committee allowed a voluntary reallocation of equity for cash among the members of the executive
management group to accommodate individual preferences. The named executive officers, other than Mr. Heim,
elected to exchange their portion of the cash bonus for additional equity and Mr. Heim and our two other
executive officers elected to exchange some of their equity for larger shares of the cash bonus. The final
allocation for the named executive officers is shown above. The amounts of restricted stock, bonus stock and
cash bonus awards were determined pursuant to our compensation philosophy and the compensation review
discussed above.
Base Salary. In 2010, base salaries for our named executive officers were established based on historical levels
for these officers, taking into consideration officer salaries in our peer group and the value of the total
compensation opportunities available to our executive officers including, in particular, the long-term equity
component of our compensation program. As described above, the second quarter compensation review
indicated that the compensation for our named executive officers was not consistent with compensation paid at
MLP peer companies or with our expanded peer group generally when the data is adjusted for company size. In
order to begin closing this gap in compensation, the Compensation Committee authorized the following
increased base salaries for our named executive officers effective July 1, 2010.
Rene R. Joyce
$
475,000
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
340,000
412,000
412,000
369,000
207,500
Annual Cash Incentives. The Compensation Committee approved our 2010 Annual Incentive Plan (the “Bonus
Plan”) in February 2010 with the following nine key business priorities to be considered when making awards
under the Bonus Plan: (i) continue to control all operating, capital and general and administrative costs,
(ii) invest in our businesses primarily within existing cash flow, (iii) continue priority emphasis and strong
performance relative to a safe workplace, (iv) reinforce business philosophy and mindset that promotes
environmental and regulatory compliance, (v) continue to tightly manage the Downstream Business’ inventory
exposure, (vi) execute on major capital and development projects, such as finalizing negotiations, completing
projects on time and on budget, and optimizing economics and capital funding, (vii) pursue selected
opportunities, including new shale play gathering and processing build-outs, other fee-based cape projects and
potential purchases of strategic assets, (viii) pursue commercial and financial approaches to achieve maximum
value and manage risks, and (ix) execute on all business dimensions, including the financial business plan. The
100
Compensation Committee also established the following overall threshold, target and maximum levels for the
Company’s bonus pool: 50% of the cash bonus pool for the threshold level; 100% for the target level and 200%
for the maximum level. The CEO and the Compensation Committee relied on compensation consultants and
market data from peer company and broader industry compensation practices to establish the threshold, target
and maximum percentage levels, which are generally consistent with peer company and broader energy
compensation practices. The cash bonus pool target amount is determined by summing, on an employee by
employee basis, the product of base salaries and market-based target bonus percentages. The CEO and the
Compensation Committee arrive at the total amount of cash to be allocated to the cash bonus pool by
multiplying percentage of target awarded by the Compensation Committee by the total target cash bonus pool.
The funding of the cash bonus pool and the payment of individual cash bonuses to executive management,
including our named executive officers, are subject to the sole discretion of the Compensation Committee.
In February 2011, the Compensation Committee approved a cash bonus pool equal to 180% of the target level
for the employee group, including our named executive officers, under the Bonus Plan for performance during
2010 in recognition of outstanding efforts and organizational performance. The Compensation Committee
determined to pay these above target level bonuses because it considered overall performance, including
organizational performance, to have substantially exceeded expectations in 2010 based on the nine key business
priorities it established for 2010. The Compensation Committee considered or subjectively evaluated (rather
than measured) organizational performance by reviewing the apparent overall performance of our personnel
with respect to the initial and subsequent business priorities relative to both the overall and management-
specific performance expectations of the Compensation Committee, each on an absolute level and relative to the
Compensation Committee’s sense of peer performance. This subjective assessment that performance
substantially exceeded expectations was based on a qualitative evaluation rather than a mechanical, quantitative
determination of results across each of the key business priorities. Aspects of performance important to this
qualitative determination included (i) continued focus on cost control, including the completion of capital
projects typically below budget, (ii) strong success investing in our businesses, (iii) proactive efforts to enhance
safety and compliance with environmental and regulatory requirements, (iv) disciplined management of NGL
inventory levels and related commodity price exposure, (v) success on transactions including project economics
and project management, (vi) pursuing multiple opportunities to expand our downstream position and to add
fee-based business, (vii) innovation in new gathering and processing commercial transactions and in securing
significant volume guarantees in downstream contracting, (viii) exceeding the financial business plan, (ix)
resolution of certain significant disputes and (x) completion of the dropdown of our businesses to the
Partnership and clarification of strategic direction for our investors. This subjective evaluation that performance
had substantially exceeded expectations occurred with the background and ongoing context of detailed board
and committee refinements of the 2010 business priorities both before the beginning of and during the year,
continued board and committee discussion and active dialogue with management about priorities in subsequent
board and committee meetings, and further board and committee discussion of performance relative to
expectations following the end of 2010. The extensive business and board experience of the Compensation
Committee and of our board of directors provide the perspective to make this subjective assessment in a
qualitative manner to evaluate management performance overall and the performance of the executive officers.
The executive officers received the following bonus awards, which are equivalent to the same average
percentage of target as the Company bonus pool:
Rene R. Joyce
$
855,000
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
489,600
593,280
593,280
531,360
224,100
In addition to the cash bonus awards approved under the Bonus Plan, in February 2011, the Compensation
Committee approved an aggregate cash bonus pool of $1.5 million for our executive officers and two other
employees in recognition of their role in extraordinary execution of the business priorities, completion of drop
downs to the Partnership and clarification of our strategic direction in 2010.
Long-term Cash Incentives. In January 2008 and 2009, we granted our executive officers cash-settled
performance unit awards linked to the performance of the Partnership’s common units that will vest in June of
2011 and 2012, with the amounts vesting under such awards dependent on the Partnership’s performance
101
compared to a peer-group consisting of the Partnership and 12 other publicly traded partnerships. The peer
group companies for 2008 and 2009 were Energy Transfer Partners, ONEOK Partners, Copano, DCP
Midstream, Regency Energy Partners, Plains All American Pipeline, MarkWest Energy Partners, Williams
Energy Partners, Magellan Midstream, Martin Midstream, Enbridge Energy Partners, Crosstex and Targa
Resources Partners LP. The 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 Partnership’s peers. The cash settlement value of these
performance unit awards will be the sum of the value of an equivalent Partnership common unit at the time of
vesting plus associated distributions over the three year period multiplied by a performance vesting percentage
which may be zero or range from 50% to 100%. This cash settlement value may be higher or lower than the
Partnership common unit price at the time of the grant. If the Partnership’s 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 based on an interpolated
basis, and for a performance ranking lower than tenth, no amounts will vest. In January 2008, our named
executive officers, who are also executive officers of the General Partner, received awards of performance units
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. In August 2008, Mr. Meloy received an award of 1,500 performance units. In January 2009, the
named executive officers received awards of performance units as follows: 34,000 performance units to
Mr. Joyce, 15,500 performance units to Mr. McParland, 20,800 performance units to Mr. Perkins and 20,800
performance units to Mr. Heim. In August 2009, Mr. Meloy received an award of 7,500 performance units.
In addition to the January 2009 grants, in December 2009, our executive officers were awarded performance
units under our long-term incentive plan for the 2010 compensation cycle that will vest in June 2013 as follows:
18,025 performance units to Mr. Joyce, 13,464 performance units to Mr. Whalen, 9,350 performance units to
Mr. McParland, 13,860 performance units to Mr. Perkins and 9,894 performance units to Mr. Heim. In August
2010, Mr. Meloy received an award of 4,000 performance units. The cash settlement value of these performance
unit awards will be the sum of the value of an equivalent Partnership common unit at the time of vesting plus
associated distributions over the three year period multiplied by a performance vesting percentage which may be
zero or range from 25% to 150%. This cash settlement value may be higher or lower than the Partnership
common unit price at the time of the grant. If the Partnership’s performance equals or exceeds the performance
for the 25th percentile of the group but is less than or equal to the 50th percentile of the group, then 25% to
100% of the award will vest. If the Partnership’s performance equals or exceeds the performance for the
50th percentile of the group but is less than or equal to the 75th percentile of the group, then 100% to 150% of
the award will vest. The vesting between the 25th percentile and the 50th percentile will be done on an
interpolated basis between 25% and 100% and the vesting between the 50th percentile and 75th percentile will
be done on an interpolated basis between 100% and 150%. If the Partnership’s performance is above the
performance of the 75th percentile of the group, the performance percentage will be 150% and all amounts will
vest. If the Partnership’s performance is below the performance of the 25th percentile of the group, the
performance percentage will be zero and no amounts will vest. The performance period for these performance
unit awards began on June 30, 2010 and ends on the third anniversary of such date.
102
Set forth below is the “performance for the median” of the peer group for each of the 2008, 2009 and 2010
grants and a comparison of the Partnership’s performance to the peer group as of December 31, 2010:
Performance (1)
Grant
Partnership
Position (2)
Peer Group
Median
43.5%
59.4%
16.8%
16.8%
Partnership
74.6%
100.6%
34.3%
34.3%
2008
2009 (January grants)
2009 (December grants)
2010
________
(1) Total return measured by (i) subtracting the average closing price per share/unit for the first ten trading days of the performance period
(the “Beginning Price”) from the sum of (a) the average closing price per share/unit for the last ten trading days ending on the date that
is 15 days prior to the end of the performance period plus (b) the aggregate amount of dividends/distributions paid with respect to a
share/unit during such period (the result being referred to as the “Value Increase”) and (ii) dividing the Value Increase by the
Beginning Price. The performance period for the 2008 and January 2009 awards begins on June 30, 2008 and June 30, 2009 while the
December 2009 and 2010 awards begins on June 30, 2010, and all awards end on the third anniversary of such dates.
1 of 13
1 of 13
100th percentile
100th percentile
(2) The Partnership’s position for the December 2009 and the 2010 grants is measured by the Partnership’s placement in a particular
quartile rather than its specific rank against the peer group.
Health and Welfare Benefits. For 2010, our named executive officers participated in our health and welfare
benefit programs, including medical, health, life insurance, dental coverage and disability insurance, on the
same basis as all of our other employees.
Perquisites. Consistent with our compensation philosophy, we did not pay for perquisites for any of our named
executive officers during 2010, other than parking subsidies.
Changes for 2011
Base Salary. The 2010 increase in base pay for the key employees closed only approximately one-half of the
gap in executive compensation highlighted by the review referred to above under “—The Role of Peer Groups
and Benchmarking. In order to begin closing this remaining gap in compensation, the Compensation
Committee authorized, and executive management will implement, the following increased base salaries for our
named executive officers effective April 1, 2011:
Rene R. Joyce
$
547,000
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
389,000
468,000
468,000
415,000
235,000
With this move in base salaries, the gap will be reduced by approximately one-half.
Annual Cash Incentives. In light of recent economic and financial events, Senior Management developed and
proposed a set of strategic priorities to the Compensation Committee. In February 2011, the Compensation
Committee approved our 2011 Annual Incentive Compensation Plan (the “2011 Bonus Plan”), the cash bonus
plan for performance during 2011, and established the following eight key business priorities: (i) continue to
control all operating, capital and general and administrative costs, (ii) invest in our businesses, (iii) continue
priority emphasis and strong performance relative to a safe workplace, (iv) reinforce business philosophy and
mindset that promotes compliance with all aspects of our business including environmental and regulatory
compliance, (v) continue to manage tightly credit, inventory, interest rate and commodity price exposures,
(vi) execute on major capital and development projects, such as finalizing negotiations, completing projects on
time and on budget, and optimizing economics and capital funding, (vii) pursue selected growth opportunities,
including new gathering and processing build-outs leveraging our NGL logistics platform for development
projects, other fee-based capex projects and potential purchases of strategic assets and (viii) execute on all
business dimensions to maximize value and manage risks. The Compensation Committee also established the
following overall threshold, target and maximum levels for the Company’s bonus pool: 50% of the cash bonus
pool for the threshold level; 100% for the target level and 200% for the maximum level. As with the Bonus
103
Plan, funding of the cash bonus pool and the payment of individual cash bonuses to executive management,
including our named executive officers, are subject to the sole discretion of the Compensation Committee. The
market-based base salary bonus percentages for the named executive officers used in determining the annual
cash incentives were increased in connection with the increases in base salary in 2010.
Long-term Incentives. On February 14, 2011, our named executive officers were awarded restricted common
stock of the Company under our stock incentive plan for the 2011 compensation cycle that will vest in three
years from the grant date as follows: 7,690 shares to Mr. Joyce, 4,250 shares to Mr. Perkins, 4,250 shares to Mr.
Whalen, 3,770 shares to Mr. Heim, 3,540 shares to Mr. McParland, and 1,260 shares to Mr. Meloy.
On February 17, 2011, our named executive officers were awarded equity-settled performance units under the
Partnership’s long-term incentive plan for the 2011 compensation cycle that will vest in June 2014 as follows:
21,110 performance units to Mr. Joyce, 11,690 performance units to Mr. Perkins, 11,690 performance units to
Mr. Whalen, 10,360 performance units to Mr. Heim, 9,710 performance units to Mr. McParland, and 3,470
performance units to Mr. Meloy. The settlement value of these performance unit awards will be determined
using the formula adopted for the performance unit awards granted in December 2009.
Compensation Committee Interlocks and Insider Participation
No member of our Compensation Committee has been at any time an employee of ours. None of our executive
officers served on the board of directors or compensation committee of a company that has an executive officer
that served on our board or Compensation Committee. No member of our board is an executive officer of a
company in which one of our executive officers serves as a member of the board of directors or compensation
committee of that company.
Messrs. Kagan and Joung, both of whom were members of our Compensation Committee during 2010, were
affiliates of Warburg Pincus during 2010. Mr. Joung resigned from our Compensation Committee in February
2011. Messrs. Kagan and Joung were directors of Broad Oak during 2010, from whom we bought natural gas
and NGL products and in which affiliates of Warburg Pincus own a controlling interest. Messrs. Kagan and
Joung are party to indemnification agreements with us. Warburg Pincus was a party to the Stockholders
Agreement and is a party to the Registration Rights Agreement with us. The Stockholders Agreement was
terminated in connection with the IPO. Mr. Kagan was also a director of Antero Resources Corporation
(“Antero”) during 2010, from whom we bought natural gas and NGL products and in which affiliates of
Warburg Pincus own a controlling interest. Please read Item 13. “Certain Relationships and Related
Transactions, and Director Independence” for a description of these transactions.
Compensation Committee Report
Messrs. Crisp, Hwang and Kagan are the current members of our Compensation Committee. In fulfilling its
oversight responsibilities, the Compensation Committee has reviewed and discussed with management the
compensation discussion and analysis contained in this Annual Report. Based on these reviews and discussions,
the Compensation Committee recommended to our board of directors that the compensation discussion and
analysis be included in the Annual Report for the year ended December 31, 2010 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 company specifically incorporates
it by reference into a document filed under the Securities Act of 1933, as amended, or the Exchange Act.
The Compensation Committee
Charles R. Crisp, Chairman Peter R. Kagan
104
Executive Compensation Tables
The following Summary Compensation Table sets forth the compensation of our named executive officers for
2010, 2009 and 2008. 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 2010
Non-Equity
Year
Salary
(2)
Bonus
Stock
Awards
($) (3)
Incentive Plan
All Other
Compensation Compensation
Total
(4)
(5)
Compensation
Name
Rene R. Joyce
2010 $
410,000 $
265,067 $
5,358,408 $
Chief Executive Officer
2009
337,500
2008
322,500
1,398,946
148,400
Jeffrey J. McParland (1)
2010
305,500
189,732
3,162,324
President - Finance &
2009
265,000
Administration
2008
253,000
683,450
110,170
Joe Bob Perkins
President
2010
361,250
229,911
3,831,960
2009
303,750
2008
290,250
James W. Whalen (1)
2010
356,750
Executive Chairman of the
2009
297,000
Board
2008
290,250
Michael A. Heim
Executive Vice President and
2010
328,000
937,915
2,699,620
Chief Operating Officer
2009
281,000
2008
268,750
810,117
129,850
970,109
129,850
3,831,960
543,150
129,850
855,000 $
510,000
247,500
489,600
400,500
194,250
592,280
459,000
222,750
592,280
445,500
222,750
531,360
424,500
206,250
22,410 $
20,187
19,205
20,904
20,061
19,031
20,448
20,129
19,124
22,338
19,936
18,871
6,910,885
2,266,633
737,605
4,168,060
1,369,011
566,451
5,036,849
1,752,988
661,974
4,804,328
1,305,586
661,721
21,776
20,089
19,071
4,518,671
1,535,706
623,921
Matthew J. Meloy (1)
2010
195,625
493,350
224,100
19,740
932,815
Senior Vice President, Chief
Financial Officer and Treasurer
____________
(1) Mr. McParland became President, Finance and Administration in December 2010 and previously served as Executive Vice President
and Chief Financial Officer. Mr. Whalen became Executive Chairman of the Board of Directors in December 2010 and previously
served as President, Finance and Administration. Mr. Meloy was promoted to Senior Vice President and Chief Financial Officer in
December 2010. Prior to his promotion, Mr. Meloy served as Vice President—Finance and Treasurer.
(2) Represents discretionary cash bonuses paid to the named executive officers in recognition of the executive team’s role in extraordinary
execution of the business priorities, completion of drop downs to the Partnership and clarification of our strategic direction in 2010.
$732,000 of the amount reported for Mr. Heim represents a cash bonus paid in lieu of equity in connection with the IPO. Please see
“Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Bonus Stock Awards”
and “Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Annual Cash
Incentives.”
(3) The restricted stock awards in 2010 to executive officers were made based upon the recommendation of the compensation consultant
using market-based precedent and market-based amounts to provide a one-time retention and incentive award in connection with our
transition from a private to a public company. Please see “Executive Compensation—Compensation Discussion and Analysis—
Application of Compensation Elements.” Amounts represent the aggregate grant date fair value of awards computed in accordance
with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in Note 24 to our “Consolidated
Financial Statements” beginning on page F-1. Detailed information about the amount recognized for specific awards is reported in the
table under “—Grants of Plan-Based Awards” below. The grant date fair value of a common stock award approved on December 6,
2010 and granted on December 10, 2010, assuming vesting will occur, is $22.00.
(4) Amounts represent awards granted pursuant to our Bonus Plan. See the narrative to the section titled “—Grants of Plan-Based
Awards” below for further information regarding these awards.
(5) For 2010 “All Other Compensation” includes the (i) aggregate value of matching and non-matching contributions to our 401(k) plan
and (ii) the dollar value of life insurance coverage provided by the Company.
105
401(k) and Profit Dollar Value of
$
Name
Rene R. Joyce
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
Sharing Plan
19,600
19,600
19,600
19,600
19,600
19,600
Life Insurance
$
2,810
1,304
848
2,738
2,176
140
Total
$
22,410
20,904
20,448
22,338
21,776
19,740
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 2010:
Grants of Plan Based Awards for 2010
Estimated Possible Payouts Under
All Other Stock
Grant Date Fair
Grant
Approval
Shares of Stocks
Non-Equity Incentive Plan Awards (1)
Awards: Number of
Value of
Stock and
Date
Date
Threshold
Target
2X Target
or Units (2)
Option Awards (3)
N/A
$
237,500 $
475,000 $
950,000
Name
Mr. Joyce
12/10/10
12/06/10
12/10/10
12/06/10
121,125 (4) $
122,439 (5)
2,644,750
2,693,658
Mr. McParland
N/A
136,000
272,000
544,000
12/10/10
12/06/10
12/10/10
12/06/10
Mr. Perkins
N/A
164,800
329,000
659,200
12/10/10
12/06/10
12/10/10
12/06/10
Mr. Whalen
N/A
164,800
329,600
659,200
12/10/10
12/06/10
12/10/10
12/06/10
Mr. Heim
N/A
147,600
295,200
590,400
12/10/10
12/06/10
12/10/10
12/06/10
56,100 (4)
87,642 (5)
67,980 (4)
106,200 (5)
67,980 (4)
106,200 (5)
60,885 (4)
61,825 (5)
1,234,200
1,928,124
1,495,560
2,336,400
1,495,560
2,336,400
1,339,470
1,360,150
Mr. Meloy
N/A
41,500
83,000
166,000
12/10/10
12/06/10
22,425 (4)
493,350
____________
(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 portion of the cash
bonus pool available for awards to the named executive officers under the Bonus Plan based on the three performance levels. In
February 2011, the Compensation Committee approved a bonus award for the named executive officers equal to 1.8x of the target. See
“—Executive Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Annual Cash
Incentives.”
(2) These common stock awards were granted under our 2010 Incentive Plan. The stock awards to executive officers were made based
upon the recommendation of the compensation consultant using market-based precedent and market-based amounts to provide a one-
time retention and incentive award in connection with our transition from a private to a public company.
(3) The dollar amounts shown for the common stock awards approved on December 6, 2010 and granted on December 10, 2010 are
determined by multiplying the shares reported in the table by $22.00 (the grant date fair value of awards computed in accordance with
FASB ASC Topic 718).
(4) Restricted stock awards.
(5) Bonus stock awards.
106
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table
A discussion of 2010 salaries, bonuses, incentive plans and awards is included in “—Executive Compensation—
Compensation Discussion and Analysis.”
2010 Stock Incentive Plan
Restricted Stock Awards. Subject to the terms of the applicable restricted stock agreement, restricted stock
granted under the 2010 Incentive Plan during 2010 has a vesting period of two years from the date of grant (with
respect to 60% of the shares awarded) and three years from the date of grant (with respect to 40% of the shares
awarded). The named executive officers have all of the rights of a stockholder of the Company with respect to
the restricted stock granted in 2010 including, without limitation, voting rights. The named executive officers do
not have the right to receive any dividends or other distributions, including any special or extraordinary
dividends or distributions, with respect to the restricted stock granted in 2010 unless and until the restricted
stock vests. Dividends on unvested restricted stock are credited to an unfunded account maintained by the
Company. These credited dividends are paid to the employee when the shares of restricted stock vest. In the
event all or any portion of the restricted stock granted in 2010 fails to vest, such restricted stock and dividends
will be forfeited to us.
Bonus Stock Awards. Bonus stock awarded in 2010 is not subject to any vesting or forfeiture provisions.
Please see “—Executive Compensation—Compensation Discussion and Analysis—Elements of Compensation
for Named Executive Officers—New Incentive Plan” and “—Executive Compensation—Compensation
Discussion and Analysis—Application of Compensation Elements—Equity Ownership” for a detailed
discussion of the grants of restricted stock and bonus stock.
Outstanding Equity Awards at 2010 Fiscal Year-End
The following table and the footnotes related thereto provide information regarding each stock option and other
equity-based awards outstanding as of December 31, 2010 for each of our named executive officers.
