UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
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
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Accelerated filer
Smaller reporting company
Emerging growth company
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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. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to
previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive
officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
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 $13,379.6 million on June 30, 2022, based on $59.67 per share, the closing price of the common
stock as reported on the New York Stock Exchange (NYSE) on such date.
As of February 17, 2023, there were 226,639,398 shares of the registrant’s common stock, $0.001 par value, outstanding.
Portions of the registrant’s definitive proxy statement for the 2023 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.
DOCUMENTS INCORPORATED BY REFERENCE
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”), “we,” “us,” “our,” “Targa,” “TRGP,” 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:
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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, including the impact of rising interest rates and
associated Federal Reserve policies and potential economic recession, our credit ratings and debt obligations, and demand for our common
equity, senior notes and commercial paper;
the impact of outbreaks of illnesses, pandemics or any other public health crises;
downside commodity price volatility from a variety of potential factors;
actions taken by other countries with significant hydrocarbon production;
the timing and success of business development efforts;
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, such as the Inflation Reduction Act of 2022 (the “IRA”), 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, changes in competition and the drive to reduce fossil fuel use and substitute
alternative forms of energy for oil and gas;
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 Inter-Bank 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, 2022. 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, 2021.
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:
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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. Our Downstream facilities 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, 2022:
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Recent Developments
In response to increasing production and to meet the infrastructure needs of producers and our downstream customers, our major expansion projects include
the following:
Permian Midland Processing Expansions
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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 commenced operations in the third quarter of 2022.
In February 2022, 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.
In August 2022, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the
“Greenwood plant”). The Greenwood plant is expected to begin operations late in the fourth quarter of 2023.
Permian Delaware Processing Expansions
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In February 2022, 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 second quarter of 2023. In conjunction with the commencement of
operations of the Midway plant, we expect to idle an existing 165 MMcf/d cryogenic natural gas processing plant (the “Sand Hills plant”).
In July 2022, we acquired a 230 MMcf/d cryogenic natural gas processing plant, which was under construction at the time of acquisition, in
Permian Delaware (the “Red Hills VI plant”) as part of our Delaware Basin Acquisition (as defined below). The Red Hills VI plant
commenced operations at the end of the third quarter of 2022.
In November 2022, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the
“Wildcat II plant”). The Wildcat II plant is expected to begin operations in the first quarter of 2024.
In February 2023, we announced the transfer of an existing cryogenic natural gas processing plant acquired in the South Texas Acquisition
(as defined below) to the Permian Delaware. The plant will be installed as a new 230 MMcf/d cryogenic natural gas processing plant (the
“Roadrunner II plant”). The Roadrunner II plant is expected to begin operations in the second quarter of 2024.
Fractionation Expansion
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In August 2022, we announced plans to construct a new 120 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 9”). Train 9 is
expected to begin operations in the second quarter of 2024.
In January 2023, we reached an agreement with our partners in Gulf Coast Fractionators (“GCF”) to reactivate GCF's 135 MBbl/d
fractionation facility. The facility is expected to be operational during the first quarter of 2024.
NGL Pipeline Expansion
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In November 2022, we announced plans to construct a new NGL pipeline (the “Daytona NGL Pipeline”) as an addition to our common
carrier Grand Prix system. The pipeline will transport NGLs from the Permian Basin and connect to the 30-inch diameter segment of Grand
Prix in North Texas, where volumes will be transported to our fractionation and storage complex in the NGL market hub at Mont Belvieu,
Texas. The Daytona NGL Pipeline is expected to be in service by the end of 2024.
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Capital Investments, Acquisitions and Divestitures
In January 2022, we completed the purchase of all of Stonepeak Infrastructure Partners’ (“Stonepeak”) interests in our development company joint ventures
(“DevCo JVs”) for $926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we owned a 75% interest in the Permian to Mont
Belvieu segment of Grand Prix through Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”) (prior to the Grand Prix Transaction, as defined below),
a 100% interest in the Train 6 fractionator in Mont Belvieu, Texas and a 25% equity interest in Gulf Coast Express Pipeline (“GCX”) (prior to the GCX
Sale, as defined below). The DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our Consolidated Balance
Sheets.
