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
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
OR
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)
811 Louisiana Street, Suite 2100, 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
Trading Symbol(s)
TRGP
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 every Interactive Data File required to be submitted 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 such
files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an
emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company”
in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
☑
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☐
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or
revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control
over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued
its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
The aggregate market value of the common stock held by non-affiliates of the registrant was $10,012.0 million on June 30, 2021, based on $44.45 per share,
the closing price of the common stock as reported on the New York Stock Exchange (NYSE) on such date.
As of February 18, 2022, there were 228,783,477 shares of the registrant’s common stock, $0.001 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of
the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual Report on Form 10-K.
TABLE OF CONTENTS
PART I
Item 1. Business.
Item 1A. Risk Factors.
Item 1B. Unresolved Staff Comments.
Item 2. Properties.
Item 3. Legal Proceedings.
Item 4. Mine Safety Disclosures.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
PART II
Item 6. Reserved
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Item 8. Financial Statements and Supplementary Data.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
Item 9A. Controls and Procedures.
Item 9B. Other Information.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Item 14. Principal Accounting Fees and Services.
Item 15. Exhibits, Financial Statement Schedules.
Item 16. Form 10-K Summary.
Signatures
PART IV
SIGNATURES
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Targa Resources Corp.’s (together with its subsidiaries, including Targa Resources Partners LP (the “Partnership” or “TRP”), “we,”
“us,” “our,” “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 statements, 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 following risks and uncertainties:
the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies
to our gathering and processing systems, oil supplies to our gathering systems and natural gas liquid supplies to our
logistics and transportation facilities and our success in connecting our facilities to transportation services and markets;
the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates
and demand for our services;
our ability to access the capital markets, which will depend on general market conditions, the credit ratings for the
Partnership’s and our debt obligations, and demand for our common equity and the Partnership’s senior notes;
the impact of outbreaks of illnesses, pandemics (like COVID-19) or any other public health crises;
the amount of collateral required to be posted from time to time in our transactions;
our success in risk management activities, including the use of derivative instruments to hedge commodity price risks;
the level of creditworthiness of counterparties to various transactions with us;
changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;
weather and other natural phenomena, and related impacts;
industry changes, including the impact of consolidations and changes in competition;
our ability to timely obtain and maintain necessary licenses, permits and other approvals;
our ability to grow through internal growth capital projects or acquisitions and the successful integration and future
performance of such assets;
general economic, market and business conditions; and
the risks described elsewhere in “Item 1A. Risk Factors” in this Annual Report and our reports and registration statements
filed from time to time with the United States Securities and Exchange Commission (“SEC”).
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.
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As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:
Bbl
BBtu
Bcf
Btu
/d
FERC
GAAP
gal
LIBOR
LPG
MBbl
MMBbl
MMBtu
MMcf
MMgal
NGL(s)
NYMEX
NYSE
SCOOP
SOFR
STACK
VLGC
Barrels (equal to 42 U.S. gallons)
Billion British thermal units
Billion cubic feet
British thermal units, a measure of heating value
Per day
Federal Energy Regulatory Commission
Accounting principles generally accepted in the United States of America
U.S. gallons
London Interbank Offered Rate
Liquefied petroleum gas
Thousand barrels
Million barrels
Million British thermal units
Million cubic feet
Million U.S. gallons
Natural gas liquid(s)
New York Mercantile Exchange
New York Stock Exchange
South Central Oklahoma Oil Province
Secured Overnight Financing Rate
Sooner Trend, Anadarko, Canadian and Kingfisher
Very large gas carrier
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Item 1. Business.
PART I
The following section of this Form 10-K generally refers to business developments during the year ended December 31, 2021.
Discussion of prior period business developments that are not included in this Form 10-K can be found in “Part I, Item 1. Business”
of our Annual Report on Form 10-K for the year ended December 31, 2020.
Overview
Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider
of midstream services and is one of the largest independent midstream infrastructure companies in North America. We own, operate,
acquire, and develop a diversified portfolio of complementary domestic midstream infrastructure assets.
Our Operations
We are engaged primarily in the business of:
gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;
transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to
LPG exporters; and
gathering, storing, terminaling, and purchasing and selling crude oil.
To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation
(also referred to as the Downstream Business).
Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil
and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets
used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment's assets are
located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the
Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma
(including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three
Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and
also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs
and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other
businesses. The Logistics and Transportation segment also includes the Grand Prix NGL Pipeline (“Grand Prix”), which connects our
gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in
Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment
and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake
Charles, Louisiana.
Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.
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The map below highlights our more significant assets as of December 31, 2021:
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Recent Developments
Permian Midland Processing Expansion
In November 2020, we announced the transfer of an existing cryogenic natural gas processing plant from our North Texas system (the
“Longhorn plant”), to our Permian Midland system. The plant was relocated to and installed in Reagan County, Texas, in 2021, as a
new 200 MMcf/d cryogenic natural gas processing plant (the “Heim plant”). The Heim plant, which commenced operations in the
third quarter of 2021, processes natural gas production from the Permian Basin.
In August 2021, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the
“Legacy plant”). The Legacy plant is expected to begin operations in the fourth quarter of 2022.
In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the
construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Legacy II plant”). The Legacy II
plant is expected to begin operations in the second quarter of 2023.
Permian Delaware Processing Expansion
In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the
construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Midway plant”). The Midway
plant is expected to begin operations in the third quarter of 2023. In conjunction with the commencement of operations of the Midway
plant, we expect to idle the Sand Hills plant.
Capital Allocation
In January 2022, we declared an increase to our common dividend to $0.35 per common share or $1.40 per common share annualized
effective for the fourth quarter of 2021 and payable in February 2022.
In January 2022, we closed on the repurchase of our interests in our development company joint ventures (“DevCo JVs”) from
investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) for approximately $925 million (the “DevCo JV
Repurchase”). Following the repurchase, we own a 75% interest in Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), a 100%
interest in our Train 6 fractionator in Mont Belvieu, Texas and owned a 25% equity interest in Gulf Coast Express Pipeline (“GCX”).
In February 2022, we announced that we executed agreements to sell Targa GCX Pipeline LLC (“GCX DevCo JV”), which held our
25% equity interest in GCX for approximately $857 million (the “GCX Sale”). We expect to receive the full proceeds from the sale in
the second quarter of 2022 following a customary call right period in favor of the other members of GCX.
In the fourth quarter of 2021, we repurchased 756,478 shares of our common stock at a weighted average price of $52.81 for a total
net cost of approximately $40 million. There was approximately $369 million remaining under our $500 million common share
repurchase program as of December 31, 2021.
Financing Activities
In February 2022, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent, Collateral Agent and
Swing Line Lender, and the other lenders party thereto (the “New TRC Revolver”). The New TRC Revolver provides for a revolving
credit facility in an initial aggregate principal amount up to $2.75 billion and matures on February 17, 2027. In connection with our
entry into the New TRC Revolver, we terminated our senior secured revolving credit facility (the “Existing TRC Revolver”) and the
Partnership’s senior secured revolving credit facility (the “Existing TRP Revolver”). For a full discussion of the New TRC Revolver
and its terms, see Note 8 – Debt Obligations in our Consolidated Financial Statements beginning on page F-1 in this Form 10-K.
COVID-19 Pandemic
The global spread of COVID-19 during 2020 and 2021 caused significant commodity market volatility. Nonetheless, we are currently
experiencing no material issues with potential workforce, supply chain or customer relationship disruptions. Although significant
progress has been made towards the development, distribution and administration of various COVID-19 vaccines, there continues to
be significant uncertainty about the disruptions and other effects related to COVID-19. As a result, we are unable to determine the
extent that these events could materially impact our future financial position, operations and/or cash flows. For further discussion, see
“Item 1A. Risk Factors.”
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Impact of Winter Weather
In February 2021, the Central region of the United States experienced unprecedented cold temperatures during a major winter storm
that disrupted production operations, midstream infrastructure and many other services. This extreme weather caused wide
fluctuations in commodity prices, short-term disruptions to our operations across Texas, New Mexico, Oklahoma and Louisiana,
including reduced throughput volumes coming into our systems, and adversely affected the operations and financial condition of some
of our counterparties. Though certain of our facilities experienced temporary outages, all facilities have since returned to full operation
without sustaining any long-term impacts or significant adverse financial impacts related to the weather event, and throughput
volumes have returned to pre-storm levels. The full financial impact of the winter storm still remains uncertain as it is subject to
recently proposed regulatory changes and potential customer and counterparty risk. For further discussion, see “Item 1A. Risk
Factors.”
Corporation Tax Matters
The Internal Revenue Service (“IRS”) notified us on April 3, 2019, that it would examine Targa’s federal income tax returns (Form
1120) for 2014, 2015 and 2016. The IRS completed their examination without proposing any adjustments, and the Joint Committee on
Taxation approved the IRS’ findings without any exception. The Joint Committee on Taxation sent Targa a closing letter dated
February 23, 2021. The closing letter effectively ends the IRS’ audit of Targa’s federal income tax returns for these years.
Additionally, in January 2022, the IRS notified us that it will examine Targa’s net operating loss (“NOL”) carryback previously
claimed under the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. The CARES Act was signed into law on March
27, 2020 and provided corporate taxpayers an expanded five-year NOL carryback period for losses generated in tax years 2018
through 2020. We received a cash refund of approximately $44 million related to the CARES Act provisions in 2020. We are
cooperating with the IRS in the audit process and do not anticipate material changes in prior year taxable income.
Organization Structure
The diagram below shows our corporate structure as of February 18, 2022:
(1) Common shares outstanding as of February 18, 2022.
Growth Drivers, Competitive Strengths and Strategies
We believe that our near-term growth will be driven by organic projects being placed into service and third-party acquisitions, as well
as the level of producer activity in the basins where our gathering and processing infrastructure is located and the level of demand for
services provided by our logistics and transportation assets.
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While we believe that we are well positioned to execute our business strategies based on our growth drivers, competitive strengths and
strategies outlined below, our business involves numerous risks and uncertainties which may prevent us from executing our strategies.
These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices, the supply of, or demand for,
these commodities, and our inability to access sufficient additional supplies to replace natural declines in production. For a more
complete description of the risks associated with an investment in us, see “Item 1A. Risk Factors.”
Comprehensive package of midstream services
We provide a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather,
process, treat, purchase and sell and transport wellhead gas to meet pipeline standards; extract, transport and fractionate NGLs for sale
into petrochemical, industrial, commercial and export markets; and gather and/or purchase and sell crude oil. We believe that our
ability to offer these integrated services provides us with an advantage in competing for new supplies because we can provide
substantially all of the services that producers, marketers and others require for moving natural gas, NGLs and crude oil from wellhead
to market on a cost-effective basis. Additionally, we believe that the significant investment we have made to construct and acquire
assets in key strategic positions and the expertise we have in operating such assets make us well-positioned to remain a leading
provider of integrated services in the midstream sector.
Our transportation assets further enhance our position to offer an integrated midstream service across the NGL and natural gas value
chain by linking supply to key markets. Grand Prix connects many of our gathering and processing positions, including the very active
Permian Basin, with our Downstream facilities in Mont Belvieu, Texas, a major U.S. NGL market hub. Additionally, our integrated
Mont Belvieu and Galena Park Marine Terminal assets allow us to provide the raw product, fractionation, storage, interconnected
terminaling, refrigeration and ship loading capabilities to support exports by third-party customers.
Strategically located and leading infrastructure positions
We believe our assets are not easily replicated, are located in many attractive and active areas of exploration and production activity
and are near key markets and logistics centers. Our gathering and processing infrastructure is located in attractive oil and gas
producing basins and is well positioned within each of those basins. Activity in the shale resource plays underlying our gathering
assets is driven by the economics of oil, condensate, gas and NGL production from the particular reservoirs in each play impacting the
volumes of natural gas and crude oil available to us for gathering, processing and/or purchase and sale on our systems. Producers
continue to focus drilling activity on their most attractive acreage, especially in the Permian Basin where we have a large, well-
positioned and interconnected footprint, benefiting from rig activity in and around our systems.
As drilling in these areas continues, the supply of NGLs requiring transportation to market hubs and fractionation is expected to
continue to grow. Continued demand for transportation, fractionation and export capacity is expected to lead to increased demand for
other related fee-based services provided by our logistics and transportation assets as well as provide other growth opportunities. The
connectivity of our gathering and processing and Downstream operations provided by Grand Prix further allows us to capture these
growth opportunities. Additionally, we are one of the largest fractionators of NGLs along the Gulf Coast. Our fractionation assets are
primarily located in key NGL market centers and are near and connected to key consumers of NGL products, including the
petrochemical and industrial markets. Our logistics assets, including fractionation facilities, storage wells, our low ethane propane de-
ethanizer, and our Galena Park Marine Terminal and related pipeline systems and interconnects, include connections to a number of
mixed NGL (“mixed NGLs” or “Y-grade”) supply pipelines, storage, interconnection and takeaway pipelines and other transportation
infrastructure. The location and interconnectivity of these assets are not easily replicated, and we have additional capability to expand
their capacity.
High quality and efficient assets
Our gathering and processing systems and logistics and transportation 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 systems (essentially all electronic and electronically linked to a central data-
base) and operations and maintenance management systems to manage work orders and implement preventative maintenance
schedules (computerized maintenance management systems). These applications have allowed proactive management of our
operations resulting in lower costs and minimal downtime. We have established a reputation in the midstream industry as a reliable
and cost-effective supplier of services to our customers and have a track record of safe, efficient and reliable operation of our
facilities. We will continue to pursue new contracts, cost efficiencies and operating improvements of our assets. In the past, such
improvements have included new production and acreage commitments, reducing fuel gas and flare volumes and improving facility
capacity and NGL recoveries. We will also continue to optimize existing plant assets to improve and maximize capacity and
throughput.
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In addition to routine annual maintenance expenses, our maintenance capital expenditures have averaged approximately $130 million
per year over the last three years. We believe that our assets are well-maintained, and we are focused on continuing to operate both our
existing and new assets in a prudent, safe and cost-effective manner.
Financial flexibility
We have historically maintained sufficient liquidity and have funded our growth investments with a mix of cash flow from operations,
equity, debt, asset sales and joint ventures over time in order to manage our leverage ratio. Disciplined management of liquidity,
leverage and commodity price volatility allow us to be flexible in our long-term growth strategy, as well as allocating our free cash
flow after dividends in a manner that strengthens our credit profile and progresses our long-term goal of achieving investment grade
ratings.
Experienced and long-term focused management team
Our current executive management team possesses breadth and depth of experience working in the midstream energy business.
Certain members of our executive management team have managed our businesses prior to acquisition by Targa or joined shortly
thereafter. Other officers and key employees have significant experience in the industry, including extensive experience in operating
our current assets and developing, permitting and constructing new assets.
Attractive cash flow characteristics, with large diverse business mix with favorable contracts and increasing fee-based business
We believe that our strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows. Geographic,
business and customer diversity enhances our cash flow profile. We provide our services under attractive contract terms,
predominantly fee-based, to a diverse mix of customers across our areas of operation. Our Gathering and Processing segment contract
mix has increasing components of fee-based margin driven by: (i) fees added to percent-of-proceeds contracts for natural gas treating
and compression, (ii) new/amended contracts with a combination of percent-of-proceeds and fee-based components, including fee
floors, and (iii) fee-based gas gathering and processing and crude oil gathering contracts. Contracts for the Coastal portion of our
Gathering and Processing segment are primarily hybrid contracts (percent-of-liquids with a fee floor) or percent-of-liquids contracts
(whereby we receive an agreed upon percentage of the actual proceeds of the NGLs).
Contracts in the Downstream Business are predominantly fee-based (based on volumes and contracted rates), with a large take-or-pay
component. Our contract mix, along with our commodity hedging program, serves to mitigate the impact of commodity price
movements on cash flow.
We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes,
future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. We
have intentionally tailored our hedges to approximate specific NGL products and to approximate our actual NGL and residue natural
gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some of our exposure to commodity
prices by entering into hedge transactions. We also monitor and manage our inventory levels with a view to mitigate losses related to
downward price exposure.
Our Business Operations
Our operations are reported in two segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as
the Downstream Business).
Gathering and Processing Segment
Our Gathering and Processing segment consists of gathering, compressing, treating, processing, transporting, and purchasing and
selling natural gas and gathering, storing, terminaling and purchasing and selling crude oil. The gathering or purchase of natural gas
consists of aggregating natural gas produced from various wells through varying 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. Once processed, the
residue gas is transported to markets through residue gas pipelines. End-users of residue gas include large commercial and industrial
customers, as well as natural gas and electric utilities serving individual consumers. We sell our 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
our facilities. The gathering or purchase of crude oil consists of aggregating crude oil production through our pipeline gathering
systems, which deliver crude oil to a combination of other pipelines, rail and truck.
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We continually seek new supplies of natural gas and crude oil, both to offset the natural decline in production from connected wells
and to increase throughput volumes. We obtain additional natural gas and crude oil supply in our operating areas by contracting for
production from new wells or by capturing existing production currently gathered by others. Competition for new natural gas and
crude oil supplies is based primarily on location of assets, commercial terms including pre-existing contracts, service levels and access
to markets. The commercial terms of natural gas gathering and processing arrangements and crude oil gathering 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.
The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including
the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko,
Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in
North Dakota (including the Bakken and Three Forks plays) and in the onshore and near offshore regions of the Louisiana Gulf Coast
and the Gulf of Mexico.
The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately
28,400 miles of natural gas pipelines and include 42 owned and operated processing plants. During 2021, we processed an average of
4,470.3 MMcf/d of natural gas and produced an average of 550.4 MBbl/d of NGLs. In addition to our natural gas gathering and
processing, the Badlands operations include a crude oil gathering system and four terminals with crude oil operational storage capacity
of 205 MBbl, and the Permian operations include a crude oil gathering system and one terminal with crude oil operational storage
capacity of 30 MBbl. During 2021, we purchased or gathered an aggregate average of 175.9 MBbl/d of crude oil in the Badlands and
Permian.
The Gathering and Processing segment’s operations consist of (i) Permian Midland and Permian Delaware (also referred to as
“Permian”), (ii) SouthTX, North Texas, SouthOK, WestOK (also referred to as “Central”), (iii) Coastal and (iv) Badlands each as
described below:
Permian Midland
The Permian Midland system consists of approximately 7,000 miles of natural gas gathering pipelines and sixteen processing plants
with an aggregate processing capacity of 2,754 MMcf/d, all located within the Permian Basin in West Texas. Ten of these plants and
approximately 4,900 miles of gathering pipelines belong to a joint venture (“WestTX”), in which we have an approximate 72.8%
ownership. Pioneer Natural Resources (“Pioneer”), a major producer in the Permian Basin, owns the remaining interest in the WestTX
system.
We completed construction of the Heim plant, a 200 MMcf/d cryogenic natural gas processing plant, which was relocated from our
North Texas system to our Permian Midland system. The Heim plant commenced operations in the third quarter of 2021.
We are constructing the Legacy plant, a 275 MMcf/d cryogenic natural gas processing plant. The Legacy plant is expected to begin
operations in the fourth quarter of 2022.
In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the
construction of the Legacy II plant, a new 275 MMcf/d cryogenic natural gas plant. The Legacy II plant is expected to begin
operations in the second quarter of 2023.
Permian Delaware
The Permian Delaware system consists of approximately 6,100 miles of natural gas gathering pipelines and eight processing plants
with an aggregate capacity of 1,290 MMcf/d, all within the Delaware Basin in West Texas and Southeastern New Mexico.
The Permian Midland and Permian Delaware systems are interconnected and volumes may flow from one system to the other
providing increased operational flexibility and redundancy.
In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the
construction of the Midway plant, a new 275 MMcf/d cryogenic natural gas processing plant. The Midway plant is expected to begin
operations in the third quarter of 2023. In conjunction with the commencement of operations of the Midway plant, we expect to idle
the Sand Hills plant.
10
SouthTX
The South Texas system contains approximately 900 miles of high-pressure and low-pressure gathering and transmission pipelines
and three natural gas processing plants in the Eagle Ford Shale. The South Texas system processes natural gas through the Silver Oak
I, Silver Oak II and Raptor gas processing plants. The Silver Oak I and II plants (the “Silver Oak plants”) are each 220 MMcf/d
cryogenic plants. The Raptor plant is a 260 MMcf/d cryogenic plant.
We participate in, and serve as operator for, two joint ventures in South Texas with a subsidiary of Southcross Energy Partners LLC,
which consist of our 75% share in T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and our 50% share in T2 Eagle Ford
Gathering Company LLC (“T2 Eagle Ford”). T2 LaSalle owns approximately 60 miles of high-pressure gathering pipeline and T2
Eagle Ford owns approximately 120 miles of high-pressure gathering pipelines. Together, these two pipelines gather and transport gas
to the Silver Oak plants. T2 Eagle Ford also owns the residue gas delivery pipelines downstream of the Silver Oak plants.
We also participate in a third joint venture (the “Carnero Joint Venture”) in South Texas with Evolve Transition Infrastructure LP
(“Evolve Transition Infrastructure”). We own a 50% interest and Evolve Transition Infrastructure owns the remaining 50% interest.
The Carnero Joint Venture owns and Targa operates the Silver Oak II plant, the Raptor plant and approximately 45 miles of high-
pressure gathering pipeline located in La Salle, Dimmitt and Webb Counties, Texas which connects Mesquite Energy Inc.’s Catarina
Ranch gathering system and Comanche Ranch acreage to the Raptor plant.
North Texas
North Texas includes the Chico gathering system in the Fort Worth Basin, which gathers gas from the Barnett Shale and Marble Falls
plays for processing at the Chico plant. The system consists of approximately 4,700 miles of pipelines gathering wellhead natural gas.
The Chico plant has a processing capacity of 265 MMcf/d.
SouthOK
The SouthOK gathering system is located in the Ardmore and Anadarko Basins and includes the Golden Trend, SCOOP, and
Woodford Shale areas of southern Oklahoma. The gathering system has approximately 1,600 miles of pipelines.
The SouthOK system includes six separate operational processing plants with an aggregate processing capacity of 710 MMcf/d,
including: the Coalgate, Stonewall, Hickory Hills and Tupelo facilities, which are owned by our Centrahoma Joint Venture, and our
wholly-owned Velma and Velma V-60 plants. We have a 60% ownership interest in Centrahoma. The remaining 40% ownership
interest in Centrahoma is held by MPLX, LP.
WestOK
The WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin and includes the Woodford
shale and the STACK. The gathering system expands into 14 counties with approximately 6,600 miles of natural gas gathering
pipelines.
The WestOK system has an aggregate processing capacity of 400 MMcf/d with two separate cryogenic natural gas processing plants
known as the Waynoka I and Waynoka II facilities.
Coastal
Our Coastal assets, located in and offshore South Louisiana, gather and process natural gas produced from shallow-water central and
western Gulf of Mexico natural gas wells and from deep shelf and deep-water Gulf of Mexico production via connections to third-
party pipelines or through pipelines owned by us. The Coastal system has an aggregate processing capacity of 2,025 MMcf/d and 11
MBbl/d of integrated fractionation capacity, and consists of approximately 1,000 miles of onshore gathering system pipelines, and
approximately 200 miles of offshore gathering system pipelines. The processing plants are comprised of three wholly-owned and
operated plants, one partially owned and operated plant, and one partially owned plant which is non-operated. Our Coastal plants have
access to markets across the U.S. through the interstate natural gas pipelines to which they are interconnected. The industry continues
to rationalize gas processing capacity along the western Louisiana Gulf Coast with most of the producer volumes going to more
efficient plants, such as our Lowry and Gillis plants.
11
Badlands
The Badlands operations are located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota and include
approximately 500 miles of crude oil gathering pipelines, 120 MBbl of operational crude oil storage capacity at the Johnsons Corner
Terminal, 30 MBbl of operational crude oil storage capacity at the Alexander Terminal, 30 MBbl of operational crude oil storage at
New Town and 25 MBbl of operational crude oil storage at Stanley. The Badlands assets also include approximately 300 miles of
natural gas gathering pipelines and the Little Missouri I-III natural gas processing plants, which have a processing capacity of 90
MMcf/d. Additionally, Targa operates the 200 MMcf/d Little Missouri 4 plant (“LM4 plant”), in which Targa Badlands and Hess
Midstream Partners LP each own a 50% interest. Targa owns 55% of Targa Badlands through a joint venture with Blackstone Credit
(“Blackstone”). The joint venture is a consolidated subsidiary and its financial results and related statistics are presented on a gross
basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority
right to the MQDs. Additionally, Blackstone’s capital contributions have a liquidation preference upon a sale of Targa Badlands.
Targa Badlands is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts and other
obligations of Targa or its other subsidiaries.
12
The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended
December 31, 2021:
Facility
Permian Midland
Consolidator (6)
Midkiff (6)
Driver (6)
Benedum (6)
Edward (6)
Buffalo (6)
Joyce (6)
Johnson (6)
Hopson (6)
Pembrook (6)
Mertzon
Sterling
Tarzan (7)
High Plains
Gateway (8)
Heim (8)(9)
Permian Delaware
Sand Hills
Loving
Oahu
Wildcat
Falcon
Eunice
Monument (10)
Peregrine
SouthTX
Silver Oak I
Silver Oak II
Raptor
North Texas
Chico
SouthOK
Coalgate (7)
Stonewall
Tupelo
Hickory Hills
Velma
Velma V-60
WestOK
Waynoka I
Waynoka II
Coastal
Gillis (11)
Big Lake (7)
VESCO
Lowry
Sea Robin
Badlands
Process
Type (1)
Operated
/Non-
Operated
% Owned
Location
Processing
Capacity
(MMcf/d) (2)
Plant
Natural Gas
Inlet Throughput
Volume (MMcf/d)
(3) (4) (5)
NGL
Production
(MBbl/d)
(3) (4) (5)
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Cryo
Operated
Cryo
Cryo
Cryo
Cryo
Cryo
Cryo
Operated
Operated
Operated
Operated
Operated
Operated
Cryo
Cryo
Operated
Operated
72.8 Reagan County, TX
72.8 Reagan County, TX
72.8 Midland County, TX
72.8 Upton County, TX
72.8 Upton County, TX
72.8 Martin County, TX
72.8 Upton County, TX
72.8 Midland County, TX
72.8 Midland County, TX
72.8 Upton County, TX
100.0 Irion County, TX
100.0 Sterling County, TX
100.0 Martin County, TX
100.0 Midland County, TX
100.0 Reagan County, TX
100.0 Reagan County, TX
Area Total
100.0 Crane County, TX
100.0 Loving County, TX
100.0 Pecos County, TX
100.0 Winkler County, TX
100.0 Culberson County, TX
100.0 Lea County, NM
100.0 Lea County, NM
100.0 Culberson County, TX
Area Total
100.0 Bee County, TX
50.0 Bee County, TX
50.0 La Salle County, TX
Area Total
100.0 Wise County, TX
Area Total
60.0 Coal County, OK
60.0 Coal County, OK
60.0 Coal County, OK
60.0 Hughes County, OK
100.0 Stephens County, OK
100.0 Stephens County, OK
Area Total
100.0 Woods County, OK
100.0 Woods County, OK
Area Total
Cryo
Cryo
Cryo
Cryo
Cryo
Operated
Operated
Operated
Operated
Non-operated
100.0 Calcasieu Parish, LA
100.0 Calcasieu Parish, LA
76.8 Plaquemines Parish, LA
100.0 Cameron Parish, LA
1.2 Vermillion Parish, LA
150.0
80.0
220.0
45.0
220.0
220.0
200.0
220.0
275.0
275.0
52.0
92.0
10.0
220.0
275.0
200.0
2,754.0
1,928.4
277.9
165.0
70.0
60.0
250.0
275.0
110.0
85.0
275.0
1,290.0
839.8
114.1
177.7
22.2
178.9
20.1
405.9
49.5
212.6
16.5
220.0
220.0
260.0
700.0
265.0
265.0
80.0
200.0
120.0
150.0
100.0
60.0
710.0
200.0
200.0
400.0
180.0
180.0
750.0
265.0
650.0
Area Total
2,025.0
587.2
33.9
55.0 McKenzie County, ND
27.5 McKenzie County, ND
Area Total
Segment System Total
90.0
200.0
290.0
8,434.0
139.8
4,470.3
16.2
550.4
13
Little Missouri I-III (12)
Little Missouri IV
Cryo/RA
RA
Operated
Operated
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.
Processing capacity represents all parties' ownership.
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of the natural gas processing plant, except for Badlands
which represents the total wellhead volume.
Plant natural gas inlet and NGL production volumes represent our ownership share of volumes for partially owned plants that we proportionately consolidate
based on our ownership interest, including our 72.8% of our undivided interest in our WestTX joint venture, as well as 100% of ownership interests for our
consolidated VESCO joint venture, Silver Oak II, Raptor, Coalgate, Stonewall, Tupelo, and Hickory Hills plants.
Per day plant natural gas inlet and NGL production statistics for plants listed above are based on the number of calendar days during 2021.
Plant natural gas inlet throughput volumes and NGL production volumes for WestTX are presented on a pro-rata net basis representing our undivided ownership
interest in WestTX, which we proportionately consolidate in our financial statements.
Plant is available and operates subject to market conditions, including availability of natural gas.
As a result of a non-consent election made by the joint owner in our WestTX Permian Basin assets, the Gateway and Heim plants are 100% owned and
consolidated by Targa.
The Heim plant commenced operations in third quarter of 2021.
(9)
(10) The Monument plant has fractionation capacity of approximately 1.8 MBbl/d.
(11) The Gillis plant has fractionation capacity of approximately 11 MBbl/d.
(12) Little Missouri Trains I and II are refrigeration plants and Little Missouri Train III is a Cryo plant.
Logistics and Transportation Segment
Our Logistics and Transportation segment is also referred to as our Downstream Business. Our Downstream Business includes the
activities and assets necessary to transport and convert mixed NGLs into NGL products and also includes other assets and value-added
services described below. The Logistics and Transportation segment includes Grand Prix, as well as our equity interest in GCX prior
to the GCX Sale. The associated assets, including these pipelines, are generally connected to and supplied in part by our Gathering and
Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park,
Texas, and in Lake Charles, Louisiana. Our fractionation, pipeline transportation, storage and terminaling businesses include
approximately 2,100 miles of company-owned pipelines to transport mixed NGLs and specification products.
The Logistics and Transportation segment also transports, distributes, purchases and sells and markets NGLs via terminals and
transportation assets across the U.S. We own or market products at terminal facilities in a number of states, including Alabama,
Arizona, California, Florida, Kentucky, Louisiana, Mississippi, New Jersey, North Carolina, Pennsylvania, Tennessee, Texas, and
Washington. The geographic diversity of our assets provides direct access to many NGL customers as well as markets via trucks,
barges, ships, rail cars and open-access regulated NGL pipelines owned by third parties.
Additional description of the Logistics and Transportation segment assets and business activities associated with Transportation
Pipelines, Fractionation, NGL Storage and Terminaling, NGL Distribution and Marketing, Wholesale Domestic Marketing, Refinery
Services, Commercial Transportation and Natural Gas Marketing follows below.
Transportation Pipelines
Our primary pipeline assets are Grand Prix and, prior to the GCX Sale, our equity interest in GCX.
Grand Prix connects our gathering and processing positions throughout the Permian Basin, North Texas, and Southern Oklahoma (as
well as third-party positions) to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix
transports NGLs from the Permian Basin on a 24-inch diameter pipeline with a capacity expandable to 550 MMBbl/d, and from North
Texas and South and Central Oklahoma via a pipeline of varying capacity, which both connect to a 30-inch diameter segment into
Mont Belvieu, which is expandable to 950 MMBbl/d. As of December 31, 2021, we owned a 56% interest in the Permian and Mont
Belvieu segments of Grand Prix through the Grand Prix Joint Venture. Following the DevCo JV Repurchase in January 2022, we own
a 75% interest in the Grand Prix Joint Venture. Volumes flowing on the pipeline from the Permian Basin to Mont Belvieu accrue to
the Grand Prix Joint Venture, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targa’s
benefit.
GCX connects the Waha hub in West Texas and other receipt points, including many of our Midland Basin processing facilities, to
Agua Dulce in South Texas and other delivery points, has a capacity of 2.0 Bcf/d and is operated by Kinder Morgan Texas Pipeline
LLC. As of December 31, 2021, we owned a 20% interest in GCX DevCo JV, but following the DevCo JV Repurchase, owned a
100% interest in GCX DevCo JV and a 25% equity interest in GCX. In February 2022, we announced the GCX Sale.
14
Additionally, through our 50% ownership interest in Cayenne Pipeline, LLC (“Cayenne”), we operate the Cayenne pipeline, which
transports mixed NGLs from VESCO in Venice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana.
Fractionation
After being extracted in the field, mixed NGLs are typically transported to a centralized facility for fractionation where the mixed
NGLs are separated into discrete NGL products: ethane, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.
Contracts for our NGL fractionation services are fee-based arrangements. These fees are subject to adjustment for changes in certain
fractionation expenses, including energy costs. The operating results of our NGL fractionation business are dependent upon the
volume of mixed NGLs fractionated, the level of fractionation fees charged and product gains/losses from fractionation.
We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the
foreseeable future due to historical increases in NGL production from shale plays and other shale-technology-driven resource plays in
areas of the U.S. that include Texas, New Mexico, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont
Belvieu, as well as from conventional production of NGLs in areas such as the Permian Basin, Mid-Continent, East Texas, South
Louisiana and shelf and deep-water Gulf of Mexico.
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 our logistics assets, including our transportation and distribution systems, give us access to both substantial sources
of mixed NGLs and a large number of end-use markets.
At our Mont Belvieu operated facility, we have eight fractionation trains, representing an aggregate capacity of 843.0 MBbl/d,
including: (1) five fractionation trains with an aggregate capacity of 493.0 MBbl/d that are part of our 88%-owned Cedar Bayou
Fractionators, (2) Train 6, a 110 MBbl/d fractionation train, a joint venture between Targa and Stonepeak, in which Targa owned a
20% interest as of December 31, 2021, (3) Train 7, a 120 MBbl/d fractionation train, a joint venture between Targa and the Williams
Companies, Inc., in which Targa owns an 80% equity interest, and (4) Train 8, a 120 MBbl/d fractionation train which is wholly-
owned by Targa. Following the DevCo JV Repurchase in January 2022, we own a 100% interest in Train 6. Certain fractionation-
related infrastructure for Train 6 and Train 7, such as storage caverns and brine handling, were funded and are owned 100% by Targa.
Our fractionation trains are fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which
includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at
Galena Park on the Houston Ship Channel.
We additionally have a wholly-owned and operated fractionation facility in Lake Charles, Louisiana, representing a capacity of 55.0
MBbl/d.
In addition to our operated facilities, we hold an equity investment in Gulf Coast Fractionators LP (“GCF”), also located at Mont
Belvieu. In January 2021, the GCF facility was temporarily idled, but is available for reactivation, subject to prevailing market
conditions and agreement with our partners. We assumed operatorship of GCF in the first half of 2021.
We also own fractionation assets in Monument, New Mexico and Gillis, Louisiana which are included in our Gathering and
Processing segment. In addition, we have a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural
gasoline, allowing customers to meet stringent fuel content standards. The facility has a capacity of 35 MBbl/d and is supported by
long-term fee-based contracts that have certain guaranteed volume commitments and/or provisions for deficiency payments.
15
The following table details the Logistics and Transportation segment’s fractionation and treating facilities:
Facility
Operated Facilities:
Cedar Bayou Fractionators (2)
Train 6 Fractionator (3)
Train 7 Fractionator
Train 8 Fractionator
Lake Charles Fractionator (4)
Targa LSNG Hydrotreater
Gulf Coast Fractionator (5)
Location
%
Owned
Capacity
(MBbl/d) (1)
Throughput
2021 (MBbl/d)
Mont Belvieu, TX
Mont Belvieu, TX
Mont Belvieu, TX
Mont Belvieu, TX
Lake Charles, LA
Mont Belvieu, TX
Mont Belvieu, TX
88.0
20.0
80.0
100.0
100.0
100.0
38.8
493.0
110.0
120.0
120.0
55.0
35.0
135.0
275.0
104.1
116.3
120.6
—
23.2
—
(1)
(2)
(3)
(4)
(5)
Actual fractionation capacities may vary due to the composition of the NGLs being processed and does not contemplate ethane rejection.
Capacity represents 100% of the volume. Capacity includes 40 MBbl/d of additional back-end butane/gasoline fractionation capacity.
Following the DevCo JV Repurchase, we own a 100% interest in Train 6.
Lake Charles Fractionator runs in a mode of ethane/propane splitting for the local petrochemical market and is configured to also handle raw product.
GCF was temporarily idled in January 2021. Targa assumed operatorship of GCF in the first half of 2021. The facility is available for reactivation, subject to
prevailing market conditions and agreement with our partners.
NGL Storage and Terminaling
In general, our NGL 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 supply and demand cycles.
Similarly, our terminaling operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and
petrochemical products in above-ground storage tanks. Our NGL underground storage and terminaling 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, including Grand Prix. In addition, some of our
facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to our customers.
We provide long and short-term storage and terminaling services and throughput capability to third-party customers for a fee.
Across the Logistics and Transportation segment, we own 34 storage wells at our facilities with a gross NGL storage capacity of
approximately 76 MMBbl, and operate seven non-owned wells, the usage of which may be limited by brine handling capacity, which
is utilized to displace NGLs from storage.
We operate our storage and terminaling facilities to support our key fractionation facilities at Mont Belvieu and Lake Charles for
receipt of mixed NGLs and storage of fractionated NGLs to service the petrochemical, refinery, export and heating customers/markets
as well as our wholesale domestic terminals that focus on logistics to service the heating market customer base. Our international
export assets include our facilities at both Mont Belvieu and the Galena Park Marine Terminal near Houston, Texas, which have the
capability to load propane, butanes and international grade low ethane propane. The facilities have an effective export capacity of up
to 15 MMBbl per month, but given the mix of propane and butane demand, vessel size and availability of supply, and a variety of
other factors, our effective working capacity is estimated to be approximately 12.5 MMBbl per month. We have the capability to load
VLGC vessels, alongside small and medium sized export vessels. We continue to experience demand growth for U.S.-based NGLs
(both propane and butane) for export into international markets and are in the process of enhancing our loading capabilities.
The following table details the Logistics and Transportation segment’s NGL storage and terminaling facilities:
Facility
Galena Park Marine Terminal (1)
Mont Belvieu Terminal & Storage
Hackberry Terminal & Storage
%
Owned
100
100
100
Location
Description
Harris County, TX
Chambers County, TX Transport and storage terminal
Cameron Parish, LA
NGL import/export terminal
Storage terminal
Throughput
for 2021
(MMgal)
Number of
Operational
Wells
Storage
Capacity
(MMBbl)
6,146.7
26,572.6
196.0
N/A
22 (2)
12 (3)
0.7
54.4
20.9
(1)
(2)
(3)
Volumes reflect total import and export across the dock/terminal and may include volumes that have also been handled at the Mont Belvieu Terminal.
Excludes seven non-owned wells which we operate on behalf of Chevron Phillips Chemical Company LP. One additional well has been drilled and is being
prepared for operations. One additional well is permitted.
Five of 12 owned wells leased to Citgo Petroleum Corporation under a long-term lease.
16
NGL Distribution and Marketing
We market our own NGL production and also purchase component NGL products from other NGL producers and marketers for
resale. Additionally, we also purchase product for resale in our Logistics and Transportation segment. During the year ended
December 31, 2021, our distribution and marketing services business sold an average of 899.7 MBbl/d of NGLs.