Outstanding Equity Awards at 2010 Fiscal Year-End
Stock Awards
Equity Incentive Plan
Equity Incentive Plan
Number of
Market Value
Awards: Number of
Awards: Market or
Shares of
of Shares of
Unearned
Payout Value of
Stock That
Stock That
Performance Units
Unearned Performance
Have not
Have not
Vested (1)
Vested (2)
That have not
Vested (3)
Units That have not
Vested (4)
121,125 $
56,100
67,980
67,980
60,885
3,247,361
1,504,041
1,822,544
1,822,544
1,632,327
56,025 $
27,550
38,160
16,964
34,194
2,263,953
1,113,254
1,542,127
686,185
1,381,504
Name
Rene R. Joyce
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
____________
(1) Represents shares of our restricted common stock awarded on December 10, 2010. These shares vest as follows: 60% on December
601,214
525,233
13,000
22,425
10, 2012 and 40% on December 10, 2013.
(2) The dollar amounts shown are determined by multiplying the number of shares of common stock reported in the table by the sum of
the closing price of a share of common stock on December 31, 2010 ($26.81).
(3) Represents the number of performance units awarded on January 17, 2008, January 22, 2009 and December 3, 2009 under our long-
term incentive plan. With respect to Mr. Meloy, the performance units were granted on October 1, 2008, August 4, 2009 and August 2,
2010. These awards vest in June 2011, June 2012, and June 2013, based on the Partnership’s performance over the applicable period
measured against a peer group of companies. These awards are discussed in more detail under the heading “—Executive
Compensation—Compensation Discussion and Analysis—Application of Compensation Elements—Long-Term Cash Incentives.”
(4) The dollar amounts shown are determined by multiplying the number of performance units reported in the table by the sum of the
closing price of a common unit of the Partnership on December 31, 2010 ($33.96) and the related distribution equivalent rights for
each award and assume full payout under the awards at the time of vesting.
107
Option Exercises and Stock Vested in 2010
The following table provides the amount realized during 2010 by each named executive officer upon the
exercise of options and upon the vesting of our restricted common stock and performance units.
Option Exercises and Stock Vested for 2010
Option Awards
Stock Awards
Number of Shares
Acquired on
Exercise (1)
155,447
108,556
117,241
45,158
127,946
$
Value Realized
on Exercise
459,957
324,555
350,520
135,012
377,735
Number of Shares
Acquired on
Vesting (2)
Value Realized
on Vesting (3)
15,000 $
8,200
10,800
10,800
10,000
499,406
273,009
359,573
359,573
332,938
Name
Rene R. Joyce
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
____________
(1) At the time of exercise of the stock options, the common stock acquired upon exercise had a value of $3.46 per share. This value was
43,162
15,942
99,881
3,000
determined by an independent consultant pursuant to a valuation of our common stock dated June 2, 2010.
(2) Represents performance units granted in February 2007 that vested in August 2010 and were settled by cash payment.
(3) Computed by multiplying the number of performance units by the value of an equivalent Partnership common unit at the time of
vesting and adding associated distributions over the vesting period.
Change in Control and Termination Benefits
2010 Incentive Plan. If a Change in Control (as defined below) occurs and the named executive officer has
remained continuously employed by us from the date of grant to the date upon which such Change in Control
occurs, then the restricted stock granted to him under our form of restricted stock agreement (the “Stock
Agreement”) and related dividends then credited to him will fully vest on the date upon which such Change in
Control occurs.
Restricted stock granted to a named executive officer under the Stock Agreement and related dividends then
credited to him will fully vest if his employment is terminated by reason of death or a Disability (as defined
below). If a named executive officer’s employment with us is terminated for any reason other than death or
Disability, then his unvested restricted stock is forfeited to us for no consideration.
The following terms have the specified meanings for purposes of the 2010 Incentive Plan and Stock Agreement:
• Affiliate means any corporation, partnership (including the Partnership), limited liability company or
partnership, association, trust, or other organization which, directly or indirectly, controls, is controlled
by, or is under common control with, the Company. For purposes of the preceding sentence, “control”
(including, with correlative meanings, the terms “controlled by” and “under common control with”), as
used with respect to any entity or organization, shall mean the possession, directly or indirectly, of the
power (i) to vote more than 50% of the securities having ordinary voting power for the election of
directors of the controlled entity or organization or (ii) to direct or cause the direction of the
management and policies of the controlled entity or organization, whether through the ownership of
voting securities or by contract or otherwise.
• Change in Control means the occurrence of one of the following events: (i) any Person, including a
“group” as contemplated by section 13(d)(3) of the Exchange Act (other than Warburg Pincus LLC or
any other Affiliate), acquires or gains ownership or control (including, without limitation, the power to
vote), by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50%
of the outstanding shares of the Company’s voting stock (based upon voting power) or more than 50%
of the combined voting power of the equity interests in the Partnership or the general partner of the
Partnership; (ii) the completion of a liquidation or dissolution of the Company or the approval by the
limited partners of the Partnership, in one or a series of transactions, of a plan of complete liquidation
of the Partnership; (iii) the sale or other disposition by the Company of all or substantially all of its
assets in or more transactions to any Person other than Warburg Pincus LLC or any other Affiliate; (iv)
the sale or disposition by either the Partnership or the general partner of the Partnership of all or
substantially all of its assets in one or more transactions to any Person other than to Warburg Pincus
108
LLC, Targa Resources GP LLC, or any other Affiliate; (v) a transaction resulting in a Person other than
Targa Resources GP LLC or an Affiliate being the general partner of the Partnership; or (vi) as a result
of or in connection with a contested election of directors, the persons who were directors of the
Company before such election shall cease to constitute a majority of the Company’s board of directors.
Notwithstanding the foregoing, with respect to an award under the 2010 Incentive Plan that is subject
to section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and with respect to
which a Change in Control will accelerate payment, “Change in Control” shall mean a “change of
control event” as defined in the regulations and guidance issued under section 409A of the Code.
• Disability means a disability that entitles the named executive officer to disability benefits under our
long-term disability plan.
• Person means an individual or a corporation, limited liability company, partnership, joint venture, trust,
unincorporated organization, association, government agency or political subdivision thereof, or other
entity.
The following table reflects payments that would have been made to each of the named executive officers under
the 2010 Incentive Plan and related agreements in the event there was a Change in Control or their employment
was terminated, each as of December 31, 2010.
Change of Control (1)
$
Name
Rene R. Joyce
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
____________
(1) Amounts relate to the unvested shares of restricted stock of the Company granted on December 10, 2010.
Termination for
Death or Disability (1)
3,247,361
$
1,504,041
1,822,544
1,822,544
1,632,327
601,214
3,247,361
1,504,041
1,822,544
1,822,544
1,632,327
601,214
Long-Term Incentive Plan. If a Change of Control (as defined below) occurs during the performance period
established for the performance units and related distribution equivalent rights granted to a named executive
officer under our form of Performance Unit Grant Agreement (a “Performance Unit Agreement”), the
performance units and related distribution equivalent rights then credited to a named executive officer will be
cancelled and the named executive officer will be paid an amount of cash equal to the sum of (i) the product of
(a) the Fair Market Value (as defined below) of a common unit of the Partnership multiplied by (b) the number
of performance units granted to the named executive officer, plus (ii) the amount of distribution equivalent
rights then credited to the named executive officer, if any.
Performance units and the related distribution equivalent rights granted to a named executive officer under a
Performance Unit Agreement will be automatically forfeited without payment upon the termination of his
employment with us and our affiliates, except that: if his employment is terminated by reason of his death, a
disability that entitles him to disability benefits under our long-term disability plan or by us other than for Cause
(as defined below), he will be vested in his performance units that he is otherwise qualified to receive payment
for based on achievement of the performance goal at the end of the Performance Period.
The following terms have the specified meanings for purposes of our long-term incentive plan:
• Change of Control means (i) any “person” or “group” within the meaning of those terms as used in
Sections 13(d) and 14(d)(2) of the Exchange Act, other than an affiliate of us, becoming the beneficial
owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more
of the combined voting power of the equity interests in the Partnership or its general partner, (ii) the
limited partners of the Partnership approving, in one or a series of transactions, a plan of complete
liquidation of the Partnership, (iii) the sale or other disposition by either the Partnership or the General
Partner of all or substantially all of its assets in one or more transactions to any person other than the
General Partner or one of the General Partner’s affiliates or (iv) a transaction resulting in a person other
than the Partnership’s general partner or one of such general partner’s affiliates being the general
partner of the Partnership. With respect to an award subject to Section 409A of the Code, Change of
109
Control will mean a “change of control event” as defined in the regulations and guidance issued under
Section 409A of the Code.
• Fair Market Value means the closing sales price of a common unit of the Partnership on the principal
national securities exchange or other market in which trading in such common units occurs on the
applicable date (or if there is not trading in the common units on such date, on the next preceding date
on which there was trading) as reported in The Wall Street Journal (or other reporting service approved
by the Compensation Committee). In the event the common units are not traded on a national securities
exchange or other market at the time a determination of fair market value is required to be made, the
determination of fair market value shall be made in good faith by the Compensation Committee.
• Cause means (i) failure to perform assigned duties and responsibilities, (ii) engaging in conduct which
is injurious (monetarily of otherwise) to us or our affiliates, (iii) breach of any corporate policy or code
of conduct established by us or our affiliates or breach of any agreement between the named executive
officer and us or our affiliates or (iv) conviction of a misdemeanor involving moral turpitude or a
felony. If the named executive officer is a party to an agreement with us or our affiliates in which this
term is defined, then that definition will apply for purposes of our long-term incentive plan and the
Performance Unit Agreement.
The following table reflects payments that would have been made to each of the named executive officers under
our long-term incentive plan and related agreements in the event there was a Change of Control or their
employment was terminated, each as of December 31, 2010.
Change of
Termination for
$
Death or Disability
Control
2,049,196
1,008,188
1,394,083
608,637
1,255,173
477,053
Name
Rene R. Joyce
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
____________
(1) Of this amount, $135,840 and $20,800 relate to the performance units and related distribution equivalent rights granted on January 17,
2008; $1,154,640 and $106,590 relate to the performance units and related distribution equivalent rights granted on January 22, 2009;
and $612,129 and $19,197 relate to the performance units and related distribution equivalent rights granted on December 3, 2009.
(2) Of this amount, $91,692 and $14,040 relate to the performance units and related distribution equivalent rights granted on January 17,
2008; $526,380 and $48,593 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and
$317,526 and $9,958 relate to the performance units and related distribution equivalent rights granted on December 3, 2009.
2,049,196
1,008,188
1,394,083
608,637
1,255,173
477,053
(1) $
(2)
(3)
(4)
(5)
(6)
(1)
(2)
(3)
(4)
(5)
(6)
(3) Of this amount, $118,860 and $18,200 relate to the performance units and related distribution equivalent rights granted on January 17,
2008; $706,368 and $65,208 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and
$470,686 and $14,761 relate to the performance units and related distribution equivalent rights granted on December 3, 2009.
(4) Of this amount, $118,860 and $18,200 relate to the performance units and related distribution equivalent rights granted on January 17,
2008; $0 and $0 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and $457,237
and $14,339 relate to the performance units and related distribution equivalent rights granted on December 3, 2009.
(5) Of this amount, $118,860 and $18,200 relate to the performance units and related distribution equivalent rights granted on January 17,
2008; $706,368 and $65,208 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; and
$336,000 and $10,537 relate to the performance units and related distribution equivalent rights granted on December 3, 2009.
(6) Of this amount, $50,940and $7,800 relate to the performance units and related distribution equivalent rights granted on October 1,
2008; $254,700 and $23,513 relate to the performance units and related distribution equivalent rights granted on August 4, 2009; and
$135,840 and $4,260 relate to the performance units and related distribution equivalent rights granted on August 1, 2010.
2005 Incentive Plan. No payments 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, 2010.
110
The following table reflects the aggregate payments that would have been made to each of the named executive
officers under the 2010 Incentive Plan, the Long-Term Incentive Plan and related agreements in the event there
was a Change in Control/Change of Control or their employment was terminated, each as of December 31,
2010.
$
Name
Rene R. Joyce
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen
Michael A. Heim
Matthew J. Meloy
Director Compensation
Change of
Termination for
Control
5,296,557
2,512,229
3,216,627
2,431,181
2,887,500
1,078,267
Death or Disability
5,296,557
$
2,512,229
3,216,627
2,431,181
2,887,500
1,078,267
The following table sets forth the compensation earned by our non-employee directors for 2010:
Director Compensation for 2010
Fees Earned Stock
$
or Paid
in Cash
Awards
($) (5)
Name
Chris Tong (1)(2)(3)
Charles R. Crisp (1)(2)(3)
In Seon Hwang
Chansoo Joung (1)(2)(4)
Peter R. Kagan (1)(2)(4)
____________
(1) On January 22, 2010, Messrs. Crisp and Tong each received 2,250 common units of the Partnership in connection with their service on
our board of directors and Messrs. Joung and Kagan each received 2,250 common units of the Partnership in connection with their
service on the board of directors of the General Partner. The grant date fair value of each common unit granted to each of these named
individuals computed in accordance with FAS 123R was $23.65, based on the closing price of the common units on the day prior to
the grant date.
71,500 $ 53,213 $
53,213
56,500
-
11,500
-
11,500
-
11,500
Total
Compensation
124,713
109,713
11,500
11,500
11,500
(2) As of December 31, 2010, Mr. Tong held 23,150 common units and 49,439 shares of common stock, Mr. Crisp held 11,350 common
units and 140,080 shares of common stock and Messrs. Joung and Mr. Kagan each held 10,250 common units of the Partnership.
(3) On February 14, 2011, Mr. Crisp received 7,200 shares of common stock of the Company and Mr. Tong received 5,500 shares of
common stock of the Company in partial consideration of their agreement to cancel outstanding stock options to acquire common
stock in connection with our IPO.
(4) Messrs. Joung and Kagan earned $131,238 and $129,738 in fees for service on the board of directors of the partnership’s General
Partner in 2010. Mr. Joung’s compensation included $56,500 in fees, $53,213 in common unit awards and $21,525 in all other
compensation. Mr. Kagan’s compensation included $55,000 in fees, $53,213 in common unit awards and $21,525 in all other
compensation.
(5) Amounts represent the aggregate grant date fair value of awards computed in accordance with FASB ASC Topic 718. For a discussion
of the assumptions and methodologies used to value the awards reported in this column, see the discussion of common unit and
common stock awards contained in the Notes to Consolidated Financial Statements at Note 24 included in this annual report.
Narrative to Director Compensation Table
For 2010, Messrs. Crisp and Tong received an annual cash retainer of $40,000. Messrs. Hwang, Joung and
Kagan received a prorated annual cash retainer, which was paid after the IPO. Prior to the IPO, Messrs. Hwang,
Joung and Kagan were not paid an annual cash retainer (or any meeting fees). The chairman of the Audit
Committee received an additional annual retainer of $20,000. All of our independent directors receive $1,500
for each Board, Audit Committee, Compensation Committee, Governance and Nominating Committee and
Conflicts Committee meeting attended. Payment of independent director fees is generally made twice annually,
at the second regularly scheduled meeting of the Board and the final regularly scheduled 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.
111
Director Long-term Equity Incentives. The Partnership made equity-based awards in January 2010 to our non-
management and independent directors under the Partnership’s long-term incentive plan. These awards were
determined by us and approved by the General Partner’s board of directors. Each of these directors received an
award of 2,250 restricted units, which will settle with the delivery of Partnership common units. 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 our directors with those of the
Partnership’s unitholders. Our independent and non-management directors currently participate in the
Partnership’s plan.
Changes for 2011
Director Compensation. In February 2011, the board of directors approved changes to director compensation
for the 2011 fiscal year. For 2011, each independent director will receive an annual cash retainer of $50,000.
Director Long-term Equity Incentives. In February 2011, each of our non-management and independent
directors received an award of 2,310 shares of our common stock under the 2010 Incentive Plan.
112
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The following table sets forth information regarding the beneficial ownership of our common stock and the
beneficial ownership of the Partnership’s common units as of February 25, 2011 held by:
• each person who beneficially owns more than 5% of our outstanding shares of common stock;
• each of our named executive officers;
• each of our directors; and
• all of our executive officers and directors as a group.
Beneficial ownership is determined under the rules of the Securities and Exchange Commission. In general,
these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power
and/or investment power with respect to those securities and include, among other things, securities that an
individual has the right to acquire within 60 days. Unless otherwise indicated, the stockholders and unitholders
identified in the table below have sole voting and investment power with respect to all securities shown as
beneficially owned by them. Percentage ownership calculations for any security holder listed in the table below
are based on 42,349,738 shares of our common stock and 84,756,009 common units of the Partnership
outstanding on February 25, 2011.
Targa Resources Partners LP
Targa Resources Corp.
Percentage
Percentage
Common
of Common
Common
of Common
Units
Units
Stock
Stock
Beneficially
Beneficially
Beneficially
Beneficially
Name of Beneficial Owner (1)
Owned (8)
Owned
Owned
Owned
Warburg Pincus Private Equity VIII, L.P. (2)
Warburg Pincus Netherlands Private Equity VIII C.V.I
(2)
WP-WPVIII Investors, L.P. (2)
Warburg Pincus Private Equity IX, L.P. (2)
Rene R. Joyce (3)
Joe Bob Perkins (4)
Michael A. Heim (5)
Jeffrey J. McParland
James W. Whalen (6)
Matthew J Meloy
In Seon Hwang (7)
Peter R. Kagan (7)
Chris Tong
Charles R. Crisp
Ershel C. Redd Jr.
All directors and executive officers
as a group (13 persons) (8)
_________
* Less than 1%.
8,617,912
20.3%
249,795
24,987
4,996,737
1,122,596
914,058
815,552
757,316
637,679
79,599
13,891,741
13,891,741
57,249
149,590
2,510
*
*
*
*
*
*
*
*
*
*
*
*
*
11.8%
2.7%
2.2%
1.9%
1.8%
1.5%
*
32.8%
32.8%
*
*
*
81,000
32,100
8,000
16,500
111,152
6,000
2,120
12,370
23,150
11,350
-
344,742
*
19,792,190
46.7%
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1000 Louisiana, Suite 4300, Houston, Texas 77002.
(2) Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership, and two affiliated partnerships, Warburg Pincus
Netherlands Private Equity VIII C.V.I., a company organized under the laws of the Netherlands, and WP-WP VIII Investors, L.P., a
Delaware limited partnership (together “WP VIII”), and Warburg Pincus Private Equity IX, L.P., a Delaware limited partnership
113
(“WP IX”), in the aggregate own, on a fully diluted basis, approximately 33% of our equity interests. The general partner of WP VIII
is Warburg Pincus Partners, LLC, a New York limited liability company (“WP Partners LLC”), and the general partner of WP IX is
Warburg Pincus IX, LLC, a New York limited liability company, of which WP Partners LLC is the sole member. Warburg Pincus &
Co., a New York general partnership (“WP”), is the managing member of WP Partners LLC. WP VIII and WP IX are managed by
Warburg Pincus LLC, a New York limited liability company (“WP LLC”). The address of the Warburg Pincus entities is 450
Lexington Avenue, New York, New York 10017. Messrs. Hwang and Kagan are Partners of WP and Managing Directors and
Members of WP LLC. Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members and Co-
Presidents of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Hwang, Kagan, Kaye and Landy disclaim
beneficial ownership of all shares held by the Warburg Pincus entities.
(4)
(3) Shares of common stock beneficially owned by Mr. Joyce include: (i) 234,959 shares issued to The Rene Joyce 2010 Grantor
Retained Annuity Trust, of which Mr. Joyce and his wife are co-trustees and have shared voting and investment power; and (ii)
561,292 shares issued to The Kay Joyce 2010 Family Trust, of which Mr. Joyce’s wife is trustee and has sole voting and investment
power.
Shares of common stock beneficially owned by Mr. Perkins include: (i) 151,805 shares issued to the JBP Liquidity Trust, of which
Ms. Claudia Capp Vaglica is trustee and has sole voting and investment power; (ii) 147,645 shares issued to the JBP Family Trust, of
which Ms. Vaglica is the trustee and has sole voting and investment power; and (iii) 4,159 shares issued to Mr. Perkins’ wife over
which she has sole voting and investment power.
Shares of common stock beneficially owned by Mr. Heim include: (i) 312,378 shares issued to The Michael Heim 2009 Family Trust,
of which Mr. Heim and Nicholas Heim are co-trustees and have shared voting and investment power; and (ii) 196,672 shares issued to
The Patricia Heim 2009 Grantor Retained Annuity Trust, of which Mr. Heim and his wife are co-trustees and have shared voting and
investment power.
(5)
(6) Shares of common stock beneficially owned by Mr. Whalen include 633,429 shares issued to the Whalen Family Investments Limited
Partnership.
(7) All shares indicated as owned by Messrs. Hwang and Kagan are included because of their affiliation with the Warburg Pincus entities.
(8) The common units of the Partnership presented as being beneficially owned by our directors and officers do not include the common
units held indirectly by us that may be attributable to such directors and officers based on their ownership of equity interests in us.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth certain information as of December 31, 2010 regarding our long-term incentive
plans, under which our common stock are authorized for issuance to employees, consultants and directors of us,
and our affiliates. Our sole compensation plan under which we will make equity grants in the future is the 2010
Incentive Plan, which was approved by our stockholders prior to our initial public offering.
Number of
securities to be
Number of securities
remaining available
for future issuance
issued upon
Weighted average
under equity
exercise of
outstanding
exercise price of
compensation plans
outstanding
(excluding securities
options, warrants
options, warrants
reflected in column
Plan category
and rights
and rights
(a)
(b)
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
(a))
(c)
5,318,634 (1)
Total
________
(1) Of these securities, 2,225,148 shares are available for issuance under the 2005 Incentive Plan and 3,093,486 are available for issuance
under the 2010 Incentive Plan. We did not make equity grants under the 2005 Incentive Plan in connection with, or subsequent to,
our IPO and will not make equity grants under the 2005 Incentive Plan going forward.
5,318,634 (1)
$
Generally, awards of restricted stock to our officers and employees under the 2010 Incentive Plan are subject to
vesting over time as determined by the Compensation Committee and, prior to vesting, are subject to forfeiture.
Stock incentive plan awards may vest in other circumstances, as approved by the Compensation Committee and
reflected in an award agreement. Restricted stock is issued, subject to vesting, on the date of grant. The
Compensation Committee may provide that dividends on restricted stock are subject to vesting and forfeiture
provisions, in which cash such dividends would be held, without interest, until they vest or are forfeited.
114
Item 13. Certain Relationships and Related Transactions, and Director Independence
Our Relationship with Targa Resources Partners LP and its General Partner
General
Our only cash generating assets consist of our interests in the Partnership, which as of February 25, 2011
consists of the following:
• a 2.0% general partner interest in the Partnership, which we hold through our 100% ownership interests
in the General Partner;
• all of the outstanding IDRs of the Partnership; and
• 11,645,659 of the 84,756,009 outstanding common units of the Partnership, representing a 13.7% limited
partnership interest.
Stockholders’ Agreement
Prior to our initial public offering, our stockholders, including our named executive officers, certain of our
directors, Warburg Pincus and BofA, were party to the Stockholders’ Agreement. The Stockholders’ Agreement
(i) provided certain holders of our then outstanding preferred stock with preemptive rights relating to certain
issuances of securities by us or our subsidiaries, (ii) imposed restrictions on the disposition and transfer of our
securities, (iii) established vesting and forfeiture provisions for securities held by our management, (iv) provided
us with the option to repurchase our securities held by our management and directors upon the termination of
their employment or service to us in certain circumstances, and (v) imposed on us the obligation to furnish
financial information to Warburg Pincus and BofA as long as they maintain a certain ownership level in our
securities.