In April 2022, we completed the bolt-on acquisition of Southcross Energy Operating LLC and its subsidiaries (“Southcross”) for a purchase price of $201.9
million (the “South Texas Acquisition”), subject to customary closing adjustments. We made a final net working capital adjustment payment of
approximately $1.5 million in the fourth quarter of 2022. We acquired a portfolio of complementary midstream infrastructure assets and associated
contracts that have been integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the two joint ventures in
South Texas that we previously held as investments in unconsolidated affiliates, which were consolidated beginning in the second quarter of 2022.
In May 2022, we completed the sale of Targa GCX Pipeline LLC, which held a 25% equity interest in GCX, to a third party for $857.0 million (the “GCX
Sale”). As a result of the GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated
Statements of Operations in the second quarter of 2022.
In July 2022, we completed the acquisition of all of the interests in Lucid Energy Delaware, LLC (“Lucid”) for approximately $3.5 billion in cash (the
“Delaware Basin Acquisition”), subject to customary closing adjustments. We received a final net working capital adjustment payment of approximately
$11.4 million in the fourth quarter of 2022. The assets acquired in the Delaware Basin Acquisition provide natural gas gathering, treating, and processing
services in the Delaware Basin, through owning and operating approximately 1,050 miles of natural gas pipelines and approximately 1.4 billion cubic feet
per day (“Bcf/d”) of cryogenic natural gas processing capacity primarily in Eddy and Lea counties of New Mexico. The Delaware Basin Acquisition assets
are integrated into our Permian Delaware operations.
In January 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in Grand Prix Joint Venture (the “Grand Prix Transaction”) for
approximately $1.05 billion in cash. Following the closing of the Grand Prix Transaction, we own 100% of Grand Prix, including the Daytona NGL
Pipeline.
For further details on our acquisitions and divestitures, see Note 4 - Acquisitions and Divestitures and Note 7 - Investments in Unconsolidated Affiliates to
our Consolidated Financial Statements beginning on page F-1 in this Form 10-K.
Common Share Repurchases and Preferred Stock Redemption
In the fourth quarter of 2022, we repurchased 395,798 shares of our common stock at a weighted average price of $70.75 for a total net cost of $28.0
million. For the year ended December 31, 2022, we repurchased 3,412,354 shares of our common stock at a weighted average price of $65.87 for a total net
cost of $224.8 million. There was $143.8 million remaining under our $500 million common share repurchase program as of December 31, 2022.
In May 2022, we redeemed all of our issued and outstanding shares of Series A Preferred Stock (“Series A Preferred”) at a redemption price of $1,050.00
per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of
May 3, 2022.
Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. See
Note 11 - Preferred Stock to our Consolidated Financial Statements for further discussion.
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Financing Activities
In February 2022, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent and Swing Line Lender, and the other
lenders party thereto (the “TRGP Revolver”). The TRGP 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 TRGP
Revolver, including a swing line sub-facility of up to $100.0 million. The TRGP Revolver matures in February 2027. In connection with our entry into the
TRGP Revolver, we terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership's senior
secured revolving credit facility (the “Partnership Revolver”). In February 2022, TRGP and the Partnership received a corporate investment grade credit
rating from Standard & Poor’s Financial Services LLC (“S&P”) and Fitch Ratings Inc., (“Fitch”) and in March 2022, the Partnership received a corporate
investment grade credit rating from Moody’s Investors Service, Inc. (“Moody's”). As a result, in accordance with the TRGP Revolver, the collateral under
the TRGP Revolver was released from the liens securing our obligations thereunder. As a result of the termination of the Previous TRGP Revolver and the
Partnership Revolver, we recorded a loss of $0.8 million due to a write-off of debt issuance costs.