We generally purchase mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and
resell these component products to petrochemical manufacturers, refineries and other marketing and retail companies. This is
primarily a physical settlement business in which we earn margins from purchasing and selling NGL products from customers under
contract. We also earn margins by purchasing and reselling NGL products in the spot and forward physical markets.
Wholesale Domestic Marketing
Our wholesale domestic propane marketing operations primarily sell propane and related logistics services to major multi-state
retailers, independent retailers and other end-users. Our propane supply primarily originates from both our refinery/gas supply
contracts and our other owned or managed Logistics and Transportation assets. We sell propane at a fixed posted price or at a market
index basis at the time of delivery and in some circumstances, we earn margins on a netback basis.
The wholesale domestic propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly in
the winter, which can impact the price and volume of propane sold in the markets we serve.
Refinery Services
In our refinery services business, we typically provide NGL balancing services through contractual arrangements with refiners in
several locations to purchase and/or market propane and to supply butanes. We use our commercial transportation assets (discussed
below) and contract for and use the storage, transportation and distribution assets included in our Logistics and Transportation
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 other refining processes. Under typical netback purchase contracts,
we generally retain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under
netback 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 our refinery services business include production volumes, prices of propane and butanes, as well
as our ability to perform receipt, delivery and transportation services in order to meet refinery demand.
Commercial Transportation
Our NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the
delivery requirements of our marketing and asset management business. We provide fee-based transportation services to refineries and
petrochemical companies throughout the Gulf Coast area. Our assets are also deployed to serve our wholesale domestic 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 our customers.
As of December 31, 2021, we lease and manage 648 railcars and 119 tractors and own two pressurized NGL barges.
17
The following table details the Logistics and Transportation segment’s raw NGL, propane and butane terminaling facilities:
Facility
% Owned
Location
Description
Greenville Terminal
Port Everglades Terminal
Calvert City Terminal
Chattanooga Terminal
Hattiesburg Terminal (3)
Sparta Terminal
Tyler Terminal
Winona Terminal
Eagle Lake Transload (2)
Abilene Transport (4)
Bridgeport Transport (4)
Gladewater Transport (4)
100 Washington County, MS
100
Broward County, FL
100 Marshall County, KY
100 Hamilton County, TN
50
100
100
100
100
100
100
100 Gregg County, TX
Forrest County, MS
Sparta County, NJ
Smith County, TX
Flagstaff County, AZ
Polk County, FL
Taylor County, TX
Jack County, TX
Marine propane terminal
Marine propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane transload
Raw NGL transport terminal
Raw NGL transport terminal
Raw NGL transport terminal
(1) Throughputs include volumes related to exchange agreements and third-party storage agreements.
(2) Rail-to-truck transload equipment.
(3) Throughput volume reflects 100% of the facility capacity.
(4) Volumes reflect total transport and injection volumes.
Natural Gas Marketing
Throughput
for 2021
(MMgal) (1)
Usable Storage
Capacity
(MMgal)
23.5
18.8
7.9
12.0
338.8
12.8
25.1
12.8
6.0
—
17.9
6.2
1.5
1.6
0.1
0.9
179.8
0.2
0.2
0.3
—
0.1
0.1
0.3
We also market natural gas available to us from the Gathering and Processing segment, purchase and resell natural gas in selected U.S.
markets and manage the scheduling and logistics for these activities.
Seasonality
Overall, parts of our business are impacted by seasonality. Our Downstream marketing business can be significantly impacted by
seasonal and weather-driven demand, which can impact the price and volume of product sold in the markets we serve, as well as the
level of inventory we hold in order to meet anticipated demand. See further discussion of the extent to which our business is affected
by seasonality in “Item 1A. Risk Factors.”
Operational Risks and Insurance
We are subject to all risks inherent in the midstream natural gas, NGLs and crude oil businesses. These risks include, but are not
limited to, explosions, fires, mechanical failure, cyber attacks, terrorist attacks, product spillage, weather, nature and inadequate
maintenance of rights of way. These risks could result in damage to or destruction of operating assets and other property, or could
result in personal injury, loss of life or environmental pollution, 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 or self-insured retentions that we consider reasonable and not excessive given the current insurance market
environment.
The occurrence of a significant loss that is not insured, fully insured or indemnified against, or the failure of a party to meet its
indemnification obligations, could materially and adversely affect our 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 our 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
our onshore operations, and potentially excess liability insurance given the current insurance market environment.
Competition
We face strong competition in acquiring new natural gas or crude oil supplies. Competition for natural gas and crude oil supplies is
primarily based on the location of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, treating
capabilities (as applicable), reliability and access to end-use markets or liquid marketing hubs. Competitors to our 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.
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We also compete for NGL supplies for Grand Prix. Competition for NGL supplies is primarily based on the proximity of gathering
and processing facilities in relation to one or more NGL pipelines, their connectivity to NGL pipeline takeaway options, access to end-
use markets or liquid marketing hubs, pricing and contractual arrangements, reputation, efficiency, flexibility, and reliability.
Competitors to our NGL pipeline include other midstream providers with NGL transportation capabilities, such as major interstate and
intrastate pipeline companies, master limited partnerships and midstream natural gas and NGL companies.
Additionally, we face competition for mixed NGLs supplies at our fractionation facilities. The fractionators in which we own an
interest in the Mont Belvieu region compete for volumes of mixed NGLs with other fractionators also located at Mont Belvieu, Texas.
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. Our other fractionation facilities compete for mixed NGLs with the fractionators at Mont
Belvieu as well as other fractionation facilities located in Louisiana. Our 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 our services.
We also compete for NGL products to market through our Logistics and Transportation segment. Our competitors include major oil
and gas producers who market NGL products for their own account and for others. Additionally, we compete with several other NGL
marketing companies.
Human Capital
We believe that our employees are the foundation to fostering the safe operation of our assets and delivery of services to our
customers. We foster a collaborative, inclusive, and safety-minded work environment, focused on working safely every day. We seek
to identify qualified internal and external talent for our organization, enabling us to execute on our strategic objectives.
As of December 31, 2021, we employed approximately 2,430 people that primarily support our operations through a wholly-owned
subsidiary of ours. None of these employees are covered by collective bargaining agreements, and we consider our employee relations
to be good.
Employee Health and Safety
Safety is a core value of ours and begins with the protection and safety of our employees, contractors and communities where we
operate. We value people above all else and remain committed to making safety and health our top priority. We believe that “Zero is
Achievable”, and our goal is to operate and deliver our products without any injuries. We continually seek to maintain and deepen our
safety culture by providing a safe working environment that encourages active employee engagement, including implementing safety
programs to achieve improvements in our safety culture.
To protect our employees, contractors, and surrounding community from workplace hazards and risks, we implement and maintain an
integrated system of policies, practices, and controls, including requirements to complete regular detailed safety and regulatory
compliance training for all applicable individuals.
In response to the ongoing COVID-19 pandemic, we moved early and quickly to protect the health and safety of our employees and
are continuing to proactively manage our response to an evolving national and global situation. We took several strategic and
proactive measures in response to information from the Centers for Disease Control and the local, state and national authorities to try
to minimize the risk of business disruption and to protect our ability to deliver reliable services to our customers. Some of these
actions included forming a COVID-19 task force of senior management to collaborate, review and execute our business response to
the pandemic by instituting various safety protocols including tracking and managing the impact of COVID-19 positive employees
and COVID-19 exposed employees, providing and requiring personal protective equipment at all facility locations, social distancing
practices, work place build-out modifications, routine cleaning protocols at all facility locations to reduce virus contagion risk and
implementing plans for safely returning to our offices over time.
Employee Experience
We are committed to fostering a work environment in which all employees treat each other with dignity and respect. This commitment
extends to providing equal employment and advancement opportunities based on merit and experience. We believe this to be a
fundamental principle and is defined in our Equal Employment Opportunity Policy and our Code of Conduct. We continually strive to
attract a diverse workforce by advertising our external open jobs to several diversity job boards and partnering with local
organizations to identify potential candidates to advance and strengthen our workforce.
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Employee Talent Development and Retention
As a midstream infrastructure operator, we understand the importance of developing and fostering talent to ensure a skilled and
talented diverse workforce both now and in the future. We value and provide opportunities for cross training and increased
responsibilities, including leadership learning and formal coaching. These efforts allow us to recruit from within our organization for
future vocational and occupational opportunities.
Our management promotes formal and informal learning and development throughout the organization. Candid feedback is provided
to employees through our annual performance review process as well as informal meetings throughout the year.
We offer developmental programs focused on building the skills of our employees and to help advance employee careers, knowledge,
and skillsets through training and related programs.
To help plan and predict succession needs, we perform annual succession planning, which is discussed and reviewed with
management and, for certain levels and positions, with the board of directors. We additionally monitor employee turnover rates and
conduct exit interviews with employees who voluntarily leave the company to better understand their reasons for leaving the
company.
Regulation of Operations
Regulation of pipeline gathering and transportation services, natural gas, NGL and crude oil sales, and transportation of natural gas,
NGLs and crude oil may affect certain aspects of our business and the market for our products and services.
Natural Gas Gathering and Processing Regulation
Our natural gas gathering operations are typically subject to open access ratable take and/or common purchaser statutes (and
implementing rules) in the states in which we operate. The common purchaser statutes generally require gathering pipelines to
purchase or take without undue discrimination, while open access gathering requirements generally give producers access to gathering
services on terms that are not unduly discriminatory. In one instance, the governing law prohibits undue discrimination with respect to
purchase or processing of natural gas. The regulations under these statutes can have the effect of imposing some restrictions on our
ability as an owner of gathering and processing facilities to decide with whom (and on what terms) we contract to gather or process
natural gas with similarly situated customers (subject, in each case, to the limitations and requirements of each jurisdiction). The states
in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers
and shippers to file complaints with state regulators in an effort to resolve grievances relating to access and rate discrimination. We
cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the
imposition of administrative, civil and, in certain cases, criminal penalties.
Section 1(b) of the Natural Gas Act of 1938 (“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 our 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, to the extent our
gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to
Order No. 704. See “—Regulation of Operations—FERC Market Transparency Rules.”
Our natural gas gathering and processing operations are not presently subject to FERC regulation. However, since May 2009, we have
been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations
depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERC Market
Transparency Rules.”
Sales of Natural Gas, NGLs and Crude Oil
The price at which we buy and sell natural gas, NGLs and crude oil is currently not subject to federal rate regulation and, for the most
part, is not subject to state rate regulation. However, with regard to our physical purchases and sales of these energy commodities and
any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations
enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See “—Regulation of Operations—EP Act of
2005.” Since May 2009, we have been required to report to FERC information regarding natural gas sale and purchase transactions for
some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of
Operations—FERC Market Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, we could also
be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.
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Interstate Natural Gas
We own (in conjunction with Pioneer) and operate the Driver Residue Pipeline, a gas transmission pipeline extending from our Driver
processing plant in West Texas approximately ten miles to points of interconnection with intrastate and interstate natural gas
transmission pipelines. We have obtained a certificate of public convenience and necessity from FERC waiving certain of the
Commission’s tariff and rate regulations. If, however, we receive a bona fide request for firm service on the Driver Residue Pipeline
from a third party, FERC would reexamine the waivers it has granted us and would require us to file for authorization to offer “open
access” transportation under its regulations, which would impose additional costs upon us.
Interstate Liquids
Targa NGL Pipeline Company LLC (“Targa NGL”), Targa Gulf Coast NGL Pipeline LLC (“Targa Gulf Coast”), and the Grand Prix
Joint Venture have interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the
Interstate Commerce Act (the “ICA”). Targa Gulf Coast leases from Targa NGL certain pipelines that run between Mont Belvieu,
Texas, and Galena Park, Texas and between Mont Belvieu, Texas, and Lake Charles, Louisiana. Each of these pipelines is 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 tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just
and reasonable and non-discriminatory. Many FERC-regulated liquids pipelines, including our pipelines discussed below, use the
FERC indexing methodology to change its rates. FERC, however, retained cost-of-service ratemaking, market-based rates and
settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. For those pipelines that
use the FERC indexing methodology, FERC reviews the index formula every five years to determine whether a change in the
methodology is required or, if not, to determine the appropriate index for the subsequent five-year period. On January 20, 2022, FERC
issued an order on rehearing of its December 17, 2020 Order Establishing Index Level in which the Commission reduced the oil
pricing index factor for oil pipelines to use for the current five-year period. As a result, the ceiling levels computed for July 1, 2021 to
June 30, 2022, and the resulting rates currently in effect for certain of Targa’s liquids pipelines, were recomputed to account for the
reduced index factor.
In 2019, Targa NGL began operating portions of Grand Prix that transports NGLs from Oklahoma to Mont Belvieu, Texas. On July
27, 2018, Targa NGL submitted a petition for declaratory order to FERC on a proposed rate structure and terms of service for such
portions of Grand Prix. The Commission granted Targa NGL’s petition for declaratory order subject to certain conditions on March
11, 2019. Targa NGL requested rehearing on April 10, 2019, which is pending at FERC. On August 6, 2020, Targa NGL submitted a
petition for declaratory order to FERC on a proposed rate structure and terms of service related to an extension of Grand Prix (the
“Central Oklahoma Extension”), extending from Southern Oklahoma to the STACK region of Central Oklahoma, and on October 1,
2020, FERC issued an order granting Targa NGL’s petition in full. Additionally, Grand Prix entered full service during the third
quarter of 2019, providing transportation for mixed NGLs from the Permian Basin, including points in New Mexico, to Mont Belvieu,
Texas.
Unless covered by a waiver, as described below, the ICA requires that we maintain tariffs on file with FERC for interstate movements
of liquids on our pipelines. Those tariffs set forth the rates we charge 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.
Targa has multiple NGL pipelines that have qualified for a waiver of applicable FERC regulatory requirements under the ICA based
on current circumstances. Additionally, the crude oil pipeline system that is part of the Badlands assets also qualifies for such a
waiver.
All such waivers are subject to revocation, however, should a particular pipeline’s circumstances change. FERC could, either at the
request of other entities or on its own initiative, assert that some or all of these pipelines no longer qualify for a waiver. In the event
that FERC were to determine that one more of these pipelines no longer qualified for waiver, we would likely be required to file a
tariff with FERC for the applicable pipeline(s) and delivery point(s), provide a cost justification for the transportation charge, and
provide service to all potential shippers without undue discrimination.
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Tribal Lands
Our intrastate natural gas pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition,
various federal agencies within the U.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”),
Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, as well as the
Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. Please
see “Other State and Local Regulation of Operations” below.
Intrastate Natural Gas
Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our
intrastate pipelines may be subject to certain FERC-imposed reporting requirements depending on the volume of natural gas
purchased or sold in a given year. See “—Regulation of Operations—FERC Market Transparency Rules.”
Our intrastate pipelines located in Texas are regulated by the Railroad Commission of Texas (the “RRC”) and are required to have
tariffs on file with the RRC. Some of these Texas intrastate pipelines also transport natural gas in interstate commerce pursuant to
Section 311 of the Natural Gas Policy Act of 1978 (“NGPA”). Under Sections 311 and 601 of the NGPA, an intrastate pipeline may
transport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gas company” under the
NGA, but must file the terms and conditions of transportation of natural gas under authority of Section 311 with FERC, and these
terms and conditions must be “fair and equitable.” Specifically, during 2021, TPL SouthTex Transmission Company LP (“TPL
SouthTex Transmission”) and Targa Midland Gas Pipeline LLC (“Targa Midland”) provided NGPA Section 311 service.
Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC, and the rates and terms of service on the pipeline are subject to
regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”).
We also operate natural gas pipelines that extend from the tailgate of our processing plants to interconnections with both intrastate and
interstate natural gas pipelines. We believe these pipelines are exempt from FERC’s jurisdiction under the Natural Gas Act under
FERC’s “stub” line exemption. Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation
activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances
relating to pipeline access and rate discrimination. The rates we charge for intrastate transportation are deemed just and reasonable
unless challenged in a complaint. A complaint also can be filed with FERC regarding the rates, terms, and conditions of service on our
pipelines providing service pursuant to Section 311 of the NGPA. We cannot predict whether such a complaint will be filed against us
in the future. Failure to comply with state or FERC regulations can result in the imposition of administrative, civil and criminal
penalties.
Intrastate Liquids
Our intrastate NGL pipelines in Texas transport mixed and purity NGL streams between Targa’s Mont Belvieu and Galena Park,
Texas facilities. Grand Prix went into service during the third quarter of 2019, and provides transportation of mixed NGLs from the
Permian Basin to Mont Belvieu, Texas. Further, we operate crude gathering pipelines in the Permian Basin. With respect to intrastate
movements, these pipelines are not subject to FERC regulation, but are subject to rate regulation by the RRC.
Our intrastate NGL pipelines in Louisiana gather mixed NGLs streams that we own from processing plants in Louisiana and deliver
such streams to the Gillis and Lake Charles fractionators in Lake Charles, Louisiana. We deliver mixed and purity NGL streams out of
our fractionator to and from Targa-owned storage, to other third-party facilities and pipelines in Louisiana. Additionally, through our
50% ownership interest in Cayenne, we operate the Cayenne pipeline, which transports mixed NGLs from the Venice gas plant in
Venice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana. These pipelines are not subject to FERC
regulation or rate regulation by the DNR. On May 9, 2019, the Louisiana Public Service Commission (“LPSC”) approved applications
to register certain pipelines of Cayenne and Targa Downstream LLC in accordance with the LPSC 2015 General Order, Docket No. R-
33390.
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EP Act of 2005
The EP 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, the EP 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 EP Act of 2005
provides FERC with the power to assess civil penalties up to a maximum amount that is adjusted annually for inflation, which for
2021 equaled approximately $1.4 million per violation per day for violations of the NGA and approximately $1.4 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 as well as entities that are otherwise subject to the NGA or NGPA. In 2006, FERC issued Order No. 670
to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 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 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 No.
704), and the quarterly reporting requirement under Order No. 735. The anti-market manipulation rule and enhanced civil penalty
authority reflect an expansion of FERC’s NGA enforcement authority.
FERC Market Transparency Rules
Beginning in 2007, FERC has issued a number of rules intended to provide for greater marketing transparency in the natural gas
industry, including Order Nos. 704, 720, and 735. Under Order No. 704, wholesale buyers and sellers of more than 2.2 Bcf 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, 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.
Under Order No. 720, 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 on a daily basis 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. In October 2011, Order No. 720 as
clarified was vacated by the Court of Appeals for the Fifth Circuit. We take the position that, at this time, all of our entities are exempt
from Order No. 720 as currently effective.
Under Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines
operating under Section 1(c) of the NGA are required 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 also extends FERC’s
periodic review of the rates charged by the subject pipelines from three years to five years. On rehearing, FERC reaffirmed Order No.
735 with some modifications. As currently written, this rule does not apply to our Hinshaw pipelines.
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 our natural gas operations. We do not believe that
we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we
compete.
Other State and Local Regulation of Operations
Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant
thereto, governing a wide variety of matters, including operations, marketing, production, pricing, community right-to-know,
protection of the environment, safety, marine traffic and other matters. In addition, the Three Affiliated Tribes promulgate and enforce
regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our
Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws
and regulations independent from federal, state and local statutes and regulations. For additional information regarding the potential
impact of federal, state, tribal or local regulatory measures on our business, see “Risk Factors—Risks Related to Our Business.”
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Environmental and Occupational Health and Safety Matters
Our business operations are subject to numerous environmental and occupational health and safety laws and regulations that may be
imposed at the federal, regional, state, tribal and local levels. The activities that we conduct in connection with (i) gathering,
compressing, treating, processing, transporting, and purchasing and selling natural gas; (ii) storing, fractionating, treating,
transporting, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and (iii) gathering, storing,
terminaling, and purchasing and selling crude oil are subject to or may become subject to stringent environmental regulation. We have
implemented programs and policies designed to monitor and pursue operation of our pipelines, plants and other facilities in a manner
consistent with existing environmental and occupational health and safety laws and regulations, and have incurred and will continue to
incur operating and capital expenditures, some of which may be material, to comply with these laws and regulations. Historically, our
environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no
assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our
business and operational results.
The more significant of these existing environmental and occupational health and safety laws and regulations include the following
U.S. legal standards, as amended from time to time:
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the Clean Air Act ("CAA"), which restricts the emission of air pollutants from many sources and imposes various
pre-construction, operational, monitoring and reporting requirements, and that the EPA has relied upon as authority
for adopting climate change regulatory initiatives relating to greenhouse gas ("GHG") emissions;
the Federal Water Pollution Control Act, also known as the Clean Water Act, which regulates discharges of
pollutants to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction
and rulemaking as protected waters of the United States;
the Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"), which
imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous
substance releases have occurred or are threatening to occur;
the Resource Conservation and Recovery Act ("RCRA"), which governs the generation, treatment, storage,
transport, and disposal of solid wastes, including hazardous wastes;
the Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities, pipelines and other
facilities, as well as lessees or permittees of areas in which offshore facilities are located, that are the site of an oil
spill in waters of the United States, to liability for removal costs and damages;
the Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of
drinking water standards and controlling the injection of waste fluids into below-ground formations that may
adversely affect drinking water sources;
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened
species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent
ban in affected areas;
the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the
potential to impact the environment and that may require the preparation of environmental assessments and more
detailed environmental impact statements that may be made available for public review and comment; and
the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and
safety of employees, including the implementation of hazard communications programs designed to inform
employees about hazardous substances in the workplace, potential harmful effects of these substances, and
appropriate control measures.
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These environmental and occupational health and safety laws and regulations generally restrict the level of substances generated as a
result of our operations that may be emitted to ambient air, discharged to surface water, and disposed or released to surface and below-
ground soils and ground water. Additionally, there exist tribal, state and local jurisdictions in the United States where we operate that
also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations
governing many of these same types of activities. Any failure by us to comply with these laws and regulations may result in the
assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and
corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the
permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities
in a particular area. Certain environmental laws also provide for citizen suits, which allow environmental organizations to act in place
of the government and sue operators for alleged violations of environmental law. The ultimate financial impact arising from
environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new
standards continue to evolve.
We own, lease, or operate numerous properties that have been used for crude oil and natural gas midstream services for many years.
Additionally, some of our properties have been operated by third parties or by previous owners or operators whose treatment and
disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. Under environmental laws such as
CERCLA and RCRA, we could incur strict joint and several liability for remediating hydrocarbons, hazardous substances or wastes
disposed of or released by us or prior owners or operators. We also could incur costs related to the clean-up of third-party sites to
which we sent regulated substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or
other claims related to releases of regulated substances at or from such third-party sites.
Over time, the trend in environmental and occupational health and safety regulation is to typically place more restrictions and
limitations on activities that may adversely affect the environment or expose workers to injury and thus, any changes in environmental
or occupational health and safety laws and regulations or reinterpretation of enforcement policies that may arise in the future and
result in more stringent or costly waste management or disposal, pollution control, remediation or occupational health and safety-
related requirements could have a material adverse effect on our business, results of operations and financial position. We may not
have insurance or be fully covered by insurance against all environmental and occupational health and safety risks, and we may be
unable to pass on increased compliance costs arising out of such risks to our customers. We review regulatory and environmental
issues as they pertain to us and we consider regulatory and environmental issues as part of our general risk management approach. For
more information on environmental and occupational health and safety matters, see the following Risk Factors under Part I, Item 1A
of this Form 10-K: “Our operations are subject to environmental laws and regulations and a failure to comply or an accidental
release into the environment may cause us to incur significant costs and liabilities,” “We could incur significant costs in complying
with stringent occupational safety and health requirements,” “Laws and regulations regarding hydraulic fracturing could result in
restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely
impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of
our assets,” “Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change (including
legislation or regulation to address climate change) that could result in increased operating costs, limit the areas in which oil and
natural gas production may occur, and reduce demand for the products and services we provide,” and “Increasing attention to
environmental, social and governance (“ESG”) matters may impact our business.”
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Pipeline Safety Matters
Many of our natural gas, NGL and crude oil pipelines are subject to regulation by the federal Pipeline and Hazardous Materials Safety
Administration (“PHMSA”), an agency of the U.S. Department of Transportation (“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, crude oil, NGL and condensate pipeline facilities. Pursuant to
these acts, PHMSA has promulgated regulations governing, among other things, pipeline design, maximum operating pressures,
pipeline patrols and leak surveys, public awareness, operation and maintenance procedures, operator qualification, 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. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement
integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas
(“HCAs”) and moderate consequence areas (“MCAs”) along pipelines and take additional safety measures to protect people and
property in these areas. The HCAs for natural gas, crude oil, NGL and condensate pipelines impose increasing safety-related
requirements as the population density or ecological sensitivity increases. An MCA is defined in relation to natural gas pipelines and
is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a
natural gas pipeline HCA. Various states have also adopted regulations, similar to existing PHMSA regulations for, and may have
established agencies analogous to PHMSA to regulate, intrastate gathering and transmission lines. We currently estimate an average
annual cost of $5.8 million between 2022 and 2024 to implement pipeline integrity management program inspections along certain
segments of our natural gas and hazardous liquids pipelines. This estimate does not include the costs, if any, of repair, remediation, or
preventative and mitigative actions that may be determined to be necessary as a result of the discovery of conditions during the
inspection program, which costs could be substantial. At this time, we 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 inspections. Historically, our pipeline safety compliance costs have not had a
material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the
future or that such future compliance will not have a material adverse effect on our business, financial condition or results of
operations. See Risk Factors “We may incur significant costs and liabilities resulting from performance of pipeline integrity programs
and related repairs” and “Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of
new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to
increased capital costs, operational delays and costs of operation” under Item 1A of this Form 10-K for further discussion on pipeline
safety standards, including integrity management requirements.
Title to Properties and Rights of Way
Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases,
easements, rights of way, permits or licenses from landowners or governmental authorities permitting the use of such land for our
operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title and we believe
that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are
held by us pursuant to ground leases or easements between us, as lessee or grantee, and the fee owner of the lands, as lessors or
grantors. We and our predecessors have leased or held easements on 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 we have satisfactory leasehold or easement
estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, rights of
way, permit, lease or license, and we believe that we have satisfactory title to all of our material leases, easements, rights of way,
permits, leases and licenses.
Financial Information by Reportable Segment
See “Segment Information” included under Note 25 of the “Consolidated Financial Statements” for a presentation of financial results
by reportable segment and see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations– By
Reportable Segment” for a discussion of our financial results by segment.
Available Information
We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website,
http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. Our press releases and recent
analyst presentations are also available on our website. The SEC also maintains an internet website at http://www.sec.gov that contains
reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.
The information contained on the websites referenced in this Annual Report on Form 10-K is not incorporated herein by reference.
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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 the other information contained in this report. If any of the following risks were to occur, then our business, financial
condition, cash flows and results of operations could be materially adversely affected.
Summary Risk Factors
Risks Related to our Results of Operations
Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and
condensate prices, and decreases in commodity prices and/or activity levels could adversely affect our results of operations and
financial condition.
The widespread outbreak of pandemics (like COVID-19) or any other public health crisis that impacts the global demand for energy
commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.
A reduction in demand for NGL products by the petrochemical, refinery or other industries or by the fuel or export markets, or a
significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of
operations and financial condition.
The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our
long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on
certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business
and operating results.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to
manage and operate our business.
If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and
processing facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be
adversely affected.
We typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems;
therefore, volumes on our systems in the future could be less than we anticipate.
We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our
operations.
If we lose any of our named executive officers, our business may be adversely affected.
Climatic events may damage our pipelines and other facilities, limit our ability to operate our business and adversely impact our
customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments
could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.
Our 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 for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for
significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our
operations and financial results could be adversely affected.
Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our
exposure to commodity price movements.
Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our
systems, which expenditures or resulting loss of revenue due to pipeline age or condition could have a material adverse effect on our
business and results of operations.
Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the
Middle East, other sustained military campaigns and civil unrest in the United States may adversely impact our results of
operations.
We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
We may incur significant costs and liabilities resulting from performance of pipeline integrity testing programs and related repairs.
Risks Related to our Capital Projects and Future Growth
Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and are
subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and
financial condition.
If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on
economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our
future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect
our financial condition and results of operations and reduce our ability to pay dividends to stockholders. In addition, we may not
achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a
negative impact on our operations and financial condition.
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Our growth and acquisition strategy requires access to new capital. Tightened capital markets or increased competition for
investment opportunities could impair our ability to grow through growth projects or acquisitions.
We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture
participants agree and certain of our joint venture partners may fail or refuse to fund their respective portions of capital projects that
we believe are necessary to expand or maintain such joint venture’s business.
Risks Related to our Financial Condition
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.
We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could
adversely affect our cash flow and results of operations.
Changes in future business conditions could have a negative impact on the demand for our services and could cause recorded long-
lived assets to become further impaired, and our financial condition and results of operations could suffer if there is a negative
impact on the demand for our services and an additional impairment of long-lived assets.
Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase
the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the
percentage of our expected equity commodity volumes that are hedged decreases substantially over time.
If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.
The amounts we pay in dividends may vary from anticipated amounts and circumstances may arise that lead to conflicts between
using funds to pay anticipated dividends or to invest in our business.
If dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to
receive that quarter’s payments in the future.
Our future tax liability may be greater than expected if our NOL carryforwards are limited, we do not generate expected deductions,
or tax authorities challenge certain of our tax positions.
Risks Related to the Ownership of our Common Stock
Our Series A Preferred Stock (“Series A Preferred”) gives the holders thereof liquidation and distribution preferences, certain rights
relating to our business and management, and the ability to convert such shares into our common stock, potentially causing dilution
to our common stockholders.
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.
Risks Related to our Indebtedness
Increases in interest rates could adversely affect our cost of capital, which could increase our funding costs and reduce the overall
profitability of our business.
We have a substantial amount of indebtedness which may adversely affect our financial position and we may still be able to incur
substantially more debt, which could collectively increase the risks associated with compliance with our financial covenants.
The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in
business or to take certain actions, including to pay dividends to our stockholders.
Risks Related to Regulatory Matters
Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change that could result in
increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products
and services we provide.
Increasing attention to ESG matters may impact our business.
We could incur significant costs in complying with more stringent occupational safety and health requirements.
Laws, regulations and executive orders limiting hydraulic fracturing activities could result in restrictions, delays or cancellations in
drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing
the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.
Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the
environment may cause us to incur significant costs and liabilities.
A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change
in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating
expenses to increase or delay or increase the cost of expansion projects.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety
controls or result in more rigorous enforcement of applicable legal requirements could subject us to increased capital costs,
operational delays and costs of operation.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to
substantial penalties and fines.
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Risks Related to our Results of Operations
Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and
condensate prices, and decreases in commodity prices and/or activity levels could adversely affect our results of operations and
financial condition.
Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The
prices of natural gas, NGLs and crude oil have been volatile, and we expect this volatility to continue. Our future cash flows may be
materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for natural gas, NGLs
and crude oil depend upon factors beyond our control. These factors include supply and demand for these commodities, which
fluctuates with changes in market and economic conditions, and other factors, including:
the impact of seasonality and weather;
general economic conditions and economic conditions impacting our primary markets;
the economic conditions of our 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 major 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 of domestic storage for crude oil;
the availability and marketing of competitive fuels and/or feedstocks;
the impact of energy conservation efforts;
stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy
sector or restrict the exploration, development and production of crude oil and natural gas; and
the extent and nature of governmental regulation and taxation, including those related to the prorationing of oil and gas
production.
Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds
arrangements. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed
percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL
products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage
of an index-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, our revenues and cash flows increase or decrease, whichever is applicable, as the prices
of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 7A. Quantitative and
Qualitative Disclosures About Market Risk.”
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The widespread outbreak pandemics (like COVID-19) or any other public health crisis that impacts the global demand for energy
commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.
We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control and could
significantly disrupt our operations and adversely affect our financial condition. For example, the global spread of COVID-19 has
caused business disruption, including disruption to the oil and gas industry. The COVID-19 pandemic has negatively impacted the
global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and
disruption of financial and commodity markets. The full extent of the impact of the COVID-19 pandemic on our operational and
financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain
and depends on various factors, including the demand for natural gas, NGLs and crude oil (including the impact that reductions in
travel, manufacturing and consumer product demand have had and will have on the demand for energy commodities), the availability
of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions
on travel, transportation and operations.
The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will also depend on
future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the
duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and
market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we
expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably
estimated at this time.
Refer to Note 5 - Property, Plant and Equipment and Intangible Assets of the “Consolidated Financial Statements” included in this
Annual Report for further discussion regarding the impact of COVID-19 and non-cash pre-tax impairments recorded by the Company
in 2020.
A reduction in demand for NGL products by the petrochemical, refinery or other industries or by the fuel or export markets, or a
significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of
operations and financial condition.
The NGL products we produce have a variety of applications, including 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), reduced demand for
propane or butane exports whether for price or other reasons, reduced demand due to the effects of the COVID-19 pandemic,
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 we handle or reduce the fees we charge for our services. Also,
increased supply of NGL products could reduce the value of NGLs handled by us and reduce the margins realized. Our NGL products
and their demand are affected as follows:
Ethane. Ethane is typically supplied as purity ethane and as part of an 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.
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 increasingly driven by international exports supplying a growing global demand for the product. Domestically in the U.S.,
propane is at its highest during the six-month peak heating season of October through March. Demand for our propane may be
reduced during periods of slow global economic growth and warmer-than-normal weather.
Normal Butane. Normal butane is used in the production of isobutane, as a refined petroleum 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
petroleum products resulting from governmental regulation, changes in feedstocks, products and economics, and demand for heating
fuel, ethylene and propylene could adversely affect demand for normal butane. The volume of butane sold is increasingly driven by
international exports supplying a growing demand for the product.
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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 petroleum 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 we access for any of the reasons stated above could
adversely affect both demand for the services we provide and NGL prices, which could negatively impact our results of operations and
financial condition.
The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-
term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain
factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and
operating results.
Our gathering systems are connected to crude oil and natural gas wells from which production will naturally decline over time, which
means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. Our logistics
assets are similarly impacted by declines in NGL supplies in the regions in which we operate as well as other regions from which we
source NGLs. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and
our treating and fractionation facilities, we must continually obtain new natural gas, NGL and crude oil supplies. A material decrease
in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise,
could result in a decline in the volume of natural gas or crude oil that we gather and process, NGLs that we transport or NGL products
delivered to our fractionation facilities. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on
the level of successful drilling and production activity near our gathering systems and, in part, on the level of successful drilling and
production in other areas from which we source NGL and crude oil supplies. We have no control over the level of such activity in the
areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In
addition, we have no control over producers or their drilling, completion 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, the 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 crude oil and natural gas prices decrease. Prices of crude
oil and natural gas have been historically volatile, and we expect this volatility to continue. Consequently, even if new natural gas or
crude oil reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. For example, low
prices for natural gas combined with high levels of natural gas in storage could result in curtailment or shut-in of natural gas
production similar to the production shut-ins we experienced in 2020 due to the impacts of the COVID-19 pandemic. Furthermore, in
response to depressed commodity prices, during 2020 and early 2021 many operators announced substantial reductions in their
estimated capital expenditures, rig count and completion crews. Reductions in exploration and production activity, competitor actions
or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace
the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced
utilization of our gathering, treating, processing, transportation and fractionation assets.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large crude oil, natural gas and
NGL companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than we do. Some of
these competitors may expand or construct gathering, processing, storage, terminaling and transportation systems that would create
additional competition for the services we provide to our customers. In addition, customers who are significant producers of natural
gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using those operated by us.
Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows
could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a
material adverse effect on our business, results of operations and financial condition.
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We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to
manage and operate our business.
We operate in areas in which industry activity has increased rapidly. As a result, demand for qualified personnel in these areas,
particularly those related to our Permian and Badlands assets, and the cost to attract and retain such personnel, has increased over the
past few years due to competition, and may increase substantially in the future. Moreover, our competitors may be able to offer better
compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development projects,
or any significant increases in costs with respect to the hiring, training or retention of qualified personnel, could have a material
adverse effect on our business, financial condition and results of operations.
If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and
processing facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be
adversely affected.
We depend upon third-party pipelines, storage and other facilities that provide delivery options to and from our gathering and
processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current
manner is not within our control. If any of these third-party facilities become partially or fully unavailable, or if the quality
specifications for their facilities change so as to restrict our ability to utilize them, our revenues could be adversely affected.
We typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems;
therefore, volumes on our systems in the future could be less than we anticipate.
We typically do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems due to the
unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have
independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves
or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional
sources of supply, then the volumes of natural gas or crude oil transported on our gathering systems in the future could be less than we
anticipate. A decline in the volumes on our systems could have a material adverse effect on our business, results of operations and
financial condition.
We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our
operations.
We do not own most of the land on which our pipelines, terminals and compression facilities are located, and we are therefore subject
to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or
leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and
governmental agencies for a specific period of time. Additionally, the federal Tenth Circuit Court of Appeals has held that tribal
ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual
Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands
under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impediment for
pipeline operators. We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way
without experiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew rights of way
contracts or leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing
operations elsewhere and reduce our revenue.
If we lose any of our named executive officers, our business may be adversely affected.
Our success is dependent upon the efforts of our named executive officers. Our named executive officers are responsible for executing
our business strategies. There is substantial competition for qualified personnel in the midstream oil and 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
business and prevent us from implementing our business strategies.
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Climatic events may damage our pipelines and other facilities, limit our ability to operate our business and adversely impact our
customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could
cause us to incur significant costs and adversely affect our business, results of operations and financial condition.
Climatic events in the areas in which we operate can cause disruptions and in some cases suspension of our operations and
development activities. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes may cause
a loss of throughput from temporary cessation of activities or lost, damaged or ineffective equipment. Our planning for normal
climatic variation, insurance programs and emergency recovery plans may inadequately mitigate the effects of such weather
conditions, and not all such effects can be predicted, eliminated or insured against. Potential climatic changes may have significant
physical effects, such as increased frequency and severity of storms, floods and wintry conditions and could have an adverse effect on
our continued operations as well as the operations of our oil and gas exploration and production customers that deliver natural gas to
us for processing and throughput, our third party vendors that supply us with goods, and third party insurance providers that make
insuring products available to defray our costs or offset any damages and losses we incur. Any unusual or prolonged severe climatic
events or increased frequency thereof, such as freezing weather or rain, earthquakes, hurricanes, droughts, or floods in our oil and gas
exploration and production customers’ or our third party vendors’ areas of operations or markets, whether due to climatic change or
otherwise, could have a material adverse effect on our business, results of operations and financial condition.
Our operations along the Gulf Coast, in offshore waters and at major river crossings in particular could be adversely impacted by
changing climatic conditions, as rising sea levels, subsidence and erosion are potential causes for serious damage to our pipelines and
other facilities, which could affect our ability to provide services. These damages could result in leakage, migration, releases or spills
from our operations to surface or subsurface soils, surface water, groundwater or to the Gulf of Mexico and could result in liability,
remedial obligations or otherwise have a negative impact on continued operations. Additionally, rising sea levels, subsidence and
erosion processes could impact our oil and gas exploration and production customers who operate along the Gulf Coast, and they may
be unable to utilize our services. Adverse climatic impacts, whether inland or along the coast or offshore, could also affect our third-
party suppliers, which could limit their ability to provide us with the necessary products and services enabling us to maintain operation
of our pipelines and other facilities. As a result, we may incur significant costs to repair, preserve or make more efficient our pipeline
infrastructure and other facilities. Such costs could adversely affect our business, financial condition, results of operations and cash
flows. In addition, local governments and landowners have filed lawsuits in recent years in Louisiana against energy companies,
alleging that their operations contributed to increased coastal rising seas and erosion and seeking substantial damages.