The Stockholders’ Agreement also required the stockholders party thereto to vote to elect to our Board of
Directors two of our executive officers (one of whom would be our chief executive officer unless otherwise
agreed by the majority holders), five individuals that were to be designated by Warburg Pincus and one
individual (two individuals if there are only four Warburg nominees or three individuals if there are only three
Warburg nominees) who were to be independent that were to be selected by Warburg Pincus, after consultation
with our chief executive officer and approved by the majority holders.
The Stockholders’ Agreement terminated upon completion of the IPO.
Registration Rights Agreement
Agreement with Series B Preferred Stock Investors
On October 31, 2005, we entered into an amended and restated registration rights agreement with the holders of
our then outstanding Series B preferred stock that received or purchased 6,453,406 shares of preferred stock
pursuant to a stock purchase agreement dated October 31, 2005. Pursuant to the registration rights agreement,
we agreed to register the sale of shares of our common stock that holders of such preferred stock received upon
conversion of the preferred stock, under certain circumstances. These holders include (directly or indirectly
through subsidiaries or affiliates), among others, Warburg Pincus and BofA.
Demand Registration Rights. At any time, the qualified holders have the right to require us by written notice to
register a specified number of shares of common stock in accordance with the Securities Act and the registration
rights agreement. The qualified holders have the right to request up to an aggregate of five registrations;
provided that such qualified holders are not limited in the number of demand registrations that constitute “shelf”
registrations pursuant to Rule 415 under the Securities Act. In no event shall more than one demand registration
occur during any six-month period or within 120 days after the effective date of a registration statement we file,
provided that no demand registration may be prohibited for that 120-day period more than once in any 12-month
period.
Piggy-back Registration Rights. If, at any time, we propose to file a registration statement under the Securities
Act with respect to an offering of common stock (subject to certain exceptions), for our own account, then we
must give at least 15 days’ notice prior to the anticipated filing date to all holders of registrable securities to
115
allow them to include a specified number of their shares in that registration statement. We will be required to
maintain the effectiveness of that registration statement until the earlier of 180 days after the effective date and
the consummation of the distribution by the participating holders.
Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and
limitations, including the right of the underwriters to limit the number of shares to be included in a registration
and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay
all registration expenses in connection with our obligations under the registration rights agreement, regardless of
whether a registration statement is filed or becomes effective.
Related Party Transactions Involving the Partnership
On April 27, 2010, we closed on our sale of the Permian Business and Straddle Assets to the Partnership,
pursuant to which we contributed to the Partnership (i) all of the limited partner interests in Targa Midstream
Services Limited Partnership (“TMS”), (ii) all of the limited liability company interests in Targa Gas Marketing
LLC (“TGM”), (iii) all of the limited and general partner interests in Targa Permian LP (“Permian”), (iv) all of
the limited partner interests in Targa Straddle LP (“Targa Straddle”), and (v) all of the limited liability company
interests in Targa Straddle GP LLC (“Targa Straddle GP”), (such limited partner interests in TMS, Permian and
Targa Straddle, general partner interests in Permian and limited liability company interests in TGM and Targa
Straddle GP being collectively referred to as the “Permian/ Straddle Business”), for aggregate consideration of
$420 million, subject to certain adjustments. Pursuant to the Permian/Straddle Purchase Agreement, we have
indemnified the Partnership, its affiliates and their respective officers, directors, employees, counsel,
accountants, financial advisers and consultants from and against (i) all losses that they incur arising from any
breach of our representations, warranties or covenants in the Permian/Straddle Purchase Agreement and (ii)
certain environmental, operational and litigation matters. The Partnership has indemnified us, our affiliates and
our respective officers, directors, employees, counsel, accountants, financial advisers and consultants from and
against all losses that we incur arising from or out of (i) the business or operations of the Permian/Straddle
Business (whether relating to periods prior to or after the closing of the acquisition of the Permian/Straddle
Business) to the extent such losses are not matters for which we have indemnified the Partnership or (ii) any
breach of the Partnership’s representations, warranties or covenants in the Permian/Straddle Purchase
Agreement. Certain of our indemnification obligations are subject to an aggregate deductible of $6.3 million and
a cap equal to $46.2 million. In addition, the parties’ reciprocal indemnification obligations for certain tax
liability and losses are not subject to the deductible and cap. Our environmental indemnification was limited to
matters for which we receive notice and a claim for indemnification prior to the second anniversary of the
closing. Indemnification claims for breaches of representations and warranties (other than for certain
fundamental representations and warranties) must be delivered to us prior to the first anniversary of the closing.
We have received no claims for indemnification under the Permian/Straddle Purchase Agreement.
On August 25, 2010, we closed on the sale of our interest in the Versado operations to the Partnership, pursuant
to which we contributed to the Partnership (i) all of the member interests in Targa Versado GP LLC (“Targa
Versado GP”) and (ii) all of the limited partner interests in Targa Versado LP (“Targa Versado LP”), for
aggregate consideration of $247 million, subject to certain adjustments, including the issuance to us of 89,813
common units and the issuance to us of 1,833 general partner units, enabling us to maintain our 2% general
partner interest in the Partnership. Targa Versado GP and Targa Versado LP, collectively, own the interests in
Versado. Pursuant to the Versado Purchase Agreement, we indemnified the Partnership, its affiliates and their
respective officers, directors, employees, counsel, accountants, financial advisers and consultants from and
against (i) all losses that they incur arising from any breach of our representations, warranties or covenants in
the Versado Purchase Agreement and (ii) certain environmental matters. The Partnership has indemnified us,
our affiliates and our respective officers, directors, employees, counsel, accountants, financial advisers and
consultants from and against all losses that we incur arising from or out of (i) the business or operations of
Targa Versado GP and Targa Versado LP (whether relating to periods prior to or after the closing of the
acquisition of the interests in Versado) to the extent such losses are not matters for which we have indemnified
the Partnership or (ii) any breach of the Partnership’s representations, warranties or covenants in the Versado
Purchase Agreement. Certain of our indemnification obligations are subject to an aggregate deductible of $3.4
million and a cap equal to $25.3 million. In addition, the parties’ reciprocal indemnification obligations for
certain tax liability and losses are not subject to the deductible and cap. Pursuant to the Versado Purchase
Agreement, we also agreed to reimburse the Partnership for maintenance capital expenditure amounts incurred
by the Partnership or its subsidiaries in respect of certain New Mexico Environmental Department capital
projects.
116
On September 28, 2010, we closed on the sale of our interests in the VESCO operations to the Partnership,
pursuant to which the Partnership acquired all of the member interests in Targa Capital LLC (“Targa Capital”),
for aggregate consideration of $175.6 million, subject to certain adjustments. Targa Capital owns a 76.7536%
ownership interest in VESCO. Pursuant to the VESCO Purchase Agreement, we indemnified the Partnership, its
affiliates and their respective officers, directors, employees, counsel, accountants, financial advisers and
consultants from and against (i) all losses that they incur arising from any breach of our representations,
warranties or covenants in the VESCO Purchase Agreement and (ii) certain environmental and litigation
matters. The Partnership has indemnified us, our affiliates and our respective officers, directors, employees,
counsel, accountants, financial advisers and consultants from and against all losses that we incur arising from or
out of (i) the business or operations of Targa Capital (whether relating to periods prior to or after the closing of
the acquisition of Targa Capital) to the extent such losses are not matters for which we have indemnified the
Partnership or (ii) any breach of the Partnership’s representations, warranties or covenants in the VESCO
Purchase Agreement. Certain of our indemnification obligations are subject to an aggregate deductible of $2.5
million and a cap equal to $18.4 million. In addition, the parties’ reciprocal indemnification obligations for
certain tax liability and losses are not subject to the deductible and cap.
Omnibus Agreement
Our Omnibus Agreement with the Partnership addresses the reimbursement to us for costs incurred on the
Partnership’s 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 us at our option if the
General Partner is removed as the Partnership’s general partner without cause and units held by us and our
affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a
Change of Control of the Partnership or its general partner.
Reimbursement of Operating and General and Administrative Expense
Under the terms of the Omnibus Agreement, the Partnership reimburses us for the payment of certain operating
and direct expenses, including compensation and benefits of operating personnel, and for the provision of
various general and administrative services for the Partnership’s benefit. Pursuant to these arrangements, we
perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk
management, health, safety and environmental, information technology, human resources, credit, payroll,
internal audit, taxes, engineering and marketing. The Partnership reimburses us for the direct expenses to
provide these services as well as other direct expenses we incur on the Partnership’s behalf, such as
compensation of operational personnel performing services for the Partnership’s benefit and the cost of their
employee benefits, including 401(k), pension and health insurance benefits. The general partner determines the
amount of general and administrative expenses to be allocated to the Partnership in accordance with the
partnership agreement. Since October 1, 2010, after the conveyance of all of our remaining operating assets by
us to the Partnership, substantially all of our general and administrative costs have been and will continue to be
allocated to the Partnership, other than our direct costs of being a separate reporting company.
During the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth
quarter of 2011, we will provide distribution support to the Partnership in the form of a reduction in the
reimbursement for general and administrative expense allocated to the Partnership if necessary (or make a
payment to the Partnership, if needed) for a 1.0 times distribution coverage ratio, at the distribution level, at the
time of the dropdown of the Downstream Business, of $0.5175 per limited partner unit, subject to maximum
support of $8.0 million in any quarter. No distribution support was necessary through the fourth quarter of 2010.
Competition
We are not restricted, under either the Partnership’s partnership agreement or the Omnibus Agreement, from
competing with the Partnership. We may acquire, construct or dispose of additional midstream energy or other
assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those
assets.
Contracts with Affiliates
Services Agreement. We entered into a service arrangement with Sajet Resources LLC, a subsidiary that we
spun off immediately prior to our IPO to persons who were equity holders in us, including our executive officers
and certain of our directors, Warburg Pincus and Bank of America Corporation (“BofA”). This company owns
117
certain real property and developmental intellectual property rights. Pursuant to the services arrangements, we
provide general and administrative services and other services in support of this company’s business operations
and will be reimbursed by this company for such services at our actual cost.
Indemnification Agreements. In February 2007, the Partnership and the General Partner entered into
indemnification agreements with each independent director of the General Partner. Each indemnification
agreement provides that each of the Partnership and the General Partner 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 the General Partner is jointly liable in the proceeding with the indemnitee, the Partnership
and the General Partner will contribute funds to the indemnitee for his Expenses (as defined in the in the
Indemnification Agreement) in proportion to relative benefit and fault of the Partnership or the General Partner
on the one hand and indemnitee on the other in the transaction giving rise to the proceeding.
Each indemnification agreement also provides that the Partnership and the General Partner will indemnify and
hold harmless the indemnitee against Expenses incurred for actions taken as a director or officer of the
Partnership or the General Partner or for serving at the request of the Partnership or the General Partner 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 indemnitee’s
conduct was unlawful. The indemnification agreement also provides that the Partnership and the General Partner
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.
In February 2007, we entered into parent indemnification agreements with each of our directors and officers,
including Messrs. Joyce, Whalen, Kagan and Joung who serve or served as directors and/or officers of the
General Partner. Each parent indemnification agreement provides that we will indemnify and hold harmless
each 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 indemnitee. If such
indemnification is unavailable as a result of a court decision and if we and the indemnitee are jointly liable in
the proceeding, we will contribute funds to the indemnitee for his Expenses in proportion to relative benefit and
fault of us and indemnitee in the transaction giving rise to the proceeding.
Each parent indemnification agreement also provides that we will indemnify the indemnitee for monetary
damages for actions taken as our director or officer or for serving at our request as a director or officer or
another position at another corporation or enterprise, as the case may be but only if (i) the indemnitee acted in
good faith and, in the case of conduct in his official capacity, in a manner he reasonably believed to be in our
best interests and, in all other cases, not opposed to our best interests and (ii) in the case of a criminal
proceeding, the indemnitee must have had no reasonable cause to believe that his conduct was unlawful. The
parent indemnification agreement also provides that we 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. In December
2010, we entered into a parent indemnification agreement with Mr. Meloy and in February 2011 we entered into
a parent indemnification agreement with Mr. Redd.
Relationships with Warburg Pincus LLC
Affiliates of Warburg Pincus beneficially own approximately 32.8% of our outstanding common stock.
Accordingly, Warburg Pincus can exert significant influence over us and any action requiring the approval of
the holders of our stock, including the election of directors and approval of significant corporate transactions.
Warburg’s concentrated ownership makes it less likely that any other holder or group of holders of common
stock will be able to affect the way we are managed or the direction of our business.
Chansoo Joung and Peter Kagan, two of our directors and directors of the General Partner during 2010, are
Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak from whom we buy natural
118
gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. During 2010
we purchased $41.5 million, of product from Broad Oak. Peter Kagan is also a director of Antero from whom
we buy natural gas and NGL products. Affiliates of Warburg Pincus own a controlling interest in Antero. We
purchased $0.1 million of product from Antero during 2010. These transactions were at market prices consistent
with similar transactions with nonaffiliated entities.
Relationships with Bank of America
Equity. Until December 10, 2010, BofA was a beneficial security holder of more than 5% of our common stock
as defined by Item 403(a) of Regulation S-K. After this date, BofA’s beneficial ownership of our outstanding
common stock dropped below 5%.
Financial Services. An affiliate of BofA is a lender and an agent under our and our subsidiaries’ senior credit
facilities with commitments of $86.0 million. BofA and its affiliates have engaged, and may in the future
engage, in other commercial and investment banking transactions with subsidiaries of the Company in the
ordinary course of their business. They have received, and expect to receive, customary compensation and
expense reimbursement for these commercial and investment banking transactions.
Hedging Arrangements. The Partnership entered into various commodity derivative transactions with BofA
which terminated, in accordance with the terms of the contracts, during 2010. The Partnership has no open
commodity derivatives with BofA as of December 31, 2010. During 2010 the Partnership received $1.9 million
from BofA in commodity derivative settlements.
Commercial Relationships. Our product sales included in revenues to affiliates of BofA during 2010 were $26.0
million. Our product purchases from affiliates of BofA during 2010 were $3.7 million.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between the General Partner
and its affiliates (including us), on the one hand, and the Partnership and its other limited partners, on the other
hand. The directors and officers of the General Partner have fiduciary duties to manage the General Partner and
us, if applicable, in a manner beneficial to our owners. At the same time, the General Partner has a fiduciary
duty to manage the Partnership in a manner beneficial to it and its unitholders. Please see “—Review, Approval
or Ratification of Transactions with Related Persons” below for additional detail of how these conflicts of
interest will be resolved.
Review, Approval or Ratification of Transactions with Related Persons
Our policies and procedures for approval or ratification of transactions with “related persons” are not contained
in a single policy or procedure. Instead, they were historically contained in the Stockholders Agreement and are
reflected in the general operation of our board of directors. Historically, our Stockholders Agreement prohibited
us from entering into, modifying, amending or terminating any transaction (other than certain compensatory
arrangements and sales or purchases of capital stock) with an executive officer, director or affiliate without the
prior written consent of the holders of at least a majority of our outstanding shares of Series B Preferred (or our
common stock if no Series B Preferred was outstanding). In addition, we were prohibited from entering into any
material transaction with Warburg Pincus and its affiliates (other than us, any of its subsidiaries or any our
managers, directors or officers or any of its subsidiaries) without the prior written consent of BofA. We
distribute and review a questionnaire to our executive officers and directors requesting information regarding,
among other things, certain transactions with us in which they or their family members have an interest. If a
conflict or potential conflict of interest arises between us and our affiliates (excluding the Partnership) on the
one hand and the Partnership and its limited partners (other than us and our affiliates), on the other hand, the
resolution of any such conflict or potential conflict is addressed as described under “—Conflicts of Interest.”
Pursuant to our Code of Conduct, our officers and directors are required to abandon or forfeit any activity or
interest that creates a conflict of interest between them and us or any of our subsidiaries, unless the conflict is
pre-approved by our board of directors.
Whenever a conflict arises between the General Partner or its affiliates, on the one hand, and the Partnership or
any other partner, on the other hand, the General Partner will resolve that conflict. The Partnership’s partnership
agreement contains provisions that modify and limit the general partner’s fiduciary duties to the Partnership’s
119
unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken that,
without those limitations, might constitute breaches of fiduciary duty.
The General Partner will not be in breach of its obligations under the partnership agreement or its duties to the
Partnership or its unitholders if the resolution of the conflict is:
• approved by the General Partner’s conflicts committee, although the General Partner is not obligated to
seek such approval;
• approved by the vote of a majority of the Partnership’s outstanding common units, excluding any
common units owned by the General Partner or any of its affiliates;
• on terms no less favorable to the Partnership than those generally being provided to or available from
unrelated third parties; or
• fair and reasonable to the Partnership, taking into account the totality of the relationships among the
parties involved, including other transactions that may be particularly favorable or advantageous to the
Partnership.
The General Partner may, but is not required to, seek the approval of such resolution from the conflicts
committee of its board of directors. If the General Partner does not seek approval from the conflicts committee
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 of 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 the partnership agreement, the general partner or its conflicts committee may consider any
factors they determines in good faith to consider when resolving a conflict. When the 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.
Director Independence
Messrs. Crisp, Hwang, Kagan, Redd and Tong are our independent directors under the NYSE’s listing
standards. Please see “Item 10. Directors, Executive Officers and Corporate Governance.” Our board of
directors examined the commercial relationships between us and companies for whom our independent directors
serve as directors or with whom family members of our independent directors have an employment relationship.
The commercial relationships reviewed consisted of product purchases and product sales at market prices
consistent with similar arrangements with unrelated entities.
120
Item 14. Principal Accountant Fees and Service
We have engaged PricewaterhouseCoopers LLP as our principal accountant. The following table summarizes
fees we were billed by PricewaterhouseCoopers LLP for independent auditing, tax and related services for each
of the last two fiscal years:
Year Ended December 31,
2010
2009
(In millions)
4.6 $
-
-
-
Audit fees (1)
$
Audit related fees (2)
Tax fees (3)
All other fees (4)
$
4.6 $
4.5
-
0.2
-
4.7
_______
(1) Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the
integrated audit of our annual financial statements and internal control over financial reporting, (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.
(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 of our financial statements and are not reported under
audit fees.
(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 and partnership tax planning
(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 LLP during the last two years.
Prior to the establishment of the Audit Committee in connection with our IPO, our board of directors approved
the use of PricewaterhouseCoopers LLP as our independent principal accountant. Following our IPO, the Audit
Committee has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant. All
services provided by our independent auditor are subject to pre-approval by the Audit Committee. The Audit
Committee is informed of each engagement of the independent auditor to provide services to us.
121
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
PART IV
Our Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of
these statements and accompanying footnotes, see “Index to Financial Statements” Page F-1 of this Annual
Report.
(a)(2) Financial Statement Schedules
All other 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 or will be filed within the
required timeframe.
(a)(3) Exhibits
Number
Description
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 LP’s 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 LP’s Current Report on Form 8-K filed October 24, 2007 (File
No. 001-33303)).
2.3
—
Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners
LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa
Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-
33303)).
2.4
—
Purchase and Sale Agreement, dated as of March 31, 2010, by and among Targa Resources
Partners LP, Targa LP Inc., Targa Permian GP LLC and Targa Midstream Holdings LLC
(incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on
Form 8-K filed April 1, 2010 (File No. 001-33303)).
2.5
—
Purchase and Sale Agreement, dated as of August 6, 2010, by and among Targa Resources
Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa
Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-
33303)).
2.6
—
Purchase and Sale Agreement, dated September 13, 2010, by and between Targa Resources
Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa
Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-
33303)).
3.1
—
Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by
reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed
December 16, 2010 (File No. 001-34991)).
3.2
—
Form of Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to
Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010
(File No. 001-34991)).
3.3
—
Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to
Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed
122
November 16, 2006 (File No. 333-138747)).
3.4
—
Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3
to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007
(File No. 333-138747)).
3.5
—
First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP
(incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on
Form 8-K filed February 16, 2007 (File No. 001-33303)).
3.6
—
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Targa
Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
3.7
—
Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference
to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed
January 19, 2007 (File No. 333-138747)).
3.8
—
Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by
reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed
October 31, 2007 (File No. 333-147066)).
3.9*
3.10
__
—
Amendment to Amended and Restated Certificate of Incorporation of Targa Resources, Inc.
Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit
3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File
No. 333-147066)).
4.1
—
Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Targa
Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No.
333-169277)).
10.1
—
10.2
—
10.3
—
Credit Agreement, dated as of January 5, 2010 among Targa Resources, Inc., as the borrower,
Deutsche Bank Trust Company Americas, as the administrative agent, Deutsche Bank
Securities Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers, Credit Suisse
Securities (USA) LLC and Citadel Securities LLC, as the co-syndication agents, Deutsche Bank
Securities Inc., Credit Suisse Securities (USA) LLC, Citadel Securities LLC, Banc of America
Securities LLC and Barclays Capital, as joint book runners, Bank of America, N.A., Barclays
Bank PLC and ING Capital LLC, as the co-documentation agents and the other lenders party
thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration
Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
Amendment No. 1 to Credit Agreement, dated November 12, 2010 among TRI Resources Inc.,
as the Borrower, Deutsche Bank Trust Company Americas, Credit Suisse AG, Cayman Islands
Branch, Bank of America, N.A., ING Capital LLC and Barclays Bank PLC, as Lenders, and
Deutsche Bank Trust Company Americas, as Administrative Agent (incorporated by reference
to Exhibit 10.94 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed
November 16, 2010 (File No. 333-169277)).
Holdco Credit Agreement, dated as of August 9, 2007 among Targa Resources Investments
Inc., as the borrower, Credit Suisse, as the administrative agent, Credit Suisse Securities (USA)
LLC and Deutsche Bank Securities Inc. and, as joint lead arrangers, Deutsche Bank Securities
Inc., as the syndication agent, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities
Inc., Lehman Brothers, Inc. and Merrill Lynch Capital Corporation, as joint book runners,
Lehman Commercial Paper Inc. and Merrill Lynch Capital Corporation, as the co-
documentation agents and the other lenders party thereto (incorporated by reference to Exhibit
4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010
(File No. 333-169277)).
123
10.4
—
10.5
—
Amendment No. 1 to Holdco Credit Agreement, dated January 5, 2010 among Targa Resources
Investments Inc., as the Borrower, Targa Resources, Inc., as Lender, Targa Capital, LLC, as
Lender, and Credit Suisse AG, Cayman Islands Brach, as Administrative Agent (incorporated
by reference to Exhibit 10.92 to Targa Resources Corp.’s Registration Statement on Form S-
1/A filed November 12, 2010 (File No. 333-169277)).