In March 2022, the Partnership redeemed all of the outstanding 5.375% Senior Notes due 2027 (the “5.375% Notes”) with available liquidity under the
TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million, comprised of $12.6
million of premiums paid and a write-off of $2.4 million of debt issuance costs.
In April 2022, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Senior Notes due 2033 (the
“4.200% Notes”) and (ii) $750.0 million aggregate principal amount of our 4.950% Senior Notes due 2052 (the “4.950% Notes”), resulting in net proceeds
of approximately $1.5 billion. A portion of the net proceeds from the issuance was used to fund the concurrent cash tender offer (the “March Tender
Offer”) and the subsequent redemption of the Partnership’s 5.875% Senior Notes due April 2026 (the “5.875% Notes”), with the remainder of the net
proceeds used for repayment of the outstanding borrowings under the TRGP Revolver. As a result of the March Tender Offer and the subsequent
redemption of the 5.875% Notes, we recorded a loss due to debt extinguishment of $33.8 million, comprised of $29.3 million of premiums paid and a
write-off of $4.5 million of debt issuance costs.
In July 2022, we completed an underwritten public offering of (i) $750.0 million in aggregate principal amount of our 5.200% Senior Notes due 2027 (the
“5.200% Notes”) and (ii) $500.0 million in aggregate principal amount of our 6.250% Senior Notes due 2052 (the “6.250% Notes”), resulting in net
proceeds of approximately $1.2 billion. We used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition.
In July 2022, we entered into the Term Loan Agreement with Mizuho Bank, Ltd. as the Administrative Agent and a lender, and other lenders party thereto
(the “Term Loan Facility”). The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility and matures in July 2025. We used
the proceeds to fund a portion of the Delaware Basin Acquisition.
In July 2022, we established an unsecured commercial paper note program (the “Commercial Paper Program”). Under the terms of the Commercial Paper
Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the
Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at
any one time not to exceed $2.75 billion. We maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount
outstanding under the Commercial Paper Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP
Revolver.
In September 2022, we amended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to, among other things, increase
the facility size from $400.0 million to $800.0 million and extend the facility termination date to September 1, 2023.
In January 2023, we completed an underwritten public offering of (i) $900.0 million in aggregate principal amount of our 6.125% Senior Notes due 2033
(the “6.125% Notes”) and (ii) $850.0 million in aggregate principal amount of our 6.500% Senior Notes due 2053 (the “6.500% Notes”), resulting in net
proceeds of approximately $1.7 billion. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining net
proceeds for general corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.
For additional information about our recent debt-related transactions, see Note 8 - Debt Obligations to our Consolidated Financial Statements.
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Organization Structure
The diagram below shows our corporate structure as of February 17, 2023:
(1)
Common shares outstanding as of February 17, 2023.
Growth Drivers, Competitive Strengths and Strategies
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.
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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 Permian Basin, with our Downstream facilities
in Mont Belvieu, Texas, the 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.
In addition to routine annual maintenance expenses, our maintenance capital expenditures have averaged approximately $141 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 maintains a strong credit
profile.
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.
10
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 predominantly fee-based contract terms 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 embedded 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.
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 30,900 miles of natural gas pipelines and include 50 owned and operated processing
plants.
11
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 7,210 miles of natural gas gathering pipelines and 17 processing plants with an aggregate
processing capacity of 3,039 MMcf/d, all located within the Permian Basin in West Texas. Eleven of these plants and approximately 5,100 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.
In response to increasing production and to meet the infrastructure needs of producers:
•
•
we are constructing 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.
we are constructing the Greenwood plant, a new 275 MMcf/d cryogenic natural gas plant. The Greenwood plant is expected to begin
operations late in the fourth quarter of 2023.