Moreover, we could incur significant costs to weatherize or upgrade weatherization of our facility equipment in anticipation of future
climatic events. For example, in June 2021, Texas Governor Greg Abbott signed Senate Bill 3 into law, requiring power facilities
including natural gas pipeline facilities to weatherize against extreme weather. The legislation, which is in response to Winter Storm
Uri that caused widespread power outages in Texas in February 2021, directs the Texas Railroad Commission to adopt rules that will
require a gas pipeline facility operator that experiences repeated or major weather-related forced interruptions of service to, among
other things, engage an independent party to assess the operator’s weatherization plans, procedures and operations, and submit the
assessment to the Texas Railroad Commission. The Texas Railroad Commission has begun developing a process for designation of
critical gas suppliers and exclusions from such designation, and further plans consideration and adoption of weatherization rules for
certain facilities subject to its jurisdiction. Depending on the outcome of the Texas Railroad Commission proceedings and
designations, we could be required to weatherize or update weatherization of certain facilities in anticipation of, or in response to
performance of such assessments, potentially resulting in our incurring significant costs.
Our 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 for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for
significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our
operations and financial results could be adversely affected.
Our operations are subject to many hazards inherent in purchasing, gathering, compressing, treating, processing and/or selling natural
gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; and purchasing, gathering, storing and/or
terminaling crude oil, 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 motor vehicles and construction, farm or utility equipment;
damage that is the result of our negligence or any of our employees’ negligence;
leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the
malfunction of equipment or facilities;
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spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that
contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural
resources; and
other hazards that could also result in personal injury, loss of life, pollution and/or 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 or natural resource damage, and may result in delay, curtailment or suspension of our
related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on
our operations. We are not fully insured against all risks inherent to our business. Additionally, while we are insured for pollution
resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental
accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully
insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we
fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In
addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of
market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate
further. For example, following the occurrence of severe hurricanes along the U.S. Gulf Coast in recent years, 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, with some coverage unavailable at any cost.
Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our
exposure to commodity price movements.
We sell processed natural gas 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. We attempt 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 us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income
from operations and cash flow.
Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our
systems, which expenditures or resulting loss of revenue due to pipeline age or condition could have a material adverse effect on our
business and results of operations.
Some portions of the pipeline systems that we operate have been in service for several decades prior to our purchase of them.
Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may
be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of some of
our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased
maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair
expenditures or loss of revenue due to the age or condition of some portions of our pipeline systems could adversely affect our
business and results of operations.
Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle
East, other sustained military campaigns and civil unrest in the United States may adversely impact our results of operations.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist
attacks on our industry in general and on us in particular is not known at this time. However, resulting regulatory requirements and/or
related business decisions associated with security are likely to increase our costs. Increased security measures taken by us as a
precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued
hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including
disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets, or
indirect casualties, of an act of terror. Additionally, recent acts of protest and civil unrest have caused economic and political
disruption in the United States.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain.
Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage or
coverage may be reduced or unavailable. Instability in the financial markets as a result of terrorism or war could also affect our ability
to raise capital.
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We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
We have experienced, and we anticipate that we will encounter from time to time, opposition to the operation and expansion of our
pipelines and facilities from governmental officials, non-governmental environmental organizations and groups, landowners, tribal
groups, local groups and other advocates. In some instances, we encounter opposition which disfavors hydrocarbon-based energy
supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many
forms, including the delay, denial or termination of required governmental permits or approvals, organized protests, attempts to block
or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets or lawsuits or other actions
designed to prevent, disrupt, delay or terminate the operation or expansion of our assets and business. In addition, destructive forms of
protest or opposition by activists, including acts of sabotage or eco terrorism could cause significant damage or injury to people,
property or the environment or lead to extended interruptions of our operations. Any such event that restricts, delays or prevents the
expansion of our business, interrupts the revenues generated by our operations or causes us to make significant expenditures not
covered by insurance could adversely affect our business, results of operations, and financial condition.
We may incur significant costs and liabilities resulting from performance of pipeline integrity testing programs and related repairs.
Pursuant to the authority under the NGPSA and HLPSA, PHMSA has established rules requiring pipeline operators to develop and
implement integrity management programs for certain natural gas and hazardous liquids pipelines located where a pipeline leak or
rupture could affect higher risk areas, known as HCAs and MCAs, which are areas where a release could have the most significant
adverse consequences. The HCAs for natural gas pipelines are predicated on high-population areas (which, for natural gas
transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crude oil, NGL and condensate pipelines are based
on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA is attributable to natural
gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the
definition of a natural gas pipeline HCA. Among other things, these regulations require operators of covered pipelines to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact an HCA, MCA or Class 3 or 4 area;
maintain processes for data collection, integration and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.
With adoption of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act and the PIPES Act of 2020 over the past decade, existing
mandates require PHMSA to impose more stringent pipeline safety standards. As a result of those legislative enactments, PHMSA has
issued several significant rulemakings. First, PHMSA published an October 2019 final rule imposing numerous requirements on
onshore gas transmission pipelines relating to maximum allowable operating pressure (“MAOP”) reconfirmation and exceedance
reporting, the integrity assessment of additional pipeline mileage found in MCAs and non-HCA Class 3 and Class 4 areas by 2033,
and the consideration of seismicity as a risk factor in integrity management. Second, PHMSA published an October 2019 final rule for
hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity
management requirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to permit such use),
increased annual, accident and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond
HCAs. More recently, in November 2021, PHMSA issued a final rule that will impose safety regulations on approximately 400,000
miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of
fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to
certain gas gathering pipelines with large diameters and high operating pressures. Separately, in June 2021, PHMSA issued an
Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and
maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA,
together with state regulators, are expected to commence inspection of operator plans in 2022. The integrity-related requirements and
other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and the PIPES Act of 2020, as well as any
implementation of PHMSA rules thereunder, could require us to pursue additional capital projects or conduct integrity or maintenance
programs on an accelerated basis and incur increased operating costs that could have a material adverse effect on our costs of
transportation services as well as our business, results of operations and financial condition.
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In addition, certain states, including Texas, Louisiana, Oklahoma, New Mexico, and North Dakota, where we conduct operations,
have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquids pipelines. We
plan to continue our pipeline integrity inspection programs to assess and maintain the integrity of our pipelines. The results of these
inspections may cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed
necessary to ensure the continued safe and reliable operation of our pipelines.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational
disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct business. For example, we
depend on digital technologies to operate our facilities, serve our customers and record financial data. At the same time, cyber
incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy
assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers,
customers and other business partners, may become the target of cyberattacks or information security breaches that could result in the
unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could adversely
disrupt our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended
period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will
likely be required to expend additional resources to enhance our security posture and cybersecurity defenses or to investigate and
remediate any vulnerability to or consequences of cyber incidents. Our insurance coverages for cyberattacks may not be sufficient to
cover all the losses we may experience as a result of a cyber incident.
Risks Related to our Capital Projects and Future Growth
Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and are subject
to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial
condition.
The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous
regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts
of capital. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. For example, the
construction of additional systems may be delayed or require greater capital investment if the commodity prices of certain supplies,
such as steel pipe, increase due to imposed tariffs. Moreover, our revenues may not increase immediately upon the expenditure of
funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gas processing plant, the construction
may occur over an extended period of time and we will not receive any material increases in revenues until the project is completed.
Moreover, we may construct pipelines or facilities to capture anticipated future growth in production in a region in which such growth
does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not
possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing
pipelines or facilities in such area. To the extent we rely on estimates of future production in any decision to construct additions to our
systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of
future production. As a result, new pipelines or facilities may not be able to attract enough throughput to achieve our expected
investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of
additions to our existing gathering and transportation assets may require us to obtain new rights of way prior to constructing new
pipelines. We may be unable to obtain or renew such rights of way to connect new natural gas and crude oil supplies to our existing
gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain
new rights of way or to renew existing rights of way. If the cost of renewing or obtaining new rights of way increases, our cash flows
could be adversely affected.
If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on
economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our
future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our
financial condition and results of operations and reduce our ability to pay dividends to stockholders. In addition, we may not achieve
the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a negative
impact on our operations and financial condition.
Our ability to grow depends, in part, on our ability to develop growth projects and/or make acquisitions that result in an increase in
cash generated from operations. We will need to focus on organic growth and third-party acquisitions. If we are unable to develop
accretive growth projects or make accretive acquisitions because we are (1) unable to develop growth projects economically or
identify attractive acquisition candidates and negotiate acceptable acquisition agreements or, (2) unable to obtain financing for these
projects or acquisitions on economically acceptable terms, or (3) unable to compete successfully for growth projects or acquisitions,
then our future growth and ability to increase dividends will be limited.
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Any growth project or acquisition involves potential risks, including, among other things:
operating a significantly larger combined organization and adding new or expanded operations;
difficulties in the assimilation of the assets and operations of the growth projects or acquired businesses, especially if the
assets developed or acquired are in a new business segment and/or geographic area;
the risk that crude oil and 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;
the assumption of environmental and other unknown liabilities;
limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects;
the failure to attain or maintain compliance with environmental and other governmental regulations;
inaccurate assumptions about the overall costs of equity or debt or the tightening of capital markets and access to new
capital;
the diversion of management’s and employees’ attention from other business concerns;
challenges associated with joint venture relationships and minority investments, including dependence on joint venture
partners, controlling shareholders or management who may have business interests, strategies or goals that are
inconsistent with ours; and
customer or key employee losses at the acquired businesses or to a competitor.
If these risks materialize, any growth project or acquired assets may inhibit our growth, fail to deliver expected benefits and/or add
further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and we
may experience unanticipated delays in realizing the benefits of a growth project or acquisition. If we consummate any future growth
project or acquisition, our capitalization and results of operations may change significantly and you may not have the opportunity to
evaluate the economic, financial and other relevant information that we will consider in evaluating future growth projects or
acquisitions.
Our growth and acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry
participants and new opportunities created by industry expansion. A material decrease in such divestitures or in opportunities for
economic commercial expansion would limit our opportunities for future growth projects or acquisitions and could adversely affect
our operations and cash flows available to pay cash dividends to our stockholders.
Growth projects may increase our concentration in a line of business or geographic region and acquisitions may significantly increase
our size and diversify the geographic areas in which we operate. In addition, we may not achieve the desired effect from any future
growth projects or acquisitions.
We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants
agree.
We participate in several 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 include, among others, 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. Without the concurrence of joint venture participants
with enough voting interests, we may be unable to cause any of our joint ventures to take or not take certain actions, even though
taking or preventing those actions may be in our best interests or the particular joint venture.
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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 our
partnering with different or additional parties.
We may operate a portion of our business with one or more joint venture partners where we own a minority interest and/or are not the
operator, which may restrict our operational and corporate flexibility. Actions taken by the other partner or third-party operator may
materially impact our financial position and results of operations, and we may not realize the benefits we expect to realize from a joint
venture.
As is common in the midstream industry, we may operate one or more of our properties with one or more joint venture partners where
we own a minority interest and/or contract with a third party to control operations. These relationships could require us to share
operational and other control, such that we may no longer have the flexibility to control completely the development of these
properties. If we do not timely meet our financial commitments in such circumstances, our rights to participate may be adversely
affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate
in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions
taken by a joint venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration
that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort
on our business.
Risks Related to our Financial Condition
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 now or 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 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 results of
operations, financial condition and ability to comply with our debt obligations.
We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could
adversely affect our cash flow and results of operations.
Many of our customers may experience financial problems that could have a significant effect on their creditworthiness, especially in
a depressed commodity price environment. A decline in natural gas, NGL and crude oil prices may adversely affect the business,
financial condition, results of operations, creditworthiness, cash flows and prospects of some of our customers. Severe financial
problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations
under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the
incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from a decline in commodity prices,
a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result
in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us.
Additionally, a decline in the share price of some of our public customers may place them in danger of becoming delisted from a
public securities exchange, limiting their access to the public capital markets and further restricting their liquidity. Furthermore, some
of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they
may default on their obligations to us. To the extent one or more of our key customers is in financial distress or commences
bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the
United States Bankruptcy Code. Furthermore, some bankruptcy courts have found that, in certain cases oil, gas and water gathering
agreements do not create covenants running with the land under governing law and are thus subject to rejection in chapter 11
proceedings. Whether a particular contract is subject to rejection depends on the wording of the contract, the governing law and the
forum where a particular bankruptcy case is filed. Financial problems experienced by our customers could result in the impairment of
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our long-lived assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and
services, which could reduce our revenues. Any material nonpayment or nonperformance by our key customers or our derivative
counterparties could reduce our ability to pay cash dividends to our stockholders.
Changes in future business conditions could have a negative impact on the demand for our services and could cause recorded long-
lived assets to become further impaired, and our financial condition and results of operations could suffer if there is a negative impact
on the demand for our services and an additional impairment of long-lived assets.
We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in
management's judgment, that the carrying value of such assets may not be recoverable. Asset recoverability is measured by comparing
the carrying value of the asset or asset group with its expected future pre-tax 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. Global oil and natural gas commodity prices, particularly crude oil, remain volatile. Decreases in commodity prices have
previously had, and could continue to have, a negative impact on the demand for our services and our market capitalization.
Should energy industry conditions deteriorate, there is a possibility that long-lived assets may be impaired in a future period. For
example, in the fourth quarter of 2021, we recorded a non-cash pre-tax impairment of $452.3 million primarily associated with the
partial impairment of gas processing facilities and gathering systems associated with our Central operations in our Gathering and
Processing segment. Any additional impairment charges that we may take in the future could be material to our financial statements.
We cannot accurately predict the amount and timing of any impairment of long-lived assets. For a further discussion of our
impairments of long-lived assets, see Note 5 — Property, Plant and Equipment and Intangible Assets of the “Consolidated Financial
Statements” included in this Annual Report.
Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase
the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the
percentage of our expected equity commodity volumes that are hedged decreases substantially over time.
We have entered into derivative transactions related to only a portion of our equity volumes, future commodity purchases and sales,
and transportation basis risk. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual
future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that
period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual
amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of
our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity. The percentages
of our expected equity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk,
we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. The derivative
instruments we utilize for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas,
NGL and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially
impact the prices we ultimately realize. Market and economic conditions may adversely affect our hedge counterparties’ ability to
meet their obligations. Given volatility in the financial and commodity markets, we may experience defaults by our hedge
counterparties. In addition, our exchange traded futures are subject to margin requirements, which creates variability in our cash flows
as commodity prices fluctuate.
As a result of these and other factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash
flows, and in certain circumstances may actually increase the variability of our cash flows. See “Item 7A. Quantitative and Qualitative
Disclosures About Market Risk.”
If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.
We may not be successful in balancing our purchases and sales of the commodities we handle. In addition, a producer could fail to
deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted
volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced,
we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
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The amounts we pay in dividends may vary from anticipated amounts and circumstances may arise that lead to conflicts between
using funds to pay anticipated dividends or to invest in our business.
The determination of the amounts of cash dividends, 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, in consultation with management, deems relevant. Many of these matters are affected by factors beyond our control and
therefore, the actual amount of cash that is available for dividends to our stockholders may vary from anticipated amounts.
Additionally, as events present themselves or become reasonably foreseeable, our board of directors, which determines our business
strategy and our dividends, may decide to address those matters by utilizing capital that may otherwise be used for our dividend. For
example, in March 2020, our board of directors approved a reduction in our quarterly cash dividend to $0.10 per share for the quarter
ended March 31, 2020 and maintained such dividend amount through the quarter ended September 30, 2021. Our board of directors
may also determine that an increase in our dividend is appropriate. If we issue additional shares of common or preferred stock or we
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.
If dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to
receive that quarter’s payments in the future.
Dividends to our common stockholders are not cumulative. Consequently, if dividends on our shares of common stock are not paid
with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.
Our future tax liability may be greater than expected if our NOL carryforwards are limited, we do not generate expected deductions,
or tax authorities challenge certain of our tax positions.
As of December 31, 2021, we have U.S. federal NOL carryforwards of $6.0 billion, some of which expire between 2036 to 2037 while
others have no expiration date. We expect to be able to utilize these NOL carryforwards and generate deductions to offset all or a
portion of our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our
income, capital expenditures and net working capital, and the current expectation that our NOL carryforwards will not become subject
to future limitations under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”).
Section 382 generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a
corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or
more stockholders (or groups of stockholders) who are each deemed to own at least 5% of our stock change their ownership by more
than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership
change were to occur, utilization of our NOLs carryforwards would be subject to an annual limitation under Section 382, determined
by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in
Section 382, subject to certain adjustments.
While we expect to be able to utilize our NOL carryforwards and generate deductions to offset all or a portion of our future taxable
income, in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the
IRS (in a tax audit or otherwise), or our NOL carryforwards are subject to future limitations under Section 382, our future tax liability
may be greater than expected.
Derivatives legislation and its implementing regulations could have a material adverse effect on our ability to use derivative
instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted on July 21, 2010, established
federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The
Dodd-Frank Act required the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act, and most of
these regulations have been finalized.
In October 2020, the CFTC adopted new rules that will place limits on positions in certain core futures and equivalent swaps contracts
for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The new rules became
effective in December 2020 but have a general compliance date of January 1, 2022 for covered future positions and January 1, 2023
for covered swaps positions. We do not expect these regulations to materially impede our hedging activity at this time.
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The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will
require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to
qualify for an exemption to such requirements. Although we qualify for the end-user exception from the mandatory clearing
requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution
requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for
hedging. The CFTC and the federal banking regulators have adopted regulations requiring certain counterparties to swaps to post
initial and variation margin. However, our current hedging activities would qualify for the non-financial end user exemption from the
margin requirements.
The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts or potentially reduce the availability of
derivatives to protect against risks we encounter. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations
implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be less predictable,
which could adversely affect our ability to plan for and fund capital expenditures.
Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
The European Union (the “EU”) and other non-U.S. jurisdictions are also implementing regulations with respect to the derivatives
market. To the extent we enter into swaps with counterparties in foreign jurisdictions or counterparties with other businesses that
subject them to regulation in foreign jurisdictions, we may be impacted by such regulations. The implementing regulations adopted by
the EU and by other non-U.S. jurisdictions could have a material adverse effect on us, our financial condition and our results of
operations.
Risks Related to the Ownership of our Common Stock
Our Series A Preferred gives the holders thereof liquidation and distribution preferences, certain rights relating to our business and
management, and the ability to convert such shares into our common stock, potentially causing dilution to our common stockholders.
In March 2016, we issued 965,100 Series A Preferred, which rank senior to the common stock with respect to distribution rights and
rights upon liquidation. Subject to certain exceptions, so long as any Series A Preferred remain outstanding, we may not declare any
dividend or distribution on our common stock unless all accumulated and unpaid dividends have been declared and paid on the Series
A Preferred. In the event of our liquidation, winding-up or dissolution, the holders of the Series A Preferred would have the right to
receive proceeds from any such transaction before the holders of the common stock. The payment of the liquidation preference could
result in common stockholders not receiving any consideration if we were to liquidate, dissolve or wind up, either voluntarily or
involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the common stock, make it harder for
us to sell shares of common stock in offerings in the future, or prevent or delay a change of control.
The Certificate of Designations governing the Series A Preferred provides the Series A Preferred holders with the right to vote, under
certain conditions, on an as-converted basis with our common stockholders on matters submitted to a stockholder vote. The holders of
the Series A Preferred do not currently have such right to vote. Also, so long as any Series A Preferred are outstanding, subject to
certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding Series A Preferred shares,
voting together as a separate class, will be necessary for effecting or validating, among other things: (i) any issuance of stock senior to
the Series A Preferred, (ii) any issuance or increase by any of our consolidated subsidiaries of any issued or authorized amount of, any
specific class or series of securities, (iii) any issuance by us of parity stock, subject to certain exceptions and (iv) any incurrence of
indebtedness by us and our consolidated subsidiaries for borrowed monies, other than under the Existing TRC Revolver and the
Existing TRP Revolver (or replacement commercial bank credit facilities, such as the New TRC Revolver) in an aggregate amount up
to $2.75 billion, or indebtedness that complies with a specified fixed charge coverage ratio. These restrictions may adversely affect our
ability to finance future operations or capital needs or to engage in other business activities.
In December 2020, we repurchased 45,800 Series A Preferred shares, and we currently have 919,300 shares outstanding. The
conversion of the Series A Preferred into common stock twelve years after the issuance of the Series A Preferred, pursuant to the
terms of the Certificate of Designations, may cause substantial dilution to holders of the common stock. Because our Board of
Directors is entitled to designate the powers and preferences of preferred stock without a vote of our shareholders, subject to NYSE
rules and regulations, our shareholders will have no control over what designations and preferences our future preferred stock, if any,
will have.
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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, 2021, we had 228,221,122 outstanding shares of common stock. 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 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
provisions which require:
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.
Risk Related to Our Indebtedness
Increases in interest rates could adversely affect our cost of capital, which could increase our funding costs and reduce the overall
profitability of our business.
We have significant exposure to increases in interest rates. As of December 31, 2021, our total indebtedness, excluding debt issuance
costs, was $6,642.2 million, of which $6,465.7 million was at fixed interest rates, $150.0 million was at variable interest rates and
$26.5 million consisted of finance lease liabilities. A hypothetical change of 100 basis points in the rate of our variable interest rate
debt would impact our annual interest expense by $1.5 million and our consolidated annual interest expense by $1.5 million based on
our December 31, 2021 debt balances. We additionally had $2,128.7 million and $670.0 million of additional borrowing capacity
available under the Existing TRP Revolver and the Existing TRC Revolver, under which borrowing is exposed to such increases in
variable interest rates. As a result of our variable interest debt, our results of operations could be adversely affected by increases in
interest rates.
Additionally, like all equity investments, an investment in our equity securities 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.
We have a substantial amount of indebtedness which may adversely affect our financial position and we may still be able to incur
substantially more debt, which could collectively increase the risks associated with compliance with our financial covenants.
We have a substantial amount of indebtedness. As of December 31, 2021, we had $6,465.7 million outstanding of the Partnership’s
senior unsecured notes. We also had $150.0 million outstanding under the Partnership’s accounts receivable securitization facility (the
“Securitization Facility”). In addition, we had (i) $71.3 million of letters of credit outstanding and $2,128.7 million of additional
borrowing capacity available under the Existing TRP Revolver, and (ii) no borrowings outstanding and $670.0 million of additional
borrowing capacity available under the Existing TRC Revolver. For the years ended December 31, 2021, 2020 and 2019, our
consolidated interest expense, net was $387.9 million, $391.3 million and $337.8 million.
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In February 2021, the Partnership issued $1.0 billion aggregate principal amount of 4% Senior Notes due 2032, resulting in net
proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender
offer (the “February Tender Offer”) and subsequent redemption payment for the Partnership’s 5⅛% Senior Notes due 2025 (the “5⅛%
Notes”), with the remainder used for repayment of borrowings under the Existing TRP Revolver and Existing TRC Revolver.
Our substantial level of indebtedness increases the possibility that we 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 lease and other
financial obligations and contractual commitments, could have other important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available on favorable terms;
satisfying our 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;
we 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;
our debt level may influence how counterparties view our creditworthiness, which could limit our ability to enter into
commercial transactions at favorable rates or require us to post additional collateral in commercial transactions;
our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy
generally; and
our debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.
Our long-term unsecured debt is currently rated by Fitch Ratings, Inc. (“Fitch”), Moody’s Investors Service, Inc. (“Moody’s”) and
Standard & Poor’s Corporation (“S&P”). As of December 31, 2021, Targa’s senior unsecured debt was rated “BB+” by Fitch, “Ba1”
by Moody’s and “BB+” by S&P. Any future downgrades in our credit ratings could negatively impact our cost of raising capital, and a
downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public
markets.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be
affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our
control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such
as reducing or delaying business activities, investments or capital expenditures, acquisitions, selling assets, restructuring or
refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cash dividends. We
may not be able to affect any of these actions on satisfactory terms, or at all.
We may be able to incur substantial additional indebtedness in the future. The New TRC Revolver provides an available commitment
of $2.75 billion and allows us to request increases in commitments up to an additional $500.0 million. Although our debt agreements
contain 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 we incur additional debt,
this could increase the risks associated with compliance with our financial covenants.
The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in
business or to take certain actions, including to pay dividends to our stockholders.
The agreements governing our outstanding indebtedness contain, and any future indebtedness we incur will likely contain, a number
of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in
acts that may be in our best long-term interests. These agreements include covenants that, among other things, restrict our ability to:
incur or guarantee additional indebtedness or issue additional preferred stock;
pay dividends on our equity securities or to our equity holders or redeem, repurchase or retire our equity securities or
subordinated indebtedness;
make investments and certain acquisitions;
sell or transfer assets, including equity securities of our subsidiaries;
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engage in affiliate transactions;
consolidate or merge;
incur liens;
prepay, redeem and repurchase certain debt, subject to certain exceptions;
enter into sale and lease-back transactions or take-or-pay contracts; and
change business activities conducted by us.
In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition
tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that
we will meet those ratios and tests.
A breach of any of these covenants could result in an event of default under our debt agreements. 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. For example, if we are unable to repay the accelerated
debt under the New TRC Revolver, the lenders under the New TRC Revolver could proceed against any collateral granted to them to
secure that indebtedness. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the
Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the assets and
equity of certain of our subsidiaries as collateral under the New TRC Revolver and the accounts receivables of Targa Receivables
LLC under the Securitization Facility. If the indebtedness under our debt agreements is accelerated, we cannot assure you that we 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 our ability to finance future operations or capital needs or to engage in other
business activities.
Risks Related to Regulatory Matters
Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change that could result in
increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and
services we provide.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. As a result,
numerous proposals have been made and could continue to be made at the international, national, regional and state levels of
government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our
operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of
regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, because the
U.S. Supreme Court has held that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other
things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the
monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement New Source
Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural
gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States.
In recent years, there has been considerable uncertainty surrounding regulation of methane emissions. In 2020, the Trump
Administration revised performance standards for methane established in 2016 to lessen the impact of those standards and remove the
transmission and storage segments from the source category for certain regulations. However, shortly after taking office, President
Biden issued an executive order calling on the EPA to revisit federal regulations regarding methane and establish new or more
stringent standards for existing or new sources in the oil and gas sector, including the transmission and storage segments. The U.S.
Congress also passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016
standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized,
would establish Quad Ob new source and Quad Oc first-time existing source standards of performance for methane and volatile
organic compound (VOC) emissions for new sources and existing sources in the crude oil and natural gas source category. This
proposed rule would apply to upstream and midstream facilities at oil and natural gas well sites, natural gas gathering and boosting
compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission
units or processes would have to comply with specific standards of performance that may include leak detection using optical gas
imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission
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requirements, operations and maintenance requirements, and so-called green well completion requirements. The EPA plans to issue a
supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements that were not included in
the November 2021 proposed rule. EPA anticipates issuing a final rule by the end of 2022. Additionally, the Biden Administration
could in the future pursue legislation that would impose a fee on methane emissions from certain oil and gas operations. In November
2021, the House of Representatives passed its version of the Build Back Better Act that targets industries producing, transporting, and
storing natural gas throughout the United States and, if the bill were passed, would assess a fee established at $900 per ton in 2023,
$1,200 in 2024 and $1,500 in 2025 and beyond. However, to date, this bill has not been deliberated by the Senate.
Various states and groups of states have also adopted or are considering adopting legislation, regulations or other regulatory initiatives
that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of
emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement
for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. President Biden
announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels
in economy-wide net GHG emissions by 2030. Moreover, the international community gathered again in Glasgow in November 2021
at the 26th Conference of the Parties (“COP26”), during which the multiple announcements were made, including a call for parties to
eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, at COP26, the United States and
European Union jointly announced the launch of a Global Methane Pledge, an initiative which over 100 countries joined, committing
to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible
reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to
fulfill the United States’ commitments under the Paris Agreement, COP26 or other international conventions cannot be predicted at
this time.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing
political risks in the United States, that may limit hydraulic fracturing of oil and natural gas wells, restrict flaring and venting during
natural gas production on federal properties, and ban new leases for production of minerals on federal properties, including onshore
lands and offshore waters. Other actions relating to oil and natural gas production activities that could be pursued by the Biden
Administration may include more restrictive requirements for the establishment of oil and natural gas pipeline infrastructure or the
permitting of liquefied natural gas export facilities. Litigation risks are also increasing, as a number of cities, local governments, and
other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal
court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global
warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging
that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to
adequately disclose those impacts.
Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in
fossil fuel energy companies but concerned about the potential effects of climate change may elect in the future to shift some or all of
their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy
companies have also become more attentive to sustainability lending practices that favor “clean” power sources such as wind and solar
photovoltaic, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy
companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be
assessing financed emissions across their portfolios and taking steps quantify and reduce those emissions. At COP26, the Glasgow
Financial Alliance for Net Zero (GFANZ) announced that commitments from over 450 firms across 45 countries had resulted in over
$130 trillion in capital committed to net zero goals. The various suballiances of GFANZ generally require participants to set short-
term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. These
and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain
industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG
emissions. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding to the
fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System
(NGFS), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in
November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential
solutions for the climate-related challenges most relevant to central banks and supervisory authorities. While we cannot predict what
policies may result from this, a material reduction in the capital available to the fossil fuel industry could make it more difficult to
secure funding for exploration, development, production, transportation, and processing activities, which could impact our business
and operations. Furthermore, the SEC has announced that it will propose rules that, amongst other matters, will establish a framework
for the reporting of climate risks. However, no such rules have been proposed to date and we cannot predict what any such rules may
require. To the extent the rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also
announced that is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if
the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.
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The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that
impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this
sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of
consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our services and products.
Additionally, political, litigation, and financial risks may result in our oil and natural gas customers restricting or cancelling
production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue
to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments
could have a material adverse effect on our business, financial condition and results of operation. Finally, increasing concentrations of
GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and
severity of storms, droughts, floods, rising sea levels and other extreme climatic events, as well as chronic shifts in temperature and
precipitation patterns. These climatic developments have the potential to cause physical damage to our assets and thus could have an
adverse effect on our operations. Additionally, changing meteorological conditions, particularly temperature, may result in changes to
the amount, timing, or location of demand for energy or the products our customers produce. While our consideration of changing
weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events
may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our
facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared
for every eventuality. If any such effects of climate changes were to occur, they could have an adverse effect on our financial
condition and results of operations and the financial condition and operations of our customers.
Increasing attention to ESG matters may impact our business.
Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential
consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our customers’ products and our
services, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets.
Increasing attention to climate change, for example, may result in demand shifts for our customers’ hydrocarbon products and
additional governmental investigations and private litigation against those customers.
As part of our ongoing effort to enhance our ESG practices, our Board of Directors has established a Sustainability Committee.
Committee members oversee management’s implementation of ESG policies and provide insight to the Board on the effectiveness of
integrating sustainability into our various business activities. While we may elect to seek out various voluntary ESG targets now or in
the future, such targets are aspirational. Moreover, despite our governance oversight in place, we may not be able to adequately
identify ESG-related risks and opportunities and, further, may not be able to meet ESG targets in the manner or on such a timeline as
initially contemplated, including as a result of unforeseen costs or technical difficulties associated with achieving such results. To the
extent we elected to pursue such targets and were able to achieve the desired target levels, such achievement may have been
accomplished as a result of entering into various contractual arrangements, including the purchase of various credits or offsets that
may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Notwithstanding our election to pursue
aspirational targets now or in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive
climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or
technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings
processes for evaluating companies on their approach to ESG matters. Additionally, we and other companies in our industry publish
sustainability reports that are made available to investors. Such ratings and reports are used by some investors to inform their
investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us or our
customers and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our
access to and costs of capital. Also, certain institutional lenders may decide not to provide funding to us or our customers’ companies
based on ESG concerns, which could adversely affect our financial condition and access to capital for potential growth projects.
We could incur significant costs in complying with more stringent occupational safety and health requirements.
We are subject to stringent federal and state laws and regulations, including the federal Occupational Safety and Health Act 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 federal Occupational Safety and Health Administration’s (“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 our operations and that this
information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an
interest are 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. Failure to comply with these laws and regulations or any
newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the
imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, any of which could
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have a material adverse effect on our business, financial condition and results of operations.
Laws, regulations and executive orders limiting hydraulic fracturing activities could result in restrictions, delays or cancellations in
drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the
volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.
While we do not conduct hydraulic fracturing, many of our oil and gas exploration and production customers do perform such
activities. Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion of
certain oil and natural gas wells whereby water, sand or alternative proppant, and chemical additives are injected under pressure into
subsurface formations to stimulate the flow of certain oil and natural gas, increasing the volumes that may be recovered. The process
is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over, proposed
or promulgated regulations governing, and conducted investigations relating to certain aspects of the process, including the EPA. For
example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources,
concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain
circumstances.
In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic
fracturing. Moreover, President Biden issued an executive order in January 2021 suspending the issuance of new leases on federal
lands and waters pending completion of a study of current oil and gas practices but, in June 2021, a U.S. District Court issued a
temporary injunction that blocked President Biden’s order suspending new leases. Notwithstanding these recent legal developments,
further restrictions may be adopted by the Biden Administration that could restrict hydraulic fracturing activities on federal lands and
waters. Many states have adopted legal requirements that have imposed new or more stringent permitting, public disclosure or well
construction requirements on hydraulic fracturing activities, including in states where we or our customers conduct operations. States
could further elect to suspend or prohibit hydraulic fracturing activities in the future. While governments may also seek to adopt
ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing
activities in particular, non-governmental organizations may also seek to restrict hydraulic fracturing through ballot initiatives, such as
those that have been pursued in Colorado. New or more stringent laws, regulations, executive orders or regulatory or ballot initiatives
relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gas drilling activities using
hydraulic fracturing techniques, while increased public opposition to activities using such techniques may result in operational delays,
restrictions, cessations, or increased litigation. Any one or more of such developments could reduce demand for our gathering,
processing and fractionation services and have a material adverse effect on our business, financial condition and results of operations.
Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the
environment may cause us to incur significant costs and liabilities.
Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational
health and safety, the discharge of pollutants into the environment or otherwise relating to environmental protection. These laws and
regulations may impose numerous obligations that are applicable to our operations including acquisition of a permit or other approval
before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be released into the
environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands,
urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control
requirements, and imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities,
such as the EPA and BLM, and analogous state agencies, have the power to enforce compliance with these laws and regulations and
the permits and approvals issued under them, which can often require difficult and costly actions. Failure to comply with these laws
and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and
criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures;
the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, and the issuance of orders enjoining
or conditioning performance of some or all of our operations in a particular area. Certain environmental 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
released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator or the
activities conducted and from which a release emanated complied with applicable law. 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 wastes into the environment.
The risk of incurring environmental costs and liabilities in connection with our operations is significant due to our handling of natural
gas, NGLs, crude oil and other petroleum products, because of air emissions and product-related discharges arising out of our
operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one
of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by
neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for
related violations of environmental laws or regulations.
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Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the
cost of any remediation that may become necessary. For example, in 2015, the EPA issued a final rule under the CAA, lowering the
National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion under both the primary and
secondary standards to provide requisite protection of the public health and welfare. State agencies are required to submit
implementation plans to EPA for attaining those 2015 standards. Additionally, in October 2021 the EPA announced plans to
reconsider the Trump Administration’s December 2020 decision to retain the 2015 ground ozone standard, rather than making it more
stringent, and litigation on that December 2020 decision remains pending, although the U.S. Department of Justice has requested that
such legal challenges be held in abeyance until the EPA completes its reconsideration. Also, there continues to be uncertainty on the
federal government’s applicable jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands,
as the EPA and the U.S. Army Corps of Engineers (“Corps”) under the Obama, Trump and Biden Administrations have pursued
multiple rulemakings since 2015 in an attempt to determine the scope of such reach. While the EPA and Corps under the Trump
Administration issued a final rule in April 2020 narrowing federal jurisdictional reach over waters of the United States, President
Biden issued an executive order in January 2021 to further review and assess these regulations consistent with the new
administration’s policy objectives, following which the EPA and Corps announced plans in June 2021 to initiate a new rulemaking
process that would repeal the 2020 rule and restore protections that were in place prior to the 2015. Although the EPA and Corps did
not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico have vacated the 2020 rule
in decisions announced during the third quarter of 2021. While these district court decisions may be appealed, it is clear that the EPA
and Corps intend to adopt a more expansive definition for waters of the United States. As an initial step, the agencies published on
December 7, 2021 a proposed rulemaking that would put back into place the pre-2015 definition of “waters of the United States” in
effect prior to 2015 rule issued under the Obama Administration and updated to reflect consideration of Supreme Court decisions. The
proposed rule, if adopted would serve as an interim approach to “waters of the United States” and provide the agency with time to
develop a subsequent rule that builds upon the currently proposed rule based, in part, on additional stakeholder involvement. To the
extent that any new final rule or rules issued by the EPA and Corps under the Biden Administration expands the scope of the Clean
Water Act’s jurisdiction in areas where we or our customers conduct operations, such developments could delay, restrict or halt the
development of projects, result in longer permitting timelines, or increased compliance expenditures or mitigation costs for our and
our oil and natural gas customers’ operations, which may reduce the rate of production of natural gas or crude oil from operators with
whom we have a business relationship and, in turn, have a material adverse effect on our business, results of operations and cash
flows. Notwithstanding these regulatory developments, there is a recent judicial development that may add to the uncertainty of the
federal government’s jurisdictional reach over waters of the United States, as the U.S. Supreme Court granted a writ of certiorari in
Sackett v. EPA on January 24, 2022, regarding “(w)hether the Ninth Circuit set forth the proper test for determining whether wetlands
are ‘waters of the United States’ under the Clean Water Act.” The Ninth Circuit relied upon a plurality opinion under the high court’s
2006 decision in Rapanos v. United States in siding with the EPA and against the Sacketts that the wetlands in question constituted
waters of the United States under the Clean Water Act. As the Rapanos decision resulted in the issuance of plurality and concurring
opinions establishing different legal standards for determining the extent of jurisdictional waters under the Clean Water Act’s
definition of waters of the United States, should the U.S. Supreme Court find in Sackett that the Ninth Circuit did not use the
appropriate legal test or otherwise seeks to establish a new test to clarify the extent of such jurisdictional reach, then such finding
could have repercussions on future regulatory efforts pursued under the Biden Administration.
A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change
in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating
expenses to increase or delay or increase the cost of expansion projects.
With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission pipeline and Tarzan 311 residue line, which are each
subject to limited FERC regulation under either the NGA or NGPA, our natural gas pipeline operations are generally exempt from
FERC regulation, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from
these businesses, including certain FERC reporting and posting requirements in a given year. We believe that the natural gas pipelines
in our 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, ongoing litigation, so the classification and regulation of our gathering facilities are
subject to change based on future determinations by FERC, the courts or Congress. We also operate natural gas pipelines that extend
from some of our processing plants to interconnections with both intrastate and interstate natural gas pipelines. Those facilities, known
in the industry as “plant tailgate” pipelines, typically operate at transmission pressure levels and may transport “pipeline quality”
natural gas. Because our plant tailgate pipelines are relatively short, we treat them as “stub” lines, which are exempt from FERC’s
jurisdiction under the Natural Gas Act.