Amended and Restated Credit Agreement, dated July 19, 2010, by and among Targa Resources
Partners LP, as the borrower, Bank of America, N.A., as the administrative agent, Wells Fargo
Bank, National Association and the Royal Bank of Scotland plc, as the co-syndication agents,
Deutsche Bank Securities Inc. and Barclays Bank PLC, as the co-documentation agents, Banc
of America Securities LLC, Wells Fargo Securities, LLC and RBS Securities Inc., as joint lead
arrangers and co-book managers and the other lenders part thereto (incorporated by reference to
Exhibit 10.1 to Targa Resources Partners LP’s Form 8-K filed on July 21, 2010 (File No. 001-
33303)).
10.6
—
Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated as of
October 28, 2005 (incorporated by reference to Exhibit 10.2 to Targa Resources Inc.’s
Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.7
—
First Amendment to Amended and Restated Stockholders’ Agreement, dated January 26, 2006
(incorporated by reference to Exhibit 10.3 to Targa Resources Inc.’s Registration Statement on
Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.8
—
Second Amendment to Amended and Restated Stockholders’ Agreement, dated March 30, 2007
(incorporated by reference to Exhibit 10.4 to Targa Resources Inc.’s Registration Statement on
Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.9
—
Third Amendment to Amended and Restated Stockholders’ Agreement, dated May 1, 2007
(incorporated by reference to Exhibit 10.5 to Targa Resources Inc.’s Registration Statement on
Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.10
—
Fourth Amendment to Amended and Restated Stockholders’ Agreement, dated December 7,
2007 (incorporated by reference to Exhibit 10.6 to Targa Resources Inc.’s Registration
Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.11
—
Fifth Amendment to Amended and Restated Stockholders’ Agreement, dated December 1, 2009
(incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Current Report on Form
8-K filed December 2, 2009 (File No. 333-147066)).
10.12
—
Form of Sixth Amendment to Amended and Restated Stockholders’ Agreement (incorporated
by reference to Exhibit 10.11 to Targa Resources Corp.’s Registration Statement on Form S-
1/A filed November 12, 2010 (File No. 333-169277)).
10.13+
—
Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to
Exhibit 10.10 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December
18, 2007 (File No. 333-147066)).
10.14+
—
First Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated
by reference to Exhibit 10.11 to Targa Resources Inc.’s Registration Statement on Form S-4/A
filed December 18, 2007 (File No. 333-147066)).
10.15+
—
Second Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan
(incorporated by reference to Exhibit 10.12 to Targa Resources Inc.’s Registration Statement on
Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.16+
—
Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-
Employee Directors) (incorporated by reference to Exhibit 10.13 to Targa Resources Inc.’s
Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
124
10.17+
—
Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-
Director Management and Other Employees) (incorporated by reference to Exhibit 10.14 to
Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File
No. 333-147066)).
10.18+
—
Form of Targa Resources Investments Inc. Incentive Stock Option Agreement (incorporated by
reference to Exhibit 10.15 to Targa Resources Inc.’s Registration Statement on Form S-4/A
filed December 18, 2007 (File No. 333-147066)).
10.19+
—
Form of Targa Resources Investments Inc. Restricted Stock Agreement (incorporated by
reference to Exhibit 10.16 to Targa Resources Inc.’s Registration Statement on Form S-4/A
filed December 18, 2007 (File No. 333-147066)).
10.20+
—
Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred
stock option exchange for directors) (incorporated by reference to Exhibit 10.17 to Targa
Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-
147066)).
10.21+
—
Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred
stock option exchange for employees) (incorporated by reference to Exhibit 10.18 to Targa
Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-
147066)).
10.22+
—
Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 of
Targa Resources Corp.’s Registration Statement on Form S-8 filed December 9, 2010 (File No.
333-171082)).
10.23+
—
Form of Targa Resources Corp. Restricted Stock Agreement – 2010 (incorporated by reference
to Exhibit 4.4 of Targa Resources Corp.’s Registration Statement on Form S-8 filed December
9, 2010 (File No. 333-171082)).
10.24+
—
Form of Targa Resources Corp. 2011 Restricted Stock Agreement – 2011 (incorporated by
reference to Exhibit 10.2 of Targa Resources Corp.’s Current Report on Form 8-K filed
February 18, 2011 (File No. 001-34991)).
10.25+
—
Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.27 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December
18, 2007 (File No. 333-147066)).
10.26+
—
Targa Resources Investments Inc. 2008 Annual Incentive Compensation Plan (incorporated by
reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed
February 27, 2009 (File No. 001-33303)).
10.27+
—
Targa Resources Investments Inc. 2009 Annual Incentive Compensation Plan (incorporated by
reference to Exhibit 10.14 to Targa Resources Partners LP’s Annual Report on Form 10-K filed
February 27, 2009 (File No. 001-33303)).
10.28+
—
Targa Resources Investments Inc. 2010 Annual Incentive Compensation Plan (incorporated by
reference to Exhibit 10.22 to Targa Resources Partners LP’s Annual Report on Form 10-K filed
March 4, 2010 (File No. 001-33303)).
10.29+
—
Targa Resources Corp. 2011 Annual Incentive Compensation Plan (incorporated by reference
to Exhibit 10.27 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February
25, 2011 (File No. 001-33303)).
125
10.30+
—
Targa Resources Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit
10.2 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1,
2007 (File No. 333-138747)).
10.31+
—
Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2007 (incorporated
by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K
filed February 13, 2007 (File No. 001-33303)).
10.32+
—
Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2010 (incorporated
by reference to Exhibit 10.15 to Targa Resources Partners LP’s Form 10-K filed March 4, 2010
(File No. 001-33303)).
10.33+
—
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2007
(incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on
Form 8-K filed with the SEC on February 13, 2007 (File No. 001-33303)).
10.34+
—
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2008
(incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on
Form 8-K filed January 22, 2008 (File No. 001-33303)).
10.35+
—
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2009
(incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on
Form 8-K filed January 28, 2009 (File No. 001-33303)).
10.36+
—
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2010
(incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on
Form 8-K filed December 7, 2009 (File No. 001-33303)).
10.37+
—
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2011
(incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on
Form 8-K filed February 18, 2011) (File No. 001-33303)).
10.38
—
Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the Guarantors named therein and U.S. Bank National Association
(incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 11,
2008 (File No. 333-147066)).
10.39
—
10.40
—
10.41
—
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National
Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s
Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed November 9, 2009 (File No. 001-33303)).
126
10.42
—
10.43
—
10.44
—
10.45
—
10.46
—
10.47
—
10.48
—
10.49
—
10.50
—
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.13 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National
Association (incorporated by reference to Exhibit 4.15 to Targa Resources Partners LP’s
Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.17 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.19 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National
Association (incorporated by reference to Exhibit 4.21 to Targa Resources Partners LP’s
Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.23 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.25 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
127
10.51
—
10.52
—
10.53
—
10.54
—
10.55
—
10.56
—
10.57
—
10.58
—
10.59
—
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa
Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa
Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa
Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q
filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa
Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa
Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q
filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa
Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated August 10, 2010 to Indenture dated June 18, 2008, among Targa
MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 10.46 to Targa Resources Corp.’s Registration Statement on Form S-
1/A filed November 12, 2010 (File No. 333-169277)).
Supplemental Indenture dated September 20, 2010 to Indenture dated June 18, 2008, among
Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP,
Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
Supplemental Indenture dated October 25, 2010 to Indenture dated June 18, 2008, among Targa
Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q
filed November 5, 2010 (File No. 001-33303)).
128
10.60
—
Registration Rights Agreement dated July 6, 2009, among Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the Guarantors named therein and the initial
purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners
LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
10.61
—
Indenture dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the Guarantors named therein and U.S. Bank National
Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current
Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
10.62
—
10.63
—
10.64
—
10.65
—
10.66
—
10.67
—
10.68
—
10.69
—
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National
Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s
Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.14 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National
Association (incorporated by reference to Exhibit 4.16 to Targa Resources Partners LP’s
Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.18 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.70
—
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
129
10.71
—
10.72
—
10.73
—
10.74
—
10.75
—
10.76
—
10.77
—
10.78
—
10.79
—
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.20 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National
Association (incorporated by reference to Exhibit 4.22 to Targa Resources Partners LP’s
Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.24 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.26 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Gas
Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa
Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa
Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa
Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q
filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa
Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa
Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q
filed May 6, 2010 (File No. 001-33303)).
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa
Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report
on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.80
—
Supplemental Indenture dated August 10, 2010 to Indenture dated July 6, 2009, among Targa
MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
130
10.81
—
10.82
—
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 10.66 to Targa Resources Corp.’s Registration Statement on Form S-
1/A filed November 12, 2010 (File No. 333-169277)).
Supplemental Indenture dated September 20, 2010 to Indenture dated July 6, 2009, among
Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP,
Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
Supplemental Indenture dated October 25, 2010 to Indenture dated July 6, 2009, among Targa
Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance
Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated
by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q
filed November 5, 2010 (File No. 001-33303)).
10.83
—
First Supplemental Indenture dated February 2, 2011 to that certain Indenture dated July 6,
2009 (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report
on Form 8-K filed February 2, 2011 (File No. 001-33303)).
10.84
—
Registration Rights Agreement dated as of August 13, 2010 among the Issuers, the Guarantors
and Banc of America Securities LLC, as representative of the several initial purchasers
(incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on
Form 8-K filed August 16, 2010 (File No. 001-33303)).
10.85
—
Indenture dated as of August 13, 2010 among the Issuers and the Guarantors and U.S. Bank
National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources
Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).
10.86
—
10.87
—
Supplemental Indenture dated September 20, 2010 to Indenture dated August 13, 2010, among
Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP,
Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners
LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001- 33303)).
Supplemental Indenture dated October 25, 2010 to Indenture dated August 13, 2010, among
Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners
Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on
Form 10-Q filed November 5, 2010 (File No. 001-33303)).
10.88
—
Registration Rights Agreement dated February 2, 2011 among the Issuers, the Guarantors,
Deutsche Bank Securities Inc., as representative of the several initial purchasers, and the Dealer
Managers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current
Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
10.89
—
Indenture dated February 2, 2011 among the Issuers, the Guarantors and U.S. Bank National
Association, as trustee thereto (incorporated by reference to Exhibit 4.1 to Targa Resources
Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
10.90
—
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 LP’s Current Report on Form 8-K filed February 16, 2007
(File No. 001-33303)).
10.91
—
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
131
10.92
—
10.93
—
Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24,
2007 (File No. 001-33303)).
Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and
among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating
LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa
Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-
33303)).
Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among
Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream
Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa
Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources
Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.94
—
Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among
Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC
(incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on
Form 8-K filed August 26, 2010 (File No. 001-33303)).
10.95
—
Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and
among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP
LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current
Report on Form 8-K filed October 4, 2010 (file No. 001-33303)).
10.96
—
Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among
Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa
Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s
Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.97
—
First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010,
by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and
Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources
Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.98+
—
Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the
directors and officers thereof (incorporated by reference to Exhibit 10.4 to Targa Resources
Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)).
10.99+
—
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 LP’s Annual
Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.100+
—
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 LP’s Annual
Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.101+
—
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
LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
21.1*
—
List of Subsidiaries of Targa Resources Corp.
23.1*
Consent of PricewaterhouseCoopers LLP
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
132
Securities Exchange Act of 1934.
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.
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.
32.1*
32.2*
—
—
* Filed herewith
** Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any
omitted exhibit or Schedule to the SEC upon request.
+ Management contract or compensatory plan or arrangement
133
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.
SIGNATURES
Targa Resources Corp.
(Registrant)
/s/ Matthew J. Meloy
By:
Matthew J. Meloy
Senior Vice President, Chief
Financial Officer and Treasurer
(Principal Financial Officer)
Date: February 25, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the
following persons on behalf of the registrant and in the capacities indicated on February 25, 2011.
Signature
Title (Position with Targa Resources Corp.)
/s/ Rene R. Joyce
Rene R. Joyce
Chief Executive Officer and Director
(Principal Executive Officer)
/s/ Matthew J. Meloy
Mathew J. Meloy
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
/s/ John R. Sparger
John R. Sparger
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
/s/ James W. Whalen
James W. Whalen
Executive Chairman of the Board
/s/ Charles R. Crisp
Charles R. Crisp
Director
/s/ In Seon Hwang
In Seon Hwang
Director
/s/ Peter R. Kagan
Peter R. Kagan
Director
/s/ Chris Tong
Chris Tong
Director
/s/ Ershel C. Redd Jr.
Ershel C. Redd Jr.
Director
134
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
TARGA RESOURCES CORP. AUDITED CONSOLIDATED FINANCIAL STATEMENTS
Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2010,
2009 and 2008
Consolidated Statement of Changes in Owners' Equity for the Years Ended December 31, 2010, 2009
and 2008
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008
Notes to Consolidated Financial Statements
Note 1 ― Organization and Operations
Note 2 ― Basis of Presentation
Note 3 ― Out of Period Adjustment
Note 4 ― Significant Accounting Policies
Note 5 ― Inventory
Note 6 ― Property, Plant and Equipment
Note 7 ― Asset Retirement Obligation
Note 8 ― Investment in Unconsolidated Affiliates
Note 9 ― Debt Obligations
Note 10 ― Convertible Participating Preferred Stock
Note 11 ― Partner Units and Related Matters
Note 12 ― Earnings Per Share
Note 13 ― Insurance Claims
Note 14 ― Derivative Instruments and Hedging Activities
Note 15 ― Related Party Transactions
Note 16 ― Commitments and Contingencies
Note 17 ― Fair Value Measurements
Note 18 ― Income Taxes
Note 19 ― Fair Value of Financial Instruments
Note 20 ― Supplemental Cash Flow Information
Note 21 ― Segment Information
Note 22 ― Other Operating Income
Note 23 ― Significant Risks and Uncertainties
Note 24 ― Stock and Other Compensation Plans
Note 25 ― Selected Quarterly Financial Data
F-1
F-2
F-3
F-4
F-5
F-6
F-7
F-8
F-9
F-9
F-9
F-10
F-14
F-14
F-14
F-15
F-16
F-20
F-20
F-22
F-23
F-24
F-26
F-28
F-29
F-31
F-32
F-33
F-33
F-36
F-36
F-39
F-43
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting.
Our internal control over financial reporting is a process designed 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.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting
objectives because of its inherent limitations. Internal control over financial reporting is a process that involves
human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human
failures. Internal control over financial reporting also can be circumvented by collusion or improper
management override. Because of such limitations, there is a risk that material misstatements may not be
prevented or detected on a timely basis by internal control over financial reporting. However, these inherent
limitations are known features of the financial reporting process. Therefore, it is possible to design into the
process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control—Integrated Framework”
issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the
effectiveness of the internal control over financial reporting. Based on that evaluation, management has
concluded that the internal control over financial reporting was effective as of December 31, 2010.
/s/ Rene R. Joyce
Rene R. Joyce
Chief Executive Officer
(Principal Executive Officer)
/s/ Matthew J. Meloy
Matthew J. Meloy
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
F-2
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Targa Resources Corp.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of
operations, of comprehensive income (loss), of changes in owners' equity and of cash flows present fairly, in all
material respects, the financial position of Targa Resources Corp. and its subsidiaries (the "Company") at
December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company’s 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.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2011
F-3
TARGA RESOURCES CORP.
CONSOLIDATED BALANCE SHEETS
Current assets:
Cash and cash equivalents
Trade receivables, net of allowances of $7.9 million and $8.0 million
ASSETS
Inventory
Deferred income taxes
Assets from risk management activities
Other current assets
Total current assets
Property, plant and equipment, at cost
Accumulated depreciation
Property, plant and equipment, net
Long-term assets from risk management activities
Other long-term assets
Total assets
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable
Accrued liabilities
Current maturities of debt
Deferred income taxes
Liabilities from risk management activities
Total current liabilities
Long-term debt, less current maturities
Long-term liabilities from risk management activities
Deferred income taxes
Other long-term liabilities
Commitments and contingencies (see Note 16)
Convertible cumulative participating series B preferred stock
(100.0 million shares authorized, none and 6.4 million shares issued and
outstanding at December 31, 2010 and December 31, 2009)
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock
($0.001 par value, 300.0 million shares authorized, 42.3 million and 3.9 million
shares issued and outstanding at December 31, 2010 and December 31, 2009)
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive income (loss)
Treasury stock, at cost
Total Targa Resources Corp. stockholders' equity
Noncontrolling interests in subsidiaries
Total owners' equity
Total liabilities and owners' equity
See notes to consolidated financial statements
F-4
$
$
$
December 31,
2010
2009
(In millions)
$
$
$
188.4
466.6
50.4
3.6
25.2
16.3
750.5
3,331.4
(822.4)
2,509.0
18.9
115.4
3,393.8
254.2
335.8
-
-
34.2
624.2
1,534.7
32.8
111.6
54.4
252.4
404.3
39.4
-
32.9
16.0
745.0
3,193.3
(645.2)
2,548.1
13.8
60.6
3,367.5
206.4
304.3
12.5
1.4
29.2
553.8
1,593.5
43.8
50.0
63.1
-
308.4
-
244.5
(100.8)
0.6
-
144.3
891.8
-
194.0
(85.8)
(20.3)
(0.5)
87.4
667.5
1,036.1
3,393.8
$
754.9
3,367.5
$
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
Revenues
Costs and expenses:
Product purchases
Operating expenses
Depreciation and amortization expenses
General and administrative expenses
Other
Income from operations
Other income (expense):
Interest expense, net
Equity in earnings of unconsolidated investments
Gain (loss) on debt repurchases (see Note 9)
Gain on early debt extinguishment (see Note 9)
Gain on insurance claims (see Note 13)
Gain (loss) on mark-to-market derivative instruments
Other income
Income before income taxes
Income tax (expense) benefit:
Current
Deferred
Net income
Less: Net income attributable to noncontrolling interest
Net income (loss) attributable to Targa Resources Corp.
Dividends on Series B preferred stock
Undistributed earnings attributable to preferred shareholders
Dividends on common equivalents
Net income (loss) available to common shareholders
Year Ended December 31,
2009
2010
2008
(In millions, except per share amounts)
$
5,469.2
$
4,536.0
$
7,998.9
4,687.7
3,791.1
7,218.5
260.2
185.5
144.4
(4.7)
5,273.1
196.1
235.0
170.3
120.4
2.0
275.2
160.9
96.4
13.4
4,318.8
7,764.4
217.2
234.5
(110.9)
(132.1)
(141.2)
5.4
(17.4)
12.5
-
(0.4)
0.5
85.8
10.6
(33.1)
(22.5)
63.3
78.3
(15.0)
(9.5)
-
(177.8)
(202.3)
5.0
(1.5)
9.7
-
0.3
1.2
14.0
25.6
3.6
18.5
(1.3)
-
99.8
153.7
(1.6)
(19.1)
(20.7)
79.1
49.8
29.3
(17.8)
(11.5)
-
-
-
$
(1.3)
(18.0)
(19.3)
134.4
97.1
37.3
(16.8)
(20.5)
-
-
-
Net income (loss) available per common share
$
(30.94)
$
Weighted average shares outstanding - basic and diluted
6.5
3.8
3.8
See notes to consolidated financial statements
F-5
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Year Ended December 31,
2010
2009
2008
(In millions)
Net income (loss) attributable to Targa Resources Corp.
Other comprehensive income (loss) attributable to Targa Resources Corp.
$
(15.0) $
29.3 $
37.3
Commodity hedging contracts:
Change in fair value
Reclassification adjustment for settled periods
Interest rate hedges:
Change in fair value
Reclassification adjustment for settled periods
Foreign currency translation adjustment
Related income taxes
Other comprehensive income (loss) attributable to Targa Resources Corp.
38.0
(4.0)
(1.9)
1.6
-
(12.8)
20.9
(49.6)
(39.5)
(7.2)
8.8
-
31.1
(56.4)
110.9
40.4
(5.0)
0.7
(1.8)
(52.8)
92.4
Comprehensive income (loss) attributable to Targa Resources Corp.