Permian Delaware
The Permian Delaware system consists of approximately 7,200 miles of natural gas gathering pipelines and 15 processing plants with an aggregate capacity
of 2,670 MMcf/d, all within the Delaware Basin in West Texas and Southeastern New Mexico.
As part of the Delaware Basin Acquisition in July 2022, we acquired approximately 1,050 miles of natural gas pipelines and 1.4 Bcf/d of cryogenic natural
gas processing capacity primarily in Eddy and Lea counties of New Mexico including the Red Hills VI plant, which was under construction at the time of
acquisition. The Red Hills VI plant commenced operations at the end of the third quarter of 2022.
In response to increasing production and to meet the infrastructure needs of producers:
we are constructing the Midway plant, a new 275 MMcf/d cryogenic natural gas processing plant. The Midway plant is expected to begin
operations in the second quarter of 2023. In conjunction with the commencement of operations of the Midway plant, we expect to idle the
Sand Hills plant.
we are constructing the Wildcat II plant, a new 275 MMcf/d cryogenic natural gas processing plant. The Wildcat II plant is expected to begin
operations in the first quarter of 2024.
we are transferring an existing cryogenic natural gas processing plant, which was acquired in the South Texas Acquisition (the “Roadrunner
II plant”), to the Permian Delaware. The plant will be installed as a new 230 MMcf/d cryogenic natural gas processing plant, and is expected
to begin operations in the second quarter of 2024.
•
•
•
SouthTX
The South Texas system contains approximately 2,100 miles of high-pressure and low-pressure gathering and transmission pipelines and three natural gas
processing plants in the Eagle Ford Shale with an aggregate processing capacity of 660 MMcf/d. The South Texas system processes natural gas through the
Silver Oak I, Silver Oak II and Raptor gas processing plants.
Prior to closing the South Texas Acquisition, we participated in and served as operator for two joint ventures in South Texas with a subsidiary of
Southcross Energy Partners LLC, which consisted 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”), together (the “T2 Joint Ventures”). Following the closing of the South Texas Acquisition, we own 100%
of the interest in the T2 Joint Ventures. T2 LaSalle owns approximately 70 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 50 miles of high-pressure
12
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 with a processing capacity of 265 MMcf/d. The system consists of approximately 4,700 miles of pipelines gathering wellhead natural
gas.
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 consists of approximately 1,600 miles of pipelines in 12 counties.
The SouthOK system includes six separate 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 consists of approximately 6,600 miles of pipelines in 15 counties.
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 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, non-operated plant. 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.
Badlands
Our 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 and Blackstone Tactical Opportunities (collectively, “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.
The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2022:
13
Facility
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)
Permian Midland
Consolidator (6)
Midkiff (6)
Driver (6)
Benedum (6)
Edward (6)
Buffalo (6)
Joyce (6)
Johnson (6)
Hopson (6)
Pembrook (6)
Gateway (6)
Mertzon
Sterling
Tarzan (7)
High Plains
Heim (8)
Legacy (8)
Permian Delaware
Sand Hills
Loving
Oahu
Wildcat
Falcon
Eunice
Monument (9)
Peregrine
Roadrunner
Red Hills I
Red Hills II
Red Hills III
Red Hills IV
Red Hills V
Red Hills VI
SouthTX
Silver Oak I
Silver Oak II
Raptor
North Texas
Chico
SouthOK
Coalgate (10)
Stonewall
Tupelo
Hickory Hills
Velma
Velma V-60
WestOK
Waynoka I
Waynoka II
Coastal
Gillis (11)
Big Lake (7)
VESCO
Lowry
Sea Robin
Badlands
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
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
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Operated
Cryo
Operated