48
Targa NGL, Targa Gulf Coast, and Grand Prix Joint Venture have pipelines that are considered common carrier pipelines subject to
regulation by FERC under ICA. The ICA requires that we maintain tariffs on file with FERC for each of the Targa NGL, Targa Gulf
Coast and Grand Prix Joint Venture common carrier pipelines that have not been granted a waiver. Those tariffs set forth the rates we
charge 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. With respect to
pipelines that have been granted a waiver of the ICA and related regulations by FERC, should a particular pipeline’s circumstances
change, FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a
waiver. In the event that FERC were to determine that one or more of these pipelines no longer qualified for a waiver, we would likely
be required to file a tariff with FERC for the applicable pipeline(s), provide a cost justification for the transportation charge, and
provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on
these pipelines could adversely affect our results of operations.
The classification of some of our gathering facilities, transportation pipelines, and purchase and sale transactions as FERC-
jurisdictional or non-jurisdictional may be subject to change based on future determinations by FERC, the courts or Congress, in
which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.
Various federal agencies within the U.S. Department of the Interior, particularly the BLM, Office of Natural Resources Revenue
(formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and
enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our
Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws
and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various
taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands.
Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. One
or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse
impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on
such lands.
Other FERC regulations may indirectly impact our 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 natural gas market. In
recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot
assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect
rights of access to transportation capacity. For more information regarding the regulation of our operations, see “Item 1. Business—
Regulation of Operations.”
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety
controls or result in more rigorous enforcement of applicable legal requirements could subject us to increased capital costs,
operational delays and costs of operation.
Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing
and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the NGPSA and
HLPSA were amended in recent years by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline
Safety Act”), the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) and, most
recently, the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020. Each of these laws imposed
increased pipeline safety obligations on pipeline operators. The 2011 Pipeline Safety Act directed the promulgation of expanded
integrity management requirements, automatic or remote-controlled valve, and excess flow valve use, leak detection system
installation, material strength pipeline testing and verification of records confirming the maximum allowable pressure of certain
intrastate gas transmission pipelines, whereas the 2016 Pipeline Safety Act also empowered PHMSA to address unsafe conditions or
practices constituting imminent hazards by imposing emergency measures on pipeline facility owners and operators without prior
notice or an opportunity for a hearing. The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency
to move forward with several regulatory initiatives, including obligating operators of non-rural gas gathering lines and new and
existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility
inspection and maintenance plans to align with those regulations. In furtherance of the PIPES Act of 2020, in November 2021,
PHMSA issued a final rule that will impose safety regulations on approximately 400,000 miles of previously unregulated onshore gas
gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting
requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with
large diameters and high operating pressures.
49
The imposition of new or enhanced safety requirements, or any issuance or reinterpretation of guidance by PHMSA or any state
agencies with respect thereto, may require us to install new or modified safety controls, pursue additional capital projects or conduct
maintenance programs on an accelerated basis, any or all of which tasks could result in increased operating costs that could have an
adverse effect on our results of operations or financial position.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to
substantial penalties and fines.
Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of the NGA
or NGPA up to a maximum amount that is adjusted annually for inflation, which for 2021 equaled approximately $1.4 million per
violation per day for violations of the NGA and approximately $1.4 million per violation per day for violations of the NGPA, as well
as authority to order disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline,
TPL SouthTex Transmission pipeline and Tarzan 311 residue line, have not been regulated by FERC under the NGA or NGPA, FERC
has adopted regulations that may subject certain of our 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 us to civil
penalty liability. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA up to a
maximum amount that is adjusted annually for inflation, which for 2021 was up to approximately $14,536 per violation per day, and
failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability. For more information
regarding regulation of our operations, see “Item 1. Business—Regulation of Operations.”
We are or may become subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing
of personal information.
The jurisdictions in which we operate (including the United States) may have laws governing how we must respond to a cyber
incident that results in the unauthorized access, disclosure, or loss of personal information. Additionally, new laws and regulations
governing data privacy and unauthorized disclosure of confidential information, including recent California legislation (which, among
other things, provides for a private right of action), pose increasingly complex compliance challenges and could potentially elevate our
costs over time. Although our business does not involve large-scale processing of personal information, our business does involve
collection, use, and other processing of personal information of our employees, investors, contractors, suppliers, and customer
contacts. As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant
resources to continue to modify or enhance our protective measures to comply with such legislation and to detect, investigate and
remediate vulnerabilities to cyber incidents. Any failure by us, or a company we acquire, to comply with such laws and regulations
could result in reputational harm, loss of goodwill, penalties, liabilities, and/or mandated changes in our business practices.
50
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
A description of our properties is contained in “Item 1. Business” in this Annual Report.
Our principal executive offices are located at 811 Louisiana Street, Suite 2100, Houston, Texas 77002 and our telephone number is
713-584-1000.
Item 3. Legal Proceedings.
On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80th District Court of Harris County (the “District
Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of
$129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that
Targa Channelview breached an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview and
Noble Americas Corp. (the “Splitter Agreement”), which provided for Targa Channelview to construct a crude oil and condensate
splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter
Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate
the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges
Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and
condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to
Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit,
Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s
voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the
Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.
On October 15, 2020, the District Court awarded Vitol $129.0 million (plus interest) following a bench trial. In addition, the District
Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The
Company has filed an appeal challenging the award, and the appeal is currently pending in the Fourteenth Court of Appeals in
Houston, Texas.
In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with
the Vitol proceedings.
Additional information required for this item is provided in Note 19 – Contingencies, under the heading “Legal Proceedings” included
in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, which is incorporated by
reference into this item.
Item 4. Mine Safety Disclosures.
Not applicable.
51
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Our common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, 2021, there were 196 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. As of February 18, 2022, there were 228,783,477 shares of common
stock outstanding.
Stock Performance Graph
The graph below compares the cumulative return to holders of Targa Resources Corp.’s common stock, the NYSE Composite Index
(the “NYSE Index”) and the Alerian US Midstream Energy Index (the “AMUS Index”) during the period beginning on December 31,
2016 and ending on December 31, 2021. The performance graph was prepared based on the following assumptions: (i) $100 was
invested in our common stock and in each of the indices at beginning of the period, and (ii) dividends were reinvested on the relevant
payment dates. The stock price performance included in this graph is historical and not necessarily indicative of future stock price
performance.
Targa Resources Corp.
NYSE Composite Index
Alerian US Midstream Energy Index
$
$
$
100.00 $
100.00 $
100.00 $
103.91 $
115.84 $
88.62 $
83.21 $
102.87 $
74.04 $
103.35 $
125.83 $
79.93 $
69.55 $
131.36 $
54.64 $
139.10
155.23
74.31
2016
2017
2018
2019
2020
2021
Year Ended December 31,
52
Pursuant to Instruction 7 to Item 201(e) of Regulation S-K, the above stock performance graph and related information is being
furnished and is not being filed with the SEC, and as such shall not be deemed to be incorporated by reference into any filing that
incorporates this Annual Report by reference.
Our Dividend Policy
We intend to continue to pay a quarterly dividend to our common stockholders; however, any payment of future dividends is
dependent upon our financial condition, results of operations, cash flows, the level of our capital expenditures, future business
prospects and any other matters that our board of directors, in consultation with management, deems relevant. Covenants contained in
our debt agreements could limit the payment of dividends. In addition, so long as any Series A Preferred are outstanding, certain
limitations on our ability to declare dividends on our common stock exist. For a discussion of restrictions on our and our subsidiaries’
ability to pay dividends or make distributions, please see Note 8 – Debt Obligations and Note 11 – Preferred Stock in our
Consolidated Financial Statements beginning on page F-1 in this Form 10-K.
Recent Sales of Unregistered Equity Securities
There were no sales of unregistered equity securities for the year ended December 31, 2021.
Repurchase of Equity by Targa Resources Corp, or Affiliated Purchasers
Period
Total number of
shares purchased
(1)
Average price
per share
Total number of shares
purchased as part of publicly
announced plans (2)
Maximum approximate
dollar value of shares that
may yet be purchased under
the plan (in thousands) (2)
1,706 $
353,224 $
405,250 $
51.46
54.24
51.58
— $
351,228 $
405,250 $
408,499.4
389,452.6
368,547.9
October 1, 2021 - October 31, 2021
November 1, 2021 - November 30, 2021
December 1, 2021 - December 31, 2021
_________________________________
(1)
Includes 756,478 shares purchased under our $500 million common share repurchase program, as well as 3,702 shares that were withheld by us to satisfy tax
withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictions on restricted stock.
In the fourth quarter 2020, our board of directors approved a share repurchase program for the repurchase of up to $500 million of our outstanding common stock.
We may discontinue this share repurchase program at any time and are not obligated to repurchase any specific dollar amount or number of shares.
(2)
Item 6. Reserved.
53
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our
consolidated financial statements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report
should be helpful to the reading of our discussion and analysis, including the following: (i) a description of our business strategy found
in “Item 1. Business–Overview”; (ii) a description of recent developments, found in “Item 1. Business–Recent Developments”; and
(iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.” Discussions of 2019 items and year-
to-year comparisons between 2020 and 2019 that are not included in this Annual Report can be found in Part II, Item 7.
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for
the year ended December 31, 2020.
General Trends and Outlook
We expect our results of operations to continue to be affected by the following key trends: commodity prices, volume throughput and
demand for our products and services, contract terms and mix, the impact of our hedging activities, the cost to operate and support
assets, volatile capital markets, competition 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.
Commodity Prices
There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil
and natural gas prices. As a result of reduced economic activity due to the COVID-19 pandemic paired with uncertainty around global
commodity supply and demand, global oil and natural gas commodity prices continue to remain volatile. 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 our systems. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas, NGL products
and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in supply, demand or these prices could
adversely affect our results of operations and financial condition.”
Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices. Our processing
profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate, both of
which are beyond our control. In a declining commodity price environment, without taking into account our hedges, we will realize a
reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. The significant level of
margin we derive from fee-based arrangements across our operations and particularly in our Downstream Business combined with our
hedging arrangements helps to mitigate our exposure to commodity price movements. For additional information regarding our
hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
The following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and
crude oil for the periods presented:
Natural Gas $/MMBtu (1)
Illustrative Targa NGL $/gal (2)
Crude Oil $/Bbl (3)
2021
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2021 Average
2020
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2020 Average
$
$
5.84 $
4.01
2.83
2.70
3.85
2.66 $
1.97
1.70
1.98
2.08
0.94 $
0.86
0.66
0.65
0.78
0.47 $
0.42
0.32
0.36
0.39
77.17
70.55
66.06
57.80
67.90
42.67
40.94
27.55
46.59
39.44
(1)
(2)
(3)
Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.
“Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the
following composition for the periods noted:
2021: 45% ethane, 31% propane, 11% normal butane, 4% isobutane and 9% natural gasoline
2020: 43% ethane, 32% propane, 12% normal butane, 4% isobutane and 9% natural gasoline
Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.
54
Volumes and Demand for our Services
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of
new oil and natural gas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among
these prices and related activity levels from our customers. In our gathering and processing operations, plant inlet volumes, crude oil
volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a
regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration and production activity in
the areas of our operations. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below
commercially acceptable levels. Producers generally focus their drilling activity on certain basins depending on commodity price
fundamentals. Our asset systems are predominantly located in some of the most economic basins in the United States.
The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business.
Accordingly, increased producer activity will drive demand for our midstream services and may result in incremental growth capital
expenditures. Demand for our transportation, fractionation and other fee-based services is largely correlated with producer activity
levels. Demand for our international export, storage and terminaling services has remained relatively constant, as demand for these
services is based on a number of domestic and international factors.
Contract Terms, Contract Mix and the Impact of Commodity Prices
Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our
services. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other
fee-based services which mitigate against low commodity prices. The significant level of margin we derive from fee-based
arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements.
With the potential for volatility of commodity prices, the contract mix of our Gathering and Processing segment (other than fee-based
contracts in certain gathering and processing business units and gathering and processing services), can have a significant impact on
our profitability, especially those percent-of-proceeds contracts that create direct exposure to changes in energy prices by paying us
for gathering and processing services with a portion of proceeds from the commodities handled (“equity volumes”).
Contract terms in the Gathering and Processing segment are based upon a variety of factors, including natural gas and crude quality,
geographic location, competitive dynamics and the pricing environment at the time the contract is executed, and customer
requirements. Our gathering and processing contract mix and, accordingly, our exposure to crude, natural gas and NGL prices may
change as a result of producer preferences, competition and changes in production as wells decline at different rates or are added, our
expansion into regions where different types of contracts are more common and other market factors.
The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations.
Transportation and fractionation services are supported by fee-based contracts whose rates and terms are driven by NGL supply and
transportation and fractionation capacity. Export services are supported by fee-based contracts whose rates and terms are driven by
global LPG supply and demand fundamentals. The Logistics and Transportation segment includes predominantly fee-based contracts.
Impact of Our Commodity Price Hedging Activities
We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes,
future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These
transactions include swaps, futures, and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity
volumes without creating volumetric risk. We intend to continue managing our exposure to commodity prices in the future by entering
into derivative transactions. We actively manage the Downstream Business product inventory and other working capital levels to
reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A. Quantitative and
Qualitative Disclosures About Market Risk–Commodity Price Risk.”
Operating Expenses
Variable costs such as service and repairs can impact our results. Continued expansion of existing assets will also give rise to
additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa
Resources LLC, a Delaware limited liability company, and an indirect wholly-owned subsidiary of ours.
55
Volatile Capital Markets and Competition
We continuously consider and enter into discussions regarding potential growth projects and acquisitions and may contemplate
external funding for potential growth projects and acquisitions. Any limitations on our access to capital may impair our ability to
execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets
may be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors influencing our
cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to
lenders. These factors may impair our ability to execute our growth and acquisition strategy.
Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully
execute our growth strategy. Due to increased volatility in commodity prices and the broader market, the ability of companies in the
oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. We
believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt
service payments and capital expenditures in 2022 and beyond. For additional information regarding our financing activities, see
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Liquidity and Capital
Resources.”
Increased Regulation
Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example,
increased regulation of hydraulic fracturing used by producers and increased GHG emission regulations may cause reductions in
supplies of natural gas, NGLs and crude oil from producers. Please read “Laws and regulations regarding hydraulic fracturing could
result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could
adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the
utilization of our assets”, “Our and our customers’ operations are subject to a number of risks arising out of the threat of climate
change (including legislation or regulation to address climate change) that could result in increased operating costs, limit the areas in
which oil and natural gas production may occur, and reduce demand for the products and services we provide,” and “Increasing
attention to ESG matters may impact our business” under Item 1A of this Annual Report. Similarly, the forthcoming rules and
regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less
predictability in our results of operations.
How We Evaluate Our Operations
The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including
fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs
associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as
well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price
movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of
increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and
NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements and the
volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our
profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services,
utilization of our assets and changes in our customer mix.
Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing
assets underpinned by fee-based margin, expansion of our Downstream facilities, continued focus on adding fee-based margin to our
existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to
increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation,
fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.
Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.
Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1)
throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following
non-GAAP measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment).
56
Throughput Volumes, Facility Efficiencies and Fuel Consumption
Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline
of existing volumes from oil and natural gas wells that are connected to our 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 crude oil and natural gas
supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL
supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our
export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL
supply from third-party facilities.
In addition, we seek to increase adjusted operating margin by limiting volume losses, reducing fuel consumption and by increasing
efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the
wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and
the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received,
stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and
Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase
efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the
wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an
indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the
processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of
our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume,
recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.
Operating Expenses
Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance and ad
valorem taxes comprise the most significant portion of our operating expenses. These expenses remain relatively stable and
independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope
of the activities performed during a specific period.
Capital Expenditures
Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures. Growth capital
expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels,
add capabilities, and reduce costs or enhance revenues. Maintenance capital 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 are
worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.
Capital spending associated with growth and maintenance projects is closely monitored. Return on investment is analyzed before a
capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational
performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.
Non-GAAP Measures
We utilize non-GAAP measures to analyze our performance. Adjusted EBITDA, distributable cash flow, adjusted free cash flow and
adjusted operating margin (segment) are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP
measures are income (loss) from operations, net income (loss) attributable to TRC and segment operating margin. These non-GAAP
measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors
should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally,
because our non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined
differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other
companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical
tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these
insights into our decision-making processes.
57
Adjusted Operating Margin
We define adjusted operating margin for our segments as revenues less product purchases and fuel. It is impacted by volumes and
commodity prices as well as by our contract mix and commodity hedging program.
Gathering and Processing adjusted operating margin consists primarily of:
service fees related to natural gas and crude oil gathering, treating and processing; and
revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and
our equity volume hedge settlements.
Logistics and Transportation adjusted operating margin consists primarily of:
service fees (including the pass-through of energy costs included in fee rates);
system product gains and losses; and
NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory
change.
The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Adjusted operating margin for our segments provides useful information to investors because it is used as a supplemental financial
measure by management and by external users of our financial statements, including investors and commercial banks, to assess:
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to other companies in the midstream energy sector, without
regard to financing or capital structure; and
the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment
opportunities.
Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management
process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our
operating results. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented
under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By
Reportable Segment.”
Adjusted EBITDA
We define adjusted EBITDA as net income (loss) attributable to TRC before interest, income taxes, depreciation and amortization,
and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in
the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and
by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to
generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.
Distributable Cash Flow and Adjusted Free Cash Flow
We define distributable cash flow as adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on
debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The
Preferred Units that were issued by the Partnership in October 2015 were redeemed in December 2020. We define adjusted free cash
flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions
to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by us
and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to
generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment
of dividends, retirement of debt or redemption of other financing arrangements.
58
Our Non-GAAP Financial Measures
The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP
measures for the periods indicated.
Reconciliation of Net income (loss) attributable to TRC to Adjusted EBITDA, Distributable Cash
Flow and Adjusted Free Cash Flow
Net income (loss) attributable to TRC
Income attributable to TRP preferred limited partners
Interest (income) expense, net
Income tax expense (benefit)
Depreciation and amortization expense
Impairment of long-lived assets
(Gain) loss on sale or disposition of business and assets
Write-down of assets
(Gain) loss from financing activities (1)
Equity (earnings) loss
Distributions from unconsolidated affiliates and preferred partner interests, net
Change in contingent considerations
Compensation on equity grants
Risk management activities
Severance and related benefits (2)
Noncontrolling interests adjustments (3)
TRC Adjusted EBITDA
Distributions to TRP preferred limited partners
Interest expense on debt obligations (4)
Maintenance capital expenditures, net (5)
Cash taxes
Distributable Cash Flow
Growth capital expenditures, net (5)
Adjusted Free Cash Flow
Year Ended December 31,
2021
2020
(In millions)
71.2
—
387.9
14.8
870.6
452.3
2.0
10.3
16.6
23.9
116.5
0.1
59.2
116.0
—
(89.4 )
2,052.0
—
(376.2 )
(131.7 )
(2.7 )
1,541.4
(407.7 )
1,133.7
$
$
$
$
(1,553.9 )
15.1
391.3
(248.1 )
865.1
2,442.8
58.4
55.6
(45.6 )
(72.6 )
108.6
(0.3 )
66.2
(228.2 )
6.5
(224.3 )
1,636.6
(15.1 )
(388.9 )
(104.2 )
44.4
1,172.8
(597.9 )
574.9
$
$
$
$
(1)
(2)
(3)
(4)
(5)
Gains or losses on debt repurchases or early debt extinguishments.
Represents one-time severance and related benefit expense related to our cost reduction measures.
Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling
interests).
Excludes amortization of interest expense.
Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates.
59
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations:
Revenues:
Sales of commodities
Fees from midstream services
Total revenues
Product purchases and fuel (1)
Operating expenses (1)
Depreciation and amortization expense
General and administrative expense
Impairment of long-lived assets
Other operating (income) expense
Income (loss) from operations
Interest expense, net
Equity earnings (loss)
Gain (loss) from financing activities
Change in contingent considerations
Other, net
Income tax (expense) benefit
Net income (loss)
Less: Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to Targa Resources Corp.
Dividends on Series A Preferred Stock
Deemed dividends on Series A Preferred Stock
Net income (loss) attributable to common shareholders
Financial data:
Adjusted EBITDA (2)
Distributable cash flow (2)
Adjusted free cash flow (2)
$
$
$
Year Ended December 31,
2021
2020
(In millions)
2021 vs. 2020
15,602.5 $
1,347.3
16,949.8
13,729.5
747.0
870.6
273.2
452.3
12.4
864.8
(387.9 )
(23.9 )
(16.6 )
(0.1 )
0.6
(14.8 )
422.1
350.9
71.2
87.3
—
(16.1 ) $
2,052.0 $
1,541.4
1,133.7
7,171.0 $
1,089.3
8,260.3
5,186.5
698.4
865.1
254.6
2,442.8
116.6
(1,303.7 )
(391.3 )
72.6
45.6
0.3
3.4
248.1
(1,325.0 )
228.9
(1,553.9 )
91.7
39.2
(1,684.8 ) $
8,431.5
258.0
8,689.5
8,543.0
48.6
5.5
18.6
(1,990.5 )
(104.2 )
2,168.5
3.4
(96.5 )
(62.2 )
(0.4 )
(2.8 )
(262.9 )
1,747.1
122.0
1,625.1
(4.4 )
(39.2 )
1,668.7
1,636.6 $
1,172.8
574.9
415.4
368.6
558.8
118 %
24 %
105 %
165 %
7 %
1 %
7 %
(81 %)
(89 %)
166 %
1 %
(133 %)
(136 %)
(133 %)
(82 %)
(106 %)
132 %
53 %
105 %
(5 %)
(100 %)
99 %
25 %
31 %
97 %
(1)
(2)
Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the
direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business.
Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion
and Analysis of Financial Condition and Results of Operations–How We Evaluate Our Operations.”
2021 Compared to 2020
The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($8,449.3 million) and higher NGL and
natural gas volumes ($917.3 million), partially offset by lower petroleum products, crude marketing and condensate volumes ($147.6
million) and the unfavorable impact of hedges ($787.5 million).
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees and fractionation volumes,
partially offset by lower terminaling and storage fees.
The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas
volumes, partially offset by lower petroleum products, crude marketing and condensate volumes.
The increase in operating expenses was due to higher labor costs and repairs and maintenance primarily due to increased activity
levels and system expansions, partially offset by the reduction in expense due to the idling of GCF in 2021.
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
The increase in general and administrative expense was primarily due to higher compensation and benefits and an increase in
insurance costs.
In 2021, we recognized a non-cash pre-tax impairment loss of $452.3 million on assets in the South Texas region associated with our
Central operations. In 2020, we recognized a non-cash pre-tax impairment loss of $2,442.8 million on assets in the Mid-Continent
region associated with our Central operations and full impairment of our Coastal operations. See Note 5 - Property, Plant and
Equipment and Intangible Assets for further discussion.
60
Other operating (income) expense in 2021 consisted primarily of the write-down of certain assets to their recoverable amounts. Other
operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in
Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts.
The decrease in equity earnings is primarily due to non-cash pre-tax impairment losses of $77.2 on our investments in T2 Eagle Ford
and T2 LaSalle located in the South Texas region and lower earnings from our investments in GCF, Cayenne and GCX DevCo JV.
See Note 7 – Investments in Unconsolidated Affiliates for further discussion.
During 2021, the Partnership redeemed the 5⅛% Notes and the 4¼% Notes and Targa Pipeline Partners LP (“TPL”) redeemed the
TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023, resulting in a $16.6 million net loss from financing activities.
During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior
Notes due 2024 and the 5¼% Senior Notes due 2023, resulting in a $45.6 million net gain from financing activities.
The increase in income tax expense is primarily due to an increase in pre-tax book income.
The increase in net income attributable to noncontrolling interests is primarily due to impairment losses allocated to noncontrolling
interest holders in the first quarter of 2020 and higher income allocated to noncontrolling interest holders in Grand Prix Joint Venture.
The increase in net income attributable to noncontrolling interests was partially offset by impairment losses allocated to
noncontrolling interest holders in the fourth quarter of 2021 and the impact of the redemption of the Partnership’s preferred units in
December 2020.
The decrease in dividends on Series A Preferred is due to the partial repurchase of our Series A Preferred in December 2020.
The decrease in deemed dividends on Series A Preferred is due to the adoption of Accounting Standards Update 2020-06, Debt - Debt
with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic
815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which no longer requires the discount
accretion related to beneficial conversion feature as a deemed dividend.
Results of Operations—By Reportable Segment
Our operating margins by reportable segment are:
Year Ended:
Gathering and
Processing
Logistics and
Transportation
(In millions)
Other
December 31, 2021 $
December 31, 2020
1,325.3
1,017.7
$
1,264.3
1,128.0
$
(115.9 )
229.7
61
Gathering and Processing Segment
Operating margin
Operating expenses (1)
Adjusted operating margin (1)
Operating statistics (2):
Plant natural gas inlet, MMcf/d (3),(4)
Permian Midland (5)
Permian Delaware
Total Permian
SouthTX (6)
North Texas
SouthOK (6)
WestOK
Total Central
Badlands (6) (7)
Total Field
Coastal
Total
NGL production, MBbl/d (4)
Permian Midland (5)
Permian Delaware
Total Permian
SouthTX (6)
North Texas
SouthOK (6)
WestOK
Total Central
Badlands (6)
Total Field
Coastal
Total
Crude oil, Badlands, MBbl/d
Crude oil, Permian, MBbl/d
Natural gas sales, BBtu/d (4)
NGL sales, MBbl/d (4)
Condensate sales, MBbl/d
Average realized prices - inclusive of hedges (8):
Natural gas, $/MMBtu
NGL, $/gal
Condensate, $/Bbl
Year Ended December 31,
2021
2020
(In millions, except operating statistics and price amounts)
2021 vs. 2020
$
$
1,325.3
476.2
1,801.5
$
$
1,017.7
429.9
1,447.6
$
$
307.6
46.3
353.9
30 %
11 %
24 %
10 %
15 %
(28 %)
(11 %)
(8 %)
(15 %)
1 %
1,745.6
729.4
2,475.0
248.1
201.6
443.0
249.5
1,142.2
137.8
3,755.0
182.8
110.4
293.2
(70.4 )
(22.7 )
(37.1 )
(36.9 )
(167.1 )
2.0
128.1
643.3
(56.1 )
(9 %)
4,398.3
72.0
2 %
250.8
99.1
349.9
26.1
23.9
52.4
20.3
122.7
16.3
488.9
40.0
528.9
156.5
43.3
2,094.8
399.5
15.5
1.27
0.26
39.40
27.1
15.0
42.1
(3.9 )
(3.8 )
(2.9 )
(3.8 )
(14.4 )
(0.1 )
27.6
11 %
15 %
(15 %)
(16 %)
(6 %)
(19 %)
(1 %)
(6.1 )
(15 %)
21.5
(15.6 )
(8.3 )
112.9
(4.9 )
(0.6 )
2.00
0.35
20.62
4 %
(10 %)
(19 %)
5 %
(1 %)
(4 %)
157 %
135 %
52 %
1,928.4
839.8
2,768.2
177.7
178.9
405.9
212.6
975.1
139.8
3,883.1
587.2
4,470.3
277.9
114.1
392.0
22.2
20.1
49.5
16.5
108.3
16.2
516.5
33.9
550.4
140.9
35.0
2,207.7
394.6
14.9
3.27
0.61
60.02
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the
direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business.
Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics
presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing
plant, other than Badlands.
Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude
producer take-in-kind volumes.
Permian Midland includes operations in WestTX, of which we own 72.8%, and other plants that are owned 100% by us. Operating results for the WestTX
undivided interest assets are presented on a pro-rata net basis in our reported financials.
Operations include facilities that are not wholly owned by us. For more information regarding our joint ventures and jointly owned facilities, see “Item 1.
Business—Our Business Operations.”
Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.
Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes. The price is calculated using total
commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator.
62
The following table presents the realized commodity hedge gain (loss) attributable to our equity volumes that are included in the
adjusted operating margin of the Gathering and Processing segment:
Year Ended December 31, 2021
Year Ended December 31, 2020
Volume
Settled
(In millions, except volumetric data and price amounts)
Price
Price
Gain
(Loss)
Volume
Settled
Spread (1)
Spread (1)
Gain
(Loss)
Natural gas (BBtu)
NGL (MMgal)
Crude oil (MBbl)
76.8 $
581.5
2.1
(1.41 ) $
(0.26 )
(14.33 )
$
(108.0 )
(153.1 )
(30.1 )
(291.2 )
68.1 $
451.4
1.9
0.37 $
0.12
18.54
$
25.1
53.3
34.9
113.3
________________
(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
2021 Compared to 2020
The increase in adjusted operating margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting
in increased margin predominantly in the Permian, partially offset by the short-term operational disruption and impacts associated
with a major winter storm during the first quarter of 2021. The increase in natural gas inlet volumes in the Permian was attributable to
higher production, higher producer activity, the addition of the Peregrine and Gateway plants during 2020 and the Heim plant during
the third quarter of 2021. In the Badlands, natural gas inlet volumes were relatively flat, while the decrease in the Central and Coastal
regions was due to lower production and continued low producer activity. Total crude oil volumes decreased in the Badlands and the
Permian due to lower production.
Operating expenses were higher due to increased activity levels in the Permian, the additions of the Peregrine and Gateway plants in
2020 and the Heim plant in the third quarter of 2021, which resulted in increased labor costs, materials and chemicals, partially offset
by a reduction in taxes.
Logistics and Transportation Segment
Operating margin
Operating expenses (1)
Adjusted operating margin (1)
Operating statistics MBbl/d (2):
NGL pipeline transportation volumes (3)
Fractionation volumes
Export volumes (4)
NGL sales
$
$
Year Ended December 31,
2021
2020
(In millions, except operating statistics)
2021 vs. 2020
1,264.3
273.0
1,537.3
$
$
396.2
616.0
316.9
899.7
1,128.0
274.0
1,402.0
$
$
293.7
602.9
300.4
752.5
136.3
(1.0 )
135.3
102.5
13.1
16.5
147.2
12%
—
10%
35%
2%
5%
20%
(1)
(2)
(3)
(4)
Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the
direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business.
Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented,
the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
Represents the total quantity of mixed NGLs that earn a transportation margin.
Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international
markets.
2021 Compared to 2020
The increase in adjusted operating margin was primarily due to higher pipeline transportation and fractionation volumes that benefited
from higher supply volumes from our Permian Gathering and Processing systems, partially offset by short-term operational
disruptions and impacts associated with the major winter storm during the first quarter of 2021. Additionally, fractionation volumes
for the full year were partially offset by an unplanned outage and associated repairs and maintenance in the fourth quarter of 2021.
Other drivers included higher marketing margin due to greater optimization opportunities, partially offset by lower LPG export margin
primarily attributable to lower fees.
Operating expenses were flat. The sale of assets in Channelview, Texas in 2020 and the absence of one-time maintenance expenses,
including hurricane damage repairs in the fourth quarter of 2020, were offset by higher taxes due to system expansions and higher
compensation and benefits.
63
Other
Operating margin
Adjusted operating margin
$
$
(115.9 )
(115.9 )
$
$
229.7
229.7
$
$
(345.6 )
(345.6 )
Year Ended December 31,
2021
2020
(In millions)
2021 vs. 2020
Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not
designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion
of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation
segment. See further details of our risk management program in “Item 7A. – Quantitative and Qualitative Disclosures About Market
Risk.”
Our Liquidity and Capital Resources
As of December 31, 2021, inclusive of our consolidated joint venture accounts, we had $158.5 million of Cash and cash equivalents
on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally
generated cash flows from operations, borrowings under the New TRC Revolver and the Securitization Facility and access to debt and
equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our
exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks
and counterparty performance risks.
We believe our sources of liquidity and capital resources are sufficient to meet our anticipated cash requirements for at least the next
twelve months to satisfy our obligations. Our ability to generate cash is subject to a number of factors, some of which are beyond our
control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well
as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors
impacting our liquidity and capital resources, please see “Recent Developments.”
Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity,
subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s
debt agreements, as well as the ability to contribute capital to the Partnership, subject to any restrictions contained in the covenants of
our debt agreements. We are entitled to the entirety of distributions made by the Partnership on its equity interests. The actual amount
we declare as distributions depends on our consolidated financial condition, results of operations, cash flow, the level of our capital
expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems
relevant.
The Partnership’s debt agreements may restrict or prohibit the payment of distributions by the Partnership to us if the Partnership is in
default. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our
common stock or Series A Preferred. In addition, so long as any of our Series A Preferred are outstanding, certain common stock
distribution limitations exist.
Short-term Liquidity
Our principal sources of short-term liquidity consist of internally generated cash flow, borrowings available under the New TRC
Revolver, as well as our right to request additional commitment increases under the New TRC Revolver, the Securitization Facility,
proceeds from debt and equity offerings and joint ventures and/or asset sales. Based on anticipated levels of operations and absent any
disruptive events, we believe our liquidity is sufficient to finance our operations, capital expenditures, quarterly cash dividends and
obligations, as discussed further below, for at least the next twelve months.
64
Our short-term liquidity on a consolidated basis as of February 18, 2022, was:
Cash on hand (1)
Total availability under the New TRC Revolver
Total availability under the Securitization Facility
Less: Outstanding borrowings under the New TRC Revolver
Outstanding borrowings under the Securitization Facility
Outstanding letters of credit under the New TRC Revolver
Total liquidity
_________________________________
(1)
Includes cash held in our consolidated joint venture accounts.
Consolidated Total
(In millions)
382.1
2,750.0
400.0
3,532.1
(825.0 )
(400.0 )
(105.2 )
2,201.9
$
$
Other potential capital resources associated with our existing arrangements includes our right to request an additional $500.0 million
in commitment increases under the New TRC Revolver, subject to the terms therein. The New TRC Revolver matures on February 17,
2027.
A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of
credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P as of February 18, 2022. They also reflect
certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices
and other factors.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given
month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from
customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported
total working capital are: (i) our cash position; (ii) liquids inventory levels and valuation, which we closely manage; (iii) changes in
payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative
contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or
business operations, such as certain organic growth capital projects and acquisitions or divestitures.
Working capital as of December 31, 2021 decreased $209.6 million compared to December 31, 2020. The decrease was primarily due
to higher product purchases and fuel payable as a result of higher commodity prices and an increase in the current liability position of
our derivative contracts, partially offset by higher receivables resulting from higher commodity prices and lower borrowings on the
Securitization Facility.
Long-term Financing
Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock,
preferred stock, or joint venture arrangements. The majority of our debt is fixed rate borrowings; however, we have some exposure to
the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the New TRC Revolver and the
Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash
flows. As of December 31, 2021, we did not have any interest rate hedges.
To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to
repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 8 - Debt Obligations to our
consolidated financial statements. For information about our interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures
About Market Risk—Interest Rate Risk.”
In February 2021, the Partnership issued $1.0 billion aggregate principal amount of 4% Senior Notes due 2032, resulting in net
proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the February Tender Offer
and subsequent redemption payment for the 5⅛% Notes, with the remainder used for repayment of borrowings under the Existing
TRP Revolver and Existing TRC Revolver. As a result of the February Tender Offer and the subsequent redemption of the 5⅛%
Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of premiums paid and a write-off of
$2.4 million of debt issuance costs.
65
Additionally, TPL redeemed all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023
(collectively, the “TPL Notes”) in February 2021 with available liquidity under the Existing TRP Revolver. As a result of the
redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.
The Partnership redeemed all of the outstanding 4¼% Senior Notes due 2023 (the “4¼% Senior Notes”) in May 2021 with available
liquidity under the Existing TRP Revolver. As a result of the redemption of the 4¼% Senior Notes, we recorded a loss due to debt
extinguishment of $1.9 million.
In April 2021, we amended the Securitization Facility to increase the facility size from $350.0 million to $400.0 million to more
closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to
April 21, 2022.
In February 2022, we entered into the New TRC Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent
and Swing Line Lender, and the other lenders party thereto. The New TRC Revolver provides for a revolving credit facility in an
initial aggregate principal amount up to $2.75 billion, with an option to increase such maximum aggregate principal amount by up to
$500.0 million in the future, subject to the terms of the New TRC Revolver, and a swing line sub-facility of up to $100.0 million. The
New TRC Revolver matures on February 17, 2027. In connection with our entry into the New TRC Revolver, we terminated the
Existing TRC Revolver and Existing TRP Revolver.
On February 18, 2022, we and certain of our subsidiaries entered into a Parent Guarantee to guarantee all of the obligations of the
Partnership and Targa Resources Partners Finance Corp. (together with the Partnership, the “Issuers”) under the respective indentures
governing the Issuers’ $6.5 billion of outstanding senior unsecured notes. For a full discussion of the senior unsecured notes and
related terms, see Note 8 – Debt Obligations in our Consolidated Financial Statements beginning on page F-1 in this Form 10-K.
We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other
debt, in open market purchases, privately negotiated transactions or otherwise. Additionally, we may redeem all or a portion of the
Series A Preferred in the future pursuant to its terms or repurchase Series A Preferred shares in privately negotiated transactions. Such
repurchases, exchanges or transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual
restrictions and other factors. The amounts involved may be material.
To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to
repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 8 - Debt Obligations to our
consolidated financial statements.
Compliance with Debt Covenants
As of December 31, 2021, both we and the Partnership were in compliance with the covenants contained in our various debt
agreements.
Cash Flow Analysis
Cash Flows from Operating Activities
2021
Year Ended December 31,
2020
(In millions)
2021 vs. 2020
$
2,302.9
$
1,744.5
$
558.4
The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs,
natural gas and other petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and
transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil (iii) changes in payables and
accruals related to major growth capital projects; and (iv) the payment of other expenses, primarily field operating costs, general and
administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price
risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements
on unsettled futures contracts.
The increase in net cash provided by operations was primarily due to higher commodity prices, resulting in higher collections from
customers, partially offset by an increase in payments for product purchases and fuel and hedge transactions.
66
Cash Flows from Investing Activities
2021
Year Ended December 31,
2020
(In millions)
2021 vs. 2020
$
(473.2 )
$
(738.1 )
$
264.9
The decrease in net cash used in investing activities was primarily due to lower outlays for property, plant and equipment of $446.5
million, resulting from the completion of Trains 7 and 8, the LPG export expansion, the Grand Prix Central Oklahoma extension, and
the Gateway and Peregrine plants and associated infrastructure in the Permian Basin in 2020, partially offset by higher proceeds from
the sale of business and assets of $186.5 million, including from the sale of our Delaware crude system in 2020.
Cash Flows from Financing Activities
Source of Financing Activities, net
Debt, including financing costs
Contributions from (distributions to) noncontrolling interests
Dividends and distributions
Redemption of Preferred Units
Partial repurchase of Series A Preferred Stock
Other
Net cash provided by (used in) financing activities
$
$
Year Ended December 31,
2021
2020
(In millions)
(1,189.1 ) $
(484.2 )
(187.5 )
—
—
(53.2 )
(1,914.0 ) $
(32.9 )
(397.7 )
(395.9 )
(125.0 )
(45.8 )
(97.4 )
(1,094.7 )
The increase in net cash used in financing activities was primarily due to higher repayments of debt and higher distributions to
noncontrolling interests in 2021, partially offset by lower dividends and distributions paid in 2021 and redemption of Preferred Units
and partial repurchase of Preferred Stock in 2020.