5.9
(27.1)
129.7
Net income attributable to noncontrolling interest
Other comprehensive income (loss) attributable to
noncontrolling interest:
Commodity hedging contracts:
Change in fair value
Reclassification adjustment for settled periods
Interest rate swaps:
Change in fair value
Reclassification adjustment for settled periods
Other comprehensive income (loss) attributable to
noncontrolling interest
Comprehensive income (loss) attributable to
noncontrolling interest
Total comprehensive income (loss)
78.3
49.8
97.1
14.5
(4.4)
(54.7)
(30.2)
95.5
24.7
(18.2)
7.7
(0.1)
6.9
(14.0)
2.0
(0.4)
(78.1)
108.2
77.9
83.8 $
(28.3)
(55.4) $
205.3
335.0
$
See notes to consolidated financial statements
F-6
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
Common Stock
Additional
Paid in Accumulated Comprehensive
Accumulated
Other
Non
Treasury Stock Controlling
Shares
Amount Capital
Deficit
Income (Loss) Shares Amount
Interest
Total
(In millions, except shares in thousands)
230.4 $
0.8
-
-
(16.8)
(152.4) $
-
-
-
-
(56.3)
-
-
-
-
18 $
-
-
70
-
- $
-
-
(0.5)
-
Balance, December 31, 2007
Option exercises
Forfeiture of non-vested common stock
Repurchases of common stock
Dividends of Series B preferred stock
Impact of equity transactions of the
Partnership
VESCO Acquisition
Distribution of property
Contributions
Dividends
Amortization of equity awards
Tax expense on vesting of common stock
Other comprehensive income
Net income
Balance, December 31, 2008
Option exercises
Forfeiture of non-vested common stock
Repurchases of common stock
Impact of equity transactions of the
Partnership
Contributions
Dividends
Dividends on Series B preferred stock
Amortization of equity awards
Tax expense on vesting of common stock
Other comprehensive income (loss)
Net income
Balance, December 31, 2009
Option exercises
Compensation on equity grants
Repurchases of common stock
Proceeds from sale of limited partner
interests in the Partnership
Impact of equity transactions of the
Partnership
Tax impact of equity offerings
Proceeds from Partnership Equity offerings
Dividends to noncontrolling interests
Dividends to common and common
equivalents
Dividends on Series B preferred stock
Series B Preferred Conversion
Other comprehensive income
Treasury shares retired
Net income (loss)
Balance, December 31, 2010
3,653 $
181
(27)
-
-
-
-
-
-
-
-
-
-
-
3,807
106
(3)
-
-
-
-
-
-
-
-
-
3,910
1,161
1,906
-
- $
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(0.4)
-
-
-
-
1.2
(1.0)
-
-
-
-
-
-
-
-
-
-
37.3
214.2
0.3
(115.1)
-
-
-
-
-
(2.9)
-
-
(17.8)
0.4
(0.2)
-
-
194.0
0.6
13.8
-
-
-
-
-
-
-
-
29.3
(85.8)
-
-
-
-
-
-
-
-
-
-
-
-
-
(15.0)
-
-
-
-
-
-
-
-
-
35,356
-
(41)
-
42,292 $
-
-
-
-
-
-
-
-
-
-
- $
258.9
(79.6)
-
-
(213.3)
(9.5)
79.9
-
(0.3)
-
See notes to consolidated financial statements
F-7
552.4 $
-
-
-
-
0.4
41.9
(14.8)
0.3
(98.5)
0.3
-
108.2
97.1
687.3
-
-
-
2.9
103.8
(98.5)
-
0.3
-
(78.1)
49.8
667.5
-
-
-
574.1
0.8
-
(0.5)
(16.8)
-
41.9
(14.8)
0.3
(98.5)
1.5
(1.0)
200.6
134.4
822.0
0.3
-
-
-
103.8
(98.5)
(17.8)
0.7
(0.2)
(134.5)
79.1
754.9
0.9
13.8
(0.1)
-
-
-
-
-
-
-
92.4
-
36.1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
88
-
(0.5)
-
-
-
-
9
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
97
(69)
-
13
(0.5)
0.3
-
(0.1)
-
-
-
-
-
-
(56.4)
-
(20.3)
-
-
-
-
-
-
224.4
224.4
-
-
-
-
-
-
-
-
-
-
-
-
(258.9)
-
317.8
(136.9)
-
-
-
20.9
-
-
-
-
-
-
(41)
-
-
-
-
-
0.3
-
-
-
-
(0.4)
-
78.3
-
(79.6)
317.8
(136.9)
(213.3)
(9.5)
79.9
20.5
-
63.3
244.5 $
(100.8) $
0.6
- $
- $
891.8 $
1,036.1
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense
Paid-in-kind interest expense
Compensation on equity grants
Depreciation and amortization expense
Asset impairment charges
Accretion of asset retirement obligations
Deferred income tax expense
Equity in earnings of unconsolidated investments, net of distributions
Risk management activities
Loss (gain) on sale of assets
Loss (gain) on debt repurchases
Loss (gain) on early debt extinguishment
Gain on property damage insurance settlement (See Note 13)
Repayments of interest of Holdco loan facility
Changes in operating assets and liabilities:
Accounts receivable and other assets
Inventory
Accounts payable and other liabilities
Net cash provided by operating activities
Cash flows from investing activities
Outlays for property, plant and equipment
Acquisitions, net of cash acquired
Proceeds from property insurance
Other
Net cash used in investing activities
Cash flows from financing activities
Loan Facilities of Targa:
Borrowings
Repayments
Loan Facilities of the Partnership:
Borrowings
Repayments
Dividends to noncontrolling interest
Proceeds from secondary offering of interests in the Partnership
Proceeds from Partnership equity offerings
Issuance of common stock
Repurchases of common stock
Dividends to common and common equivalent shareholders
Dividends to preferred shareholders
Costs incurred in connection with financing arrangements
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
2010
Year Ended December 31,
2009
(In millions)
2008
$
63.3
$
79.1
$
134.4
9.4
10.9
13.4
174.7
10.8
3.3
33.1
3.4
29.9
(1.5)
17.4
(12.5)
-
(0.9)
(119.2)
(11.4)
(15.6)
208.5
(139.3)
-
3.5
1.2
(134.6)
495.0
(1,087.4)
1,593.1
(1,057.0)
(136.9)
224.4
317.8
0.9
(0.1)
(210.1)
(238.0)
(39.6)
(137.9)
(64.0)
252.4
10.2
25.9
0.7
168.8
1.5
2.9
19.1
-
40.3
0.1
1.5
(9.7)
-
(6.0)
(140.1)
19.3
122.2
335.8
(99.4)
-
38.8
1.3
(59.3)
-
(589.2)
806.6
(596.6)
(98.5)
-
103.8
0.3
-
-
-
(13.3)
(386.9)
(110.4)
362.8
9.6
38.2
1.5
160.9
-
1.9
18.0
(9.4)
(64.5)
(5.9)
(25.6)
(3.6)
(18.5)
(4.3)
600.7
72.8
(515.5)
390.7
(132.3)
(124.9)
48.3
2.2
(206.7)
95.9
(74.6)
435.3
(350.6)
(98.5)
-
0.3
0.8
(0.5)
-
-
(7.2)
0.9
184.9
177.9
$
188.4
$
252.4
$
362.8
See notes to consolidated financial statements
F-8
TARGA RESOURCES CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data
within these footnote disclosures are stated in millions of dollars.
Note 1 —Organization and Operations
Targa Resources Corp., formerly Targa Resources Investments Inc. (“TRC”), is a Delaware corporation formed
on October 27, 2005. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or
“Targa” are intended to mean our consolidated business and operations.
Note 2 – Basis of Presentation
The accompanying financial statements and related notes present our consolidated financial position as of
December 31, 2010 and 2009, and the results of our operations, comprehensive income, cash flows and changes
in owners’ equity for the years ended December 31, 2010, 2009 and 2008.
We have prepared our consolidated financial statements in accordance with accounting principles generally
accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions
have been eliminated.
We are the sole member of Targa Resources GP LLC, the managing general partner of Targa Resources
Partners LP (“the Partnership”). Because we control the General Partner of the Partnership, under generally
accepted accounting principles, we must reflect our ownership interest in the Partnership on a consolidated
basis. Accordingly, our financial results are combined with the Partnership’s financial results in our
consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the
terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The
limited partner interests in the Partnership not owned by controlling affiliates of us are reflected in our results of
operations as net income attributable to non-controlling interests and in our balance sheet equity section as
noncontrolling interests in subsidiaries. Throughout these footnotes, we make a distinction where relevant
between financial results of the Partnership versus those of a standalone parent and its non-partnership
subsidiaries.
As of December 31, 2010, our interests in the Partnership consist of the following:
• a 2% general partner interest, which we hold through our 100% ownership interest in the general partner
of the Partnership;
• all Incentive Distribution Rights (IDRs); and
• 11,645,659 common units of the Partnership, representing a 15.4% limited partnership interest.
In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred
after December 31, 2010, up until the issuance of the financial statements. See Notes 9, 11, 12and 24.
Note 3 – Out of Period Adjustment
During 2009, we recorded adjustments related to prior periods which decreased our income before income taxes
for 2009 by $5.4 million. The adjustments consisted of $7.2 million related to debt issue costs that should have
been expensed during 2007 and $1.8 million of revenue which should have been recorded during 2006.
Had these adjustments been previously recorded in their appropriate periods, net income attributable to Targa
for the year ended December 31, 2009 would have increased by $3.4 million.
After evaluating the quantitative and qualitative aspects of these errors, we concluded that our previously issued
financial statements were not materially misstated and the effect of recognizing these adjustments in 2009
financial statements was not material to the 2009 or 2007 results of operations, financial position or cash flows.
F-9
Note 4 —Significant Accounting Policies
Consolidation Policy. Our consolidated financial statements include our accounts and those of our subsidiaries
in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities
in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our
consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities
of these undivided interests.
We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise
significant influence over the operating and financial policies of the investee.
Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and
investments with original maturities of three months or less. We consider cash equivalents to include short-term,
highly liquid investments that are readily convertible to known amounts of cash and which are subject to an
insignificant risk of changes in value.
Comprehensive Income. Comprehensive income includes net income and other comprehensive income (“OCI”),
which includes unrealized gains and losses on derivative instruments that are designated as hedges and currency
translation adjustments.
Allowance for Doubtful Accounts. 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 party’s
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 an allowance for
doubtful accounts may be required.
Inventory. Our product inventories consist primarily of NGLs. Most product inventories turn over monthly, but
some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season
requirements of our customers. Product inventories are valued at the lower of cost or market using the average
cost method.
Product Exchanges. Exchanges of NGL products are executed to satisfy timing and logistical needs of the
exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the
locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price
differential is recorded as either accounts receivable or accrued liabilities.
Gas Processing Imbalances. Quantities of natural gas and/or NGLs over-delivered or under-delivered related to
certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the
weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the
lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are
settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments. We employ derivative instruments to manage the volatility of cash flows due to
fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase
and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes
in fair value will depend on whether the derivative is designated and effective as a hedge for accounting
purposes. We have designated certain Downstream liquids marketing contracts that meet the definition of a
derivative as normal purchases and normal sales which, under GAAP, are not accounted for as derivatives.
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 (“AOCI”), a
component of owners’ equity, 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. As such, we include the cash flows from commodity derivative instruments in revenues and
from interest rate derivative instruments in interest expense.
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. The ultimate gain or loss on the derivative transaction upon settlement is also
recognized as a component of other income and expense.
F-10
We formally document all relationships between hedging instruments and hedged items, as well as our risk
management objectives and strategy for undertaking the hedge. This documentation includes the specific
identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner
in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an
ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting
changes in cash flows of hedged items.
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. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of
the unrealized gain or loss to earnings in the current period.
We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to
be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting
has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a
hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to
earnings immediately.
For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal
basis.
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.
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 or major asset component.
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.
We 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.
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. Asset recoverability is measured by comparing the carrying value of the asset with the
asset’s 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. If
the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to
write down the carrying amount of the asset to 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. 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. See Note 6.
Asset Retirement Obligations (“AROs”). AROs are legal obligations associated with the retirement of tangible
long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An
ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record 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 the straight-line 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.
F-11
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. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted
cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset
retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the
related long-lived asset. Upon settlement, AROs will be extinguished by us at either the recorded amount or we
will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost. See
Note 7.
Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are deferred and charged to
interest expense over the term of the related debt. Gains or losses on debt repurchases and debt extinguishments
include any associated unamortized debt issue costs.
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. See Note 16.
Income Taxes. We account for income taxes using the asset and liability method of accounting for deferred
income taxes and provide deferred income taxes for all significant temporary differences.
As part of the process of preparing our consolidated financial statements, we are required to estimate our income
taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax
payable and related tax expense together with assessing temporary differences resulting from differing treatment
of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred
tax assets and liabilities, which are included within our consolidated balance sheets.
We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income
and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or
all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the
valuation allowance would impact our income tax provision and net income in the period in which such a
determination is made. We consider all available evidence, both positive and negative, to determine whether,
based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about
our current financial position and our results of operations for the current and preceding years, as well as all
currently available information about future years, including our anticipated future performance, the reversal of
deferred tax liabilities and tax planning strategies.
We believe future sources of taxable income, reversing temporary differences and other tax planning strategies
will be sufficient to realize assets for which no reserve has been established.
Non-controlling Interest. Non-controlling interest represents third party ownership in the net assets of our
consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned
subsidiaries are consolidated with any third party investors’ interest shown as non-controlling interest within the
equity section of the balance sheet. In the statements of operations, non-controlling interest reflects the
allocation of earnings to third party investors. We account for the difference between the carrying amount of our
investment in the Partnership and the underlying book value arising from issuance of common units by the
Partnership, where we maintain control, as an equity transaction. If the Partnership issues common units at a
price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to
paid-in capital.
Revenue Recognition. Our primary types of sales and service activities reported as operating revenues include:
• sales of natural gas, NGLs and condensate;
• natural gas processing, from which we generate revenues through the compression, gathering, treating,
and processing of natural gas; and
• NGL fractionation, terminalling and storage, transportation and treating.
F-12
We recognize 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) collectability is reasonably assured.
For processing services, we receive either fees or a percentage of commodities as payment for these services,
depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes.
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. A significant portion of our Straddle plant processing contracts are
hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on
market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and
recognized in accordance with the criteria outlined above.
We generally report revenues gross in our consolidated statements of operations. Except for fee-based contracts,
we act 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.
Share-Based Compensation. We award share-based compensation to employees and directors in the form of
restricted stock, stock options and performance unit awards. Compensation expense on restricted stock and
stock options is measured by the fair value of the award as determined by management at the date of grant.
Compensation expense on performance unit awards that qualify as liability arrangements is initially measured
by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through
the settlement period. Compensation expense is recognized in general and administrative expense over the
requisite service period of each award. See Note 24.
Earnings per share. We account for earnings per share (EPS) in accordance with ASC 260 – Earnings per
Share. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue
common stock were exercised or converted into common stock or resulted in the issuance of common stock so
long as it does not have an anti-dilutive effect on EPS. Securities that meet the definition of a participating
security are required to be considered for inclusion in the computation of basic earnings per unit using the two-
class method. Prior to the conversion of the Series B Preferred Stock on December 10, 2010, we used the two-
class method of allocating earnings between our common and preferred class of stock outstanding for the
purposes of presenting net income per share. See Note 12.
Use of Estimates. When preparing financial statements in conformity with accounting principles generally
accepted in the United States of America, management must make estimates and assumptions based on
information available at the time. These estimates and assumptions affect the reported amounts of assets,
liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of
the financial statements. 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, product purchases and operating and general and administrative costs, (2)
developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing
long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts
to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially
from estimated amounts.
Accounting Pronouncements Recently Adopted
Fair Value Measurements
In January 2010, FASB issued guidance that requires additional disclosures about fair value measurements
including transfers in and out of Levels 1 and 2 and increased disclosure of different types of financial
instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales,
issuances and settlements should be presented separately. This guidance is effective for annual and interim
reporting periods beginning after December 15, 2009 for most of the new disclosures and for periods beginning
after December 15, 2010 for the new Level 3 disclosures. Comparative disclosures are not required in the first
F-13
year the disclosures are required. Our adoption did not have a material impact on our consolidated financial
statements.
Note 5 —Inventory
Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market
adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash
adjustments are charged to product purchases in the period they are recognized, with the related cash impact in
the subsequent period of sale. For 2010 and 2009, we did not recognize an adjustment to the carrying value of
our NGL inventory. At December 31, 2008, we recognized $6.0 million to reduce the carrying value of NGL
inventory to its net realizable value.
Note 6 – Property, Plant and Equipment
December 31,
2010
2009
Range of
Years
Targa
Resources
Partners LP
TRC-Non-
Partnership
Targa
Resources
Corp-
Consolidated
Targa
Resources
Partners LP
Targa
Resources
Corp-
Consolidated
TRC-Non-
Partnership
Natural gas gathering systems
$
1,630.9 $
-
1,630.9 $
1,578.0 $
- $
1,578.0 5 to 20
Processing and fractionation facilities
Terminalling and natural gas liquids
storage facilities
Transportation assets
Other property, plant and equipment
Land
Construction in progress
961.9
6.6
968.5
949.8
6.2
956.0 5 to 25
244.7
275.6
46.8
51.2
88.4
$
3,299.5 $
-
-
22.6
-
2.7
31.9
244.7
275.6
69.4
51.2
91.1
238.6
271.6
45.3
50.9
21.3
8.0
-
20.9
1.8
0.9
246.6 5 to 25
271.6 10 to 25
66.2 3 to 25
52.7
22.2
-
-
3,331.4 $
3,155.5 $
37.8 $
3,193.3
Note 7 – Asset Retirement Obligations
Our asset retirement obligations primarily relate to certain of the Partnership’s gas-gathering pipeline and
processing facilities and are included in our consolidated balance sheets as a component of other long-term
liabilities. The changes in our aggregate asset retirement obligations are as follows:
Beginning of period
Liabilities incurred(1)
Liabilities settled
Change in cash flow estimate(2)
Accretion expense
Year Ended December 31,
2010
2009
2008
$
34.1 $
34.0 $
-
-
0.3
3.3
-
-
(2.8)
2.9
12.6
16.9
(0.2)
2.8
1.9
End of period
________
(1) The 2008 amount relates to our consolidation of Venice Energy Services Company, LLC (“VESCO”). See Note 8.
(2) The change in cash flow estimate is primarily from a reassessment of abandonment cost estimates for our offshore gathering systems.
34.1 $
37.7 $
34.0
$
F-14
Note 8 – Investment in Unconsolidated Affiliates
As of December 31, 2010 and 2009, the Partnership’s unconsolidated investment consisted of a 38.8%
ownership interest in Gulf Coast Fractionators LP (“GCF), included in Other long-term assets on the
consolidated balance sheet.
Prior to July 31, 2008 our unconsolidated investments also included a 22.9% ownership interest in VESCO. On
July 31, 2008, we acquired an additional 53.9% interest, giving us effective control under the terms of the
operating agreement; therefore, we have consolidated the operations of VESCO in our financial results effective
August 1, 2008.
The following table shows the activity related to our unconsolidated investments for the years indicated:
Equity in earnings of
VESCO (1)(2)
GCF
Cash Distributions:
GCF
December 31,
2010
2009
2008
$
$
$
- $
5.4
5.4 $
- $
5.0
5.0 $
10.1
3.9
14.0
8.8 $
5.0 $
4.6
______
1)
2)
Includes our equity earnings through July 31, 2008.
Includes business interruption insurance claims of $4.1 million for 2008.
The allocated cost basis of GCF at the date of its acquisition date was less than our partnership equity balance
by approximately $5.2 million. This basis difference is being amortized over the estimated useful life of the
underlying fractionating assets (25 years) on a straight-line basis and is included as a component of the
Partnership’s equity in earnings of unconsolidated investments.
F-15
Note 9 – Debt Obligations
Our consolidated debt obligations include our obligations, the obligations of TRI Resources, Inc. (“TRI”) and
the Partnership’s obligations.
Long-term debt:
Obligations of Targa:
TRC Holdco loan facility, variable rate, due February 2015 (1)
$
89.3 $
385.4
December 31,
December 31,
2010
2009
TRI Senior secured revolving credit facility, variable rate, due July 2014 (2)
TRI Senior secured term loan facility, variable rate, due October 2012
TRI Senior unsecured notes, 8½% fixed rate, due November 2013
Obligations of the Partnership: (3)
Senior secured revolving credit facility, variable rate, due July 2015 (4)
Senior secured revolving credit facility, variable rate, due February 2012
Senior unsecured notes, 8¼% fixed rate, due July 2016
Senior unsecured notes, 11¼% fixed rate, due July 2017
Unamortized discounts, net of premiums
Senior unsecured notes, 7⅞% fixed rate, due October 2018
Total debt
Current maturities of TRI debt
Total long-term debt
Irrevocable standby letters of credit:
-
-
-
765.3
-
209.1
231.3
(10.3)
250.0
-
62.2
250.0
-
479.2
209.1
231.3
(11.2)
-
1,534.7
1,606.0
-
(12.5)
$
1,534.7 $
1,593.5
Letters of credit outstanding under the TRI senior secured synthetic letter of
credit facilities
$
- $
9.5
Letters of credit outstanding under senior secured revolving credit facilities
of the Partnership
$
101.3
101.3 $
108.4
117.9
___________
(1) Quarterly, we make an election to pay interest when due or refinance the interest as part of our long-term debt.
(2) As of December 31, 2010, availability under TRI’s senior secured revolving credit facility was $75.0 million.
(3) While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments
or debt payments with respect to the debt of the Partnership.
(4) As of December 31, 2010, availability under the Partnership’s senior secured revolving credit facility was $233.4 million.
The following table shows the range of interest rates paid and weighted average interest rate paid on our
variable-rate debt obligations during the year ended December 31, 2010:
TRC Holdco loan facility
Senior secured term loan facility of TRI, due 2014
Senior secured revolving credit facility of the Partnership
Range of interest Weighted average
rates paid
interest rate paid
3.3% to 5.4%
5.8% to 6.0%
1.2% to 5.0%
5.0%
5.9%
2.3%
Compliance with Debt Covenants
As of December 31, 2010, both we and the Partnership were in compliance with the covenants contained in our
various debt agreements.
F-16
TRC Holdco Loan Facility
During the year ended December 31, 2010, we completed transactions that have been recognized in our
consolidated financial statements as a debt extinguishment, and recognized a pretax gain of $36.8 million. The
transactions, executed by us, were payments of $269.3 million to acquire $306.1 million of outstanding
borrowings (including accrued interest of $23.1 million) under our Holdco credit agreement (“Holdco debt”)
and write offs of associated debt issue costs totaling $2.0 million. After this transaction, we removed all of the
debt covenants associated with the TRC Holdco Loan Facility, as we have cumulatively repurchased over 50%
of the original principal of the Holdco debt.
On November 3, 2010, we amended our Holdco agreement to name our wholly-owned subsidiary, Targa
Resources Inc. (“TRI”), as guarantor to our obligations under the credit agreement. The operations and assets of
the Partnership continue to be excluded as guarantors of the Holdco debt.
During the year ended December 31, 2009, we completed a transaction that has been recognized in our
consolidated financial statements as a debt extinguishment, and recognized a pretax gain of $24.5 million, net of
debt issue costs of $0.7 million. The transactions, executed by TRI, were payments of $39.3 million to acquire
$64.5 million of outstanding borrowings (including accrued interest of $6.0 million) under our Holdco debt. We
wrote-off $0.7 million of associated debt issuance costs.
Interest on borrowings are payable, at our option, either (i) entirely in cash, (ii) entirely by increasing the
principal amount of the outstanding borrowings or (iii) 50% cash and 50% by increasing the principal amount of
the outstanding borrowings.
Borrowings outstanding under the credit facility bear interest at a rate equal to an applicable rate plus, at our
option, either (i) a base rate determined by reference to the higher of (1) the prime rate of Credit Suisse or (2)
the federal funds rate plus 0.5% or (ii) LIBOR as determined by reference to the costs of funds for dollar
deposits for the interest period relevant to such borrowing adjusted for certain statutory reserves. At December
31, 2010, the applicable rate for borrowings under the credit facility was 4% with respect to base rate
borrowings and 5% with respect to LIBOR borrowings.
Principal amounts outstanding under the credit facility are due and payable in February 2015. We may prepay
all of part of the principal amount outstanding, at our option, at 101% of the principal amount outstanding until
August 9, 2011, then at 100% of the principal amount outstanding.
TRI Senior Secured Credit Agreement
On January 5, 2010 TRI entered into a senior secured credit agreement (the “credit agreement”) providing senior
secured financing of $600.0 million, consisting of:
• $500.0 million senior secured term loan facility; and
• $100.0 million senior secured revolving credit facility (the “credit facility”).
The entire amount of our credit facility is available for letters of credit and includes a limited borrowing
capacity for borrowings on same-day notice referred to as swing line loans. Our available capacity under this
facility is currently $75 million. TRI is the borrower under this facility.
Borrowings under the credit agreement bear interest at a rate equal to an applicable margin, plus at our option,
either (a) a base rate determined by reference to the higher of (1) the prime rate of Deutsche Bank, (2) the
federal funds rate plus 0.5%, and (3) solely in the case of term loans, 3%, or (b) LIBOR as determined by
reference to the higher of (1) the British Bankers Association LIBOR Rate and (2) solely in the case of term
loans, 2%.
In addition to paying interest on outstanding principal under the senior secured credit facilities, TRI is required
to pay other fees. TRI is required to pay a commitment fee equal to 0.5% of the current unutilized commitments.
The commitment fee rate may fluctuate based upon TRI’s leverage ratios. TRI is also required to pay a fronting
fee equal to 0.25% on outstanding letters of credit.
F-17
The credit agreement requires TRI to prepay loans outstanding under the senior secured term loan facility,
subject to certain exceptions, with:
• 50% of our annual excess cash flow (which percentage will be reduced to 25% if our total leverage ratio
is no more than 3.00 to 1.00 and to 0% if our total leverage ratio is no more than 2.50 to 1.00);
• up to 100% of the net cash proceeds of all non-ordinary course asset sales, transfers or other dispositions
of property, subject to our consolidated leverage ratio; and
• 100% of the net cash proceeds of any incurrence of debt, other than debt permitted under the credit
agreement.
During the year ended December 31, 2010, our term loan facility was paid in full, the available capacity of the
revolving credit facility was reduced to $75.0 million and the full amount is available for borrowing as of
December 31, 2010.
All obligations under the credit agreement and certain secured hedging arrangements are unconditionally
guaranteed, subject to certain exceptions, by each of TRI’s existing and future domestic restricted subsidiaries,
referred to, collectively, as the guarantors. TRI has pledged the following assets, subject to certain exceptions, as
collateral:
• the capital stock and other equity interests held by TRI or any guarantor; and
• a security interest in, and mortgages on, TRI’s and its guarantors’ tangible and intangible assets.
The credit agreement contains a number of covenants that, among other things, restrict, subject to certain
exceptions, TRI’s ability to incur additional indebtedness (including guarantees and hedging obligations); create
liens on assets; enter into sale and leaseback transactions; engage in mergers or consolidations; sell assets; pay
dividends and make distributions or repurchase capital stock and other equity interests; make investments, loans
or advances; make capital expenditures; repay, redeem or repurchase certain indebtedness; make certain
acquisitions; engage in certain transactions with affiliates; amend certain debt and other material agreements;
change TRI’s lines of business; and impose certain restrictions on restricted subsidiaries that are not guarantors,
including restrictions on the ability of such subsidiaries that are not guarantors to pay dividends.
The credit agreement requires TRI to maintain certain specified maximum total leverage ratios and certain
specified minimum interest coverage ratios. In each case we are required to comply with certain limitations,
including minimum cash consideration requirements.
On January 5, 2010, concurrent with the execution of the credit agreement, TRI borrowed $500.0 million on the
term loan facility net of a $5.0 million discount. There was no initial funding on the revolving credit line. The
proceeds from the term loan were used to:
• complete the cash tender offer and consent solicitation for all $250.0 million of TRI’s outstanding 8 ½%
senior notes due 2013;
• repay the outstanding balance of $62.2 million on TRI’s existing senior secured term loan due 2012;
• purchase $164.2 million in face value of the Holdco Notes for $131.4 million ; and
• fund working capital and pay fees and expenses under the credit agreement.
During the year ended December 31, 2010, TRI incurred a gain on early debt extinguishments of $12.5 million
from the write-off of debt issue costs related to the repayments of TRI’s term loan, and the purchase of the
Holdco Notes as discussed above.
During 2009, TRI repaid substantially all of its senior secured term loan facility and recognized a $14.8 million
loss on early debt extinguishment consisting of the write-off of debt issue costs related to the facility.
During 2009, TRI also incurred a loss on debt repurchases of $17.4 million comprising $10.9 million of
premiums paid and $6.5 million from the write-off of debt issue costs related to the repurchase of TRI’s 8½%
F-18
senior notes discussed above. The premiums paid were included as a cash outflow from a financing activity in
the Statement of Cash Flows.
Senior Secured Credit Facility of the Partnership
On July 19, 2010, the Partnership entered into an Amended and Restated Credit Agreement that replaced the
Partnership’s existing variable rate Senior Secured Credit Facility with a new variable rate Senior Secured
Credit Facility due July 2015. The amended and restated Senior Secured Credit Facility increases available
commitments to the Partnership to $1.1 billion from $958.5 million and allows the Partnership to request
increases in commitments up to an additional $300 million.
The Partnership incurred a charge of $0.8 million related to a partial write-off of debt issue costs associated with
this amended and restated credit facility related to a change in syndicate members. The remaining balance in
debt issue costs of $4.7 million is being amortized over the life of the amended and restated credit facility.
The Partnership’s amended and restated credit facility bears interest at LIBOR plus an applicable margin
ranging from 2.25% to 3.5% dependent on the Partnership’s consolidated funded indebtedness to consolidated
adjusted EBITDA ratio. The Partnership’s new credit facility is secured by substantially all of the Partnership’s
assets. As of December 31, 2010, availability under the Partnership’s Senior Secured Revolving Credit Facility
was $233.4 million, after giving effect to $101.3 million in outstanding letters of credit.
The Partnership’s senior secured credit facility restricts its ability to make distributions of available cash to
unitholders if a default or an event of default (as defined in its senior secured credit agreement) has occurred and
is continuing. The senior secured credit facility requires the Partnership to maintain a consolidated funded
indebtedness to consolidated adjusted EBITDA of less than or equal to 5.50 to 1.00. The Partnership’s senior
secured credit facility also requires it to maintain an interest coverage ratio (the ratio of its consolidated
EBITDA to its consolidated interest expense, as defined in its senior secured credit agreement) of greater than or
equal to 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, as well as upon the occurrence of certain events, including the incurrence of additional
permitted indebtedness.
Senior Unsecured Notes of the Partnership
The Partnership has three issues of unsecured senior notes. On June 18, 2008, the Partnership privately placed
$250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “8¼% Notes”). On July 6, 2009,
the Partnership privately placed $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the
“11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of
$237.4 million. On August 13, 2010 the Partnership privately placed $250 million in aggregate principal amount
of 7⅞% senior notes due 2018 (the “7⅞% Notes”).
These notes are unsecured senior obligations that rank pari passu in right of payment with existing and future
senior indebtedness, including indebtedness under our credit facility. They are senior in right of payment to any
of our future subordinated indebtedness and are unconditionally guaranteed by the Partnership. These notes are
effectively subordinated to all secured indebtedness under our credit agreement, which is secured by
substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.
Interest on the 8¼% Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on
January 1 and July 1. Interest on the 11¼% Notes accrues at the rate of 11¼% per annum and is payable semi-
annually in arrears on January 15 and July 15. Interest on the 7⅞% Notes accrues at the rate of 7⅞% per annum
and is payable semi-annually in arrears on April 15 and October 15, commencing on April 15, 2011.
The Partnership may redeem up to 35% of the aggregate principal amount each of our series of notes, at any
time prior to July 1, 2011 for the 8¼% Notes (July 15, 2012 for the 11¼% Notes, and October 15, 2013 for the
7⅞% Notes), with the net cash proceeds of one or more equity offerings. The Partnership must pay a redemption
price of 108.25% of the principal amount for the 8¼% Notes (111.25% for the 11¼% Notes, and 107.875% for
the 7⅞ Notes), plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided
that:
(1) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us)
remains outstanding immediately after the occurrence of such redemption; and
F-19
(2) the redemption occurs within 90 days of the date of the closing of such equity offering.
The Partnership may also redeem all or a part of each of the series of notes, on or after July 1, 2012 for the
8¼% Notes (July 15, 2013 for the 11¼% Notes, October 15, 2014 for the 7⅞ Notes) at the redemption prices set
forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated
damages, if any, on the notes redeemed, if redeemed during the twelve-month period beginning on July 1 for the
8¼% Notes (July 15 for the 11¼% Notes, October 15 for the 7⅞% Notes) of each year indicated below:
8¼% Notes
11¼% Notes
7⅞% Notes
Year
Redemption %
Year
Redemption %
Year
Redemption %
2012
2013
104.125%
2013
102.063%
2014
105.625%
2014
102.813%
2015
2014 and thereafter
100.000%
2015 and thereafter
100.000%
2016 and thereafter
103.938%
101.969%
100.000%
During 2008, the Partnership repurchased $40.9 million face value of our outstanding 8¼% Notes in open
market transactions at an aggregate purchase price of $28.3 million, including $1.5 million of accrued interest.
The Partnership recognized a gain on the debt repurchases of $13.1 million associated with the purchased notes.
The repurchased 8¼% Notes were retired and are not eligible for re-issue at a later date.
During 2009, the Partnership repurchased $18.7 million face value ($17.8 million carrying value) of the
outstanding 11¼% Notes in open market transactions at an aggregated purchase price of $18.9 million plus
accrued interest of $0.3 million. The Partnership recognized a loss on the debt repurchases of $ 1.5 million,
including $0.4 million in debt issue costs associated with the repurchased notes. The repurchased 11¼% Notes
were retired and are not eligible for re-issue at a later date.
Subsequent Events. On February 2, 2011, the Partnership closed on a private placement of $325 million in
aggregate principal amount of 6⅞% Senior Notes due 2021 (“the 6⅞% Notes”) resulting in net proceeds of
$319.3 million.
On February 4, 2011 the Partnership exchanged $158.6 million under an exchange offer to holders of its 11¼%
Notes due 2017 for $158.6 million principal amount 6⅞% Notes due 2021. In conjunction with the exchange
the Partnership paid a premium in cash of $28.6 million. The debt covenants related to the remaining $72.7
million of face value 11¼% Notes due 2017 were removed as the Partnership received sufficient consents in
connection with the exchange offer to amend the indenture.
Note 10 – Convertible Participating Preferred Stock
The holders of the Series B stock accrued dividends at an annual rate of 6% of the accreted value of the stock
(purchase price plus unpaid dividends, compounded quarterly) until December 10, 2010, at which time we
completed our IPO and all of our Series B stock converted to common stock based (a) a conversion ratio of one
share of our Series B stock to 4.92 shares of our Common Stock plus (b) the accreted value per share of the
Series B stock divided by the IPO price after deducting underwriter discounts and commissions.
Cash dividends on the Series B stock were payable when declared by our Board of Directors, subject to
restrictions under our debt agreements. During the year ended 2010, we paid dividends of $238 million to the
Series B preferred shareholders and an additional $177.8 million to common equivalent shareholders. The
common equivalent shareholders are the holders of the Series B stock that participate ratably in such common
dividend in proportion to the number of shares of common stock that were issuable upon the conversion of the
shares of Series B stock.
Note 11 – Partnership Units and Related Matters
On January 19, 2010, the Partnership completed a public offering of 5,500,000 common units representing
limited partner interests in the Partnership (“common units”) under its existing shelf registration statement on
Form S-3 (“Registration Statement”) at a price of $23.14 per common unit ($22.17 per common unit, net of
underwriting discounts), providing net proceeds of $121.9 million. Pursuant to the exercise of the underwriters’
overallotment option, the Partnership sold an additional 825,000 common units, providing net proceeds of
$18.3 million. In addition, we contributed $3.0 million for 129,082 general partner units to maintain our 2%
F-20
general partner interest. The Partnership used the net proceeds from the offering for general partnership
purposes, which included reducing borrowings under its senior secured credit facility.
On April 14, 2010, Targa LP Inc., a wholly-owned subsidiary of ours, closed on a secondary public offering of
8,500,000 common units of the Partnership at $27.50 per common unit. Proceeds from this offering, after
underwriting discounts and commission were $224.4 million before expenses associated with the offering. This
offering also triggered a mandatory prepayment on our senior secured credit agreement of $3.2 million related to
TRI’s senior secured revolving credit facility and $105.6 million on TRI’s senior secured term loan facility.
On April 27, 2010, we completed the sale of our interests in the Permian Business and Straddle Assets to the
Partnership for $420.0 million, effective April 1, 2010. This sale triggered a mandatory prepayment on TRI’s
senior secured credit agreement of $152.5 million, which was paid on April 27, 2010. As part of the closing of
the sale of our Permian Business and Straddle Assets, we amended our Omnibus Agreement with the
Partnership, to continue to provide general and administrative and other services to the Partnership through
April 2013.
On August 13, 2010, the Partnership completed an offering of 6,500,000 of its common units under the
Registration Statement at a price of $24.80 per common unit ($23.82 per common unit, net of underwriting
discounts) providing net proceeds to the Partnership of approximately $154.8 million. Pursuant to the exercise
of the underwriters’ overallotment option, the Partnership sold an additional 975,000 common units, providing
net proceeds of approximately $23.2 million. In addition, we contributed $3.8 million for 152,551 general
partner units to maintain a 2% general partner interest. The Partnership used the net proceeds from this offering
to reduce borrowings under its senior secured credit facility.
On August 25, 2010, we completed the sale to the Partnership of our 63% equity interest in Versado, effective
August 1, 2010, for $247.2 million in the form of $244.7 million in cash and $2.5 million in partnership interests
represented by 89,813 common units and 1,833 general partner units. The sale triggered a mandatory
prepayment of $91.3 million under TRI’s senior secured credit facility. Under the terms of the Versado Purchase
and Sale Agreement, Targa will reimburse the Partnership for future maintenance capital expenditures required
pursuant to our New Mexico Environmental Department settlement agreement, of which our share is currently
estimated at $19.0 million, to be incurred through 2011.
On September 28, 2010, we completed the sale to the Partnership of our Venice Operations, which includes
Targa’s 76.8% interest in Venice Energy Services Company, L.L.C. (“VESCO”), for aggregate consideration of
$175.6 million, effective September 1, 2010. The sale triggered a mandatory prepayment of $73.5 million under
TRI’s senior secured credit facility.
The net impact of our sale of assets to the Partnership resulted in an increase to additional paid-in capital of
$243 million and a corresponding reduction of the non-controlling interest in these assets.
The following table lists the Partnership’s distributions declared and paid in the years ended December 31, 2010
and 2009:
Date Paid
2010
November 12, 2010
August 13, 2010
May 14, 2010
February 12, 2010
2009
November 14, 2009
August 14, 2009
May 15, 2009
February 13, 2009
For the Three
Months Ended
Limited Partners
General Partner
Distributions Paid
Common
Subordinated
Incentive
2%
Total
(In millions, except per unit amounts)
Distributions
per limited
partner unit
September 30, 2010
June 30, 2010
March 31, 2010
December 31, 2009
September 30, 2009
June 30, 2009
March 31, 2009
December 31, 2008
$
$
$
$
40.6
35.9
35.2
35.2
31.9
23.9
18.0
18.0
$
$
-
-
-
-
-
-
5.9
6.0
$
$
4.6
3.5
2.8
2.8
2.6
2.0
1.9
1.9
$
$
$
$
0.9
0.8
0.8
0.8
0.7
0.5
0.5
0.5
46.1
40.2
38.8
38.8
35.2
26.4
26.3
26.4
0.5375
0.5275
0.5175
0.5175
0.5175
0.5175
0.5175
0.5175
As part of our sale of the Downstream Business to the Partnership in 2009, we agreed to provide distribution
support to the Partnership through the fourth quarter of 2011, in the form of a reduction in the reimbursement
for general and administrative expense that we allocate to the Partnership if necessary for a 1.0 times
distribution coverage, at a distribution level of the Partnership’s at the time of the sale of the Downstream
F-21
Business of $0.5175 per limited partner unit, subject to a maximum support of $8.0 million in any quarter. No
distribution support has been necessary through the fourth quarter of 2010.
Subsequent Events. On January 24, 2011, the Partnership completed a public offering of 8,000,000 common
units representing limited partner interests in the Partnership (“common units”) under an existing shelf
registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of
underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters’
overallotment option, the Partnership sold an additional 1,200,000 common units, providing net proceeds of
$38.9 million. In addition, we contributed $6.3 million for 187,755 general partner units to maintain our 2%
interest in the Partnership.
On February 14, 2011, the Partnership paid a cash distribution of $0.5475 per common unit on our outstanding
common units. The total distribution paid was $53.5 million, with $40.0 million paid to the Partnership’s non-
affiliated common unitholders and $6.4 million, $1.1 million and $6.0 million paid to us for our common unit
ownership, general partner interest and incentive distribution rights.
Note 12 – Earnings per Share
Basic earnings per share are computed using the weighted average number of common shares outstanding
during the period. Diluted earnings per share are computed using the weighted average shares outstanding
during the period, but also include the dilutive effect of restricted stock awards and stock options. Diluted EPS
also includes the assumed conversion of the Series B Convertible Participating Preferred Stock for periods prior
to December 10, 2010.
Prior to the conversion of the Series B Preferred Stock to common stock on December 10, 2010, net income
after the impact of preferred dividends was allocated according to the preferred stock agreement. The terms of
the preferred stock agreement stipulated that common shareholders are not entitled to any dividends, unless
approved with written consent of a majority of the outstanding preferred stockholders, until the preferred
holders recapture the carrying value of their preferred securities which includes accreted dividends. For 2008
and 2009, there was no net income available to common shareholders as the preferred shareholders are entitled
to all undistributed earnings. As such, there were no earnings per share to our common shareholders during
2008 and 2009. For 2010, there was no allocation to preferred shareholders as the Company was in a loss
position and the preferred shareholders do not participate in losses under the terms of the preferred stock
agreement.
For each of the periods presented below, all of the potentially dilutive securities were excluded from the
calculation of diluted EPS as they were anti-dilutive.
The following table reflects the weighted average of outstanding securities that were excluded from the diluted
calculation of net income (loss) available to common shareholders as the effect of including such securities
would have been anti-dilutive (in thousands).
Restricted Stock - 2010 Stock Incentive Plan (1)
Restricted Stock - 2005 Incentive Compensation Plan (2)
Stock Options - 2005 Incentive Compensation Plan (3)
Conversion of Series B Preferred Stock (4)
2010
Years Ended December 31,
2009
(in thousands)
-
488.9
2,313.1
31,515.3
1,350.0
10.6
1,470.0
33,322.5
2008
-
1,518.6
2,341.5
31,515.3
________
(1)
In connection with the IPO in December 2010, the Company issued 1,350,000 shares of restricted stock under the 2010 Stock
Incentive Plan to employees. At December 31, 2010, all of these shares were unvested.
(2) Amounts represent the weighted average number of unvested shares outstanding for each year.
(3) Amounts represent the weighted average number of unexercised stock options outstanding for each year. Prior to the closing of the
IPO in December 2010, all outstanding options were either exercised or cashed out. As of December 31, 2010, there are no
outstanding stock options.
(4) Amounts in 2009 and 2008 represent the assumed conversion of the Series B Preferred Stock into common shares as of January 1 for
each year. During 2010, in connection with the closing of the IPO, 6,409,697 shares of Series B Convertible Participating Preferred
Stock, plus accreted value, were converted into 35,356,698 shares of common stock. Beginning on December 10, 2010, these shares
are included in the calculation of weighted average shares outstanding – basic and diluted. The amount included in the table above for
2010 represents the weighted average shares for the period from January 1, 2010 through December 9, 2010 (based on the actual
number of shares converted on December 10, 2010).
F-22
Subsequent event. On February 21, 2011, we paid a cash dividend of $0.0616 per share of our outstanding
common stock. The total dividend paid was $2.6 million. This dividend was pro-rated to give effect to a partial
quarter following our IPO.
Note 13 – Insurance Claims
Hurricanes Katrina and Rita
Hurricanes Katrina and Rita affected certain Gulf Coast facilities in 2005. The final purchase price allocation of
our acquisition from Dynegy in October 2005 included an $81.1 million receivable for insurance claims related
to property damage caused by Hurricanes Katrina and Rita. The insurance claim process was completed with
respect to Hurricanes Katrina and Rita for property damage and business interruption insurance, which resulted
in an $18.5 million gain recorded in 2008. This amount was reported in the other income line in the other
income (expense) section of our Consolidated Statement of Operations.
Hurricanes Gustav and Ike
Certain Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008
hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a
$19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2010
and 2009, the estimate was reduced by $3.3 million and $3.7 million to give effect to higher insurance
recoveries and lower out of pocket costs. These amounts were reported in the Other line in the costs and
expenses section of our Consolidated Statements of Operations.
During the year ended December 31, 2010, expenditures related to the hurricanes were $0.3 million. During the
year ended December 31, 2009, expenditures related to the hurricanes included $35.9 million for repairs and
$7.6 million capitalized as improvements.
Total business interruption proceeds related to Hurricanes Gustav and Ike recorded as revenues during 2010 and
2009 were $5.5 million and $19.5 million, respectively. No hurricane-related business interruption proceeds
were received during 2008. We were entitled to receive all post dropdown insurance proceeds under the terms of
the Purchase and Sale Agreements with the Partnership. These amounts were reported in the revenues line on
our Consolidated Statements of Operations.
F-23
Note 14 – Derivative Instruments and Hedging Activities
Commodity Hedges
In an effort to reduce the variability of cash flows, the Partnership has hedged the commodity price associated
with a portion of our expected natural gas, NGL and condensate equity volumes through 2014 by entering into
derivative financial instruments including swaps and purchased puts (floors).
The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those
of our physical equity volumes. The NGL hedges cover baskets of ethane, propane, normal butane, iso-butane
and natural gasoline based upon our expected equity NGL composition, as well as specific NGL hedges of
ethane and propane. This strategy avoids uncorrelated risks resulting from employing hedges on crude oil or
other petroleum products as “proxy” hedges of NGL prices. Additionally, the NGL hedges are based on
published index prices for delivery at Mont Belvieu and the natural gas hedges are based on published index
prices for delivery at Mid-Continent, WAHA and Permian Basin (El Paso), which closely approximate our
actual NGL and natural gas delivery points.
The Partnership hedges a portion of its condensate sales using crude oil hedges that are based on the NYMEX
futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for
condensate. This necessarily exposes the Partnership to a market differential risk if the NYMEX futures do not
move in exact parity with the sales price of our underlying West Texas condensate equity volumes.
Hedge ineffectiveness has been immaterial for all periods.
At December 31, 2010, the notional volumes of our commodity hedges were:
Commodity
Instrument
Unit
2011
2012
2013
2014
Natural Gas
NGL
NGL
Condensate
Swaps
Swaps
Floors
Swaps
Interest Rate Swaps
MMBtu/d
30,100
23,100
8,000
8,550
6,700
3,400
253
1,100
294
950
-
800
700
-
-
-
Bbl/d
Bbl/d
Bbl/d
As of December 31, 2010, the Partnership had $765.3 million outstanding under its credit facility, with interest
accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows
attributable to changes in market interest rates the Partnership has entered into interest rate swaps and interest
rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:
Period
Fixed Rate
2011
2012
2013
2014
3.52%
3.40%
3.39%
3.39%
Notional
Amount
Notional
Amount
Fair
Value
Fair
Value
$
($ in millions)
300 $
300
300
300
$
(7.8)
(7.5)
(4.0)
(0.8)
(20.1)
All interest rate swaps and interest rate basis swaps have been designated as cash flow hedges of variable rate
interest payments on borrowings under the Partnership’s credit facility.
F-24
The following schedules reflect the fair values of derivative instruments in our financial statements:
Asset Derivatives
Liability Derivatives
Balance
Fair Value as of
Balance
Fair Value as of
Sheet
December 31,
Sheet
December 31,
Location
2010
2009
Location
2010
2009
Derivatives designated as hedging instruments
Commodity contracts
Current assets
$
24.8 $
31.6 Current liabilities
$
25.5 $
20.7
Long-term assets
18.9
11.7 Long-term liabilities
20.5
39.1
Interest rate contracts
Current assets
-
0.2 Current liabilities
7.8
8.0
Total derivatives designated as hedging instruments
Long-term assets
-
43.7 $
1.9 Long-term liabilities
$
45.4
12.3
66.1 $
4.7
72.5
$
Derivatives not designated as hedging instruments
Commodity contracts
Current assets
$
0.4 $
1.1 Current liabilities
$
0.9 $
0.5
Total derivatives not designated as hedging instruments
Long-term assets
-
0.4 $
0.2 Long-term liabilities
$
1.3
-
0.9 $
-
0.5
$
Total derivatives
$
44.1 $
46.7
$
67.0 $
73.0
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.