Common Stock Dividends
The following table details the dividends declared and/or paid by us to common shareholders for 2021:
Three Months Ended
Date Paid or
To Be Paid
Total Common
Dividends Declared
Amount of
Common
Dividends Paid or
To Be Paid
Accrued
Dividends (1)
Dividends Declared
per Share of
Common Stock
December 31, 2021
September 30, 2021
June 30, 2021
March 31, 2021
(In millions, except per share amounts)
$
February 15, 2022
November 15, 2021
August 16, 2021
May 14, 2021
81.4 $
23.3
23.3
23.3
80.1 $
22.9
22.9
22.9
1.3 $
0.4
0.4
0.4
0.35000
0.10000
0.10000
0.10000
(1)
Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
Preferred Dividends
Our Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly
45 days after the end of each fiscal quarter.
Cash dividends of $87.3 million were paid to holders of the Series A Preferred during the year ended December 31, 2021. As of
December 31, 2021, cash dividends accrued for our Series A Preferred were $21.8 million, which were paid on February 14, 2022.
67
Capital Expenditures
The following table details cash outlays for capital projects for the years ended December 31, 2021 and 2020:
Capital expenditures:
Growth (1)
Maintenance (2)
Gross capital expenditures
Transfers from materials and supplies inventory to property, plant and equipment
Change in capital project payables and accruals, net
Cash outlays for capital projects
Year Ended December 31,
2021
2020
(In millions)
$
$
421.9 $
138.6
560.5
(2.4 )
(53.0 )
505.1 $
617.3
109.5
726.8
(2.1 )
226.9
951.6
(1)
Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were
$407.7 million and $597.9 million for the years ended December 31, 2021 and 2020.
(2) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $131.7 million and $104.2 million for the years ended December 31,
2021 and 2020.
The decrease in total growth capital expenditures was primarily due to lower spending on growth capital investments in 2021, as a
significant portion of our major projects began full service in 2020, including Trains 7 and 8, the LPG export expansion, the Grand
Prix Central Oklahoma extension, and the Gateway and Peregrine plants and associated infrastructure in the Permian Basin. The
increase in total maintenance capital expenditures was primarily due to system expansions.
We currently estimate that in 2022 we will invest between $700 to $800 million in net growth capital expenditures for announced
projects. Future growth capital expenditures may vary based on investment opportunities. We expect that 2022 maintenance capital
expenditures, net of noncontrolling interests, will be approximately $150 million.
Off-Balance Sheet Arrangements
As of December 31, 2021, there were $65.2 million in surety bonds outstanding related to various performance obligations. These are
in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and
(ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying
performance requirement.
We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to
these investments, as well as our obligations with respect to related letters of credit, see Note 7 – Investments in Unconsolidated
Affiliates and Note 8 – Debt Obligations.
Contractual Obligations
We believe we have sufficient liquidity to fund our operations and meet our short-term and long-term obligations. The following is a
summary of our material future contractual obligations:
Contractual Obligations:
Long-term debt obligations (1)
Interest on debt obligations (2)
Operating leases (3)
Finance leases (4)
Land site lease and rights of way (5)
Purchase obligations (6)
Other long-term liabilities (7)
Total
$
$
Total
Within 12 Months
(in millions)
$
6,465.7
2,457.4
51.6
27.9
237.3
1,477.0
112.2
10,829.1
$
—
359.3
13.3
13.1
4.5
645.0
11.8
1,047.0
(1) Represents scheduled future maturities of long-term debt obligation. See Note 8 - Debt Obligations for more information.
(2) Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2021 rates for floating debt. See Note 8 - Debt
Obligations for more information.
Includes minimum payments on operating lease obligations for office space and railcars. See Note 10 - Leases for more information.
Includes minimum payments on finance lease obligations for vehicles and tractors. See Note 10 - Leases for more information.
(3)
(4)
(5) Land site lease and rights of way provides 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 with varying terms, some of which are perpetual. See Note 18 - Commitments for more information.
Includes commitments for pipeline capacity payments for firm transportation and throughput and deficiency agreements, purchase of natural gas and NGLs,
capital expenditures, operating expenses and service contracts. Contracts that will be settled at future spot prices are valued using prices as of December 31, 2021.
(6)
68
(7)
Includes long-term liabilities of which we are certain of the amount and timing, including certain arrangements that resulted in deferred revenue and other
liabilities pertaining to accrued dividends. See Note 9 - Other Long-term Liabilities for more information.
Critical Accounting Policies and Estimates
The accounting 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.
Depreciation of Property, Plant and Equipment and Amortization of Intangible Assets
Depreciation of our property, plant and equipment is computed 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.
The determination of useful lives of property, plant and equipment requires us to make various assumptions, including our expected
use of the asset and the supply of and demand for hydrocarbons in the markets served, normal wear and tear of facilities, and the
extent and frequency of maintenance programs.
We amortize the costs of our intangible assets in a manner that closely resembles the expected benefit pattern of the intangible assets
or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided
to customers. At the time assets are placed in service or acquired, we believe such assumptions are reasonable; however,
circumstances may develop that would cause us to change these assumptions, which would change our depreciation/amortization
amounts prospectively.
Impairment of Long-Lived Assets, including Intangible Assets
We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our
carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment
of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected
future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows
are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and
assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other
factors.
If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment charge
equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value
techniques if quotes are unavailable. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair
value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections
reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and
long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and
the use of an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in
significant revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments.
Price Risk Management (Hedging)
Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. In an effort to
reduce the volatility of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated
with a portion of our expected natural gas, NGL, and condensate equity volumes, future commodity purchases and sales, and
transportation basis risk.
One of the factors that can affect our operating results each period is the price assumptions used to value our derivative financial
instruments, which are reflected at their fair values on the balance sheet. We determine the fair value of our derivative instruments
using present value methods or standard option valuation models with assumptions about commodity prices based on those observed
in underlying markets. Changes in the methods or assumptions we use to calculate the fair value of our derivative instruments could
have a material effect on our consolidated financial statements.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see Note 3 – Significant Accounting Policies in our
Consolidated Financial Statements.
69
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and
crude oil, changes in interest rates, as well as nonperformance by our risk management counterparties and customers.
Risk Management
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. All of our commodity derivatives are
with major financial institutions or major energy companies. Should any of these financial counterparties not perform, we may not
realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of
operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result
in losses.
Crude oil, NGL and natural gas prices are volatile. In an effort to reduce the variability of our cash flows, we have entered into
derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate
equity volumes, future commodity purchases and sales, and transportation basis risk through 2025. Market conditions may also impact
our ability to enter into future commodity derivative contracts.
Commodity Price Risk
A portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the
sale of commodities as payment for services. The prices of natural gas, NGLs and crude oil 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 our commodity risk management activities is to hedge some of the exposure to commodity price risk and
reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our
cash flows, as of December 31, 2021, we have hedged the commodity price associated with a portion of our expected (i) natural gas,
NGL, and condensate equity volumes in our Gathering and Processing segment that result from our percent-of-proceeds processing
arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas
transportation basis risk in our Logistics and Transportation segment. We hedge a higher percentage of our expected equity volumes in
the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. We also
enter into commodity financial instruments to help manage other short term commodity related business risks of our ongoing
operations and in conjunction with marketing opportunities available to us in the operations of our logistics and transportation assets.
With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities and we pay the hedge
counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers
substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to
effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than
our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We utilize
purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric
risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our
exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors),
futures or other derivative instruments as market conditions permit.
When entering into new hedges, we intend to 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 specific NGL products based upon the 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 fair value of our natural gas and NGL hedges are based on published index prices for
delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate
sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet
crude.
A majority of these commodity price hedges are 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. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure
due to a rise in commodity prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral
securing the New TRC Revolver that ranks equal in right of payment with liens granted in favor of Targa’s senior secured lenders. As
long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to
secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of
70
higher commodity prices or because there has been a change in our creditworthiness. Upon Targa achieving an investment grade
rating, the first priority lien securing such hedges may be terminated at our election. A purchased put (or floor) transaction does not
expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the
transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor
its obligation under the put transaction.
We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are
subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL or crude oil
prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.
These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us
protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at
which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges
(other than with respect to purchased calls).
To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the
change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does
not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement
impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a
corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivative instruments are also
influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.
The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of
December 31, 2021:
Natural gas
NGLs
Crude oil
Total
Fair Value
Result of 10% Price
Decrease
Result of 10% Price
Increase
$
$
(82.5 ) $
(187.4 )
(46.8 )
(316.7 ) $
(36.0 ) $
(114.6 )
(24.5 )
(175.1 ) $
(129.0 )
(260.2 )
(69.1 )
(458.3 )
The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk,
which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to
our gas transportation arrangements.
During the years ended December 31, 2021 and 2020, our operating revenues increased (decreased) by ($490.6) million and $296.9
million as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved
from a net liability position of ($51.2) million at December 31, 2020 to a net liability position of ($316.7) million at December 31,
2021. Forward commodity prices have increased relative to the fixed prices on our derivative contracts, creating this net liability
position.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the New TRC Revolver
and the Securitization Facility. As of December 31, 2021, we do not have any interest rate hedges. However, we may enter into
interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that
interest rates increase, interest expense for the New TRC Revolver and the Securitization Facility will also increase. As of
December 31, 2021, the Partnership had $150.0 million in outstanding variable rate borrowings under the Securitization Facility and
we had no borrowings under the Existing TRP Revolver and Existing TRC Revolver. A hypothetical change of 100 basis points in the
rate of our variable interest rate debt would impact the Partnership’s annual interest expense by $1.5 million and our consolidated
annual interest expense by $1.5 million based on our December 31, 2021 debt balances.
Counterparty Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to
commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts)
at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily.
Should the creditworthiness of one or more of the counterparties decline, our 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, we may sustain a loss and our cash receipts could be negatively impacted. We have
71
master netting provisions in the International Swap Dealers Association agreements with our derivative counterparties. These netting
provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity. As of
December 31, 2021, all our commodity derivative instruments were in a net liability position, and as such, we had no counterparty
credit risk exposure as of that date.
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 performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and
requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit,
prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and
financial loss is mitigated or minimized.
We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity
issues of counterparties. Our allowance for doubtful accounts was $0.1 million as of December 31, 2021 and December 31, 2020.
Changes in the allowance for doubtful accounts were not material for the year ended December 31, 2021.
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 in this Annual Report.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Management, 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, 2021, our disclosure
controls and procedures were effective to provide reasonable assurance 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 SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
(a) Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included on page F-2 of this Annual Report and is
incorporated herein by reference. Management concluded that our internal control over financial reporting was effective as of
December 31, 2021.
(b) Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during our most recent fiscal quarter ended
December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial
reporting.
Item 9B. Other Information.
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
None.
72
Item 10. Directors, Executive Officers and Corporate Governance.
PART III
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of
stockholders and is incorporated herein by reference.
Item 11. Executive Compensation
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of
stockholders and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of
stockholders and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of
stockholders and is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of
stockholders and is incorporated herein by reference.
73
Item 15. Exhibits, 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 Consolidated Financial Statements” on Page F-1 in this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in
the consolidated financial statements or notes thereto.
(a)(3) Exhibits
Number
Description
3.1
3.2
3.3
3.4
3.5
4.1
4.2
4.3
4.4
4.5
4.6
4.7
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)).
Certificate of Amendment to the 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 May 26,
2021 (File No. 001-34991)).
Certificate of Designations of Series A Preferred Stock of Targa Resources Corp., filed with the Secretary of State
of the State of Delaware on March 16, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s
Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).
Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.2 to Targa
Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).
First Amendment to the 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 January 15, 2016 (File No. 001-34991)).
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)).
Registration Rights Agreement, dated March 16, 2016, by and among Targa Resources Corp. and the purchasers
named on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Current Report
on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).
Amendment No. 1 to the Registration Rights Agreement dated March 16, 2016, dated September 13, 2016, among
Targa Resources Corp. and Stonepeak Target Holdings, LP and Stonepeak Target Upper Holdings LLC
(incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed
November 4, 2016 (File No. 001-34991)).
Registration Rights Agreement, dated March 16, 2016, by and among Targa Resources Corp. and the purchasers
named on Schedule A thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s Current Report
on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).
Amendment No. 1 to the Registration Rights Agreement dated March 16, 2016, dated September 13, 2016, among
Targa Resources Corp. and Stonepeak Target Holdings, LP and Stonepeak Target Upper Holdings LLC
(incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed
November 4, 2016 (File No. 001-34991)).
Board Representation and Observation Rights Agreement, dated as of March 16, 2016, by and between Targa
Resources Corp. and Stonepeak Target Holdings LP (incorporated by reference to Exhibit 4.3 to Targa Resources
Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).
Warrant Agreement, dated as of March 16, 2016, by and among Targa Resources Corp., Computershare Inc. and
Computershare Trust Company, N.A. (incorporated by reference to Exhibit 4.4 to Targa Resources Corp.’s Current
Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).
74
4.8
10.1
10.2
10.3
10.4
10.5+
10.6+
10.7+
10.8+
10.9+
10.10+
10.11+
Description of Securities Registered Under Section 12 of the Exchange Act (incorporated by reference to Exhibit 4.8
to Targa Resources Corp.’s Annual Report on Form 10-K filed February 20, 2020 (File No. 001-34991)).
Third Amendment and Restatement Agreement dated as of June 29, 2018, by and among Targa Resources Partners
LP, Bank of America, N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to
Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed July 3, 2018).
First Amendment to Fourth Amended and Restated Credit Agreement, dated as of June 7, 2019, by and among
Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto (incorporated by
reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed June 11, 2019 (File
No. 001-33303)).
Credit Agreement, dated as of February 27, 2015, among Targa Resources Corp., each lender from time to time
party thereto and Bank of America, N.A. as administrative agent, collateral agent, swing line lender and letter of
credit issuer (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K
filed March 4, 2015 (File No. 001-34991)).
First Amendment to Credit Agreement dated as of June 29, 2018, by and among Targa Resources Corp., Bank of
America, N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources
Corp.’s Current Report on Form 8-K filed July 3, 2018 (File No. 001-34991)).
Amended and Restated Targa Resources Corp. 2010 Stock Incentive Plan, as amended and restated effective May
22, 2017 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed
May 23, 2017 (File No. 001-34991)).
Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s
Current Report on Form 8-K filed July 18, 2013 (File No. 001-34991)).
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Current
Report on Form 8-K filed July 18, 2013 (File No. 001-34991)).
Form of Restricted Stock Agreement for Directors, dated as of January 17, 2018 (incorporated by reference to
Exhibit 10.13 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-
34991)).
Form of Restricted Stock Agreement under Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by
reference to Exhibit 10.3 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016 (File No.
001-34991)).
Form of Performance Share Unit Grant Agreement, dated as of January 17, 2019 under Targa Resources Corp. 2010
Stock Incentive Plan (incorporated by reference to Exhibit 10.19 to Targa Resources Corp.’s Annual Report on
Form 10-K filed March 1, 2019 (File No. 001-34991).
Form of Performance Share Unit Grant Agreement, dated as of January 16, 2020 under Targa Resources Corp. 2010
Stock Incentive Plan (incorporated by reference to Exhibit 10.12 to Targa Resources Corp.’s Annual Report on
Form 10-K filed February 20, 2020 (File No. 001-34991)).
10.12+*
Form of Performance Share Unit Grant Agreement, dated as of January 20, 2022 under Targa Resources Corp. 2010
Stock Incentive Plan.
10.13+*
Omnibus Amendment to Performance Share Unit Grant Agreements, dated as of December 15, 2021.
10.14+
10.15+
10.16+
10.17+
Form of Restricted Stock Unit Agreement (Bonus Grant), dated as of January 16, 2020 under Targa Resources Corp.
2010 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 to Targa Resources Corp.’s Annual Report on
Form 10-K filed February 20, 2020 (File No. 001-34991)).
Form of Restricted Stock Unit Agreement, dated as of January 16, 2020 under Targa Resources Corp. 2010 Stock
Incentive Plan (incorporated by reference to Exhibit 10.14 to Targa Resources Corp.’s Annual Report on Form 10-K
filed February 20, 2020 (File No. 001-34991)).
Targa Resources Corp. 2020 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to
Targa Resources Corp.’s Current Report on Form 8-K filed January 23, 2020 (File No. 001-34991)).
First Amendment to the Targa Resources Corp. Amended and Restated Stock Incentive Plan (incorporated by
reference to Exhibit 10.16 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 18, 2021 (File
No. 001-34991)).
75
10.18+
10.19+
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
Targa Resources Executive Officer Change in Control Severance Program (incorporated by reference to Exhibit
10.3 to Targa Resources Corp.’s Current Report on Form 8-K filed January 19, 2012 (File No. 001-34991)).
First Amendment to the Targa Resources Executive Officer Change in Control Severance Program, dated December
3, 2015 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed
December 8, 2015 (File No. 001-34991)).
Indenture dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance
Corporation and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit
10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-34991)).
Registration Rights Agreement dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources
Partners Finance Corporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several
initial purchasers party thereto (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Current Report
on Form 8-K filed October 12, 2016 (File No. 001-34991)).
Supplemental Indenture dated March 10, 2017 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, 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 4, 2017 (File No. 001-33303)).
Supplemental Indenture dated June 16, 2017 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.7 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-34991)).
Supplemental Indenture dated December 18, 2017 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.61 to Targa Resources
Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-34991)).
Supplemental Indenture dated January 9, 2018 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.62 to Targa Resources
Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-34991)).
Supplemental Indenture dated July 24, 2018 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.8 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)).
Supplemental Indenture dated July 19, 2019 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.5 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)).
Supplemental Indenture dated February 20, 2020 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.4 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed May 7, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2020 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.5 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 5, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2021 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.1 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 4, 2021 (File No. 001-34991)).
10.31*
Supplemental Indenture dated November 30, 2021 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
76
10.32*
Supplemental Indenture dated January 28, 2022 to Indenture dated October 6, 2016, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
10.33
10.34
10.35
10.36
10.37
10.38
10.39
10.40
10.41
10.42*
10.43*
10.44
10.45
Indenture dated as of October 17, 2017 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
(File No. 001-33303) filed October 17, 2017).
Registration Rights Agreement dated as of October 17, 2017 among the Issuers, the Guarantors and Citigroup
Global Markets Inc., as representative of the several Initial Purchasers party thereto (incorporated by reference to
Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed October 17,
2017).
Supplemental Indenture dated December 18, 2017 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.66 to Targa Resources
Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-34991)).
Supplemental Indenture dated January 9, 2018 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.67 to Targa Resources
Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-34991)).
Supplemental Indenture dated July 24, 2018 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.9 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)).
Supplemental Indenture dated July 19, 2019 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.6 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)).
Supplemental Indenture dated February 20, 2020 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.5 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed May 7, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2020 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.6 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 5, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2021 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.2 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 4, 2021 (File No. 001-34991)).
Supplemental Indenture dated November 30, 2021 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Supplemental Indenture dated January 28, 2022 to Indenture dated October 17, 2017, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Indenture dated as of April 12, 2018 among the Issuers, 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 (File
No. 001-33303) filed April 16, 2018).
Registration Rights Agreement dated as of April 12, 2018 among the Issuers, the Guarantors and Merrill Lynch,
Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated
by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303)
filed April 16, 2018).
77
10.46
10.47
10.48
10.49
10.50
10.51*
10.52*
10.53
10.54
10.55
10.56
10.57
10.58
Supplemental Indenture dated July 24, 2018 to Indenture dated April 12, 2018, among the Guaranteeing Subsidiary,
Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and
U.S. Bank National Association (incorporated by reference to Exhibit 10.10 to Targa Resources Corp.’s Quarterly
Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)).
Supplemental Indenture dated July 19, 2019 to Indenture dated April 12, 2018, among the Guaranteeing Subsidiary,
Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and
U.S. Bank National Association (incorporated by reference to Exhibit 10.7 to Targa Resources Corp.’s Quarterly
Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)).
Supplemental Indenture dated February 20, 2020 to Indenture dated April 12, 2018, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.6 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed May 7, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2020 to Indenture dated April 12, 2018, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.7 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 5, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2021 to Indenture dated April 12, 2018, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.3 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 4, 2021 (File No. 001-34991)).
Supplemental Indenture dated November 30, 2021 to Indenture dated April 12, 2018, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Supplemental Indenture dated January 28, 2022 to Indenture dated April 12, 2018, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Indenture dated as of January 17, 2019 among the Issuers, 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 (File
No. 001-33303) filed January 23, 2019).
Registration Rights Agreement dated as of January 17, 2019 among the Issuers, the Guarantors and Merrill Lynch,
Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated
by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303)
filed January 23, 2019).
Registration Rights Agreement dated as of January 17, 2019 among the Issuers, the Guarantors and Merrill Lynch,
Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated
by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303)
filed January 23, 2019).
Supplemental Indenture dated July 19, 2019 to Indenture dated January 17, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.8 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)).
Supplemental Indenture dated February 20, 2020 to Indenture dated January 17, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.7 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed May 7, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2020 to Indenture dated January 17, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.8 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 5, 2020 (File No. 001-34991)).
78
10.59
10.60*
10.61*
10.62
10.63
10.64
10.65
10.66
10.67*
10.68*
10.69
10.70
10.71
10.72
Supplemental Indenture dated September 17, 2021 to Indenture dated January 17, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.4 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 4, 2021 (File No. 001-34991)).
Supplemental Indenture dated November 30, 2021 to Indenture dated January 17, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Supplemental Indenture dated January 28, 2022 to Indenture dated January 17, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Indenture dated as of November 27, 2019 among the Issuers, 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 (File
No. 001-33303) filed December 3, 2019).
Registration Rights Agreement dated as of November 27, 2019 among the Issuers, the Guarantors and RBC Capital
Markets, LLC, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit
to 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed December 3, 2019.
Supplemental Indenture dated February 20, 2020 to Indenture dated November 27, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.8 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed May 7, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2020 to Indenture dated November 27, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.9 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 5, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2021 to Indenture dated November 27, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.5 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 4, 2021 (File No. 001-34991)).
Supplemental Indenture dated November 30, 2021 to Indenture dated November 27, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Supplemental Indenture dated January 28, 2022 to Indenture dated November 27, 2019, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Indenture dated as of August 18, 2020 among the Issuers, 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 (File
No. 001-33303) filed August 21, 2020).
Registration Rights Agreement dated as of August 18, 2020 among the Issuers, the Guarantors and Wells Fargo
Securities, LLC, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit
4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed August 21, 2020).
Supplemental Indenture dated September 17, 2020 to Indenture dated August 18, 2020, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.10 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 5, 2020 (File No. 001-34991)).
Supplemental Indenture dated September 17, 2021 to Indenture dated August 18, 2020, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.6 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 4, 2021 (File No. 001-34991)).
10.73*
Supplemental Indenture dated November 30, 2021 to Indenture dated August 18, 2020, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
79
10.74*
Supplemental Indenture dated January 28, 2022 to Indenture dated August 18, 2020, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
10.75
10.76
10.77
10.78
10.79*
10.80*
10.81+
10.82+
10.83+
10.84+
10.85+
10.86+
10.87+
10.88+
10.89+
Purchase Agreement dated as of January 19, 2021, among the Issuers, the Guarantors and BofA Securities, Inc. as
representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources
Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed January 22, 2021).
Indenture dated as of February 2, 2021 among the Issuers, 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 (File
No. 001-3303) filed February 5, 2021).
Registration Rights Agreement dated as of February 2, 2021 among the Issuers, the Guarantors and BofA Securities,
Inc., as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to
Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-3303) filed February 5, 2021).
Supplemental Indenture dated September 17, 2021 to Indenture dated February 2, 2021 among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.7 to Targa Resources
Corp.’s Quarterly Report on Form 10-Q filed November 4, 2021 (File No. 001-34991)).
Supplemental Indenture dated November 30, 2021 to Indenture dated February 2, 2021, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
Supplemental Indenture dated January 28, 2022 to Indenture dated February 2, 2021, among the Guaranteeing
Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary
Guarantors and U.S. Bank National Association.
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)).
Targa Resources Partners LP Indemnification Agreement for Robert B. Evans 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)).
Indemnification Agreement by and between Targa Resources Corp. and Laura C. Fulton, dated February 26, 2013
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 1,
2013 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Waters S. Davis, IV, dated July 23, 2015
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 24,
2015 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and D. Scott Pryor, dated November 12, 2015
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed November
16, 2015 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Patrick J. McDonie, dated November 12,
2015 (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Current Report on Form 8-K filed
November 16, 2015 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Clark White, dated November 12, 2015
(incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Current Report on Form 8-K filed November
16, 2015 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Robert B. Evans, dated March 1, 2016
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 7,
2016 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Robert Muraro, dated February 22, 2017
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February
27, 2017 (File No. 001-34991)).
80
10.90+
10.91+
10.92+
10.93
10.94
10.95
10.96
10.97
10.98
10.99
10.100
10.101
Indemnification Agreement by and between Targa Resources Corp. and Beth A. Bowman, dated September 7, 2018
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed September
11, 2018 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Julie Boushka, dated February 22, 2017
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 5,
2019 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Jennifer Kneale, dated July 1, 2016
(incorporated by reference to Exhibit 10.90 to Targa Resources Corp.’s Annual Report on Form 10-K filed February
20, 2020 (File No. 001-34991)).
Indemnification Agreement by and between Targa Resources Corp. and Lindsey M. Cooksen, dated June 1, 2020
(incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed June 3,
2020 (File No. 001-34991)).
Amended and Restated Registration Rights Agreement dated as of October 31, 2005 (incorporated by reference to
Exhibit 10.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No.
333-169277)).
Receivables Purchase Agreement, dated January 10, 2013, by and among Targa Receivables LLC, the Partnership,
as initial Servicer, the various conduit purchasers from time to time party thereto, the various committed purchasers
from time to time party thereto, the various purchaser agents from time to time party thereto, the various LC
participants from time to time party thereto and PNC Bank, National Association as Administrator and LC Bank
(incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed
January 14, 2013 (File No. 001-33303)).
Purchase and Sale Agreement, dated January 10, 2013, between the originators from time to time party thereto as
Originators and Targa Receivables LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s
Current Report on Form 8-K filed January 14, 2013 (File No. 001-33303)).
Second Amendment to Receivables Purchase Agreement, dated December 13, 2013, by and among Targa
Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers,
purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC
Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed
December 17, 2013 (File No. 001-33303)).
Fourth Amendment to Receivables Purchase Agreement, dated December 11, 2015, by and among Targa
Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers,
purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC
Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed
December 15, 2015 (File No. 001-33303)).
Fifth Amendment to Receivables Purchase Agreement, dated December 9, 2016, by and among Targa Receivables
LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents
and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated
by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 6, 2017
(File No. 001-33303)).
Seventh Amendment to Receivables Purchase Agreement, dated December 7, 2018, by and among Targa
Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers,
purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC
Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed
December 10, 2018 (File No. 001-33303)).
Eighth Amendment to Receivables Purchase Agreement, dated December 6, 2019, by and among Targa Receivables
LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents
and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated
by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 10, 2019 (File
No. 001-34991)).
81
10.102
10.103
10.104*
10.105
10.106
Ninth Amendment to Receivables Purchase Agreement, dated April 22, 2020, by and among Targa Receivables
LLC, as seller, Targa Resources Partners LP, as servicer, the various conduit purchasers, committed purchasers,
purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC
Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed April
24, 2020 (File No. 001-34991)).
Tenth Amendment to Receivables Purchase Agreement, dated April 21, 2021, by and among Targa Receivables
LLC, as seller, Targa Resources Partners LP, as servicer, the various conduit purchasers, committed purchasers,
purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC
Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed April
23, 2021 (File No. 001-34991)).
Eleventh Amendment to Receivables Purchase Agreement, dated December 13, 2021, by and among Targa
Receivables LLC, as seller, Targa Resources Partners LP, as servicer, the various conduit purchasers, committed
purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as
administrator and LC Bank.
Commitment Increase Request, dated February 23, 2017, by and among Targa Receivables LLC, as seller, the
Partnership, as servicer, and PNC Bank, National Association, as administrator, purchaser agent and LC Bank
(incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed
February 24, 2017 (File No. 001-33303)).
Commitment Increase Request, dated December 11, 2020, by and among Targa Receivables LLC, as seller, the
Partnership, as servicer, and PNC Bank, National Association, as administrator, purchaser agent and LC Bank, and
Wells Fargo Bank, National Association, as purchaser agent and LC Participant (incorporated by reference to
Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 14, 2020 (File No. 001-
34991)).
21.1*
List of Subsidiaries of Targa Resources Corp.
23.1*
Consent of Independent Registered Public Accounting Firm.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of
1934.
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of
1934.
32.1**
32.2**
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.
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.
101.INS*
Inline XBRL Instance Document
101.SCH*
Inline XBRL Taxonomy Extension Schema Document
101.CAL*
Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
Inline XBRL Taxonomy Extension Presentation Linkbase Document
104
Cover Page Interactive Data File (embedded within the Inline XBRL document).
Filed herewith
Furnished herewith
*
**
+ Management contract or compensatory plan or arrangement
Item 16. Form 10-K Summary
None.
82
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
Date: February 24, 2022
Targa Resources Corp.
(Registrant)
By: /s/ Jennifer R. Kneale
Jennifer R. Kneale
Chief Financial Officer
(Principal Financial Officer)
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 24, 2022.
Signature
/s/ Matthew J. Meloy
Matthew J. Meloy
/s/ Jennifer R. Kneale
Jennifer R. Kneale
/s/ Julie H. Boushka
Julie H. Boushka
/s/ Paul W. Chung
Paul W. Chung
/s/ Beth A. Bowman
Beth A. Bowman
/s/ Lindsey M. Cooksen
Lindsey M. Cooksen
/s/ Charles R. Crisp
Charles R. Crisp
/s/ Waters S. Davis, IV
Waters S. Davis, IV
/s/ Robert B. Evans
Robert B. Evans.
/s/ Laura C. Fulton
Laura C. Fulton
/s/ Rene R. Joyce
Rene R. Joyce
/s/ Joe Bob Perkins
Joe Bob Perkins
/s/ Ershel C. Redd Jr.
Ershel C. Redd Jr.
/s/ Chris Tong
Chris Tong
Title (Position with Targa Resources Corp.)
Chief Executive Officer and Director
(Principal Executive Officer)
Chief Financial Officer
(Principal Financial Officer)
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
Chairman of the Board and Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
83
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 (PCAOB ID: 238)
Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020, and 2019
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the Years Ended December 31,
2021, 2020 and 2019
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019
Notes to Consolidated Financial Statements
Note 1 ― Organization and Operations
Note 2 ― Basis of Presentation
Note 3 ― Significant Accounting Policies
Note 4 ― Joint Ventures and Divestitures
Note 5 ― Property, Plant and Equipment and Intangible Assets
Note 6 ― Goodwill
Note 7 ― Investment in Unconsolidated Affiliates
Note 8 ― Debt Obligations
Note 9 ― Other Long-term Liabilities
Note 10 ― Leases
Note 11 ― Preferred Stock
Note 12 ― Common Stock and Related Matters
Note 13 ― Partnership Units and Related Matters
Note 14 ― Earnings Per Common Share
Note 15 ― Derivative Instruments and Hedging Activities
Note 16 ― Fair Value Measurements
Note 17 ― Related Party Transactions
Note 18 ― Commitments
Note 19 ― Contingencies
Note 20 ― Revenue
Note 21 ― Other Operating (Income) Expense
Note 22 ― Income Taxes
Note 23 ― Supplemental Cash Flow Information
Note 24 ― Compensation Plans
Note 25 ― Segment Information
Note 26 ― Condensed Parent Only Financial Statements
F-1
F-2
F-3
F-5
F-6
F-7
F-8
F-10
F-11
F-11
F-11
F-11
F-18
F-21
F-23
F-24
F-25
F-31
F-32
F-33
F-34
F-35
F-36
F-36
F-39
F-41
F-42
F-42
F-42
F-43
F-43
F-45
F-45
F-48
F-50
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”) in 2013 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, 2021.
The effectiveness of our
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-3.
internal control over financial reporting as of December 31, 2021 has been audited by
/s/ Matthew J. Meloy
Matthew J. Meloy
Chief Executive Officer
(Principal Executive Officer)
/s/ Jennifer R. Kneale
Jennifer R. Kneale
Chief Financial Officer
(Principal Financial Officer)
F-2
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Targa Resources Corp.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Targa Resources Corp. and its subsidiaries (the “Company”) as of
December 31, 2021 and 2020, and the related consolidated statements of operations, of comprehensive income (loss), of changes in
owners' equity and Series A preferred stock and of cash flows for each of the three years in the period ended December 31, 2021,
including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's
internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of
the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in
our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,
2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over
financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the
Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We
are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules
and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to
error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well
as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable
basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect
on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
F-3
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements
that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are
material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a
whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or
on the accounts or disclosures to which it relates.
Impairment Assessment of Certain Gas Processing Facilities and Gathering Systems associated with the Central Operations in the
Gathering and Processing Segment
As described in Notes 3 and 5 to the consolidated financial statements, the Company’s consolidated property, plant and equipment,
net and intangible assets, net balances were $11,667.7 million and $1,094.8 million, respectively, as of December 31, 2021.
Management reviews and evaluates long-lived assets, including intangible assets, for impairment when events or changes in
circumstances indicate that the carrying amount of an asset may not be recoverable. Asset recoverability is measured by comparing the
carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. If the carrying amount exceeds the
expected future undiscounted cash flows, management recognizes a non-cash pre-tax impairment loss equal to the excess of net book
value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable.
The estimated cash flows used to assess recoverability of the Company’s long-lived assets and measure fair value of the asset groups
are derived from current business plans, which are developed using near-term price and volume projections reflective of the current
environment and management's projections for long-term average prices and volumes. In addition to near and long-term price
assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an
appropriate terminal value and discount rate. In the fourth quarter of 2021, due to lower expectations regarding volumes and rates in
the South Texas region, the Company recorded a non-cash pre-tax impairment of $452.3 million for the partial impairment of certain
gas processing facilities and gathering systems associated with the Central Operations in the Gathering and Processing Segment.
The principal considerations for our determination that performing procedures relating to the impairment assessment of certain gas
processing facilities and gathering systems associated with the Central Operations in the Gathering and Processing segment is a
critical audit matter are (i) the significant judgment by management when developing the estimated cash flows and subsequent
estimated fair value determination by applying a discount rate; (ii) the high degree of auditor judgment, subjectivity and effort in
performing procedures and evaluating management’s significant assumptions related to the future natural gas production volumes,
price assumptions, and discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion
on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the assessment of
property, plant and equipment, net and intangible assets, net for impairment, including controls over management’s development of
assumptions used in the estimated cash flows and the estimated fair value. Our procedures also included, among others (i) testing
management’s process for developing the estimated cash flows and estimating fair value; (ii) evaluating the appropriateness of the
estimated cash flow model; (iii) testing the completeness and accuracy of data used in the model, and (iv) evaluating the significant
assumptions used by management related to the future natural gas production volumes, price assumptions, and discount rate.
Evaluating management’s assumptions related to future natural gas production volumes and price assumptions involved evaluating
whether the assumptions used by management were reasonable considering the current and past performance of the asset group and
whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and
knowledge were used to assist in evaluating the appropriateness of the model and the reasonableness of the discount rate assumption.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 24, 2022
We have served as the Company’s auditor since 2005.
F-4
Item 1. Financial Statements.
PART I – FINANCIAL INFORMATION
TARGA RESOURCES CORP.
CONSOLIDATED BALANCE SHEETS
December 31, 2021
December 31, 2020
(In millions)
Current assets:
Cash and cash equivalents
Trade receivables, net of allowances of $0.1 million and $0.1 million at December 31, 2021 and December 31,
2020
Inventories
Assets from risk management activities
Other current assets
$
ASSETS
Total current assets
Property, plant and equipment, net
Intangible assets, net
Long-term assets from risk management activities
Investments in unconsolidated affiliates
Other long-term assets
Total assets
$
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Accounts payable
Accrued liabilities
Distributions payable
Interest payable
Liabilities from risk management activities
Current debt obligations
Total current liabilities
$
Long-term debt
Long-term liabilities from risk management activities
Deferred income taxes, net
Other long-term liabilities
Contingencies (see Note 19)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, 919,300 shares
issued and outstanding as of December 31, 2021 and 2020), net of discount (see Note 11)
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 450,000,000 shares authorized as of December 31, 2021 and 300,000,000
shares authorized as of December 31, 2020)
Issued Outstanding
December 31, 2021 236,105,293 228,221,122
December 31, 2020 234,792,888 228,061,853
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized,
no shares issued and outstanding)
Additional paid-in capital
Retained earnings (deficit)
Accumulated other comprehensive income (loss)
Treasury stock, at cost (7,884,171 shares as of December 31, 2021 and 6,731,035 shares as of December 31,
2020)
Total Targa Resources Corp. stockholders' equity
Noncontrolling interests
Total owners' equity
Total liabilities, Series A Preferred Stock and owners' equity
$
See notes to consolidated financial statements.
158.5 $
242.8
1,331.9
153.4
43.1
82.9
1,769.8
11,667.7
1,094.8
7.7
586.5
81.7
15,208.2 $
1,402.3 $
272.2
64.5
138.5
258.2
162.8
2,298.5
6,434.4
109.3
136.0
301.6
862.8
181.5
85.5
87.7
1,460.3
12,173.6
1,382.4
49.3
714.0
96.1
15,875.7
833.8
186.4
115.4
132.6
142.6
368.6
1,779.4
7,387.1
43.4
152.1
309.1
749.7
301.4
0.2
0.2
—
4,268.9
(1,822.3 )
(230.9 )
(204.1 )
2,011.8
3,166.9
5,178.7
15,208.2 $
—
4,839.9
(1,893.5 )
(141.8 )
(150.9 )
2,653.9
3,249.3
5,903.2
15,875.7
F-5
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
2021
Year Ended December 31,
2020
(In millions, except per share amounts)
2019
Revenues:
Sales of commodities
Fees from midstream services
Total revenues
Costs and expenses:
Product purchases and fuel
Operating expenses
Depreciation and amortization expense
General and administrative expense
Impairment of long-lived assets
Other operating (income) expense
Income (loss) from operations
Other income (expense):
Interest expense, net
Equity earnings (loss)
Gain (loss) from financing activities
Gain (loss) from sale of equity-method investment
Change in contingent considerations
Other, net
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Less: Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to Targa Resources Corp.
Dividends on Series A Preferred Stock
Deemed dividends on Series A Preferred Stock
Net income (loss) attributable to common shareholders
Net income (loss) per common share - basic
Net income (loss) per common share - diluted
Weighted average shares outstanding - basic
Weighted average shares outstanding - diluted
$
$
$
$
15,602.5 $
1,347.3
16,949.8
13,729.5
747.0
870.6
273.2
452.3
12.4
864.8
(387.9 )
(23.9 )
(16.6 )
—
(0.1 )
0.6
436.9
(14.8 )
422.1
350.9
71.2
87.3
—
(16.1 ) $
(0.07 ) $
(0.07 ) $
228.6
228.6
7,171.0 $
1,089.3
8,260.3
5,186.5
698.4
865.1
254.6
2,442.8
116.6
(1,303.7 )
(391.3 )
72.6
45.6
—
0.3
3.4
(1,573.1 )
248.1
(1,325.0 )
228.9
(1,553.9 )
91.7
39.2
(1,684.8 ) $
(7.26 ) $
(7.26 ) $
232.2
232.2
7,393.8
1,277.3
8,671.1
6,208.0
703.4
971.6
280.7
225.3
89.2
192.9
(337.8 )
39.0
(1.4 )
69.3
(8.7 )
—
(46.7 )
87.9
41.2
250.4
(209.2 )
91.7
33.1
(334.0 )
(1.44 )
(1.44 )
232.5
232.5
See notes to consolidated financial statements.