The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue and
expense:
Gain (Loss)
Recognized in OCI on
Derivatives in
Derivatives (Effective Portion)
Cash Flow Hedging
Year Ended December 31,
Relationships
2010
2009
2008
Interest rate contracts
Commodity contracts
$
$
(20.1) $
52.5
32.4 $
(7.3) $
(104.3)
(111.6) $
(19.0)
206.4
187.4
Gain (Loss)
Reclassified from OCI into
Location of Gain (Loss)
Income (Effective Portion)
Reclassified from
Year Ended December 31,
OCI into Income
2010
2009
2008
Interest expense, net
Revenues
$
$
(9.3) $
8.4
(0.9) $
(15.7) $
69.7
54.0 $
(2.7)
(65.1)
(67.8)
F-25
Our earnings are also affected by the use of the mark-to-market method of accounting for our derivative
financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The
changes in fair value of these instruments are recorded on the balance sheets and through earnings (i.e., using
the “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 2010, 2009 and 2008, we recorded the following
mark-to-market gains (losses):
Derivatives
Not Designated as
Hedging Instruments
Location of Gain (Loss)
Recognized in Income
on Derivatives
Amount of Gain (Loss) Recognized
in Income on Derivatives
Year Ended
December 31,
2009
2010
2008
Commodity contracts
Other income (expense) $
(0.4) $
0.3 $
(1.3)
The following table shows the unrealized gains (losses) included in OCI:
Year Ended December 31,
2010
2009
2008
Unrealized gain (loss) on commodity hedges, before tax
$
4.5 $ (29.4) $
59.6
Unrealized gain (loss) on commodity hedges, net of tax
2.7
(18.3)
Unrealized gain (loss) on interest rate swaps, before tax
Unrealized gain (loss) on interest rate swaps, net of tax
(3.4)
(2.1)
(3.1)
(1.9)
39.3
(4.7)
(3.1)
As of December 31, 2010, deferred net losses of $3.9 million on commodity hedges and $7.5 million on interest
rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense, respectively, during
the next twelve months.
In July 2008, we paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity
swaps. Prior to the terminations, these swaps were designated as hedges. During the years ended December 31,
2010, 2009 and 2008 deferred net losses of $29.6 million, $40.0 million and $20.8 million were reclassified
from OCI as a non-cash reduction of revenue.
In May 2008 we entered into certain NGL derivative contracts with Lehman Brothers Commodity Services,
Inc., a subsidiary of Lehman Brothers Holdings Inc. (“Lehman”). Due to Lehman’s bankruptcy filing, it is
unlikely that we will receive full or partial payment of any amounts that may become owed to us under these
contracts. Accordingly, we discontinued hedge accounting treatment for these contracts in July 2008. Deferred
losses of $0.2 million and $0.3 million will be reclassified to revenues during 2011 and 2012 when the
forecasted transactions related to these contracts are expected to occur. During 2008, we recognized a non-cash
mark-to-market loss on derivatives of $1.3 million to adjust the fair value of the Lehman derivative contracts to
zero. In October 2008, we terminated the Lehman derivative contracts.
See Note 15, Note 17 and Note 23 for additional disclosures related to derivative instruments and hedging
activity.
Note 15—Related Party Transactions
Relationship with Warburg Pincus LLC
Chansoo Joung and Peter Kagan, two of our directors, are Managing Directors of Warburg Pincus LLC and are
also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products.
Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. During 2010, 2009 and 2008, we
purchased $41.5 million, $9.7 million and $4.8 million of product from Broad Oak.
Peter Kagan is also a director of Antero Resources Corporation (“Antero”) from whom we buy natural gas and
NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Antero. We purchased $0.1
million, $0.5 million, and $64.4 million of product from Antero during the year ended December 31, 2010,
F-26
2009, and 2008. These transactions were at market prices consistent with similar transactions with other
nonaffiliated entities.
Relationships with Bank of America (“BofA”)
Equity. Prior to December 10, 2010, BofA was considered a beneficial owner of more than 5% of our common
stock. Upon our initial public offering, BofA was reduced its ownership below 5%.
Financial Services. An affiliate of BofA is a lender and an agent under the Partnership’s senior credit facility
with commitments of $72 million. BofA and its affiliates have engaged, and may in the future engage, in other
commercial and investment banking transactions with us or the Partnership in the ordinary course of their
business. They have received, and expect to receive, customary compensation and expense reimbursement for
these commercial and investment banking transactions.
Commodity Hedges. The Partnership has previously entered into various commodity derivative transactions with
BofA. As of December 31, 2010, the Partnership has no open positions with BofA. During 2010, 2009 and
2008, the Partnership received from (paid to) BofA $1.9 million, $24.2 million and ($30.5) million in
commodity derivative settlements.
Commercial Relationships. The Partnership’s product sales and product purchases with BofA were:
Year Ended
December 31,
2010
2009
2008
Included in revenues
Included in costs and expenses
$ 26.0
3.7
$ 36.7
1.0
$ 97.0
5.1
Relationships with Sequent Energy Management, EOG Resources Inc., and Intercontinental Exchange, Inc.
Charles Crisp, one our directors, is also a director of AGL Resources Inc. (“AGL”), EOG Resources Inc.
(“EOG”) and Intercontinental Exchange Inc. (“Intercontinental”). Sequent Energy Management (“Sequent”) is a
subsidiary of AGL. The following schedule shows the transactions with each of these related parties.
Sales
Purchases
Year Ended, December 31,
Year Ended, December 31,
2010
14.3 $
$
(1)
-
2009
11.7 $
(1)
-
2008
- $
-
-
2010
27.4 $
10.0
0.2
2009
2008
5.0 $
5.6
0.2
-
13.1
0.2
Sequent
EOG
Intercontinental
________
(1) Less than $0.1 million
These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
F-27
Transactions with Unconsolidated Affiliates
For the years indicated, our natural gas and NGL sales and purchases with our unconsolidated affiliates were:
Included in revenues
GCF
VESCO(1)
Included in costs and expenses
GCF
VESCO(1)
December 31,
2010
2009
2008
$
$
$
$
0.3 $
-
0.3 $
1.1 $
-
1.1 $
0.2 $
-
0.2 $
1.4 $
-
1.4 $
0.5
0.7
1.2
3.5
178.1
181.6
_______
(1) For 2008, our commercial transactions with VESCO are reflected through July 31, 2008. As a result of acquiring an additional
ownership in VESCO, and we have consolidated the operations of VESCO in our financial results from August 1, 2008.
Note 16 – Commitments and Contingencies
Certain property and equipment is leased under non-cancelable leases that require fixed monthly rental
payments and expire at various dates through 2099. Transportation contracts require us to make payments for
capacity and expire at various dates through 2013. Surface and underground access for gathering, processing,
and distribution assets that are located on property not owned by us is obtained through right-of-way
agreements, which require annual rental payments and expire at various dates through 2099. Future non-
cancelable commitments related to certain contractual obligations are presented below:
Payment Due by Period
Total
2011
2012
2013
2014 2015 Thereafter
Partnership:
Operating lease and service contract (1)
$
36.7 $
10.6 $
8.4 $
3.8 $
2.7 $
2.6 $
Capacity and terminalling payments (2)
Land site lease and right-of-way (3)
12.9
20.4
6.6
1.3
4.7
1.6
-
-
1.2
1.2
1.1
1.0
14.6
8.6
-
TRC:
Operating leases (4)
15.3
2.5
2.1
2.2
2.2
2.2
4.1
$
85.3 $
21.0 $
16.4 $
8.8 $
6.0 $
5.8 $
27.3
Includes minimum lease payment obligations associated with gas processing plant site leases, railcar leases, and office space leases.
______
(1)
(2) Consists of capacity payments for firm transportation contracts.
(3) Provides for surface and underground access for gathering, processing, and distribution assets that are located on property not owned
by us; agreements expire at various dates through 2099.
Includes minimum lease payment obligations associated with corporate operations.
(4)
The following table shows the above mentioned expenses of the Partnership:
Year Ended December 31,
2010
2009
2008
Operating leases
Capacity payments
Land site lease and right-of-way
$
13.5 $
8.6
2.8
13.7 $
9.6
2.3
14.7
6.7
4.0
F-28
Environmental
For environmental matters, we record liabilities when remedial efforts are probable and the costs can be
reasonably estimated. Environmental reserves do not reflect management’s assessment of any 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.
Our environmental liability at December 31, 2010 and December 31, 2009 was $1.6 million and $3.2 million.
Our December 31, 2010 liability consisted of $0.2 million for gathering system leaks and $1.4 million for
ground water assessment and remediation.
In May 2007, the New Mexico Environmental Department (“NMED”) alleged air emissions violations at the
Eunice, Monument and Saunders gas processing plants operated by Targa Midstream Services Limited
Partnership and owned by Versado Gas Processors, LLC (“Versado”), which were identified in the course of an
inspection of the Eunice plant conducted by the NMED in August 2005.
In January 2010, Versado settled the alleged violations with NMED for a penalty of approximately $1.5 million.
As part of the settlement, Versado agreed to install two acid gas injection wells, additional emission control
equipment and monitoring equipment. We estimate the total cost to complete these projects to be approximately
$33.4 million, of which $4.0 million has already been paid. The Partnership is responsible for its 63% pro-rata
ownership percentage of the total costs of the projects. Under the terms of the Versado Purchase and Sale
Agreement, we must reimburse the Partnership for the cost of these compliance investments.
Legal Proceedings
We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and
complaints arising in the ordinary course of business that have been filed or are pending against us. We believe
all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material
effect on our financial position, results of operations, or cash flows, except for the items more fully described
below.
On December 8, 2005, WTG Gas Processing, L.P. (“WTG”) filed suit in the 333rd District Court of Harris
County, Texas against several defendants, including Targa and two 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, along with ConocoPhillips Company (“ConocoPhillips”)
and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase SAOU from
ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted
from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in
2004. In October 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s
claims. In February 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of
defendants in its entirety. In January 2011, the Texas Supreme Court denied the WTG’s petition for review of
the lower courts’ judgment and WTG filed a motion for rehearing with the Texas Supreme Court requesting the
court reconsider its denial to review WTG’s appeal. We have agreed to indemnify the Partnership for any claim
or liability arising out of the WTG suit.
Except as provided above, neither we nor the Partnership is a party to any other legal proceedings other than
legal proceedings arising in the ordinary course of our business. The Partnership is a party to various
administrative and regulatory proceedings that have arisen in the ordinary course of our business.
Note 17 — Fair Value Measurements
We categorize the inputs to the fair value of our financial assets and liabilities using a three-tier fair value
hierarchy that prioritizes the significant inputs used in measuring fair value:
• Level 1 – observable inputs such as quoted prices in active markets;
• Level 2 – inputs other than quoted prices in active markets that are either directly or indirectly
observable; and
F-29
• Level 3 – unobservable inputs in which little or no market data exists, therefore requiring an entity to
develop its own assumptions.
Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts
and fixed price commodity contracts with certain counterparties. We determine the value of our derivative
contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options,
based on inputs that are readily available in public markets. We have consistently applied these valuation
techniques in all periods presented and believe we have obtained the most accurate information available for the
types of derivative contracts we hold.
The following tables present the fair value of our financial assets and liabilities according to the fair value
hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input
that is significant to the fair value measurement. Our assessment of the significance of a particular input to the
fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities
and their placement within the fair value hierarchy levels.
December 31, 2010
Total
Level 1
Level 2
Level 3
Assets from commodity derivative contracts
Assets from interest rate derivatives
Total assets
Liabilities from commodity derivative
contracts
Liabilities from interest rate derivatives
Total liabilities
$
$
$
$
44.1
$
-
44.1
$
46.9
$
20.1
67.0
$
-
-
-
-
-
-
$
$
$
$
43.9
$
-
43.9
$
35.1
$
20.1
55.2
$
0.2
-
0.2
11.8
-
11.8
December 31, 2009
Total
Level 1
Level 2
Level 3
Assets from commodity derivative contracts
$
Assets from interest rate derivatives
Total assets
$
Liabilities from commodity derivative contracts $
Liabilities from interest rate derivatives
Total liabilities
$
44.6 $
2.1
46.7 $
60.3 $
12.7
73.0 $
- $
-
- $
- $
-
- $
44.6 $
2.1
46.7 $
46.6 $
12.7
59.3 $
-
-
-
13.7
13.7
The following table sets forth a reconciliation of the changes in the fair value of our financial instruments
classified as Level 3 in the fair value hierarchy:
Balance at January 1
Unrealized gains included in OCI
$
Purchases
Settlements included in Income
Transfers out of Level 3 (1)
Commodity Derivative Contracts
2010
2009
2008
(13.7) $
2.6
-
(0.5)
-
148.2 $
(57.1)
-
(35.0)
(69.8)
(124.2)
149.6
81.1
41.7
-
Balance at December 31
_________
(1) During 2009, we reclassified certain of our NGL derivative contracts from Level 3 (unobservable inputs in which little or no market
(11.6) $
(13.7) $
148.2
$
data exists) to Level 2 as we were able to obtain directly observable inputs other than quoted prices in active markets.
For all periods indicated in the above table, all Level 3 derivative instruments were designated as cash flow
hedges, and, as such, all changes in their fair value are reflected in Other Comprehensive Income. Therefore,
F-30
there are no unrealized gains or losses reflected in revenues or other income (expense) with respect to Level 3
derivative instruments.
Note 18—Income Taxes
Our provisions for income taxes for the periods indicated are as follows:
Current expense (benefit)
Deferred expense
Year Ended December 31,
2008
2010
2009
$
$
(10.6) $
33.1
22.5 $
1.6 $
19.1
20.7 $
1.3
18.0
19.3
Our deferred income tax assets and liabilities at December 31, 2010 and 2009 consist of differences related to
the timing of recognition of certain types of costs as follows:
Deferred tax assets:
Net operating loss
Property, Plant and Equipment
Risk management contracts
Other
Tax credits
Deferred tax assets before valuation allowance
Valuation allowance
Deferred tax liabilities:
Investments(1)
Risk management contracts
Property, Plant and Equipment
Net deferred tax liability
Federal
Foreign
State
Balance sheet classification of deferred tax assets
(liabilities):
Current asset
Long-term asset (valuation allowance)
Current liability
Long-term liability
December 31,
2010
2009
$
-
-
48.3
13.1
-
61.4
(3.5)
57.9
(145.8)
-
(23.6)
(169.4)
60.1
6.3
-
3.6
16.8
86.8
-
86.8
(132.8)
(5.4)
-
(138.2)
(111.5)
$
(51.4)
(106.6)
0.5
(5.4)
(111.5)
3.6
(3.5)
-
(111.6)
(111.5)
$
$
$
$
(60.2)
0.5
8.3
(51.4)
-
(1.4)
(50.0)
(51.4)
$
$
$
$
$
$
______
(1) Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of the assets and
liabilities of our wholly-owned partnerships and equity method investments.
As a result of dropdown transactions in 2009 and 2010, differences related to the date of income recognition for
book and tax occurred. While these are temporary differences, the reversal of these differences will not be
recognized until we sell the units of the Partnership. Therefore, the tax effect of these differences is recorded as
a valuation allowance of $3.5 million in deferred taxes, as a component of other long term assets for 2010.
As of December 31, 2010, for federal income tax purposes, both regular tax net operating losses (“NOLs”) and
alternative minimum tax NOLs were fully utilized.
F-31
Set forth below is reconciliation between our income tax provision (benefit) computed at the United States
statutory rate on income before income taxes and the income tax provision in the accompanying consolidated
statements of operations for the periods indicated:
Years Ending
December 31,
$
2010
Income tax reconciliation:
Income before income taxes
Less: Net income attributable to noncontrolling interest
Income attributable to TRC before income taxes
Federal statutory income tax rate
U.S. federal income tax provision at statutory rate
State income taxes, net of federal tax benefit (1)
Valuation allowance
Other, net
Income Tax Provision
________
(1) For 2010, primarily consists of the write-off of an $11.9 million Texas margin tax credit.
85.8 $
(78.3)
7.5
35%
2.6
13.4
3.0
3.5
22.5 $
$
2009
2008
99.8 $
(49.8)
50.0
35%
17.5
1.8
-
1.4
20.7 $
153.7
(97.1)
56.6
35%
19.8
1.2
-
(1.7)
19.3
We have not identified any uncertain tax positions. We believe that our income tax filing positions and
deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse
effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income
tax positions have been recorded.
On April 14, 2010, we closed on a secondary public offering of 8,500,000 common units of the Partnership. The
direct tax effect of the change in ownership interest in the Partnership as a result of the secondary public
offering was recorded as a reduction in shareholders’ equity of $79.1 million, an increase in current tax liability
of $41.9 million and an increase in deferred tax liability of $37.2 million. There was no tax impact on
consolidated net income as a result of the secondary public offering.
On April 27, 2010, we sold our interests in the Permian and Straddle Systems to the Partnership. On September
28, 2010, we sold our interests in the Venice Operations to the Partnership. Under applicable accounting
principles, the tax consequences of transactions with common control entities are not to be reflected in pre-tax
income. Consequently, there was no tax impact on consolidated pre-tax net income as a result of the sale of the
Permian and Straddle Systems and the Venice Operations. The tax effect of these sales was recorded as an
increase in other long term assets of $64.7 million, to be amortized over the remaining life of the underlying
assets, an increase in current tax liability of $94.9 million, a decrease in deferred tax liability of $27.5 million
and an increase in current tax expense of $2.7 million.
Note 19—Fair Value of Financial Instruments
We have determined the estimated fair values of assets and liabilities classified as financial instruments using
available market information and valuation methodologies described below. We apply considerable judgment
when interpreting market data to develop the estimates of fair value. The use of different market assumptions or
valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is
based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices
based on trades of such debt.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the
short-term maturities of these instruments. Derivative financial instruments included in our financial statements
are stated at fair value.
F-32
The carrying amounts and fair values of our other financial instruments are as follows as of the dates indicated:
December 31, 2010
December 31, 2009
Carrying
Amount
$
Fair
Value
Carrying
Amount
Fair
Value
Holdco loan facility (1)
Senior secured term loan facility, due 2012 (2)
Senior unsecured notes, 8½% fixed rate (3)
Senior unsecured notes of the Partnership, 8¼% fixed rate
Senior unsecured notes of the Partnership, 11¼% fixed rate
Senior unsecured notes of the Partnership, 7 7/8% fixed rate
________
(1) For the fair value of the Holdco loan facility, since we cannot obtain an indicative quote from external sources, we are using the value
385.4 $
62.2
250.0
209.1
231.3
-
89.3 $
-
-
209.1
231.3
250.0
86.8 $
-
-
219.4
265.0
259.7
278.9
61.9
259.2
206.5
253.5
-
of the November 2010 purchases that we made at 97.18% of face value.
(2) The carrying amount of the debt as of December 31, 2009 approximates the fair value as the variable rate is periodically reset to
prevailing market rates.
(3) The fair value as of December 31, 2009 represents the value of the last trade of the year which occurred on December 9, 2009. On
January 5, 2010 we paid $264.7 million to complete a cash tender offer for all outstanding aggregate principal amount plus accrued
interest of $3.8 million.
Note 20 — Supplemental Cash Flow Information
Supplemental cash flow information was as follows for the periods indicated:
Year Ended
December 31,
2009
2008
2010
$
$
90.8
92.6
$
82.4
6.5
94.2
1.6
Cash:
Interest paid
Income taxes paid (1)
Non-cash
Inventory line-fill transferred to property, plant and
equipment
0.4
-
10.9
79.9
-
-
3.2
9.8
-
25.9
-
-
-
-
-
5.8
38.2
-
14.1
14.8
-
Like-kind exchange of property, plant and equipment
Paid-in-kind interest refinanced to Holdco principal
Conversion of series B preferred stock (accretive value)
Settlement of Partnership notes
Distribution of property to noncontrolling interest
Distribution of property to common shareholders
________
(1) During 2010, cash tax payments of $92.6 million were made to the Internal Revenue Service and various states in connection with
taxable gains recognized upon Targa’s sale of the Permian Business and Straddle Assets, its interests in the Venice Operations and its
secondary public offering of 8,500,000 common units of the Partnership. Under applicable accounting principles, the income tax
consequences of these transactions are generally deferred and recognized over time. For income tax purposes, the tax consequences
must be recognized in 2010 when the dispositions were completed.
Note 21 – Segment Information
The Partnership’s operations are presented under four segments: (1) Field Gathering and Processing, (2) Coastal
Gathering and Processing, (3) Logistics Assets and (4) Marketing and Distribution. The financial results of our
hedging activities are reported in Other.
The Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced
from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural
gas liquids and removing impurities. The Field Gathering and Processing segment assets are located in North
Texas and the Permian Basin of Texas and New Mexico and the Coastal Gathering and Processing segment
assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico.
F-33
The NGL Logistics and Marketing division is also referred to as our Downstream Business. It includes all the
activities necessary to convert raw natural gas liquids into NGL products, market the finished products and
provide certain value added services.
The Logistics Assets segment is involved in transporting and storing mixed NGLs and fractionating, storing,
and transporting finished NGLs. These assets are generally connected to and supplied, in part, by our Gathering
and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana.
The Marketing and Distribution segment covers all activities required to distribute and market raw and finished
natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids
production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied
petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and
providing related propane logistics services to multi-state retailers, independent retailers and other end users;
and (4) marketing natural gas available to us from our Gathering and Processing segments and the purchase and
resale of natural gas in selected United States markets.
Other contains the results of our derivatives and hedging transactions. Eliminations of inter-segment
transactions are reflected in the eliminations column.
Our segment information is shown in the following tables. With the conveyance of all of our remaining
operating assets to the Partnership in September 2010, all operating assets are now owned by the Partnership.
We have segregated the following segment information between Partnership and Non-partnership activities.
Partnership activities have been presented on a common control accounting basis which reflects the dropdown
transactions as if they occurred in prior periods similar to a pooling of interests. The Non-Partnership results
include activities related to certain assets and liabilities contractually excluded from the dropdown transactions
and certain historical hedge activities that could not be reflected under GAAP in the Partnership common
control results.
Field
Coastal
Partnership
Year Ended December 31, 2010
Gathering
Gathering
Marketing
and
and
Logistics
and
Corporate
and
Processing
Processing
Assets
Distribution
Other
Eliminations
TRC Non-
Partnership
Consolidated
Revenues
Intersegment revenues
Revenues
Operating margin
Other financial
information:
Total assets
Capital expenditure
$
$
$
$
$
211.6 $
446.6 $
84.5 $
4,713.5 $
4.0 $
- $
1,084.4
755.7
88.0
494.8
-
(2,422.9)
1,296.0 $
1,202.3 $
172.5
$
5,208.3
$
4.0 $
(2,422.9) $
236.6 $
107.8 $
83.8 $
80.5 $
4.0 $
- $
9.0 $
-
9.0 $
8.6 $
1,623.4 $
451.5 $
471.9 $
519.9 $
44.1 $
75.6 $
207.4 $
67.8 $
6.9 $
66.3 $
2.7 $
- $
- $
3.5 $
5,469.2
-
5,469.2
521.3
3,393.8
147.2
F-34
Revenues
Intersegment revenues
Revenues
Operating margin
Other financial
information:
Total assets
Capital expenditure
$
$
$
$
$
Year Ended December 31, 2009
Partnership
Field
Gathering
and
Processing
Coastal
Gathering
and
Processing
Logistics
Assets
Marketing
and
Distribution
Other
Corporate
and
Eliminations
TRC Non-
Partnership
Consolidated
191.7 $
392.0 $
780.1
525.0
76.7 $
79.5
337.4
-
(1,722.0)
3,797.1 $
46.3 $
- $
32.2 $
4,536.0
971.8 $
917.0 $
156.2 $
4,134.5 $
46.3 $
(1,722.0) $
183.2 $
89.7 $
74.3 $
83.0 $
46.3 $
- $
1,668.2 $
489.0 $
414.4 $
442.3 $
46.8 $
92.0 $
214.8 $
53.4 $
14.0 $
15.8 $
16.0 $
- $
- $
2.7 $
Year Ended December 31, 2008
Partnership
Field
Coastal
Gathering
Gathering
Marketing
Corporate
and
and
Logistics
and
and
TRC Non-
Processing
Processing
Assets
Distribution
Other
Eliminations
Partnership
Consolidated
415.9 $
781.2 $
69.1 $
6,797.5 $
(33.6) $
- $
(31.2) $
7,998.9
-
32.2 $
33.4 $
-
4,536.0
509.9
3,367.5
101.9
$
$
$
Revenues
Intersegment revenues
Revenues
Operating margin
Other financial
information:
Total assets
1,530.8
736.4
103.4
619.5
-
(2,990.1)
-
1,946.7 $
1,517.6 $
172.5 $
7,417.0 $
(33.6) $
(2,990.1) $
(31.2) $
385.4 $
105.4 $
40.1 $
41.3 $
(33.6) $
- $
(33.4) $
1,725.7 $
522.4 $
421.5 $
356.9 $
202.1 $
120.0 $
293.2 $
Capital expenditure
82.7
13.1
37.2
4.2
-
-
8.3
The following table shows our revenues by product and service for each period presented:
Natural gas sales
NGL sales
Condensate sales
Fractionating and treating fees
Storage and terminalling fees
Transportation fees
Gas processing fees
Hedge settlements
Business interruption insurance
Other
Year Ended December 31,
2010
2009
2008
$
1,076.5 $
809.4 $
1,590.3
4,115.3
3,365.3
6,148.4
95.1
55.8
40.1
33.8
32.1
9.1
6.0
5.4
95.5
61.2
41.0
43.4
24.0
69.7
21.5
4.6
131.5
66.8
33.0
39.2
22.0
(65.1)
32.9
(0.1)
$
5,469.2 $
4,536.0 $
7,998.9
F-35
-
7,998.9
505.2
3,641.8
145.5
The following table is a reconciliation of operating margin to net income for each period presented:
Year Ended December 31,
2010
2009
2008
Reconciliation of operating margin to net income
Operating margin
$
521.3 $
509.9 $
505.2
Depreciation and amortization expense
General and administrative expense
Interest expense, net
Income tax expense
Other, net
Net income
(185.5)
(144.4)
(110.9)
(22.5)
5.3
(170.3)
(160.9)
(120.4)
(96.4)
(132.1)
(141.2)
(20.7)
12.7
(19.3)
47.0
$
63.3 $
79.1 $
134.4
Note 22 – Other Operating Income
Our other operating (income) expense consists of the following items for the periods indicated:
Year Ended December 31,
2010
2009
2008
Abandoned project costs
$
Casualty loss (gain) adjustment (see Note 13)
Loss (gain) on sale of assets (1)
0.1 $
(3.3)
(1.5)
$
(4.7) $
5.5 $
(3.6)
0.1
2.0 $
-
19.3
(5.9)
13.4
________
(1) For 2008, $5.8 million gain on sale of assets was due to a like-kind exchange. See Note 20.
Note 23 – Significant Risks and Uncertainties
Our primary business objective is to increase our available cash for dividends to our stockholders by assisting
the Partnership in executing its business strategy. We may facilitate the Partnership’s growth through various
forms of financial support, including, but not limited to, modifying the Partnership’s IDRs, exercising the
Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital
contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the
Partnership, if needed, to support its ability to make distributions. In addition, we may acquire assets that could
be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or
further development.
Nature of the Partnership’s Operations in Midstream Energy Industry
The Partnership operates in the midstream energy industry. Its business activities include gathering,
transporting, processing, fractionating and storage of natural gas, NGLs and crude oil. The Partnership’s 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, condensate 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.
The Partnership’s profitability could be impacted by a decline in the volume of natural gas, NGLs and
condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate
production or condensate 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 condensate
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
F-36
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 the Partnership’s
results of operations, cash flows and financial position.
The principal market risks are exposure to changes in commodity prices, particularly to the prices of natural gas
and NGLs, as well as changes in interest rates. The fair value of commodity and interest rate 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 the Partnership to the risk of financial loss in certain
circumstances. The Partnership’s hedging arrangements provide it protection on its hedged volumes if prices
decline below the prices at which these hedges are set. If prices rise above the prices at which they are hedged,
the Partnership will receive less revenue on the hedged volumes than it would receive in the absence of hedges.
Commodity Price Risk. A majority of the revenues from the natural gas gathering and processing business are
derived from percent-of-proceeds contracts under which the Partnership receives 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
market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional
factors beyond our control. The Partnership monitors these risks and enters into commodity derivative
transactions designed to mitigate the impact of commodity price fluctuations on its business. 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.
In an effort to reduce the variability of our cash flows the Partnership has hedged the commodity price
associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the
years 2010 through 2014 by entering into derivative financial instruments including swaps and purchased puts
(or floors). The percentages of expected equity volumes that are hedged decrease over time. With swaps, the
Partnership typically receives an agreed upon fixed price for a specified notional quantity of natural gas or NGL
and pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since
the Partnership receives from its 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 actual equity volumes,
the Partnership typically limits its use of swaps to hedge the prices of less than its expected natural gas and NGL
equity volumes. The Partnership utilizes purchased puts (or floors) to hedge additional expected equity
commodity volumes without creating volumetric risk. The Partnership’s commodity hedges may expose it to the
risk of financial loss in certain circumstances. Hedging arrangements provide it protection on the hedged
volumes if market prices decline below the prices at which these hedges are set. If market 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. See Note 14.
Interest Rate Risk. The Partnership is exposed to changes in interest rates, primarily as a result of variable rate
borrowings under its credit facility. In an effort to reduce the variability of its cash flows, the Partnership has
entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which
are accounted for as cash flow hedges, the base interest rate on the specified notional amount of variable rate
debt is effectively fixed for the term of each agreement. See Note 14.
Counterparty Risk – Credit and Concentration
Derivative Counterparty Risk
Where the Partnership is exposed to credit risk in our financial instrument transactions, management analyzes
the counterparty’s 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.
The Partnership has master netting agreements with most of its hedge counterparties. These netting
arrangements allow it to net settle asset and liability positions with the same counterparties. As of December 31,
2010, the Partnership had $25.8 million in liabilities to offset the default risk of counterparties with which it also
had asset positions of $38.4 million as of that date.
F-37
The credit exposure related to commodity derivative instruments is represented by the fair value of contracts
with a net positive fair value to the Partnership at the reporting date. At such times, these outstanding
instruments expose it to credit loss in the event of nonperformance by the counterparties to the agreements.
Should the creditworthiness of one or more of the counterparties decline, the ability to mitigate nonperformance
risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a
novation of the derivative contract to a third party. In the event of a counterparty default, the Partnership may
sustain a loss and its cash receipts could be negatively impacted.
As of December 31, 2010, affiliates of Barclays, Credit Suisse and British Petroleum (“BP”) accounted for 62%,
13% and 12%, respectively, of the Partnership’s net counterparty credit exposure related to commodity
derivative instruments. Barclays, Credit Suisse and BP are major financial institutions or corporations each
possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s
Ratings Services.
Customer Credit Risk
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. The following table summarizes the activity affecting our allowance for bad
debts:
Balance at beginning of year
Additions
Deductions
Balance at end of year
Significant Commercial Relationships
Year Ended December 31,
2010
2009
2008
$
$
8.0 $
-
(0.1)
7.9 $
9.2 $
-
(1.2)
8.0 $
0.9
8.3
-
9.2
We are exposed to concentration risk when a significant customer or supplier accounts for a significant portion
of our business activity. The following table lists the percentage of our consolidated sales or purchases with
customers and suppliers which accounted for more than 10% of our consolidated revenues and consolidated
product purchases for the periods indicated:
% of consolidated revenues
Chevron Phillips Chemical Company LLC
% of product purchases
Louis Dreyfus Energy Services L.P.
Year Ended December 31,
2010
2009
2008
10%
10%
15%
11%
19%
9%
All transactions in the above table were associated with the Marketing and Distribution segment.
Casualty or Other Risks
Targa maintains coverage in various insurance programs, which provides us with property damage, business
interruption and other coverages which are customary for the nature and scope of our operations. The financial
impact of storm events such as Hurricanes Katrina and Rita, and more recently Hurricanes Gustav and Ike, as
well as the current economic environment, have affected many insurance carriers, and may affect their ability to
meet their obligation or trigger limitations in certain insurance coverages. At present, there is no indication of
any of our insurance carriers being unable or unwilling to meet their coverage obligations.
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
F-38
unavailable, or available for only reduced amounts of coverage. As a result, we 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 obligations.
Note 24 – Stock and Other Compensation Plans
2005 Incentive Compensation Plan
Stock Option Plans
Under Targa’s 2005 Incentive Compensation Plan (“the Plan”), options to purchase a fixed number of shares of
its stock may be granted to our employees, directors and consultants. Generally, options granted under the Plan
have a vesting period of four years and remain exercisable for ten years from the date of grant.
The fair value of each option granted was estimated on the date of grant using a Black-Scholes option pricing
model, which incorporates various assumptions for 2010, 2009 and 2008, including (i) expected term of the
options of ten years, (ii) a risk-free interest rate of 3.9% for 2010 and 3.6% for 2009 and 2008, (iii) expected
dividend yield of 0%, and (iv) expected stock price volatility on TRC’s common stock of 39.4% for 2010 and
25.5% for 2009 and 2008. Our selection of the risk-free interest rate was based on published yields for United
States government securities with comparable terms. Because TRC was a non-public company until December
10, 2010, its expected stock price volatility was estimated based upon the historical price volatility of the Dow
Jones U.S. Pipelines Index over a period equal to the expected average term of the options granted. The
calculated fair value of options granted during the year ended December 31, 2010, and 2008 was $4.09, and
$3.01 per share. There were no options granted in 2009.
We recognized compensation expense associated with stock options of $0.2 million, $0.1 million and $0.2
million during 2010, 2009 and 2008.
The following table shows stock option activity for the periods indicated:
Number of
Options (1)
Weighted Average
Exercise Price (2)
Outstanding at December 31, 2009
Granted
Exercised
Rescinded
Cashed out
Forfeited
2,215,442 $
46,018
(1,189,863)
(987,629)
(59,002)
(24,966)
17.04
7.22
0.67
24.87
1.90
25.51
Outstanding at December 31, 2010
_______
(1) The number of options was adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.
(2) The weighted average prices were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.
-
The aggregated intrinsic value of stock options exercised in 2010, 2009 and 2008 was $3.4 million, $0.2 million,
and $0.5 million.
Concurrent with the IPO, unexercised in-the-money stock options were cashed out, resulting in $1.2 million of
additional compensation expense in 2010. Unexercised out-of-the-money stock options were rescinded. As
such, there are no outstanding stock options at December 31, 2010.
In connection with our extraordinary special distribution of dividends to our common and common equivalent
shareholders (Note 10), in April 2010, we reduced the strike price on all of our outstanding options by $5.63.
All unvested options were deemed to have immediately vested in May 2010. The weighted average exercise
prices in the table above were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03, and
the reduced strike prices for options exercised, rescinded, and cashed out after the strike price was reduced in
F-39
May 2010. There were no options granted or forfeited after May 2010. This reduction is considered an award
modification for accounting purposes; therefore, we re-determined the fair value of the options immediately
following the reduction. The modification did not result in any additional compensation expense.
Non-vested (Restricted) Common Stock
Restricted stock awards entitle recipients to exchange restricted common shares for unrestricted common shares
(at no cost to them) once the defined vesting period expires, subject to certain forfeiture provisions. The
restrictions on the non-vested shares generally lapse four years from the date of grant.
Conversion of Vested Restricted Common Stock
Concurrent with the IPO in December 2010, all vested restricted common shares converted to unrestricted
common stock in the Company. The following table provides a summary of our non-vested restricted common
stock awards for the periods indicated:
Outstanding at beginning of period
Granted
Vested
Year Ended
Weighted Average
December 31, 2010 (1)
Grant-Date Fair Value (2)
25,091 $
30,198
(55,289)
3.40
7.22
5.49
Outstanding at end of period
_______
(1) The number of restricted stock was adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.
(2) The weighted average prices were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.
-
The following table presents weighted average fair value of shares granted and total fair value of shares vested
during the periods indicated.
Weighted average fair value of shares granted (per share) (1) $
7.22 $
- $
7.02
Year Ended December 31,
2010
2009
2008
Total fair value of shares vested (in millions)
_______
(1) The weighted average prices were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.
16.6
2.4
0.3
During 2010, 2009 and 2008, we recognized $0.2 million, $0.3 million and $1.0 million of compensation
expense associated with the vesting of restricted stock.
2010 TRC Stock Incentive Plan
In connection with our IPO in December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive
Plan (“TRC Plan”) for employees, consultants and non-employee directors of the Company. The TRC Plan
allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws
(“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and
together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with
Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock
awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance awards, or (viii) any
combination of such awards (collectively referred to a “Awards”).
On December 6, 2010, we awarded 556,514 bonus stock awards to our executive management team which
vested upon the closing of our IPO on December 10, 2010. Total compensation expense associated with these
awards in 2010 was $12.2 million. The compensation expense was calculated based on the fair value of the
stock of $22 per share at grant date.
On December 6, 2010, we granted to executive management and certain employees 1,350,000 Restricted Stock
Awards. These awards vest over a three year period at 60% in 24 months and the remaining 40% in 36 months.
F-40
There are no restrictions on the shares once the vesting requirement is met. Total compensation expense
associated with these awards in 2010 was $1.1 million. We expect to incur an additional $28.6 million of
expense related to the restricted awards over the next three years. The compensation expense was calculated
based on the fair value of the stock of $22 per share at grant date.
Subsequent Event. In February 2011, our Compensation Committee (the “Committee”) made awards to our
executive management for the 2011 compensation cycle of 33,140 restricted common shares under TRC’s Plan
that will vest three years from the grant date and 68,030 equity-settled performance units under the Partnership’s
LTIP that will vest in June 2014. The settlement value of these performance unit awards will be determined
using the formula adopted for the performance unit awards granted in December 2009.
Non-Employee Director Grants and Incentive Plan related to the Partnership’s Common Units
In connection with the Partnership’s IPO in February 2007, we adopted a long-term incentive plan (“LTIP”) for
employees, consultants and directors of the Partnership or its affiliates who perform services for us or our
affiliates. The LTIP provides for the grant of cash-settled performance units which are linked to the performance
of the Partnership’s common units and may include distribution equivalent rights (“DERs”). The LTIP is
administered by the compensation committee of our board of directors. Subject to applicable vesting criteria, a
DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.
Each vested performance unit will entitle the grantee to a cash payment equal to the then value of a Partnership
common unit, including DERs. The amount vesting under such awards is based on the total return per common
unit of the Partnership through the end of the performance period multiplied by the vesting percentage
determined from the Partnership’s ranking in a defined peer group.
The following table summarizes the LTIP units for the year ended 2010:
Unit outstanding January 1, 2010
Granted
Vested and paid
Forfeited
Units outstanding December 31, 2010
Program Year
2007 Plan
2008 Plan
2009 Plan
2010 Plan
275,400
-
(275,400)
-
-
135,800
-
-
(2,000)
133,800
534,900
-
-
(7,400)
527,500
90,403
219,597
-
(3,000)
307,000
Total
1,036,503
219,597
(275,400)
(12,400)
968,300
Calculated fair market value as of December 31, 2010
Liabilities recognized as of December 31, 2010:
Current
Long-term
$
$
5,176,263 $
20,113,575 $
13,621,590 $
38,911,428
4,276,430 $
-
- $
10,145,414
- $
3,434,471
4,276,430
13,579,885
To be recognized in future periods
899,833
9,968,161
10,187,119
21,055,113
Vesting date
June 2011
June 2012
June 2013
Because the performance units require cash settlement, they have been accounted for as liabilities in our
financial statements. During 2010, we paid $9.1 million for vested LTIP units.
During 2010, we changed the fair value measurement model from a Black-Scholes option pricing model to a
Monte Carlo simulation model. We considered the Monte Carlo simulation model to be more appropriate for
LTIP valuation purposes than our previous method because it directly incorporates the peer group ranking
market conditions.
Prior to the change, the fair value of a performance unit was the sum of: (i) the closing price of one of our
common units on the reporting date; (ii) the fair value of an at-the-money call option on a performance unit with
a grant date equal to the reporting date and an expiration date equal to the last day of the performance period;
and (iii) estimated DERs. The fair value of the call options was estimated using a Black-Scholes option pricing
model. The market condition was indirectly incorporated into the valuation based on our point-in-time ranking
versus peers at the measurement date.
With the Monte Carlo simulation model, the fair value of a performance unit is the sum of: (i) the simulated
F-41
share price of multiple correlated assets incorporated with peer ranking; and (ii) the estimated value of expected
DERs. The simulated stock price was estimated using the Monte Carlo simulation with discount rate of 7.17%
and expected volatility of 33.8%.
The remaining weighted average recognition period for the unrecognized compensation cost is approximately
two years. During 2010, 2009 and 2008 we recognized compensation expense of $13.9 million, $10.5 million
and $0.1 million related to the performance units.
Director Grants
During 2010 and 2009, Targa Resources GP LLC, the Partnership’s general partner, also made equity-based
awards of 15,750 and 32,000 of the Partnership’s restricted common units (2,250 and 4,000 of its restricted
common units to each of the Partnership’s and our non-management directors) under its Incentive 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. During 2010, 2009 and 2008,
the Partnership recognized compensation expense of $0.4 million, $0.3 million and $0.3 million related to these
awards with an offset to common equity. The Partnership estimates that the remaining fair value of $0.2 million
will be recognized in expense over approximately one year. As of December 31, 2010 there were 39,074
unvested restricted common units outstanding under this plan.
The following table summarizes the Partnership’s unit-based awards for each of the periods indicated (in units
and dollars):
Year Ended
December 31, 2010
Weighted-average
Grant-Date Fair Value
Outstanding at beginning of year
Granted
Vested
Outstanding at end of year
$
41,993 $
15,750
(18,669)
39,074
12.88
23.51
15.06
16.12
The weighted average grant-date fair value of the unit-based awards for the years ended 2010, 2009 and 2008
were $16.12, $12.88 and $22.12.
Subsequent event. On February 14, 2011, the Partnership’s general partner made equity based awards of 10,600
of the Partnership’s restricted common units (2,120 restricted common units under to each of the Partnership’s
non-management directors) under its Incentive 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.
Other Compensation Plans
We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain
limitations in the plan). We also contribute an amount equal to 3% of each employee’s eligible compensation to
the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa
contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $7.2 million,
$6.6 million, and $8.4 million during 2010, 2009, and 2008.
F-42
Note 25—Selected Quarterly Financial Data (Unaudited)
Our results of operations by quarter for the years ended December 31, 2010 and 2009 were as follows:
Year Ended December 31, 2010:
Revenues
Gross margin
Operating income
Net income (loss)
Net income (loss) attributable to Targa Resources Corp.
Net income (loss) available to common shareholders (1)
Net income (loss) per common
share - basic and diluted
Year Ended December 31, 2009:
Revenues
Gross margin
Operating income
Net income (loss)
Net income (loss) attributable to Targa Resources Corp.
First
Second
Third
Fourth
Quarter
Quarter
Quarter
Quarter
Total
(In millions, except per share amounts)
$
1,483.6
$
1,240.0 $
1,218.3 $
1,527.3 $
5,469.2
186.2
227.1
185.9
54.8
35.9
21.9
182.3
48.5
7.4
(11.5)
-
$
(191.8) $
43.2
(4.2)
(17.4)
(19.0) $
49.6
24.2
(8.0)
781.5
196.1
63.3
(15.0)
(9.0) $
(202.3)
-
$
(48.10) $
(3.77)
$
(0.68) $
(30.94)
$
$
$
1,005.6
$
1,013.8 $
1,125.7 $
1,390.9 $
4,536.0
155.9
174.9
189.4
224.7
25.4
(0.4)
1.3
48.5
20.5
12.2
50.1
10.5
(0.5)
(5.1) $
93.2
48.5
16.3
- $
744.9
217.2
79.1
29.3
-
-
Net income (loss) available to common shareholders
$
(3.0)
$
- $
Net income (loss) per common
share - basic and diluted
________
(1) We paid dividends of $177.8 million to Series B Preferred shareholders during the second quarter of 2010, which reduces the net
(3.77) $
(0.81)
- $
- $
$
$
income available to common shares.
F-43
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 Corp.;
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 registrant’s 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 15d-(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 registrant’s 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 registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s 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 registrant’s 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 registrant’s internal control over financial reporting.
Date: February 25, 2011
By: /s/ Rene R. Joyce
Name: Rene R. Joyce
Title: Chief Executive Officer of Targa Resources Corp.
(Principal Executive Officer)
Exhibit 31.2
CERTIFICATION
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Matthew J. Meloy, certify that:
1. I have reviewed this Annual Report on Form 10-K of Targa Resources Corp.;
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 registrant’s 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 15d-(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 registrant’s 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 registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s 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 registrant’s 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 registrant’s internal control over financial reporting.
Date: February 25, 2011
By: /s/ Matthew J. Meloy
Name: Matthew J. Meloy
Title: Senior Vice President, Chief Financial Officer and Treasurer of
Targa Resources Corp.
(Principal Financial Officer)
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER 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 Corp., for the year ended December
31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Rene R.
Joyce, as Chief Executive Officer of Targa Resources Corp., 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 Targa Resources Corp.
By: /s/ Rene R. Joyce
Name: Rene R. Joyce
Title: Chief Executive Officer of Targa Resources Corp.
Date: February 25, 2011
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.
Exhibit 32.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER 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 Corp. for the year ended December 31,
2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Matthew J.
Meloy, as Chief Financial Officer of Targa Resources Corp., 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 Targa Resources Corp.
By: /s/ Matthew J. Meloy
Name: Matthew J. Meloy
Title: Senior Vice President, Chief Financial Officer and Treasurer of
Targa Resources Corp.
Date: February 25, 2011
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.
[THIS PAGE INTENTIONALLY LEFT BLANK]