F-6
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Year Ended December 31,
2021
Related
Income
Tax
After
Tax
Pre-Tax
2020
Related
Income
Tax
(In millions)
Pre-Tax
After
Tax
Pre-Tax
2019
Related
Income
Tax
After
Tax
$ 422.1
$ (1,325.0 )
$
41.2
Net income (loss)
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value
$ (534.6 ) $ 128.4
(406.2 ) $ (218.3 ) $
51.5
23.3
74.8
(166.8 ) $ 135.6 $
(67.5 )
(234.3 )
(1,559.3 )
(138.0 )
(2.4 )
228.9
$ (1,788.2 )
(32.3 )
103.3
32.9
(105.1 )
0.6
(1.8 )
39.4
250.4
$ (211.0 )
Settlements reclassified to revenues
417.3
(100.2 )
317.1
(90.8 )
Other comprehensive income (loss)
(117.3 )
28.2
(89.1 )
(309.1 )
Comprehensive income (loss)
Less: Comprehensive income (loss) attributable
to noncontrolling interests
Comprehensive income (loss) attributable to
Targa Resources Corp.
333.0
350.9
$
(17.9 )
See notes to consolidated financial statements.
F-7
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK
Common Stock
Shares
Amount
Additional
Paid in
Capital
Retained
Earnings
(Accumulated
Deficit)
Accumulated
Other
Comprehensive
Income (Loss)
Treasury
Shares
Shares
Amount
Total
Noncontrolling
Interests
Owner's
Equity
Series A
Preferred
Stock
(In millions, except shares in thousands)
Balance, December 31, 2018
Compensation on equity grants
Distribution equivalent rights
Shares issued under compensation program
Shares and units tendered for tax withholding obligations
Series A Preferred Stock dividends
Dividends - $95.00 per share
Dividends in excess of retained earnings
Deemed dividends - accretion of beneficial conversion
feature
Common stock dividends
Dividends - $3.64 per share
Dividends in excess of retained earnings
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Sale of ownership interests in subsidiaries, net
Other comprehensive income (loss)
Net income (loss)
Balance, December 31, 2019
Compensation on equity grants
Distribution equivalent rights
Shares issued under compensation program
Shares and units tendered for tax withholding obligations
Repurchases of common stock
Series A Preferred Stock dividends
Dividends - $95.00 per share
Dividends in excess of retained earnings
Deemed dividends - accretion of beneficial conversion
feature / partial repurchase of Series A Preferred Stock
Common stock dividends
Dividends - $1.21 per share
Dividends in excess of retained earnings
Partial repurchase of Series A Preferred Stock
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Non-cash allocation to noncontrolling interests
Other comprehensive income (loss)
Net income (loss)
Balance, December 31, 2020
$
231,791
—
—
1,397
(344 )
—
—
—
—
—
—
—
—
—
—
232,844
—
—
939
(235 )
(5,486 )
—
—
—
—
—
—
—
—
—
—
—
228,062
$
0.2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
0.2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
0.2
$
$
6,154.9
60.3
(14.2 )
—
—
—
(91.7 )
(33.1 )
—
(846.8 )
—
—
(8.2 )
—
—
5,221.2
66.2
(5.4 )
—
—
—
—
(91.7 )
(39.2 )
—
(282.0 )
(29.2 )
—
—
—
—
—
4,839.9
$
$
(130.4 )
—
—
—
—
(91.7 )
91.7
—
(846.8 )
846.8
—
—
—
—
(209.2 )
(339.6 )
—
—
—
—
—
(91.7 )
91.7
—
(282.0 )
282.0
—
—
—
—
—
(1,553.9 )
(1,893.5 )
$
$
94.3
—
—
—
—
—
—
—
—
—
—
—
—
(1.8 )
—
92.5
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(234.3 )
—
(141.8 )
666
—
—
—
344
—
—
—
—
—
—
—
—
—
—
1,010
—
—
—
235
5,486
—
—
—
—
—
—
—
—
—
—
—
6,731
See notes to consolidated financial statements.
F-8
$
(39.6 )
—
—
—
(13.9 )
—
—
—
—
—
—
—
—
—
—
(53.5 )
—
—
—
(5.9 )
(91.5 )
—
—
—
—
—
—
—
—
—
—
—
(150.9 )
$
$
$
$
1,391.4
—
—
—
—
7,470.8
60.3
(14.2 )
—
(13.9 )
(91.7 )
—
(33.1 )
(846.8 )
—
(294.7 )
555.3
1,611.5
(1.8 )
41.2
8,442.9
66.2
(5.4 )
—
(5.9 )
(91.5 )
(91.7 )
—
(39.2 )
(282.0 )
—
(29.2 )
(570.7 )
41.5
27.5
(234.3 )
(1,325.0 )
5,903.2
$
$
245.7
—
—
—
—
—
—
33.1
—
—
—
—
—
—
—
278.8
—
—
—
—
—
—
—
37.6
—
—
(15.0 )
—
—
—
—
—
301.4
—
—
—
—
—
(294.7 )
555.3
1,619.7
—
250.4
3,522.1
—
—
—
—
—
—
—
—
—
—
—
(570.7 )
41.5
27.5
—
228.9
3,249.3
$
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK
Common Stock
Shares
Amount
Additional
Paid in
Capital
Retained
Earnings
(Accumulated
Deficit)
Accumulated
Other
Comprehensive
Income (Loss)
Treasury
Shares
Shares
Amount
Total
Noncontrolling
Interests
Owner's
Equity
Series A
Preferred
Stock
(In millions, except shares in thousands)
Balance, December 31, 2020
Impact of accounting standard adoption (see Note 3)
Compensation on equity grants
Distribution equivalent rights
Shares issued under compensation program
Shares and units tendered for tax withholding obligations
Repurchases of common stock
Series A Preferred Stock dividends
Dividends - $95.00 per share
Dividends in excess of retained earnings
Common stock dividends
Dividends - $0.40 per share
Dividends in excess of retained earnings
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Other comprehensive income (loss)
Net income (loss)
Balance, December 31, 2021
228,062
—
—
—
1,312
(397 )
(756 )
—
—
—
—
—
—
—
—
228,221
$
$
0.2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
0.2
$
$
4,839.9
(448.3 )
59.2
(3.1 )
—
—
—
—
(87.3 )
—
(91.5 )
—
—
—
—
4,268.9
$
$
(1,893.5 )
—
—
—
—
—
—
(87.3 )
87.3
(91.5 )
91.5
—
—
—
71.2
(1,822.3 )
$
$
(141.8 )
—
—
—
—
—
—
—
—
—
—
—
—
(89.1 )
—
(230.9 )
6,731
—
—
—
—
397
756
—
—
—
—
—
—
—
—
7,884
$
$
(150.9 )
—
—
—
—
(13.2 )
(40.0 )
—
—
—
—
—
—
—
—
(204.1 )
$
$
3,249.3
—
—
—
—
—
—
—
—
—
—
(449.1 )
15.8
—
350.9
3,166.9
$
$
5,903.2
(448.3 )
59.2
(3.1 )
—
(13.2 )
(40.0 )
(87.3 )
—
(91.5 )
—
(449.1 )
15.8
(89.1 )
422.1
5,178.7
$
$
301.4
448.3
—
—
—
—
—
—
—
—
—
—
—
—
—
749.7
See notes to consolidated financial statements.
F-9
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
2021
Year Ended December 31,
2020
(In millions)
2019
Cash flows from operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
$
422.1 $
(1,325.0 ) $
Amortization in interest expense
Compensation on equity grants
Depreciation and amortization expense
Impairment of long-lived assets
(Gain) loss on sale or disposition of business and assets
Write-downs of assets
Accretion of asset retirement obligations
Increase (decrease) in redemption value of mandatorily redeemable preferred
interests
Deferred income tax expense (benefit)
Equity (earnings) loss of unconsolidated affiliates
Distributions of earnings received from unconsolidated affiliates
Risk management activities
(Gain) loss from financing activities
(Gain) loss from sale of equity-method investment
Change in contingent considerations
Changes in operating assets and liabilities:
Receivables and other assets
Inventories
Accounts payable, accrued liabilities and other liabilities
Interest payable
Net cash provided by operating activities
Cash flows from investing activities
Outlays for property, plant and equipment
Proceeds from sale of business and assets
Investments in unconsolidated affiliates
Proceeds from sale of equity-method investment
Return of capital from unconsolidated affiliates
Other, net
Net cash used in investing activities
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities
Repayments of credit facilities
Proceeds from borrowings under accounts receivable securitization facility
Repayments of accounts receivable securitization facility
Proceeds from issuance of senior notes
Redemption of senior notes
Principal payments of finance leases
Costs incurred in connection with financing arrangements
Payment of contingent consideration
Repurchase of shares and units
Sale of ownership interests in subsidiaries
Contributions from noncontrolling interests
Redemption of Preferred Units
Distributions to noncontrolling interests
Partial repurchase of Series A Preferred Stock
Distributions to Partnership unitholders
Dividends paid to common and Series A Preferred shareholders
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
$
See notes to consolidated financial statements.
F-10
10.3
59.2
870.6
452.3
2.0
10.3
4.0
13.6
12.1
23.9
84.0
116.0
16.6
—
0.1
(392.4 )
40.6
551.7
5.9
2,302.9
(505.1 )
12.2
(0.6 )
—
20.2
0.1
(473.2 )
620.0
(1,455.0 )
630.0
(830.0 )
1,000.0
(1,132.0 )
(12.5 )
(9.6 )
—
(53.2 )
—
15.8
—
(500.0 )
—
—
(187.5 )
(1,914.0 )
(84.3 )
242.8
158.5 $
11.1
66.2
865.1
2,442.8
58.4
55.6
3.6
—
(232.7 )
(72.6 )
86.8
(228.2 )
(45.6 )
—
(0.3 )
(25.6 )
(27.7 )
105.7
6.9
1,744.5
(951.6 )
198.7
(2.7 )
—
13.2
4.3
(738.1 )
2,195.0
(1,795.0 )
576.4
(596.4 )
1,000.0
(1,390.6 )
(12.4 )
(9.9 )
—
(97.4 )
—
41.5
(125.0 )
(439.2 )
(45.8 )
(11.7 )
(384.2 )
(1,094.7 )
(88.3 )
331.1
242.8 $
41.2
10.3
60.3
971.6
225.3
71.1
17.9
4.7
—
(87.9 )
(39.0 )
49.6
112.8
1.4
(69.3 )
8.7
(24.7 )
(45.0 )
35.0
45.8
1,389.8
(2,877.8 )
14.8
(266.8 )
70.3
3.5
(15.9 )
(3,071.9 )
3,100.0
(3,800.0 )
944.2
(854.2 )
2,500.0
(749.4 )
(11.5 )
(35.5 )
(317.1 )
(13.9 )
1,619.7
555.3
—
(191.7 )
—
(11.3 )
(953.5 )
1,781.1
99.0
232.1
331.1
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
Our Organization
Targa Resources Corp. (“TRC”) owns, operates, acquires, and develops a diversified portfolio of complementary domestic midstream
infrastructure assets.
In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended
to mean our consolidated business and operations. TRC controls the general partner of and owns all of the outstanding common units
representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership” or “TRP.” Targa
consolidates TRP and its subsidiaries under accounting principles generally accepted in the United States of America (“GAAP”).
Targa’s consolidated financial statements include differences from the consolidated financial statements of TRP; however, such
differences are immaterial. Such immaterial differences include:
the inclusion of the TRC revolving credit facility;
the inclusion of Series A Preferred Stock (“Series A Preferred”); and
the impacts of TRC’s treatment as a corporation for U.S. federal income tax purposes.
Our Operations
The Company is primarily engaged in the business of:
gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;
transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to
LPG exporters; and
gathering, storing, terminaling, and purchasing and selling crude oil.
See Note 25 – Segment Information for certain financial information regarding our business segments.
Note 2 — Basis of Presentation
These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2021 and
2020, and the results of operations, comprehensive income (loss), cash flows, and changes in owners’ equity for the years ended
December 31, 2021, 2020 and 2019. We have prepared these consolidated financial statements in accordance with GAAP. All
significant intercompany balances and transactions have been eliminated in consolidation.
Certain amounts in prior periods have been reclassified to conform to the current year presentation. Beginning in 2021, we reclassified
certain fuel and power costs previously included in Operating expenses to Product purchases and fuel within our Consolidated
Statements of Operations to better reflect the direct relationship of these costs to our revenue-generating activities and align with our
evaluation of the performance of the business. For the years ended December 31, 2021, 2020 and 2019, we reclassified $64.9 million,
$81.4 million and $89.5 million in fuel and power costs, respectively.
Note 3 — Significant Accounting Policies
Consolidation Policy
Our consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts
of certain gas gathering and processing facilities in which we own an undivided interest and are responsible for our proportionate
share of the costs and expenses of the facilities. Third party ownership interests in our controlled subsidiaries are presented as
noncontrolling interests within the equity section of our Consolidated Balance Sheets. In our Consolidated Statements of Operations
and Consolidated Statements of Comprehensive Income (Loss), noncontrolling interests reflect the attribution of results to third-party
investors. All intercompany balances and transactions have been eliminated in consolidation.
F-11
We apply the equity method of accounting to investments over which we exercise significant influence over the operating and
financial policies of our investee, but do not exercise control. We evaluate our equity investments for impairment when evidence
indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not
necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method
investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an
equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the
excess of the carrying value over the estimated fair value as a non-cash pre-tax impairment loss within Equity earnings (loss) in our
Consolidated Statements of Operations.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect
the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information
available at the time such estimates and judgments are made. Changes in facts and circumstances may result in revised estimates and
actual results could differ materially from those estimates. Estimates and judgments are used in, among other things, (1) estimating
unbilled revenues, product purchases and operating and general and administrative cost accruals, (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, (5) estimating contingencies, guarantees and indemnifications and (6) estimating redemption
value of mandatorily redeemable preferred interests.
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily
convertible into cash, and have original maturities of three months or less.
Allowance for Doubtful Accounts
Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. We estimate the allowance for
doubtful accounts through various procedures, including extensive review of our trade receivable balances by counterparty, assessing
economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount
and age of past due accounts.
We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not
received by the contractual due date. Our evaluation procedures also include performing account reconciliations, dispute resolution
and payment confirmation.
As the financial condition of any counterparty changes, circumstances develop or additional information becomes available,
adjustments to our allowance may be required.
Inventories
Our inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the
average cost method. Most NGL 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. Commodity inventories that are not physically or
contractually available for sale under normal operations (“deadstock”) are included in Property, plant and equipment.
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, an
exchange differential may be billed or owed. The exchange 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 net realizable value using the average cost method; 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.
F-12
Derivative Instruments
We utilize derivative instruments to manage the volatility of our cash flows due to fluctuating energy commodity prices. For balance
sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the
related fair values and any related collateral by counterparty on a gross basis. Cash flows from derivative instruments designated as
hedges are recognized in the same financial statement line item as the cash flows from the respective item being hedged.
We formally document all relationships between hedging instruments and hedged items, as well as its 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
achieving the offset of changes in cash flows attributable to the hedged risk.
We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales
election.
The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial
statements:
Recognition and Measurement
Derivative Treatment
Normal Purchases and Normal
Sales
Mark-to-Market
Balance Sheet
Fair value not recorded
Recorded at fair value
Cash Flow Hedge
Recorded at fair value with changes in fair value deferred in
Accumulated Other Comprehensive Income ("AOCI")
Income Statement
Earnings recognized when volumes are physically delivered
or received
Change in fair value recognized currently in earnings
The gain/loss on the derivative instrument is reclassified out
of AOCI into earnings when the forecasted transaction
occurs
We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or
the forecasted transaction is no longer probable to occur. 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 probable that a hedged
forecasted transaction will not occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
Property, Plant and Equipment
Property, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the
straight-line method over the estimated useful lives of the assets. The determination of the useful lives of property, plant and
equipment requires us to make various assumptions, including our expected use of the asset and the supply of and demand for
hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.
Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.
Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its
existing service potential or prevents environmental contamination are capitalized and depreciated over the remaining useful life of the
asset or major asset component. Certain costs directly related to the construction of assets, including internal labor costs, interest and
engineering costs, are capitalized.
Impairment of Long-Lived Assets
We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our
carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment
of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected
future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows
are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and
assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other
factors.
F-13
If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment loss equal to
the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if
quotes are unavailable. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our
asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of
the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term
price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs, and the use of
an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in significant
revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments. We believe our
estimates and models used to determine fair value are similar to what a market participant would use.
Goodwill
Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of
the acquired business. Goodwill is not subject to amortization but is tested for impairment at least annually. This test requires us to
attribute goodwill to an appropriate reporting unit, which is an operating segment or one level below an operating segment (also
known as a component). We evaluate goodwill for impairment on November 30 of each year, or whenever impairment indicators are
present. Prior to us conducting the goodwill impairment test, we complete a review of the carrying values of our long-lived assets,
including property, plant and equipment and other intangible assets. If it is determined that the carrying values are not recoverable, we
reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment.
As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment
test is necessary. If we choose to bypass this qualitative assessment or determine that a goodwill impairment test is required, our
annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including
attributed goodwill). We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of
goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unit’s fair value.
The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when
measuring goodwill, we consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit, if
applicable.
Intangible Assets
Our intangible assets include producer dedications under long-term contracts and customer relationships associated with business and
asset acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present
value of estimated future cash flows. We amortize the costs of our assets in a manner that closely resembles the expected benefit
pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we
benefit from services provided to customers.
Asset Retirement Obligations
Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result
from their acquisition, construction, development and/or normal operation. We record a liability and increase the basis in the
underlying asset for the present value of each expected ARO when there is a legal obligation to settle under existing or enacted law,
statute, written or oral contract or by legal construction.
Our obligations are estimated based on discounted cash flow (“DCF”) estimates. Over time, the ARO liability is accreted to its present
value as a period cost and the capitalized amount is depreciated over the asset’s respective useful life. At least annually, we review the
projected timing and amount of AROs and reflect revisions as an increase or decrease in the carrying amount of the liability and the
basis in the underlying asset. Upon settlement, we will recognize any difference between the recorded amount and the actual
settlement cost as a gain or loss.
Debt Issuance Costs
Costs incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged
to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities are presented as other
long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to
the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt
extinguishments include any associated unamortized debt issuance costs.
F-14
Accounts Receivable Securitization Facility
Proceeds from the sale or contribution of certain receivables under the Partnership’s accounts receivable securitization facility (the
“Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the
Securitization Facility are reflected as cash flows from financing activities in our Consolidated Statements of Cash Flows.
Environmental Liabilities and Other Loss Contingencies
We accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation,
fines, penalties and other sources, when the loss is probable and reasonably estimable.
Income Taxes
We file many income tax returns with the United States Department of the Treasury, as well as numerous states. 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
reported on a net basis by jurisdiction within our Consolidated Balance Sheets. We report these timing differences based on statutory
tax rates applicable to the scheduled timing difference reversal periods.
We assess the likelihood that we will recover our deferred tax assets from future taxable income. We establish a valuation allowance if
we believe that it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will
not be realized. 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 to determine whether, based on the weight of the evidence, we need
a valuation allowance. 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.
Dividends
Preferred and common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was
available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.
Mandatorily Redeemable Preferred Interests
Mandatorily redeemable preferred interests are included in other long-term liabilities on our Consolidated Balance Sheets, and such
interests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date.
This point-in-time value does not represent the amount that ultimately would be redeemed in the future. Changes in the redemption
value are included in interest expense, net in our Consolidated Statements of Operations.
Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK
natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing
system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s
election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.
The joint ventures, collectively, hold $1.9 billion face value in notes receivable from our partner, which are due July 2042. The
interest rate payable under the notes receivable is a variable LIBOR-based rate. For the years ended December 31, 2021, 2020 and
2019, interest earned on the notes receivable of $12.3 million, $8.6 million, and $8.1 million, exclusive of the return payable to our
partner, is reflected within Interest expense, net in our Consolidated Statements of Operations. We have accounted for the notes
receivable at fair value. Upon redemption: (i) the distributable value of our partner’s interest in each joint venture is required to be
adjusted by mutual agreement or under a valuation procedure outlined in each joint venture agreement based, among other things, on
changes in the market value of the joint venture’s assets allocable to our partner (including the value of the notes receivable); and (ii)
the parties are obligated to set off the value of the notes receivable from our partner against the value of our partner’s interest in the
applicable joint venture. For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to
be recorded as if the redemption had occurred on the reporting date. Because redemption will not be required until at least 2022, the
actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of
redemption value.
F-15
Comprehensive Income
Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of
derivative instruments that are designated as cash flow hedges.
Revenue Recognition
Our operating revenues are primarily derived from the following activities:
sales of natural gas, NGLs, condensate and crude oil;
services related to compressing, gathering, treating, and processing of natural gas; and
services related to NGL fractionation, terminaling and storage, transportation and treating.
We have multiple types of contracts with commercial counterparties and many of these contracts contain embedded fees with
settlement provisions that deduct these fees from the sales price paid by Targa in exchange for commodities. The commercial
relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts
are excluded from the provisions of the revenue recognition guidance in Topic 606, Revenue from Contracts with Customers. Any
cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases and fuel.
Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We
recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales
and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues.
We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal
in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of
inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances
where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction
on a combined net basis.
Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be
transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each
unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining
benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the
benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of
distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each
distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at
a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate
the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally
represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at
the fixed price.
Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered
inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single
overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are
not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and
therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple
performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a
series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we
recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output
method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining
days of service promised under the contract.
F-16
The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the
volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our
efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct
service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for
variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue
when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability
related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the
service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the
commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when
the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the
fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is
consistent with the output method of progress selected for the performance obligation.
Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end,
and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition
purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial
reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at
the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved,
and can be included in that month or quarter’s revenue.
We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for
revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that
performance will be provided.
Contract Assets
We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold
or services performed at the end of reporting period.
Share-Based Compensation
We award share-based compensation to employees, directors and non-management directors in the form of restricted stock, restricted
stock units and performance share units. Compensation expense on our equity-classified awards is recorded at grant-date fair value.
Compensation expense is recognized in general and administrative expense over the requisite service period of each award, and
forfeitures are recognized as they occur. We may purchase a portion of the shares issued to satisfy employees’ tax withholding
obligations on vested awards. These shares are recorded in treasury stock, at cost, and cash paid is classified as a financing activity in
our Consolidated Statements of Cash Flows. All excess tax benefits and tax deficiencies related to share-based compensation are
recognized as income tax benefit or expense in our Consolidated Statements of Operations, with the tax effects of exercised or vested
awards treated as discrete items in the reporting period which they occur. Excess tax benefits are classified as an operating activity.
Earnings per Share
Basic earnings (loss) per common share (“EPS”) is based on the sum of the weighted-average number of common shares outstanding
and vested restricted stock, restricted stock units and performance share units. Diluted EPS includes any dilutive effect of preferred
stock, unvested restricted stock, restricted stock units and performance share units. The dilutive effect is calculated through the
application of i) the if-converted method for convertible preferred stock, and ii) the treasury stock method for unvested stock awards.
Leases
We recognize the following for all leases (with the exception of short-term leases) at the commencement date:
A lease liability, which is a lessee’s obligation to make lease payments arising from a lease.
A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for
the lease term.
F-17
We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered
short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the
commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any
lease prepayments and excludes lease incentives. As most of the Company’s leases do not provide an implicit interest rate, we use our
incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is
determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease
commencement for all subsequent leases.
Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For
variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the
commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and
lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such
variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in
the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option.
Recent Accounting Pronouncements
Recently adopted accounting pronouncements
Convertible Debt and Equity Instruments
In August 2020, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2020-06, Debt - Debt with
Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40):
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The amendments in this update simplify the
accounting for convertible debt instruments and convertible preferred stock by reducing the number of accounting models and
embedded conversion features that can be recognized separately from the primary contract. These amendments also enhance
transparency and improve disclosures for convertible instruments and earnings per share guidance. These amendments are effective
for fiscal years, and interim periods within those years, beginning after December 15, 2021, with early adoption permitted. This update
permits the use of either the modified retrospective or full retrospective method of adoption.
On a modified retrospective basis, we adopted the amendments early, effective January 1, 2021. The primary effect of adoption on the
Company was attributable to the elimination of the beneficial conversion feature accounting model (“BCF”), which resulted in the
presentation of the Series A Preferred as a single unit of account, without bifurcation of the BCF and corresponding discount.
Therefore, upon adoption, the carrying value of the Series A Preferred was reflected at $749.7 million, which is the allocated amount
based on the initial relative fair value allocation of net proceeds at issuance (prior to the allocation to the BCF) of $787.1 million, less
the carrying value of the portion repurchased in December 2020 (refer to Note 11 – Preferred Stock). The adoption did not have an
impact on retained earnings (deficit), but rather, the adoption impact flowed through additional paid-in capital where the BCF was
previously included. In addition, the adoption also eliminates the corresponding discount attributable to the BCF and therefore,
accretion of the discount as a deemed dividend is no longer required. The other aspects of this guidance did not have a material effect
on our consolidated financial statements.
Note 4 – Joint Ventures and Divestitures
Joint Ventures
Little Missouri 4 Joint Venture
In January 2018, we formed a 50/50 joint venture in Little Missouri 4 LLC (“Little Missouri 4”) with Hess Midstream Partners LP to
construct a new 200 MMcf/d natural gas processing plant (“LM4 plant”) at Targa’s existing Little Missouri facility. Little Missouri 4
began operations in the third quarter of 2019. Targa is the operator of the LM4 plant. See Note 7 – Investments in Unconsolidated
Affiliates for activity related to Little Missouri 4.
F-18
DevCo Joint Ventures
In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak
Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix Pipeline (“Grand Prix”), Gulf Coast Express Pipeline (“GCX”)
and an approximately 110 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). As of December 31, 2021, Stonepeak owned a
95% interest in the Grand Prix DevCo JV, which owned a 20% interest in the Grand Prix Pipeline LLC (the “Grand Prix Joint
Venture”) (which does not include the extensions into Southern Oklahoma and Central Oklahoma). Additionally, Stonepeak owned an
80% interest in both Targa GCX Pipeline LLC (“GCX DevCo JV”), which owned our 25% interest in GCX, and Targa Train 6 LLC
(“Train 6 DevCo JV”), which owned a 100% interest in the fractionation train. The Train 6 DevCo JV did not include certain
fractionation-related infrastructure such as brine and storage, which were funded and owned 100% by us. As of December 31, 2021,
we held the remaining interests in the DevCo JVs as well as controlled the management and operation of Grand Prix and Train 6 and
consolidated each of the DevCo JVs in our financial statements. We accounted for the Grand Prix Joint Venture on a consolidated
basis in our consolidated financial statements and for GCX as an equity method investment, as disclosed in Note 7 – Investments in
Unconsolidated Affiliates.
For a four-year period beginning on the date that all three projects commenced commercial operations, we had the option to acquire all
or part of Stonepeak’s interests in the DevCo JVs (the “DevCo JV Call Right”). The purchase price payable for such partial or full
interests was based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak
from the DevCo JVs. Targa would control the management of the DevCo JVs unless and until Targa declined to exercise its option to
acquire Stonepeak's interests.
Subsequent Events
In January 2022, we exercised the DevCo JV Call Right and closed on the repurchase of our interests in the DevCo JVs from
Stonepeak for approximately $925 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we own a 75%
interest in the Grand Prix Joint Venture, a 100% interest in Train 6 and owned a 25% equity interest in GCX, prior to the sale of our
GCX equity interest in February 2022.
In February 2022, we announced that we executed agreements to sell GCX DevCo JV, which held our 25% equity interest in GCX,
for approximately $857 million (the “GCX Sale”). We expect to receive the full proceeds from the sale in the second quarter of 2022
following a customary call right period in favor of the other members of GCX.
Carnero Joint Venture
In May 2018, we merged our 50% interests in the Carnero gathering and Carnero processing joint ventures with Evolve Transition
Infrastructure LP’s respective 50% interests in the Carnero gathering and Carnero processing joint ventures, which own the high-
pressure Carnero gathering line and Raptor natural gas processing plant, to form an expanded 50/50 joint venture in South Texas (the
“Carnero Joint Venture”). We operate the gas gathering and processing facilities in the joint venture. The Carnero Joint Venture is a
consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
Divestitures
Sale of Versado Gathering System
In December 2018, we exchanged a portion of our Versado gathering system, located primarily in Yoakum County, Texas, and Lea
County, New Mexico, and associated contracts and assets, with a third party for consideration that includes 1) a gathering system
located primarily in Lea County, New Mexico, and associated contracts and assets, 2) an initial cash payment and 3) deferred
payments due semi-annually beginning on June 30, 2019, through December 31, 2022. We later agreed to accept a lump sum payment
from the third party in October 2019 to satisfy the third party’s payment obligations. The acquired gathering system has been
integrated into the Versado gathering system. Due to the significant monetary portion of the consideration received, the exchange of
these assets was accounted for as a derecognition of nonfinancial assets, and a gain of $44.4 million was recognized in our
Consolidated Statements of Operations for the year ended December 31, 2018 as part of Other operating (income) expense. The gain
was calculated as the difference between the fair value of the consideration received, including the fair value of the acquired gathering
system, less our book basis of the assets transferred.
F-19
Sale of Interest in Train 7
In February 2019, we announced an extension of Grand Prix from Southern Oklahoma to the STACK region of Central Oklahoma
where it will connect with the Williams Companies, Inc. (“Williams”) Bluestem Pipeline and link the Conway, Kansas, and Mont
Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will
transport on Grand Prix and fractionate at our Mont Belvieu facilities. Williams also exercised its option to acquire a 20% equity
interest in Train 7 and subsequently executed a joint venture agreement with us in the second quarter of 2019. Certain fractionation-
related infrastructure for Train 7, including storage caverns and brine handling, were funded and are owned 100% by Targa. We
present Train 7 on a consolidated basis in our consolidated financial statements.
Sale of Interest in Targa Badlands LLC
In April 2019, we closed on the sale of a 45% interest in Targa Badlands LLC (“Targa Badlands”), the entity that holds substantially
all of the assets previously wholly owned by Targa in North Dakota, to funds managed by Blackstone Credit (“Blackstone”) for $1.6
billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital
program. Future growth capital of Targa Badlands is expected to be funded on a pro rata ownership basis. Targa Badlands pays a
minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Once
Blackstone receives funds sufficient to meet a predetermined fixed return on their invested capital, their interest will convert to a 7.5%
equity interest in Targa Badlands, and it will no longer have a priority right on MQDs. Additionally, upon a sale of Targa Badlands,
Blackstone’s capital contributions would have a liquidation preference equal to a predetermined fixed return on their invested capital.
After the seventh anniversary of the closing date or upon the occurrence of certain triggering events, we have the option to acquire all
of Blackstone’s interest in Targa Badlands for a purchase price payable to Blackstone based on their liquidation preference after
taking into account all prior distributions to Blackstone, plus a set percentage on a multiple of the trailing twelve-month EBITDA of
Targa Badlands. Targa will continue to control the management of Targa Badlands pending the occurrence of certain triggering
events, including if Blackstone has not received funds sufficient to meet its liquidation preference and Targa has not exercised its
purchase right to acquire Blackstone’s interest by April 3, 2029.
We continue to be the operator of Targa Badlands and hold majority governance rights. As a result, we continue to present Targa
Badlands on a consolidated basis in our consolidated financial statements and Blackstone’s contributions are reflected as
noncontrolling interests. The sale of interest in Targa Badlands is included in our Gathering and Processing segment. Targa Badlands
is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts and other obligations of Targa or
its other subsidiaries.
Sale of Delaware Crude System
In January 2020, we closed on the sale of our Delaware crude system for approximately $134 million, which was effective December
1, 2019. As a result of the sale, we recognized a loss of $59.5 million included within Other operating (income) expense in our
Consolidated Statements of Operations for the year ended December 31, 2019. The Delaware crude system is included in our
Gathering and Processing segment and does not qualify for reporting as a discontinued operation as its divestiture did not represent a
strategic shift that would have a major effect on our operations and financial results.
Sale of Assets in Channelview, Texas
In October 2020, we closed on the sale of our assets in Channelview, Texas for approximately $58 million. As a result of the sale, we
recognized a loss of $58.3 million included within Other operating (income) expense in our Consolidated Statements of Operations to
reduce the carrying value of our assets to their recoverable amounts. The sale of the assets is included in our Logistics and
Transportation segment and does not qualify for reporting as a discontinued operation, as its divestiture did not represent a strategic
shift that would have a major effect on our operations or financial results.
F-20
Note 5 — Property, Plant and Equipment and Intangible Assets
Property, Plant and Equipment and Intangible Assets
December 31, 2021
December 31, 2020
Estimated Useful Lives (In Years)
Gathering systems
Processing and fractionation facilities
Terminaling and storage facilities
Transportation assets
Other property, plant and equipment
Land
Construction in progress
Finance lease right-of-use assets
Property, plant and equipment
Accumulated depreciation, amortization and impairment
Property, plant and equipment, net
Intangible assets
Accumulated amortization and impairment
Intangible assets, net
$
$
$
9,318.2 $
6,388.8
1,313.8
2,671.0
340.9
160.8
347.0
55.6
20,596.1
(8,928.4 )
11,667.7 $
2,642.9
(1,548.1 )
1,094.8 $
9,216.1
6,276.8
1,555.1
2,567.7
32.4
160.8
324.3
51.8
20,185.0
(8,011.4 )
12,173.6
2,643.5
(1,261.1 )
1,382.4
5 to 20
5 to 25
5 to 25
10 to 50
3 to 50
—
—
10 to 20
During the preparation of the Company's 2020 consolidated financial statements, the Company identified certain gathering pipelines
that should not have had value ascribed to them as part of a prior acquisition as these assets were inactive. The Company does not
believe this error is material to its previously issued historical consolidated financial statements for any of the periods impacted and
accordingly, has not adjusted the historical financial statements. The Company wrote these assets down in 2020 and recognized a non-
cash loss of $32.4 million in Other operating (income) expense in our Consolidated Statements of Operations.
During the preparation of the Company's first quarter 2019 consolidated financial statements, the Company identified an error related
to depreciation expense on certain assets that should have been placed in service during 2018. The Company does not believe this
error is material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly,
has not adjusted the historical financial statements. The Company recorded the cumulative impact of a one-time $12.5 million
overstatement of depreciation expense during the first quarter of 2019.
For each of the years ended December 31, 2021, 2020, and 2019 depreciation expense was $739.6 million, $721.1 million and
$800.0 million, respectively.
Impairments of Long-Lived Assets
We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances
indicate that the related carrying amount of such assets may not be recoverable, including changes to our estimates that could have an
impact on our assessment of asset recoverability.
2021
In the fourth quarter of 2021, we recorded a non-cash pre-tax impairment charge of $452.3 million for the partial impairment of
certain gas processing facilities and gathering systems associated with our Central operations in our Gathering and Processing
segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while
positive, will not be sufficient to recover the existing total net book value of the underlying assets. Underlying our assessment were
lower expectations regarding volumes and rates associated with the renewal of future expiring contracts and negotiation of new
contracts in the South Texas region.
F-21
2020
In the first quarter of 2020, we recorded a non-cash pre-tax impairment charge of $2,442.8 million primarily associated with the
partial impairment of certain gas processing facilities and gathering systems associated with our Central operations and the full
impairment of our Coastal operations in our Gathering and Processing segment. The impairment was a result of our assessment that
forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net
book value of the underlying assets. Underlying our assessment was an observed global commodity price decline due to factors that
significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be
implemented globally, the demand for commodities declined. Additionally, the supply shock late in the first quarter of 2020 from
certain major oil producing nations increasing production also significantly contributed to the sharp drop in commodity prices. The
drop in commodity prices resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets
and resultant drilling activity and shutting-in production. Our impairment assessment forecasted continued decline in natural gas
production across the Mid-Continent and Gulf of Mexico regions.
2019
In the fourth quarter of 2019, we recorded a non-cash pre-tax impairment charge of $225.3 million for the partial impairment of
certain gas processing facilities and gathering systems associated with our Central and Coastal operations in our Gathering and
Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from
operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Underlying our
assessment was the expected continuing decline in natural gas production across the Barnett Shale in North Texas and Gulf of Mexico
due to a sustained low commodity price environment.
For the 2021, 2020, and 2019 impairment assessments discussed above, we determined fair value through the use of discounted
estimated cash flows to measure the impairment loss for each asset group for which undiscounted future net cash flows were not
sufficient to recover the net book value.
The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived
from current business plans, which are developed using near-term price and volume projections reflective of the current environment
and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other
key assumptions include volume projections, operating costs, timing of incurring such costs, and the use of an appropriate terminal
value and discount rate. We believe our estimates and models used to determine fair value are similar to what a market participant
would use.
The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as
discussed above) and thus represents a Level 3 measurement. The significant unobservable inputs used include discount rates and
determination of terminal values. We utilized a weighted average discount rate of 9.5%, 14.0% and 8.5% when deriving the fair value
of the asset groups impaired during 2021, 2020 and 2019, respectively. The weighted average discount rate and terminal values reflect
management’s best estimate of inputs a market participant would utilize. The carrying value adjustments are included in Impairment
of long-lived assets in our Consolidated Statements of Operations.
We may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the
carrying value of our long-lived assets and may result in future impairments.
Intangible Assets
Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of
these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash
flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to
customers.
As a result of the triggering events and analysis described above, in 2021 and 2020, we recognized non-cash pre-tax impairment losses
of $156.6 million and $208.6 million, respectively, associated with certain intangible customer relationships for which undiscounted
future net cash flows were not sufficient to recover the net book value.
For each of the years ended December 31, 2021, 2020, and 2019 amortization expense for our intangible assets was $131.0 million,
$144.0 million and $171.6 million, respectively. The estimated annual amortization expense for intangible assets is approximately
$112.0 million, $106.8 million, $103.0 million, $99.9 million and $97.6 million for each of the years 2022 through 2026. As of
December 31, 2021, the weighted average amortization period for our intangible assets was approximately 11.3 years.
F-22
The changes in our intangible assets are as follows:
Balance at beginning of period
Impairment
Amortization
Balance at end of period
Note 6 – Goodwill
December 31, 2021
December 31, 2020
$
$
1,382.4 $
(156.6 )
(131.0 )
1,094.8 $
1,735.0
(208.6 )
(144.0 )
1,382.4
We recognized goodwill of $46.6 million related to the March 1, 2017 acquisition of gas gathering and processing and crude oil
gathering assets in the Permian Basin. At December 31, 2021, we had $45.2 million of goodwill included in Other long-term assets on
the Consolidated Balance Sheets.
Permian Midland
Permian Delaware
Goodwill
December 31, 2021
December 31, 2020
$
$
23.2 $
22.0
45.2 $
23.2
22.0
45.2
The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural gas and NGL
prices. The direct and indirect effects of significant declines in commodity prices from the date of acquisition would likely cause the
fair values of these reporting units to fall below their carrying values, and could result in an impairment of goodwill.
As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or
more frequently if we believe necessary based on events or changes in circumstances. For our 2021 and 2020 annual evaluations, we
performed a qualitative assessment, which indicated that it is not more likely than not that the fair values of the Permian Midland and
Permian Delaware reporting units were less than their carrying amounts, and therefore, a quantitative goodwill impairment test was
not necessary. Our qualitative assessment considered, among other things, the overall financial performance and future outlook of the
Permian Midland and Permian Delaware reporting units, industry and market considerations, and other relevant entity specific events.
Our annual quantitative evaluation in 2019 utilized an income approach including a terminal value to estimate the fair values of our
reporting units based on a DCF analysis. The future cash flows for our reporting units are based on our estimates, at that time, of
future revenues, income from operations and other factors, such as working capital and timing of capital expenditures. We take into
account current and expected industry and market conditions, including commodity pricing and volumetric forecasts in the basins in
which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital
determined from relevant market comparisons. We did not record any goodwill impairment charges for the year ended December 31,
2019, as the fair values of the respective reporting units exceeded their carrying values. While no impairment was recorded, a portion
of goodwill attributable to the former Permian Supersystem reporting unit was allocated to held for sale assets, which were
subsequently sold in January 2020.
The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the
market and therefore represent Level 3 inputs, as defined in Note 16 – Fair Value Measurements. These inputs require significant
judgments and estimates at the time of valuation.
F-23
Note 7 – Investments in Unconsolidated Affiliates
Our investments in unconsolidated affiliates consist of the following:
Gathering and Processing Segment
two operated joint ventures in South Texas: a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”) and a
50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), (together the “T2 Joint Ventures”); and
a 50% operated ownership interest in Little Missouri 4.
Logistics and Transportation Segment
a 25% non-operated ownership interest in GCX (prior to the GCX Sale);
a 38.8% operated ownership interest in Gulf Coast Fractionators LP (“GCF”); and
a 50% operated ownership interest in Cayenne Pipeline LLC (“Cayenne”).
The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated
financial statements, but do afford us the significant influence required to employ the equity method of accounting.
See Note 4 – Joint Ventures and Divestitures for further discussion of GCX and Little Missouri 4.
The following table shows the activity related to our investments in unconsolidated affiliates:
GCX (1)
Little Missouri 4
T2 Eagle Ford (2)
T2 LaSalle (2)
GCF
Cayenne
Agua Blanca
Total
GCX (1)
Little Missouri 4
T2 Eagle Ford
T2 LaSalle
GCF
Cayenne
Total
GCX (1)
Little Missouri 4
T2 Eagle Ford
T2 LaSalle
GCF (3)
Cayenne
Total
Balance at
December 31, 2018
$
Equity
Earnings
(Loss)
Cash
Distributions
Disposition
Contributions
Balance at
December 31, 2019
$
Equity
Earnings
(Loss)
Cash
Distributions
Disposition
Contributions
211.6 $
67.3
99.0
49.3
40.3
16.6
6.4
490.5 $
447.5 $
103.7
89.6
44.8
37.2
15.9
738.7 $
435.2 $
104.7
79.8
39.6
38.5
16.2
714.0 $
27.7 $
3.4
(9.4 )
(4.5 )
16.1
7.2
(1.5 )
39.0 $
(25.3 ) $
—
—
—
(19.2 )
(8.2 )
(0.4 )
(53.1 ) $
— $
—
—
—
—
—
(4.5 )
(4.5 ) $
66.3 $
10.8
(8.9 )
(4.8 )
2.9
6.3
72.6 $
(81.3 ) $
(9.8 )
(0.9 )
(0.4 )
(1.6 )
(6.0 )
(100.0 ) $
— $
—
—
—
—
—
— $
63.4 $
10.9
(57.0 )
(35.0 )
(8.6 )
2.4
(23.9 ) $
(78.1 ) $
(17.5 )
(1.0 )
(0.4 )
(1.1 )
(6.1 )
(104.2 ) $
— $
—
—
—
—
—
— $
Balance at
December 31, 2019
447.5
103.7
89.6
44.8
37.2
15.9
—
738.7
233.5 $
33.0
—
—
—
0.3
—
266.8 $
Balance at
December 31, 2020
435.2
104.7
79.8
39.6
38.5
16.2
714.0
2.7 $
—
—
—
—
—
2.7 $
Balance at
December 31, 2021
421.0
98.1
21.9
4.2
28.8
12.5
586.5
0.5 $
—
0.1
—
—
—
0.6 $
Balance at
December 31, 2020
$
Equity
Earnings
(Loss)
Cash
Distributions
Disposition
Contributions
$
$
$
(1)
(2)
(3)
Our 25% interest in GCX was owned by GCX DevCo JV, of which we owned a 20% interest as of December 31, 2021. GCX DevCo JV is accounted for on a
consolidated basis in our consolidated financial statements. Following the DevCo JV Repurchase in January 2022, we owned a 25% equity interest in GCX.
Subsequently, in February 2022, we announced the GCX Sale. See Note 4 – Joint Ventures and Divestitures for further discussion.
Effective December 31, 2018, we (i) conveyed our 50% ownership interest in T2 EF Cogen to our joint venture partner and received a distribution of certain
assets from the joint venture and (ii) were named as operator of the T2 Joint Ventures. On April 1, 2019, we assumed the operatorship of the T2 Joint Ventures.
Targa assumed operatorship of GCF in the first half of 2021.
F-24
Our equity loss for the year ended December 31, 2021 includes the effect of impairments in the carrying values of our investments in
T2 Eagle Ford and T2 LaSalle. As a result of the decrease in current and expected future utilization of the underlying assets, we have
determined that factors indicate that a decrease in the value of our investments occurred that was other than temporary. As a result of
this evaluation, we recorded non-cash pre-tax impairment losses of $47.3 million and $29.9 million on our investments in T2 Eagle
Ford and T2 LaSalle, respectively, in the fourth quarter of 2021. The impairment losses represent our proportionate share of
impairment charges recorded by the joint ventures, as well as our impairments of the unamortized excess fair values resulting from the
purchase accounting related to the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015.
During 2019, we closed on the sale of an equity-method investment for $73.8 million, of which $3.5 million contingent consideration
was received in January 2020. As a result of the sale, we recognized a gain of $69.3 million reported in Gain (loss) from sale of
equity-method investment.
Note 8 — Debt Obligations
Current:
Obligations of the Partnership: (1)
Accounts receivable securitization facility, due April 2022 (2)
TPL notes, 4¾% fixed rate, due November 2021 (3)
$
Finance lease liabilities
Current debt obligations
Long-term:
TRC obligations:
TRC Senior secured revolving credit facility, variable rate, due June 2023 (4)
Obligations of the Partnership: (1)
Senior secured revolving credit facility, variable rate, due
June 2023 (5)
Senior unsecured notes:
4¼% fixed rate, due November 2023
5⅛% fixed rate, due February 2025
5⅞% fixed rate, due April 2026
5⅜% fixed rate, due February 2027
6½% fixed rate, due July 2027
5% fixed rate, due January 2028
6⅞% fixed rate, due January 2029
5½% fixed rate, due March 2030
4⅞% fixed rate, due February 2031
4% fixed rate, due January 2032
TPL notes, 5⅞% fixed rate, due August 2023 (3)
Unamortized premium
Debt issuance costs, net of amortization
Finance lease liabilities
Long-term debt
Total debt obligations
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRC Senior
secured credit facility (4)
Letters of credit outstanding under the Partnership senior
secured revolving credit facility (5)
$
$
$
December 31, 2021
December 31, 2020
150.0 $
—
150.0
12.8
162.8
—
—
—
—
963.2
468.1
705.2
700.3
679.3
949.6
1,000.0
1,000.0
—
—
6,465.7
(45.0 )
13.7
6,434.4
6,597.2 $
— $
71.3
71.3 $
350.0
6.5
356.5
12.1
368.6
555.0
280.0
583.9
481.0
963.2
468.1
705.2
700.3
679.3
949.6
1,000.0
—
48.1
0.2
7,413.9
(45.5 )
18.7
7,387.1
7,755.7
—
44.4
44.4
(1) 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
(2)
(3)
(4)
(5)
respect to the debt of the Partnership.
As of December 31, 2021, the Partnership had $150.0 million of qualifying receivables under its $400.0 million Securitization Facility, resulting in $250.0
million availability.
“TPL” refers to Targa Pipeline Partners LP.
As of December 31, 2021, availability under TRC’s $670.0 million senior secured revolving credit facility (“Existing TRC Revolver”) was $670.0 million.
As of December 31, 2021, availability under the Partnership’s $2.2 billion senior secured revolving credit facility (“Existing TRP Revolver”) was $2,128.7
million.
F-25
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations
during the year ended December 31, 2021:
Existing TRC Revolver
Existing TRP Revolver
Securitization Facility
Compliance with Debt Covenants
Range of Interest Rates
Incurred
1.9% - 1.9%
1.6% - 1.9%
1.1% - 1.8%
Weighted Average Interest
Rate Incurred
1.9%
1.8%
1.2%
As of December 31, 2021, we were in compliance with the covenants contained in our various debt agreements.
Debt Obligations
New TRC Credit Agreement
In February 2022, the Company entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent, Collateral
Agent and Swing Line Lender, and the other lenders party thereto (the “New TRC Revolver”). The New TRC Revolver provides for a
revolving credit facility in an initial aggregate principal amount up to $2.75 billion (with an option to increase such maximum
aggregate principal amount by up to $500.0 million in the future, subject to the terms of the New TRC Revolver) and a swing line sub-
facility of up to $100.0 million. The New TRC Revolver matures on February 17, 2027.
The New TRC Revolver provides for, among other things, certain changes to occur upon the occurrence of an “Investment Grade
Event,” including the release of all security interests in all “Collateral” at the request of the Company.
The revolving credit facility bears interest at the Company’s option at: (a) the Base Rate, which is the highest of Bank of America’s
prime rate, the federal funds rate plus 0.5% and the Term SOFR (as such term is defined in the New TRC Revolver) rate plus 1.0%
(subject in each case to a floor of 0.0%), plus an applicable margin (i) prior to the occurrence of an Investment Grade Event, ranging
from 0.25% to 1.25%, dependent on the Company’s ratio of consolidated funded indebtedness to consolidated adjusted EBITDA (the
“Consolidated Leverage Ratio”) and (ii) upon and after the occurrence of an Investment Grade Event, ranging from 0.125% to 0.75%,
dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such
time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt
Rating”), or (b) Term SOFR (which includes, for Term SOFR loans, a SOFR adjustment of plus 0.10%) plus an applicable margin (i)
prior to the occurrence of an Investment Grade Event, ranging from 1.25% to 2.25%, dependent on the Company’s Consolidated
Leverage Ratio and (ii) upon and after the occurrence of an Investment Grade Event, ranging from 1.125% to 1.75%, dependent on the
Company’s Debt Rating.
The Company is required to pay a commitment fee equal to an applicable rate ranging from (a) prior to the occurrence of an
Investment Grade Event, 0.20% to 0.35% (dependent on the Company’s Consolidated Leverage Ratio) and (b) upon and after the
occurrence of an Investment Grade Event, 0.125% to 0.35% (dependent on the Company’s Debt Rating), in each case times the actual
daily unused portion of the revolving credit facility.
The obligations under the New TRC Revolver are guaranteed by substantially all material wholly-owned domestic subsidiaries of the
Company, including by Targa Resources Partners LP and, prior to the occurrence of an Investment Grade Event, secured by
substantially all personal property assets of, and certain material real property owned by, the Company and the guarantors.
The New TRC Revolver requires the Company to maintain a Consolidated Leverage Ratio, determined as of the last day of each
quarter for the four-fiscal quarter period ending on the date of determination, of no more than 5.50 to 1.00. Prior to the occurrence of
an Investment Grade Event, the New TRC Revolver also requires the Company to maintain an interest coverage ratio of no less than
2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination. For
any four-fiscal-quarter-period during which a material acquisition or disposition occurs, the total leverage ratio and interest coverage
ratio (prior to the occurrence of an Investment Grade Event) will be determined on a pro forma basis as though such event had
occurred as of the first day of such four-fiscal-quarter-period.
The New TRC Revolver restricts the Company’s ability to make dividends to stockholders if a default or an event of default (as
defined in the New TRC Revolver) exists or would result from such distribution, and if, before the Investment Grade Event, the
Company is not in pro forma compliance with the financial covenants. In addition, the New TRC Revolver contains various covenants
that may limit, among other things, the Company’s ability to incur indebtedness, grant liens, make investments, repay or amend the
terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates.
F-26
Existing TRC Revolver
The Existing TRC Revolver, which had a maturity date of June 2023, provided available commitments up to $670.0 million and
allowed us to request up to $200.0 million in additional commitments. The Existing TRC Revolver’s interest rate was dependent on
the consolidated leverage ratio of non-Partnership consolidated funded indebtedness to consolidated Adjusted EBITDA, as defined in
the Existing TRC Revolver.
We were required to pay a commitment fee ranging from 0.375% to 0.5% (dependent upon the Company’s consolidated leverage
ratio) on the daily average unused portion of the Existing TRC Revolver. Loans under the Existing TRC Revolver accrued interest at
either a base rate or LIBOR (at our option) plus (i) for revolving loans, a margin of 0.75% to 1.75% (in the case of base rate loans) or
1.75% to 2.75% (in the case of LIBOR loans), in each case based on our consolidated leverage ratio and (ii) for term loans, 3.75% (in
the case of base rate loans) or 4.75% (in the case of LIBOR loans).
The Existing TRC Revolver was secured by a pledge of the Company’s equity interests in the Partnership and required us to maintain
a consolidated leverage ratio (the ratio of consolidated funded non-partnership indebtedness to consolidated Adjusted EBITDA) of no
more than 4.00 to 1.00 for each fiscal quarter. The Existing TRC Revolver restricted our ability to pay dividends to shareholders if, on
a pro forma basis after giving effect to such dividend, (a) any default or event of default has occurred and is continuing or (b) we were
not in compliance with our consolidated leverage ratio as of the last day of the most recent test period. In addition, it included various
covenants that may have limited, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend
the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates.
In February 2022, in connection with entering into the New TRC Revolver, we terminated the Existing TRC Revolver.
Existing TRP Revolver
The Existing TRP Revolver, which had a maturity date of June 2023, provided available commitments up to $2.2 billion and allowed
the Partnership to request up to $500.0 million in additional commitments.
The Existing TRP Revolver provided for certain changes to occur upon the Partnership receiving an investment grade credit rating
from Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Corporation (“S&P”), including the release of the security
interests in all collateral at the request of the Partnership.
The Existing TRP Revolver accrued interest, at the Partnership’s option, either at the base rate or the Eurodollar rate. The base rate
was equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate
plus 1.0%, plus an applicable margin (a) before the collateral release date, ranging from 0.25% to 1.25% (dependent on the
Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (b) upon and after the collateral
release date, ranging from 0.125% to 0.75% (dependent on the Partnership’s non-credit-enhanced senior unsecured long-term debt
ratings). The Eurodollar rate was equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from
1.25% to 2.25% (dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (ii)
upon and after the collateral release date, ranging from 1.125% to 1.75% (dependent on the Partnership’s non-credit-enhanced senior
unsecured long-term debt ratings).
The Partnership was required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date,
0.25% to 0.375% (dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and
(b) upon and after the collateral release date, 0.125% to 0.35% (dependent on the Partnership’s non-credit-enhanced senior unsecured
long-term debt ratings), in each case, times the actual daily average unused portion of the Existing TRP Revolver. Additionally, issued
and undrawn letters of credit accrued interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to
2.25% (dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (ii) upon and
after the collateral release date, ranging from 1.125% to 1.75% (dependent on the Partnership’s non-credit-enhanced senior unsecured
long-term debt ratings).
The Existing TRP Revolver was collateralized by a pledge of assets and equity from certain of the Partnership’s subsidiaries.
Borrowings were guaranteed by the Partnership’s restricted subsidiaries.
The Existing TRP Revolver required the Partnership to maintain a total leverage ratio (the ratio of consolidated indebtedness to the
Partnership’s consolidated Adjusted EBITDA, in each case as defined in the Existing TRP Revolver), determined as of the last day of
each quarter for the four-fiscal quarter period ending on the date of determination, of no more than (a) before the collateral release
date, 5.50 to 1.00 and (b) upon and after the collateral release date, 5.25 to 1.00 (or 5.50 to 1.00 during a specified acquisition period).
F-27
The Existing TRP Revolver also required the Partnership to maintain an interest coverage ratio of no less than 2.25 to 1.00 determined
as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination. For any four-fiscal quarter
period during which a material acquisition or disposition occurred, the total leverage ratio and interest coverage ratio would be
determined on a pro forma basis as though such event had occurred as of the first day of such four-fiscal quarter period.
The Existing TRP Revolver restricted the Partnership’s ability to make distributions of available cash to unitholders if a default or an
event of default (as defined in the Existing TRP Revolver) existed or would result from such distribution. In addition, the Existing
TRP Revolver contained various covenants that may have limited, among other things, the Partnership’s ability to incur indebtedness,
grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in
transactions with affiliates (in each case, subject to the Partnership’s right to incur indebtedness or grant liens in connection with, and
convey accounts receivable as part of, a permitted receivables financing, the aggregate principal of which shall not exceed $400.0
million).
On June 7, 2019, the Partnership entered into the First Amendment to the Existing TRP Revolver (the “First Amendment”). The First
Amendment, among other things, amended the Existing TRP Revolver to (a) increase the maximum percentage of Consolidated
EBITDA attributable to Material Project EBITDA Adjustments from 20% to 30% solely for the fiscal periods from and including the
fiscal period ending June 30, 2019 until and including the fiscal period ending June 30, 2020, after which time the maximum
percentage of Consolidated EBITDA attributable to Material Project EBITDA Adjustments shall revert to 20% of Consolidated
EBITDA and (b) include in the calculation of Consolidated EBITDA for a period certain cash distributions received by the Partnership
(or and of its consolidated restricted subsidiaries) from unrestricted subsidiaries (or entities that are not subsidiaries) after the end of
such period but on or prior to the date that TRP calculates Consolidated EBITDA for such period.
In February 2022, in connection with entering into the New TRC Revolver, we terminated the Existing TRP Revolver.
The Partnership’s Accounts Receivable Securitization Facility
In April 2021, we amended the Securitization Facility to increase the facility size from $350.0 million to $400.0 million to more
closely align with our expected borrowing needs given current commodity prices and to extend the facility termination date to April
21, 2022.
The Securitization Facility provides up to $400.0 million of borrowing capacity at LIBOR market index rates plus a margin through
April 21, 2022. Under the Securitization Facility, certain Partnership subsidiaries sell or contribute certain qualifying receivables,
without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated
subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the
eligible receivables to third-party financial institutions. Sold or contributed receivables up to the amount of the outstanding debt under
the Securitization Facility are not available to satisfy the claims of the creditors of the selling or contributing subsidiaries or the
Partnership. Any excess receivables are eligible to satisfy the claims.
The Partnership’s Senior Unsecured Notes
All issues of senior unsecured notes are pari passu with existing and future senior indebtedness. They are senior in right of payment to
any of our future subordinated indebtedness and are unconditionally guaranteed by the Partnership and the Partnership’s restricted
subsidiaries. These notes are effectively subordinated to all secured indebtedness under the New TRC Revolver and the Securitization
Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that
indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.
The Partnership’s senior unsecured notes and associated indenture agreements 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 either Moody’s or S&P and no Default or Event of Default (each 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.
The Partnership may redeem the senior unsecured notes, in whole or in part, at any time prior to their maturity at a redemption price
equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest and liquidation damages, if
any, to the redemption date, as specified in the indenture of each series.
F-28
The Partnership may also redeem up to 35% of the aggregate principal amount of each series of notes at the redemption dates and
prices set forth in the indentures plus accrued and unpaid interest and liquidation damages, if any, to the redemption date with the net
cash proceeds of one or more equity offerings, provided that: (i) 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 (ii) the redemption occurs
within 180 days of the date of the closing of such equity offering.
The Partnership may also redeem all or part of each of the series of senior unsecured notes on or after the redemption dates as
specified in the indenture of each series at the redemption prices as specified in the indenture of each series plus accrued and unpaid
interest to the redemption date and liquidation damages, if any, on the notes redeemed.
Senior Unsecured Notes Issuances
In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes
due January 2029, resulting in total net proceeds of $1,486.6 million. The net proceeds from the issuance were used to redeem in full
the Partnership’s outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date, with the
remainder used to repay borrowings under the Existing TRP Revolver and for general partnership purposes.
In November 2019, the Partnership issued $1.0 billion aggregate principal amount of 5½% Senior Notes due March 2030, resulting in
net proceeds of $990.8 million. The net proceeds from the issuance were used to repay borrowings under the Existing TRP Revolver
and for general partnership purposes.
In August 2020, the Partnership issued $1.0 billion aggregate principal amount of 4⅞% Senior Notes due 2031 (the “August 2020
Offering”), resulting in net proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund
the concurrent cash tender offer (the “August Tender Offer”) of the Partnership’s 6¾% Senior Notes due 2024 (the “6¾% Notes”) and
redeem any 6¾% Notes that remained outstanding after consummation of the August Tender Offer, with the remainder used for
repayment of borrowings under the Existing TRP Revolver. See “Debt Repurchases and Extinguishments” for further details of the
August Tender Offer.
In February 2021, the Partnership issued $1.0 billion aggregate principal amount of 4% Senior Notes due 2032 (the “February 2021
Offering”), resulting in net proceeds of approximately $991 million. The 4% Senior Notes due 2032 have substantially similar terms
and covenants as our other series of Senior Notes. A portion of the net proceeds from the issuance was used to fund the concurrent
cash tender offer (the “February Tender Offer”) and subsequent redemption payment for the Partnership’s 5⅛% Senior Notes due
2025 (the “5⅛% Notes”), with the remainder used for repayment of borrowings under the Existing TRP Revolver and Existing TRC
Revolver. See “Debt Repurchases and Extinguishments” for further details of the February Tender Offer.
May 2019 Shelf Registration
Our universal shelf registration statement on Form S-3 filed in May 2016 (the “May 2016 Shelf”) expired in May 2019. Accordingly,
in May 2019, we filed with the SEC a universal shelf registration statement on Form S-3 that registers the issuance and sale of certain
debt and equity securities from time to time in one or more offerings (the “May 2019 Shelf”). The May 2019 Shelf will expire in May
2022. See Note 12 – Common Stock and Related Matters.
Debt Repurchases & Extinguishments
In February 2019, the Partnership redeemed in full its outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest
through the redemption date. The redemption resulted in a non-cash loss due to write-off $1.4 million of unamortized debt issuance
costs.
During the first half of 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $239.8
million plus accrued interest to repurchase $303.3 million of the notes. As a result, we recorded a gain due to debt extinguishment of
$61.1 million, comprised of $63.5 million discounts and a write-off of $2.4 million in related debt issuance costs.
Concurrent with the August 2020 Offering, the Partnership commenced the August Tender Offer to purchase for cash, subject to
certain terms and conditions, any and all of our outstanding 6¾% Notes. We accepted for purchase all the notes that were validly
tendered as of the early tender date, which totaled $262.1 million. Subsequent to the closing of the August Tender Offer in August
2020, the Partnership redeemed the 6¾% Notes for the remaining note balance of $318.0 million (the “2024 Note Redemption”). As a
result of the August Tender Offer and the 2024 Note Redemption, we recorded a loss due to debt extinguishment of $13.7 million
comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.
F-29
In November 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023. As a result, we
recorded a loss due to debt extinguishment of $1.8 million related to a write-off of debt issuance costs.
Concurrent with the February 2021 Offering, the Partnership commenced the February Tender Offer to redeem subject to certain
terms and conditions, any and all of our outstanding 5⅛% Notes. As a result of the February Tender Offer and the subsequent
redemption of the 5⅛% Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of
premiums paid and a write-off of $2.4 million of debt issuance costs.
Additionally, TPL redeemed all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023
(collectively, the “TPL Notes”) in February 2021 with available liquidity under the Existing TRP Revolver. As a result of the
redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.
The Partnership redeemed all of the outstanding 4¼% Senior Notes due 2023 (the “4¼% Senior Notes”) in May 2021 with available
liquidity under the Existing TRP Revolver. As a result of the redemption of the 4¼% Senior Notes, we recorded a loss due to debt
extinguishment of $1.9 million.
Debt Repurchases and Extinguishments Summary
The following table summarizes the impact of debt repurchases and extinguishments that are included in our Consolidated Statements
of Operations:
Discount (premium) over face value paid upon redemption:
2021
2020
2019
TPL Notes
Partnership 5⅛% Senior Notes due 2025
Partnership 6¾% Senior Notes due 2024
Partnership 5⅞% Senior Notes due 2026
Partnership 5⅜% Senior Notes due 2027
Partnership 5% Senior Notes due 2028
Partnership 6½% Senior Notes due 2027
Partnership 6⅞% Senior Notes due 2029
Partnership 5½% Senior Notes due 2030
Write-off of debt issuance costs:
Partnership 5⅛% Senior Notes due 2025
Partnership 4¼% Senior Notes due 2023
Partnership 5¼% Senior Notes due 2023
Partnership 6¾% Senior Notes due 2024
Partnership 5⅞% Senior Notes due 2026
Partnership 5⅜% Senior Notes due 2027
Partnership 5% Senior Notes due 2028
Partnership 6½% Senior Notes due 2027
Partnership 6⅞% Senior Notes due 2029
Partnership 5½% Senior Notes due 2030
Partnership 4⅛% Senior Notes due 2019
Gain (loss) from financing activities
$
$
0.2
(12.5 )
—
—
—
—
—
—
—
(2.4 )
(1.9 )
—
—
—
—
—
—
—
—
—
(16.6 )
$
$
—
4.4
(11.1 )
7.1
5.3
11.7
9.3
15.5
10.2
(0.1 )
—
(1.8 )
(2.6 )
(0.2 )
(0.2 )
(0.4 )
(0.4 )
(0.6 )
(0.5 )
—
45.6
$
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1.4 )
(1.4 )
F-30
The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2021, for the
next five years, and in total thereafter:
Total
2022
Scheduled Maturities of Debt
2024
2025
2023
2026
Thereafter
Existing TRC Revolver
Existing TRP Revolver
Partnership's Senior unsecured notes
Securitization Facility
Total
$
$
— $
—
6,465.7
150.0
6,615.7 $
— $
—
—
150.0
150.0 $
— $
—
—
—
— $
— $
—
—
—
— $
— $
—
—
—
— $
— $
—
963.2
—
963.2 $
—
—
5,502.5
—
5,502.5
Subsequent Event
In February 2022, we entered into the New TRC Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent
and Swing Line Lender, and the other lenders party thereto. The New TRC Revolver provides for a revolving credit facility in an
initial aggregate principal amount up to $2.75 billion, with an option to increase such maximum aggregate principal amount by up to
$500.0 million in the future, subject to the terms of the New TRC Revolver, and a swing line sub-facility of up to $100.0 million. The
New TRC Revolver matures on February 17, 2027. In connection with the entry into the New TRC Revolver, we terminated the
Existing TRC Revolver and Existing TRP Revolver.
On February 18, 2022, we and certain of our subsidiaries entered into a Parent Guarantee to guarantee all of the obligations of the
Partnership and Targa Resources Partners Finance Corp. (together with the Partnership, the “Issuers”) under the respective indentures
governing the Issuers’ $6.5 billion of outstanding senior unsecured notes.
Note 9 — Other Long-term Liabilities
Other long-term liabilities are comprised of the following obligations:
Deferred revenue
Asset retirement obligations
Operating lease liabilities
Other liabilities
Total long-term liabilities
Deferred Revenue
December 31, 2021
December 31, 2020
171.8 $
72.1
34.5
23.2
301.6 $
168.5
68.3
46.2
26.1
309.1
$
$
Deferred revenue for the years ended December 31, 2021 and 2020, was $171.8 million and $168.5 million, respectively, which
includes $129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a
subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the
construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement.
The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The
timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent on the outcome of current litigation
with Vitol.
Deferred revenue also includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas
gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant
other observable inputs representative of a Level 2 fair value measurement. In December 2017, we received monetary consideration to
further amend the terms of the gas gathering and processing agreement. The deferred revenue related to these amendments is being
recognized on a straight-line basis through the end of the agreement’s term in 2035.
F-31
For the years ended December 31, 2021, 2020 and 2019, we recognized $3.9 million, $3.8 million and $3.9 million of revenue for
these transactions, respectively.
The following table shows the components of deferred revenue:
Splitter agreement
Gas contract amendment
Other
Total deferred revenue
The following table shows the changes in deferred revenue:
Balance at beginning of period
Additions
Revenue recognized
Balance at end of period
Asset Retirement Obligations
$
$
$
$
December 31, 2021
December 31, 2020
129.0 $
34.8
8.0
171.8 $
2021
2020
168.5 $
7.2
(3.9 )
171.8 $
129.0
37.3
2.2
168.5
172.0
0.3
(3.8 )
168.5
Our ARO primarily relate to certain gas gathering pipelines and processing facilities and NGL pipelines. The changes in our ARO are
as follows:
Beginning of period
Accretion expense
Retirement of ARO
Change in cash flow estimate
End of period
Note 10 – Leases
$
$
2021
2020
68.3 $
4.0
—
(0.2 )
72.1 $
66.3
3.6
0.2
(1.8 )
68.3
We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, and storage and terminal
assets. We have finance leases primarily associated with our tractors and vehicles. Our leases have remaining lease terms of 1 to 8
years, some of which include options to extend the lease term for up to 20 years.
The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated
Balance Sheets are as follows:
Right-of-use assets
Operating leases, gross
Finance leases, gross
Lease liabilities
Current:
Operating leases
Finance leases
Non-current:
Operating leases
Finance leases
Balance Sheet Location
2021
2020
Year Ended December 31,
Other long-term assets
Property, plant and equipment
$
Accrued liabilities
Current debt obligations
Other long-term liabilities
Long-term debt
$
$
50.8 $
55.6
11.7 $
12.8
34.5 $
13.7
52.7
51.8
12.0
12.1
46.2
18.7
F-32
Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our
Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and
amortization expense and Interest income (expense) in our Consolidated Statements of Operations. The components of lease expense
were as follows:
Lease cost
Operating lease cost
Short-term lease cost
Variable lease cost
Finance lease cost
Amortization of right-of-use assets
Interest expense
Total lease cost
Other supplemental information related to our leases are as follows:
Cash paid for amounts included in the measurement
of lease liabilities
Operating cash flows for operating leases
Operating cash flows for finance leases
Financing cash flows for finance leases
$
$
$
2021
Year Ended December 31,
2020
2019
12.2 $
20.4
5.7
13.3
1.1
52.7 $
11.6 $
20.7
5.5
13.6
1.4
52.8 $
9.9
30.0
6.7
13.1
1.6
61.3
2021
Year Ended December 31,
2020
2019
14.1 $
1.0
12.5
12.3 $
1.4
12.4
8.7
1.6
11.5
The weighted-average remaining lease terms for operating leases and finance leases are 6 years and 3 years, respectively. The
weighted-average discount rates for operating leases and finance leases are 4.0% and 3.4%, respectively.
The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2021:
2022
2023
2024
2025
2026
Thereafter
Total undiscounted cash flows
Less imputed interest
Total lease liabilities
Note 11 – Preferred Stock
Preferred Stock
Operating Leases
Finance Leases
13.3
11.5
7.1
4.2
3.9
11.6
51.6
(5.4 )
46.2
$
$
13.1
8.0
3.5
2.2
1.1
—
27.9
(1.4 )
26.5
$
$
Our Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly
45 days after the end of each fiscal quarter. The Series A Preferred has no mandatory redemption date, but is redeemable at our
election on or prior to March 16, 2022 for a 10% premium to the liquidation preference and for a 5% premium to the liquidation
preference thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right to convert the
Series A Preferred into TRC common stock at an exercise price of $20.77, which represented a 10% premium over the ten-day volume
weighted average price (“VWAP”) prior to the February 18, 2016 signing date ($18.88) of the Purchase Agreement underlying the
first of two tranches of Series A Preferred sold to investors in a private placement in the first quarter of 2016. If the investors do not
elect to convert their Series A Preferred into TRC common stock, Targa has a right after year twelve to force conversion, but only if
the VWAP for the ten preceding trading days is greater than 120% of the conversion price. A change of control provision could result
in forced redemption, at the option of the investor, if the Series A Preferred could not otherwise remain outstanding or be replaced
with a “substantially equivalent security.” The change of control premium to the liquidation preference on the redemption is 10% in
years four through six and 5% thereafter.
F-33
The Series A Preferred ranks senior to the common outstanding stock with respect to the payment of dividends and distributions in
liquidation. The holders of Series A Preferred generally only have voting rights in certain circumstances, subject to certain exceptions,
which include:
the issuance or the increase by the Company of any specific class or series of stock that is senior to the Series A Preferred,
the issuance or the increase by any of the Company’s consolidated subsidiaries of any specific class or series of securities,
changes to the Certificates of Incorporation or Designations of the Series A Preferred that would materially and adversely
affect the Preferred Stock holder,
the issuance of stock on parity with the Series A Preferred, subject to certain exceptions, if the Company has exceeded a
stipulated fixed charge coverage ratio or an aggregate amount of net proceeds from all future issuances of Parity Stock, or
would use the proceeds of such issuance to pay dividends,
the incurrence of indebtedness, other than indebtedness that complies with a stipulated fixed charge coverage ratio or
under the Existing TRC Revolver and Existing TRP Revolver (or replacement commercial bank facilities) in an aggregate
amount up to $2.75 billion.
The Series A Preferred does not qualify as a liability instrument because it is not mandatorily redeemable. However, as SEC
Regulation S-X, Rule 5-02-27 does not permit a probability assessment for a change of control provision, our Series A Preferred must
be presented as mezzanine equity between liabilities and shareholders’ equity on our Consolidated Balance Sheets because a change of
control event, although not considered probable, could force the Company to redeem the Series A Preferred. A maximum of
44,260,953 common shares would be issued upon conversion of the Series A Preferred.
Preferred Stock Dividends
As of December 31, 2021, we have accrued cumulative preferred dividends of $21.8 million, which were paid on February 14, 2022.
During the years ended December 31, 2021, 2020 and 2019, we paid $87.3 million, $91.7 million and $91.7 million of dividends at a
rate of $23.75 per share each quarter to Series A Preferred shareholders, and recorded deemed dividends of $39.2 million and $33.1
million for the years ended December 31, 2020 and 2019, attributable to accretion of the preferred discount resulting from BCF
accounting. Such accretion is included in the book value of the Series A Preferred. After adoption of ASU 2020-06 in 2021, we no
longer recognize such accretion. See Note 3 – Significant Accounting Policies for further information.
Preferred Stock Partial Redemption
In December 2020, we repurchased 45,800 shares of the Series A Preferred at $1,000 per share (the “Liquidation Preference”), plus an
amount equal to all unpaid dividends through the repurchase date. The repurchase was executed at a discount relative to the
redemption price of $1,100 per share (the Liquidation Preference multiplied by 110%), which became effective March 16, 2021. The
difference between the consideration paid (including unpaid dividends of $1.1 million) and the net carrying value of the shares
repurchased was $2.7 million, which was recorded as an addition to preferred stock dividends for the year ended December 31, 2020.
Note 12 — Common Stock and Related Matters
Public Offerings of Common Stock
On May 9, 2017, we entered into an equity distribution agreement under the May 2016 Shelf (the “May 2017 EDA”), pursuant to
which we may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock (“2017
ATM Program”).
On September 20, 2018, we entered into an equity distribution agreement under the May 2016 Shelf (the “September 2018 EDA”),
pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common
stock (“2018 ATM Program”).
In May 2019, we filed (i) the May 2019 Shelf, (ii) a new prospectus supplement to continue the 2017 ATM Program and (iii) a new
prospectus supplement to continue the 2018 ATM Program.
During 2020 and 2021, no shares of common stock were issued under either the May 2017 EDA or the September 2018 EDA. As a
result, we have $382.1 million and $750.0 million remaining under the May 2017 EDA and September 2018 EDA, respectively, as of
December 31, 2021.
F-34
Common Stock Dividends
The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2021,
2020 and 2019:
Three Months Ended
Date Paid or
To Be Paid
Total Common
Dividends Declared
Amount of
Common
Dividends Paid or
To Be Paid
Accrued
Dividends (1)
Dividends Declared
per Share of
Common Stock
(In millions, except per share amounts)
2021
December 31, 2021
September 30, 2021
June 30, 2021
March 31, 2021
2020
December 31, 2020
September 30, 2020
June 30, 2020
March 31, 2020
2019
December 31, 2019
September 30, 2019
June 30, 2019
March 31, 2019
$
$
$
February 15, 2022
November 15, 2021
August 16, 2021
May 14, 2021
February 16, 2021
November 16, 2020
August 17, 2020
May 15, 2020
February 18, 2020
November 15, 2019
August 15, 2019
May 15, 2019
81.4 $
23.3
23.3
23.3
23.3 $
23.8
23.7
23.7
216.0 $
215.5
215.1
215.2
80.1 $
22.9
22.9
22.9
22.9 $
23.3
23.3
23.3
212.0 $
211.8
211.5
211.5
1.3 $
0.4
0.4
0.4
0.4 $
0.5
0.4
0.4
4.0 $
3.7
3.6
3.7
0.35000
0.10000
0.10000
0.10000
0.10000
0.10000
0.10000
0.10000
0.91000
0.91000
0.91000
0.91000
(1)
Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
Note 13 — Partnership Units and Related Matters
Distributions
We are entitled to receive all Partnership distributions from available cash on the Partnership’s common units each quarter.
The following table details the distributions declared and/or paid by the Partnership during 2021, 2020 and 2019:
Three Months Ended
Date Paid or To Be Paid
Total Distributions
(In millions, except per share amounts)
Distributions to
Targa Resources Corp.
2021
2020
2019
December 31, 2021
September 30, 2021
June 30, 2021
March 31, 2021
December 31, 2020
September 30, 2020
June 30, 2020
March 31, 2020
December 31, 2019
September 30, 2019
June 30, 2019
March 31, 2019
Contributions
February 11, 2022
November 11, 2021
August 12, 2021
May 12, 2021
February 11, 2021
November 13, 2020
August 13, 2020
May 13, 2020
February 13, 2020
November 13, 2019
August 13, 2019
April 5, 2019
$
$
$
103.7 $
45.6
45.5
47.0
54.3 $
51.7
51.7
53.1
241.9 $
242.1
242.4
437.8
103.7
45.6
45.5
47.0
47.6
48.9
48.9
50.3
239.1
239.3
239.6
435.0
All capital contributions to the Partnership continue to be allocated 98% to the limited partner and 2% to the general partner; however,
no units will be issued for those contributions. For the years ended December 31, 2021, 2020 and 2019, we made a total of $46.0
million, $50.0 million and $200.0 million in contributions to the Partnership.
F-35
Preferred Units
In December 2020, the Partnership redeemed all of its 5,000,000 issued and outstanding Preferred Units at a redemption price of
$25.00 per unit, plus an amount equal to all unpaid distributions up to the date of redemption. The difference between the
consideration paid (including unpaid distributions of $0.5 million) and the net carrying value of the units redeemed was $4.9 million,
which was recorded as an increase to Net income (loss) attributable to noncontrolling interests for the year ended December 31, 2020.
The Preferred Units were reported as noncontrolling interests in our financial statements and were previously listed on the NYSE
under the symbol “NGLS/PA” and are no longer traded following the redemption.
For the years ended December 31, 2020 and 2019, the Partnership paid total distributions of $15.1 million and $11.3 million to the
Preferred Unitholders.
Note 14 — Earnings per Common Share
The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and
diluted net income per common share:
Net income (loss) attributable to Targa Resources Corp.
Less: Dividends on Series A Preferred (1)
Less: Deemed dividends on Series A Preferred (2)
Net income (loss) attributable to common shareholders for basic earnings per share
Weighted average shares outstanding - basic
Dilutive effect of unvested stock awards (3)
Weighted average shares outstanding - diluted
Net income (loss) available per common share - basic
Net income (loss) available per common share - diluted
2021
Year Ended December 31,
2020
(In millions, except per share amounts)
2019
71.2 $
87.3
—
(16.1 ) $
228.6
—
228.6
(0.07 ) $
(0.07 ) $
(1,553.9 ) $
91.7
39.2
(1,684.8 ) $
232.2
—
232.2
(7.26 ) $
(7.26 ) $
(209.2 )
91.7
33.1
(334.0 )
232.5
—
232.5
(1.44 )
(1.44 )
$
$
$
$
(1)
(2)
(3)
Includes $1.1 million attributable to the dividends paid upon the partial repurchase of Series A Preferred in December 2020.
Includes $1.6 million attributable to the partial repurchase of Series A Preferred in December 2020. Refer to Note 11 – Preferred Stock.
For all periods presented above, all unvested restricted stock awards and Series A Preferred were antidilutive because a net loss existed for those respective
periods.
The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the
inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis):
Unvested restricted stock awards
Series A Preferred (1)
2021
Year Ended December 31,
2020
2019
3.3
44.3
2.3
46.4
1.2
46.5
(1)
The Series A Preferred has no mandatory redemption date, but is redeemable at our election for a 10% premium to the liquidation preference on or prior to
March 16, 2022 and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed prior to March 16, 2028, the investors
have the right to convert the Series A Preferred into TRC common stock.
Note 15 — Derivative Instruments and Hedging Activities
The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce
volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the
commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering
and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in
our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment.
The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in
periods of rising commodity prices and are primarily designated as cash flow hedges for accounting purposes.
F-36
The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural
gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges
or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We
believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy”
hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.
We hedge a portion of our condensate equity volumes 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 exposes us to a market differential
risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
We also enter into derivative instruments to help manage other short-term commodity-related business risks and take advantage of
market opportunities. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to
revenues as current income.
At December 31, 2021, the notional volumes of our commodity derivative contracts were:
Commodity
Natural Gas
Natural Gas
NGL
NGL
Condensate
Instrument
Swaps
Basis Swaps
Swaps
Futures
Swaps
Unit
MMBtu/d
MMBtu/d
Bbl/d
Bbl/d
Bbl/d
2022
152,262
339,925
33,936
8,099
4,790
2023
83,862
275,000
19,228
—
3,055
2024
34,221
240,000
7,292
—
1,070
2025
7,479
110,041
—
—
—
Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset
and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our
Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules
reflect the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma
reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
Derivatives designated as hedging instruments
Commodity contracts
Total derivatives designated as hedging instruments
Derivatives not designated as hedging instruments
Commodity contracts
Total derivatives not designated as hedging instruments
Total current position
Total long-term position
Total derivatives
Fair Value as of
December 31, 2021
Fair Value as of
December 31, 2020
Balance Sheet
Location
Derivative
Assets
Derivative
Liabilities
Derivative
Assets
Derivative
Liabilities
Current
$
Long-term
$
Current
$
Long-term
$
$
$
25.5 $
6.2
31.7 $
17.6 $
1.5
19.1 $
43.1 $
7.7
50.8 $
(252.6 ) $
(84.3 )
(336.9 ) $
(5.6 ) $
(25.0 )
(30.6 ) $
(258.2 ) $
(109.3 )
(367.5 ) $
24.2 $
5.1
29.3 $
61.3 $
44.2
105.5 $
85.5 $
49.3
134.8 $
(140.2 )
(43.4 )
(183.6 )
(2.4 )
—
(2.4 )
(142.6 )
(43.4 )
(186.0 )
F-37
The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:
December 31, 2021
Asset
Liability
Collateral
Gross Presentation
Pro Forma Net Presentation
Liability
Asset
Current Position
Counterparties with offsetting positions or collateral
Counterparties without offsetting positions - assets
Counterparties without offsetting positions - liabilities
$
Long-Term Position
Counterparties with offsetting positions or collateral
Counterparties without offsetting positions - assets
Counterparties without offsetting positions - liabilities
Total Derivatives
Counterparties with offsetting positions or collateral
Counterparties without offsetting positions - assets
Counterparties without offsetting positions - liabilities
Current Position
December 31, 2020
Counterparties with offsetting positions or collateral
Counterparties without offsetting positions - assets
Counterparties without offsetting positions - liabilities
Long-Term Position
Counterparties with offsetting positions or collateral
Counterparties without offsetting positions - assets
Counterparties without offsetting positions - liabilities
Total Derivatives
Counterparties with offsetting positions or collateral
Counterparties without offsetting positions - assets
Counterparties without offsetting positions - liabilities
39.2 $
3.9
—
43.1
(241.9 ) $
—
(16.3 )
(258.2 )
7.4
0.3
—
7.7
(95.1 )
—
(14.2 )
(109.3 )
46.6
4.2
—
50.8 $
(337.0 )
—
(30.5 )
(367.5 ) $
5.0 $
—
—
5.0
3.1
—
—
3.1
8.1
—
—
8.1 $
0.3 $
3.9
—
4.2
—
0.3
—
0.3
0.3
4.2
—
4.5 $
(198.0 )
—
(16.3 )
(214.3 )
(84.6 )
—
(14.2 )
(98.8 )
(282.6 )
—
(30.5 )
(313.1 )
Gross Presentation
Asset
Liability
Collateral
Pro Forma Net Presentation
Liability
Asset
81.1 $
4.4
—
85.5
(142.0 ) $
—
(0.6 )
(142.6 )
29.8 $
—
—
29.8
37.8
11.5
—
49.3
(42.5 )
—
(0.9 )
(43.4 )
—
—
—
—
118.9
15.9
—
134.8 $
(184.5 )
—
(1.5 )
(186.0 ) $
29.8
—
—
29.8 $
$
15.7 $
4.4
—
20.1
14.6
11.5
—
26.1
30.3
15.9
—
46.2 $
(46.8 )
—
(0.6 )
(47.4 )
(19.3 )
—
(0.9 )
(20.2 )
(66.1 )
—
(1.5 )
(67.6 )
$
$
Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral
securing the New TRC Revolver that ranks equal in right of payment with liens granted in favor of Targa’s senior secured lenders.
Some of our hedges are futures contracts executed through brokers that clear the hedges through an exchange. We maintain a margin
deposit with the brokers in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is
considered collateral, which is located within Other current assets on our Consolidated Balance Sheets and is not offset against the fair
value of our derivative instruments.
The fair value of our 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
estimated fair value of our derivative instruments was a net liability of ($316.7) million as of December 31, 2021. As of December 31,
2021, all our commodity derivative instruments were in a net liability position, and as such, we had no counterparty credit risk
exposure as of that date. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated
by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented.
Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.
The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue for the periods indicated:
Derivatives in Cash Flow
Hedging Relationships
Commodity contracts
Location of Gain (Loss)
Revenues
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
2019
2020
2021
$
(534.6 ) $
(218.3 )
$
135.6
Gain (Loss) Reclassified from OCI into Income (Effective Portion)
2019
2020
2021
$
(417.3 ) $
90.8
$
138.0
F-38
Based on valuations as of December 31, 2021, we expect to reclassify commodity hedge related deferred losses of ($304.0) million
included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2025, with ($225.9)
million of losses to be reclassified over the next twelve months.
Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative 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 sheet and through earnings rather than being deferred until the anticipated transaction settles. 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. For the year ended December 31, 2021, the unrealized mark-to-market losses are primarily attributable to
unfavorable movements in natural gas forward basis prices, as compared to our positions.
Derivatives Not Designated
as Hedging Instruments
Commodity contracts
Location of Gain (Loss)
Recognized in Income
on Derivatives
Revenue
Gain (Loss) Recognized in Income on Derivatives
2019
2020
2021
$
(73.3 )
$
206.1
$
(142.1 )
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Note 16 – Fair Value Measurements and Note 25 –
Segment Information for additional disclosures related to derivative instruments and hedging activities.
Note 16 — Fair Value Measurements
Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities
(“financial instruments”). Derivative financial instruments are reported at fair value on our Consolidated Balance Sheets. Other
financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are
additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
Fair Value of Derivative Financial Instruments
Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward
commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods
or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We
have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate
information available for the types of derivative contracts we hold.
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The
financial position of these derivatives at December 31, 2021, a net liability position of ($316.7) million, reflects the present value,
adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward
pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of
($458.3) million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value
reflecting a net liability of ($175.1) million.
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash
equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial
instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures
for our long-term debt as follows:
The Existing TRC Revolver, Existing TRP Revolver, and the Securitization Facility are based on carrying value, which
approximates fair value as their interest rates are based on prevailing market rates; and
The Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.
F-39
Fair Value Hierarchy
We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date 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 we can directly or indirectly observe to the extent that the
markets are liquid for the relevant settlement periods; and
Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.
The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our
Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)
Liabilities from commodity derivative contracts (1)
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents
Existing TRC Revolver
Existing TRP Revolver
Partnership's Senior unsecured notes
Securitization Facility
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)
Liabilities from commodity derivative contracts (1)
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents
Existing TRC Revolver
Existing TRP Revolver
Partnership's Senior unsecured notes
Securitization Facility
Carrying
Value
December 31, 2021
Fair Value
Total
Level 1
Level 2
Level 3
$
$
46.6
363.3
$
46.6
363.3
$
—
—
$
46.6
363.3
158.5
—
—
6,465.7
150.0
158.5
—
—
6,924.5
150.0
—
—
—
—
—
—
—
—
6,924.5
150.0
—
—
—
—
—
—
—
Carrying
Value
December 31, 2020
Fair Value
Total
Level 1
Level 2
Level 3
$
$
134.8
186.0
$
134.8
186.0
$
—
—
$
134.8
185.8
—
0.2
242.8
555.0
280.0
6,585.4
350.0
242.8
555.0
280.0
7,036.8
350.0
—
—
—
—
—
—
555.0
280.0
7,036.8
350.0
—
—
—
—
—
(1)
The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 15 –
Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the
Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have
both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.
Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets
We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable
market prices or implied volatilities for substantially the full term of the derivative asset or liability. For valuations that include both
observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation
is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into
unobservable periods.
The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis
curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on
observable or public data sources and extrapolated when observable prices are not available.
F-40
The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were (i) the forward natural gas
liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied
volatilities, which are unobservable as a result of inactive natural gas liquids options trading. As of December 31, 2021, we had no
derivative contracts categorized as Level 3.
The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
Balance, December 31, 2020
Transfers out of Level 3 (1)
Balance, December 31, 2021
Commodity
Derivative Contracts
Asset (Liability)
$
$
(0.2 )
0.2
—
(1)
Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis upon impairment.
During the year ended December 31, 2021, we recorded a non-cash pre-tax impairment of $452.3 million. The impairment charge is
primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central
operations in our Gathering and Processing segment. During the year ended December 31, 2020, we recorded non-cash pre-tax
impairments of $2,442.8 million. The impairment charge is primarily associated with the partial impairment of certain gas processing
facilities and gathering systems associated with our Central operations and full impairment of our Coastal operations. During the year
ended December 31, 2019, we recorded non-cash pre-tax impairments of $225.3 million. The impairment charge is primarily
associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central and
Coastal operations. For disclosures related to valuation techniques, see Note 5 – Property, Plant and Equipment and Intangible Assets.
The techniques described above may produce a fair value calculation that may not be indicative or reflective of future fair values.
Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of
different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a
different fair value measurement at the reporting date.
Note 17 — Related Party Transactions
Transactions with Unconsolidated Affiliates
The following table summarizes transactions with unconsolidated affiliates:
2021:
Revenues
Product purchases and fuel
Operating expenses
General and administrative expenses
2020:
Revenues
Product purchases and fuel
Operating expenses
General and administrative expenses
2019:
Revenues
Product purchases and fuel
Operating expenses
General and administrative expenses
$
$
$
GCF
T2 Joint
Ventures
Cayenne
GCX
Missouri 4
Little
Agua
Blanca
Total
— $
—
(1.1 )
—
0.4 $
—
(16.0 )
—
0.3 $
(7.9 )
—
—
4.4 $
—
(2.3 )
—
4.5 $
—
(1.2 )
—
3.7 $
—
(2.0 )
—
— $
— $
(4.8 )
(0.2 )
—
(66.5 )
—
—
— $
0.2 $
(5.9 )
(0.2 )
—
(67.2 )
—
—
— $
0.5 $
(7.9 )
(0.2 )
—
(24.3 )
—
—
10.6 $
—
(2.5 )
(0.8 )
12.6 $
—
(2.2 )
(0.8 )
6.3 $
—
—
(0.3 )
— $
—
—
—
— $
—
—
—
— $
—
(1.2 )
—
15.0
(71.3 )
(6.1 )
(0.8 )
17.7
(73.1 )
(19.6 )
(0.8 )
10.8
(40.1 )
(3.4 )
(0.3 )
F-41
Relationship with Targa Resources Partners LP
We provide general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and
assets acquired from third parties. The Partnership Agreement between the Partnership and us, as general partner of the Partnership,
governs the reimbursement of costs incurred on behalf of the Partnership.
The employees supporting the Partnership’s operations are our employees. The Partnership reimburses us for the payment of certain
operating expenses, including compensation and benefits of operating personnel assigned to the Partnership’s assets, and for the
provision of various general and administrative services for the benefit of the Partnership. 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. Since October 1, 2010, substantially all
of our general and administrative costs have been allocated to the Partnership, other than costs attributable to our status as a separate
reporting company.
Note 18 — Commitments
Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years
and in aggregate thereafter:
Land sites and rights of way (1)
In Aggregate
$
237.3 $
2022
2023
2024
2025
4.5 $
4.6 $
5.2 $
6.6 $
2026
Thereafter
207.8
8.6 $
(1)
Land site lease and rights of way provides 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, with varying terms, some of which are perpetual.
Total expenses incurred under the above non-cancelable commitments were:
Land sites and rights of way
$
5.9
$
6.5
$
6.1
2021
2020
2019
Note 19 – Contingencies
Legal Proceedings
We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course
of our business. We and the Partnership are also parties to various proceedings with governmental environmental agencies, including,
but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of
Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota
Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including
air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities
in the ordinary course of our business.
Note 20 – Revenue
Fixed consideration allocated to remaining performance obligations
The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting
period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a
guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation,
export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 18 years.
Fixed consideration to be recognized as of December 31, 2021
2022
2023
2024 and after
$
468.4 $
396.2 $
2,290.8
Based on the optional exemptions that we elected to apply, the amounts presented in the table above exclude remaining performance
obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration
of one year or less.
For additional information on our revenue recognition policy, see Note 3 – Significant Accounting Policies, and for disclosures related
to disaggregated revenue, see Note 25 – Segment Information.
F-42
Note 21 – Other Operating (Income) Expense
Other operating (income) expense is comprised of the following:
2021
Year Ended December 31,
2020
2019
(Gain) loss on sale or disposition of business and assets
Write-down of assets (1)
Other
$
$
2.0
10.3
0.1
12.4
$
$
58.4
55.6
2.6
116.6
(1)
Related to the write-down of certain assets to their recoverable amounts.
The (Gain) loss on sale or disposition of business and assets is comprised of the following:
Channelview asset sale (1)
Delaware crude system (1)
Other
2021
Year Ended December 31,
2020
—
—
2.0
2.0
$
$
58.3
—
0.1
58.4
$
$
(1)
Refer to Note 4 – Joint Ventures and Divestitures for further discussion regarding these sales.
Note 22 – Income Taxes
Components of the federal and state income tax provisions for the periods indicated are as follows:
$
$
$
$
71.1
17.9
0.2
89.2
—
59.5
11.6
71.1
2019
Current expense (benefit)
Deferred expense (benefit)
Total income tax expense (benefit)
2021
2020
2019
$
$
2.7 $
12.1
14.8 $
(15.4 ) $
(232.7 )
(248.1 ) $
—
(87.9 )
(87.9 )
Our deferred income tax assets and liabilities as of December 31, 2021 and 2020 consist of recognition differences related to certain
types of costs as follows:
Deferred tax assets:
Net operating loss
Other
Deferred tax assets before valuation allowance
Valuation allowance
Deferred tax assets
Deferred tax liabilities:
Investments (1)
Property, plant, and equipment
Other
Deferred tax liabilities
Net deferred tax asset (liability)
Net deferred tax asset (liability)
Federal
State
Long-term deferred tax liability, net
2021
2020
1,411.3 $
—
1,411.3
(210.6 )
1,200.7
(1,323.0 )
(4.1 )
(9.6 )
(1,336.7 )
(136.0 ) $
(106.7 ) $
(29.3 )
(136.0 ) $
1,573.5
—
1,573.5
(196.5 )
1,377.0
(1,519.4 )
(4.0 )
(5.7 )
(1,529.1 )
(152.1 )
(147.7 )
(4.4 )
(152.1 )
$
$
$
$
F-43
(1) Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership.
During the preparation of the Company's 2021 consolidated financial statements, the Company identified errors related to its 2020
state tax provision. The Company does not believe these errors are material to its previously issued historical consolidated financial
statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. In 2021, the Company
recorded an additional $23.3 million of income tax expense in the Consolidated Statements of Operations and corresponding increase
to its deferred tax liabilities in the Consolidated Balance Sheets.
On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act was enacted. The CARES Act provided
corporate taxpayers an expanded five-year net operating loss (“NOL”) carryback period for losses generated in tax years 2018 through
2020. Additionally, the CARES Act allowed corporate taxpayers to request an immediate refund of alternative minimum tax credits.
We requested a cash refund from the Internal Revenue Service (“IRS”) of approximately $44 million related to the CARES Act
provisions and received the refund in the second quarter of 2020.
All federal statutes of limitations for returns filed in 2018 (for calendar year 2017) have expired. For Texas, the statute of limitations
has expired for 2017 returns (for calendar year 2016). Similarly, the statute of limitations expired on substantially all other 2017 state
income tax returns that were filed prior to October 15, 2018.
As of December 31, 2021, we have total NOL carryforwards of $6.0 billion, $1.4 billion of which will expire between 2036 and 2037.
The remaining $4.6 billion NOL will not expire, but is limited to offsetting 80% of taxable income per year. During 2020, we recorded
a federal tax-effected valuation allowance of $194.2 million against our deferred tax assets, primarily due to the tax consequences of
the impairment of long-lived assets. See Note 5 – Property Plant and Equipment and Intangible Assets. Our total tax effected balance
at December 31, 2020 was $196.5 million. As of December 31, 2021, our tax effected valuation allowance was $210.6 million, an
increase of $14.1 million from December 31, 2020. Of this valuation allowance, $164.0 million of the valuation allowance is federal,
and the remaining $46.6 million is state. The decrease in the federal valuation allowance is primarily because of positive book
earnings in 2021, and the increase in the state valuation allowance is due to the establishment of a state valuation allowance in 2021.
As we continue to sustain profitability, we will give more weight to projections of future taxable income to determine whether such
projections provide adequate taxable income to realize our deferred tax assets. This evaluation may result in a change to our valuation
allowance within the next twelve months. The change could result in a full release of the valuation allowance by year ended 2022.
Set forth below is the 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 our Consolidated Statements of Operations for the periods indicated:
Income tax reconciliation:
Income (loss) before income taxes
Less: Net income attributable to noncontrolling interest
Income attributable to TRC before income taxes
Federal statutory income tax rate
Provision for federal income taxes
Valuation allowance
State income taxes, net of federal tax benefit
CARES Act NOL carryback
Return-to-provision
Change in statutory income tax rate
Permanent adjustments
Stock compensation shortfall
Other, net
Income tax provision (benefit)
2021
2020
2019
$
$
436.9 $
(350.9 )
86.0
21 %
18.1
14.1
(5.4 )
—
(39.3 )
21.0
4.1
1.4
0.8
14.8 $
(1,573.1 ) $
(228.9 )
(1,802.0 )
21 %
(378.4 )
194.2
(51.2 )
(16.9 )
—
—
4.5
—
(0.3 )
(248.1 ) $
(46.7 )
(250.4 )
(297.1 )
21 %
(62.4 )
—
(5.8 )
—
—
(14.4 )
(6.3 )
—
1.0
(87.9 )
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.
Subsequent Event
In January 2022, the IRS notified us that it will examine Targa’s NOL carryback previously claimed under the CARES Act. We are
cooperating with the IRS in the audit process and do not anticipate material changes in prior year taxable income.
F-44
Note 23 - Supplemental Cash Flow Information
Cash:
Interest paid, net of capitalized interest (1)
Income taxes (received) paid, net
Non-cash investing activities:
$
Change in deadstock commodity inventory
Impact of capital expenditure accruals on property, plant and equipment, net
Transfers from materials and supplies inventory to property, plant and
equipment
Change in ARO liability and property, plant and equipment due to revised
cash flow estimate and additions
$
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests
Reduction of owner's equity related to accrued dividends on unvested equity
awards under share compensation arrangements
Accretion of deemed dividends on Series A Preferred
$
Non-cash balance sheet movements related to assets held for sale (2):
Trade receivables
Intangible assets, net accumulated amortization and estimated loss on sale
Goodwill
Property, plant and equipment, net of accumulated depreciation and estimated
loss on sale
Accounts payable and accrued liabilities
Other long-term obligations
$
Lease liabilities arising from recognition of right-of-use assets:
Operating lease
Finance lease
$
2021
Year Ended December 31,
2020
2019
356.0 $
1.3
(15.0 ) $
53.0
2.4
(0.2 )
$
$
374.1
43.7
5.3
(226.9 )
2.1
(1.8 )
(50.9 ) $
(5.2 )
$
3.1
—
— $
—
—
—
—
—
20.1 $
24.7
$
5.4
37.6
—
—
—
—
—
—
$
13.2
6.0
287.7
(1.9 )
21.8
(194.4 )
25.1
6.7
91.7
14.2
33.1
6.9
52.1
1.4
77.3
6.2
0.2
6.9
10.1
(1) Interest capitalized on major projects was $4.1 million, $33.0 million and $61.8 million for the years ended December 31, 2021, 2020 and 2019.
(2) Includes non-cash balance sheet movements related to the sale of our crude gathering and storage business assets in the Permian Delaware, which was classified as
held for sale as of December 31, 2019. See Note 4 – Joint Ventures and Divestitures.
Note 24 – Compensation Plans
2010 TRC Stock Incentive Plan
In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan for employees, consultants and non-employee
directors of the Company. In May 2017, the 2010 TRC Plan was amended and restated (the “2010 TRC Plan”). Total authorized
shares of common stock under the plan is 15,000,000, comprised of 5,000,000 shares originally available and an additional 10,000,000
shares that became available in May 2017. The 2010 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 granted in conjunction with Options or
Phantom Stock Awards, (iv) restricted stock awards, (v) phantom stock awards, (vi) bonus stock awards, (vii) performance unit
awards, or (viii) any combination of such awards.
Unless otherwise specified, the compensation costs for the awards listed below were recognized as expenses over related vesting
periods based on the grant-date fair values, reduced by forfeitures incurred.
Restricted Stock Awards - Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be
accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the
dividends, and paid in cash when the award vests. Upon issuance, the restricted stock awards will be included in the outstanding
shares of our common stock.
Director Grants – The Compensation Committee of the Targa board of directors (the “Compensation Committee”) awarded our
common stock to our outside directors. In 2021, 2020 and 2019, we issued 67,591, 31,621 and 25,344 shares of director grants with
the weighted average grant-date fair value of $30.33, $39.85 and $42.83, respectively.
F-45
Restricted Stock Units Awards – Restricted Stock Units (“RSUs”) are similar to restricted stock, except that shares of common stock
are not issued until the RSUs vest. The vesting periods generally vary from one year to six years. In 2021, 2020 and 2019, we issued
848,630, 1,299,592 and 1,042,344 shares of RSUs with the weighted average grant-date fair value of $37.94, $24.64 and $39.95. The
2020 and 2019 issuances include, 16,134 and 85,547 shares of RSUs for our retention program. These shares will vest in October
2022.
Restricted Stock Units in Lieu of Bonus – In 2020 and 2019, we granted 81,336 and 95,687 shares of RSUs in lieu of cash bonuses for
our executives at the weighted average grant-date fair value of $41.39 and $42.83. These awards cliff vest over one to three years.
The following table summarizes the restricted stock and RSUs under the 2010 TRC Plan in shares and in dollars for the year indicated.
Outstanding at December 31, 2020
Granted
Forfeited
Vested
Outstanding at December 31, 2021
Performance Share Units
Number
of shares
Weighted Average
Grant-Date Fair Value
3,835,856
$
916,221
(77,251 )
(983,998 )
3,690,828
40.81
37.38
35.57
50.72
37.42
During 2021, 2020 and 2019, we granted 319,320, 291,365 and 261,245 performance share units (“PSUs”) to executive management
for the 2021, 2020 and 2019 compensation cycle that will vest/have vested in January 2024, January 2023 and January 2022. The
PSUs granted under the 2010 TRC Plan are three-year equity-settled awards linked to the performance of shares of our common stock.
The awards also include dividend equivalent rights (“DERs”) that are based on the notional dividends accumulated during the vesting
period.
The vesting of the PSUs is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s
total shareholder return (“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream
companies (the “LTIP Peer Group”) measured over designated periods. For the PSUs granted in 2019, the TSR performance factor is
determined by the Compensation Committee at the end of the overall performance period based on relative performance over the
designated weighting periods as follows: (i) 25% based on annual relative TSR for the first year; (ii) 25% based on annual relative
TSR for the second year; (iii) 25% based on annual relative TSR for the third year; and (iv) the remaining 25% based on cumulative
three-year relative TSR over the entirety of the performance period. For the PSUs granted in 2020 and 2021, the TSR performance
factor is determined by the Compensation Committee based on relative TSR over a cumulative three-year performance period.
With respect to the PSUs granted in 2019, the weighting period(s), the Compensation Committee determines a guideline performance
percentage, which could range from 0% to 250%, based upon the Company’s relative TSR performance for the applicable period. The
TSR performance factor will be calculated by averaging the guideline performance percentage for each weighting period, and the
average percentage may then be decreased or increased by the Compensation Committee at its discretion. With respect to the three
year performance period of the PSUs granted in 2020 and 2021, the Compensation Committee determines a guideline performance
percentage for the performance period and the percentage may then be decreased or increased by the Compensation Committee at its
discretion. The grantee will become vested in a number of PSUs equal to the target number awarded multiplied by the TSR
performance factor, and vested PSUs will be settled by the issuance of Company common stock. The value of dividend equivalent
rights will be paid in cash when the awards vest.
Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant
date. The compensation cost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that
incorporates peer ranking. DERs associated with equity-settled PSUs were accrued over the performance period as a reduction of
owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model and historical volatility assumption with
an expected term of three years. The expected volatilities were 83%, 73% and 32% - 37% for PSUs granted in 2021, 2020 and 2019.
F-46
The following table summarizes the PSUs under the 2010 TRC Plan in shares and in dollars for the years indicated.
Outstanding at December 31, 2020
Granted
Vested
Outstanding at December 31, 2021
Cash-settled Awards
Number
of shares
Weighted Average
Grant-Date Fair Value
719,054
$
319,320
(171,165 )
867,209
70.53
56.36
81.02
63.24
During 2019, we issued 7,836 shares of cash-settled awards for our retention program. These awards are liability awards and vest each
quarter for one year. The fair value of the awards is evaluated based on the average of TRC stock prices for the last ten trading days at
the end of each quarter. All cash-settled awards vested in 2019. Payments for the cash-settled awards are classified within operating
activities in the Consolidated Statements of Cash Flows.
Stock Compensation Expenses
Stock compensation expense under our plans totaled $59.2 million, $66.3 million, and $61.8 million for the years ended
December 31, 2021, 2020 and 2019. As of December 31, 2021, we have $69.2 million of unrecognized compensation expense
associated with share-based awards and an approximate remaining weighted average vesting periods of 1.9 years related to our various
compensation plans.
The fair values of share-based awards vested in 2021, 2020 and 2019 were $73.8 million, $62.7 million and $55.4 million. Cash
dividends paid for the vested awards were $8.7 million, $9.4 million and $15.0 million for 2021, 2020 and 2019.
In relation to our equity compensation plans, we recognized $1.6 million and $2.0 million of tax deficiencies for the years ended
December 31, 2021 and December 31, 2020, respectively, and $7.7 million in windfall tax benefits for the year ended December 31,
2019.
Subsequent Events
In January 2022, the Compensation Committee made the following awards under the 2010 TRC Plan.
31,117 shares of restricted stock to our outside directors that will vest in January 2023.
182,365 shares of RSUs to executive management for the 2022 compensation cycle that will vest in January 2025.
173,013 shares of PSUs to executive management for the 2022 compensation cycle that will vest in January 2025.
In January 2022, 63,907 shares of director grants vested with no shares withheld to satisfy tax withholding obligations.
In January 2022, 513,048 shares of 2019 PSUs vested with 203,759 shares withheld to satisfy tax withholding obligations.
In January 2022, 508,266 shares of RSUs vested with 181,835 shares withheld to satisfy tax withholding obligations.
Targa 401(k) Plan
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. As part of our cost reduction
measures in response to the COVID-19 pandemic, we temporarily suspended our matching contributions in the second quarter of
2020, and reinstated such contributions on January 1, 2021. We made contributions to the 401(k) plan totaling $21.8 million, $16.2
million and $23.7 million during 2021, 2020 and 2019.
F-47
Note 25 — Segment Information
We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the
Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the
products and services provided.
Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil
and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets
used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment's assets are
located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the
Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma
(including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three
Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and
also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs
and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other
businesses. The Logistics and Transportation segment also includes Grand Prix, which connects our gathering and processing
positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. The
associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the
pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.
Elimination of inter-segment transactions are reflected in the corporate and eliminations column.
Reportable segment information is shown in the following tables:
Revenues
Sales of commodities
Fees from midstream services
Intersegment revenues
Sales of commodities
Fees from midstream services
Revenues
Operating margin (1)
Other financial information:
Total assets (2)
Goodwill
Capital expenditures
Year Ended December 31, 2021
Gathering and
Processing
Logistics and
Transportation
Other
Corporate
and
Eliminations
Total
$
$
$
$
$
$
606.8 $
747.3
1,354.1
6,067.9
3.5
6,071.4
7,425.5 $
1,325.3 $
15,111.6 $
600.0
15,711.6
409.5
38.6
448.1
16,159.7 $
1,264.3 $
8,010.0 $
7,030.0 $
45.2 $
471.7 $
— $
78.1 $
(115.9 ) $
—
(115.9 )
—
—
—
(115.9 ) $
(115.9 )
14.0 $
— $
— $
— $
—
—
(6,477.4 )
(42.1 )
(6,519.5 )
(6,519.5 ) $
154.2 $
— $
10.7 $
15,602.5
1,347.3
16,949.8
—
—
—
16,949.8
15,208.2
45.2
560.5
(1) Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.
(2) Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.
F-48
Revenues
Sales of commodities
Fees from midstream services
Intersegment revenues
Sales of commodities
Fees from midstream services
Revenues
Operating margin (1)
Other financial information:
Total assets (2)
Goodwill
Capital expenditures
Year Ended December 31, 2020
Gathering and
Processing
Logistics and
Transportation
Other
Corporate
and
Eliminations
Total
$
$
$
$
$
$
659.9 $
487.2
1,147.1
2,173.2
6.5
2,179.7
3,326.8 $
1,017.7 $
6,281.4 $
602.1
6,883.5
205.9
31.5
237.4
7,120.9 $
1,128.0 $
8,743.5 $
6,860.0 $
45.2 $
293.9 $
— $
414.0 $
229.7 $
—
229.7
—
—
—
229.7 $
229.7
86.3 $
— $
— $
— $
—
—
(2,379.1 )
(38.0 )
(2,417.1 )
(2,417.1 ) $
7,171.0
1,089.3
8,260.3
—
—
—
8,260.3
185.9 $
— $
18.9 $
15,875.7
45.2
726.8
(1) Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.
(2) Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.
Revenues
Sales of commodities
Fees from midstream services
Intersegment revenues
Sales of commodities
Fees from midstream services
Revenues
Operating margin (1)
Other financial information:
Total assets (2)
Goodwill
Capital expenditures
Year Ended December 31, 2019
Gathering and
Processing
Logistics and
Transportation
Other
Corporate
and
Eliminations
Total
$
$
$
$
$
$
1,101.6 $
728.0
1,829.6
2,628.4
7.4
2,635.8
4,465.4 $
1,006.4 $
6,406.1 $
549.3
6,955.4
132.2
28.7
160.9
7,116.3 $
867.2 $
11,929.8 $
6,741.8 $
45.2 $
— $
1,273.3 $
1,412.2 $
(113.9 ) $
—
(113.9 )
—
—
—
(113.9 ) $
(113.9 )
1.0 $
— $
— $
— $
—
—
(2,760.6 )
(36.1 )
(2,796.7 )
(2,796.7 ) $
7,393.8
1,277.3
8,671.1
—
—
—
8,671.1
142.5 $
— $
23.0 $
18,815.1
45.2
2,708.5
(1) Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.
(2) Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.
F-49
The following table shows our consolidated revenues disaggregated by product and service for the periods presented:
2021
Year Ended December 31,
2020
2019
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas
NGL
Condensate and crude oil
Petroleum products
Non-customer revenue:
Derivative activities - Hedge
Derivative activities - Non-hedge (1)
Total sales of commodities
Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing
NGL transportation, fractionation and services
Storage, terminaling and export
Other
Total fees from midstream services
$
3,523.9 $
12,210.8
358.4
—
16,093.1
(417.3 )
(73.3 )
(490.6 )
15,602.5
730.3
190.6
379.7
46.7
1,347.3
1,359.0 $
5,181.3
264.0
69.8
6,874.1
90.8
206.1
296.9
7,171.0
476.0
163.1
401.9
48.3
1,089.3
Total revenues
$
16,949.8 $
8,260.3 $
(1)
Represents derivative activities that are not designated as hedging instruments under ASC 815.
1,321.7
5,233.8
716.1
126.3
7,397.9
138.0
(142.1 )
(4.1 )
7,393.8
722.4
169.4
356.4
29.1
1,277.3
8,671.1
The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the
periods presented:
Reconciliation of reportable segment operating
margin to income (loss) before income taxes:
Gathering and Processing operating margin
Logistics and Transportation operating margin
Other operating margin
Depreciation and amortization expense
General and administrative expense
Impairment of long-lived assets
Interest expense, net
Equity earnings (loss)
Gain (loss) on sale or disposition of business and assets
Write-down of assets
Gain (loss) from financing activities
Gain (loss) from sale of equity-method investment
Change in contingent considerations
Other, net
Income (loss) before income taxes
2021
Year Ended December 31,
2020
2019
$
$
1,325.3 $
1,264.3
(115.9 )
(870.6 )
(273.2 )
(452.3 )
(387.9 )
(23.9 )
(2.0 )
(10.3 )
(16.6 )
—
(0.1 )
0.1
436.9 $
1,017.7 $
1,128.0
229.7
(865.1 )
(254.6 )
(2,442.8 )
(391.3 )
72.6
(58.4 )
(55.6 )
45.6
—
0.3
0.8
(1,573.1 ) $
1,006.4
867.2
(113.9 )
(971.6 )
(280.7 )
(225.3 )
(337.8 )
39.0
(71.1 )
(17.9 )
(1.4 )
69.3
(8.7 )
(0.2 )
(46.7 )
Note 26 — Condensed Parent Only Financial Statements
The condensed parent only financial statements represent the financial information required by Rule 5-04 of the Securities and
Exchange Commission Regulation S-X for Targa Resources Corp.
In the condensed financial statements, Targa’s Investments in consolidated subsidiaries are presented under the equity method of
accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the
consolidated subsidiaries are recorded in the balance sheets. The Income (loss) from operations of the consolidated subsidiaries is
reported as Equity in income (loss) of consolidated subsidiaries. Other comprehensive income has been adjusted for Targa’s share of
the investees’ currently reported Other comprehensive income (loss).
F-50
A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial
statements should be read in conjunction with Targa’s consolidated financial statements, which begin on page F-1 in this Annual
Report.
TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED BALANCE SHEETS
ASSETS
Investment in consolidated subsidiaries
Deferred income taxes
Debt issuance costs
Other long-term assets
Total assets
$
$
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Accrued current liabilities
Long-term debt
Other long-term liabilities
Series A Preferred, net of discount
Targa Resources Corp. stockholders' equity
Total liabilities, Series A Preferred and owners' equity
$
$
December 31,
2021
2020
2,746.2 $
65.1
1.7
8.8
2,821.8 $
30.8 $
—
29.5
749.7
2,011.8
2,821.8 $
TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
2021
Year Ended December 31,
2020
2019
Equity in net income (loss) of consolidated subsidiaries
General and administrative expense
Income (loss) from operations
Other income (expense):
Interest expense
Income (loss) before income taxes
Deferred income tax (expense) benefit
Net income (loss) attributable to Targa Resources Corp.
Other comprehensive income (loss)
Total comprehensive income (loss)
Dividends on Series A Preferred
Deemed dividends on Series A Preferred
Net income (loss) attributable to common shareholders
Net income (loss) attributable to Targa Resources Corp.
89.1 $
(17.3 )
71.8
(6.0 )
65.8
5.4
71.2
(89.1 )
(17.9 ) $
87.3
—
(16.1 )
71.2 $
(1,534.9 ) $
(12.4 )
(1,547.3 )
(12.5 )
(1,559.8 )
5.9
(1,553.9 )
(234.3 )
(1,788.2 ) $
91.7
39.2
(1,684.8 )
(1,553.9 ) $
$
$
$
F-51
3,507.2
59.7
2.9
9.4
3,579.2
30.5
555.0
38.4
301.4
2,653.9
3,579.2
(186.2 )
(13.1 )
(199.3 )
(17.0 )
(216.3 )
7.1
(209.2 )
(1.8 )
(211.0 )
91.7
33.1
(334.0 )
(209.2 )
TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED STATEMENTS OF CASH FLOWS
Net cash provided by (used in) operating activities
$
(54.4 ) $
(193.9 ) $
48.3
2021
Year Ended December 31,
2020
2019
Cash flows from investing activities
Advances to consolidated subsidiaries
Distributions from consolidated subsidiaries (1)
Net cash provided by (used in) investing activities
Cash flows from financing activities
Proceeds from long-term debt borrowings
Repayments of long-term debt
Transaction costs incurred related to sale of ownership interests
Repurchase of common stock
Dividends paid to common and Series A Preferred shareholders
Partial repurchase of Series A Preferred
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents - beginning of year
Cash and cash equivalents - end of year
_____________
(1) Amounts reflect distributions from consolidated subsidiaries in excess of earnings.
$
133.5
716.6
850.1
30.0
(585.0 )
—
(53.2 )
(187.5 )
—
(795.7 )
—
—
— $
214.1
387.2
601.3
155.0
(35.0 )
—
(97.4 )
(384.2 )
(45.8 )
(407.4 )
—
—
— $
(222.5 )
1,152.4
929.9
(450.0 )
450.0
(10.8 )
(13.9 )
(953.5 )
—
(978.2 )
—
—
—
F-52