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
Non-operated
Little Missouri I-III (12)
Little Missouri IV
Cryo/RA
Cryo
Operated
Operated
72.8
72.8
72.8
72.8
72.8
72.8
72.8
72.8
72.8
72.8
72.8
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Reagan County, TX
Reagan County, TX
Midland County, TX
Upton County, TX
Upton County, TX
Martin County, TX
Upton County, TX
Midland County, TX
Midland County, TX
Upton County, TX
Reagan County, TX
Irion County, TX
Sterling County, TX
Martin County, TX
Midland County, TX
Reagan County, TX
Midland County, TX
Area Total
Crane County, TX
Loving County, TX
Pecos County, TX
Winkler County, TX
Culberson County, TX
Lea County, NM
Lea County, NM
Culberson County, TX
Eddy County, NM
Lea County, NM
Lea County, NM
Lea County, NM
Lea County, NM
Lea County, NM
Lea County, NM
Area Total
100.0
50.0
50.0
Bee County, TX
Bee County, TX
La Salle County, TX
Area Total
100.0
Wise County, TX
Area Total
60.0
60.0
60.0
60.0
100.0
100.0
Coal County, OK
Coal County, OK
Coal County, OK
Hughes County, OK
Stephens County, OK
Stephens County, OK
Area Total
100.0
100.0
Woods County, OK
Woods County, OK
Area Total
100.0
100.0
76.8
100.0
1.2
Calcasieu Parish, LA
Calcasieu Parish, LA
Plaquemines Parish, LA
Cameron Parish, LA
Vermillion Parish, LA
Area Total
55.0
27.5
McKenzie County, ND
McKenzie County, ND
Area Total
Segment System Total
14
150.0
70.0
220.0
45.0
220.0
220.0
220.0
220.0
275.0
275.0
275.0
52.0
92.0
10.0
220.0
200.0
275.0
3,039.0
165.0
70.0
60.0
250.0
275.0
110.0
85.0
275.0
230.0
60.0
200.0
200.0
230.0
230.0
230.0
2,670.0
200.0
200.0
260.0
660.0
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
2,025.0
90.0
200.0
290.0
10,059.0
2,223.6
321.7
1,536.1
193.9
276.5
187.0
31.2
21.2
406.8
47.6
208.7
14.6
537.6
32.0
134.9
5,511.2
16.1
678.3
(1)
(2)
(3)
(4)
(5)
(6)
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 2022. Plants acquired in the Delaware Basin
acquisition and reflected in Permian Delaware include reported volumes based on number of calendar days during 2022 from August 1 through December 31, 2022.
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. In December 2022, the Gateway plant achieved the payout event related to the non-consent election made by the joint
owner in our WestTX Permian Basin assets. As a result, the Gateway plant is now 72.8% owned and proportionately consolidated by Targa. Prior to the payout event, the Gateway plant
was 100% owned and consolidated by Targa.
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 Heim and Legacy plants are 100% owned and consolidated by Targa.
The Monument plant has fractionation capacity of approximately 1.8 MBbl/d.
(7)
(8)
(9)
(10) We anticipate shutting down the Coalgate plant in 2023.
(11)
(12)
The Gillis plant has fractionation capacity of approximately 11 MBbl/d.
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 and associated assets, which are generally connected to and supplied in part by our Gathering and
Processing segment. These assets 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 2,300 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.
Transportation Pipelines
Our primary pipeline asset is Grand Prix, which 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, which is expandable to 550 MBbl/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 MBbl/d. As of
December 31, 2022, we owned a 75% interest in the Permian to Mont Belvieu segment of Grand Prix through the Grand Prix Joint Venture. In January
2023, we announced and closed on the acquisition of the remaining 25% interest in the Grand Prix Joint Venture.
We are constructing the Daytona NGL Pipeline as an addition to Grand Prix. The pipeline will transport NGLs from the Permian Basin and connect to the
30-inch diameter segment of Grand Prix in North Texas, where volumes will be transported to our fractionation and storage complex in the NGL market
hub at Mont Belvieu, Texas. The Daytona NGL Pipeline is expected to be in service by the end of 2024.
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.
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
15
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, which is wholly-owned by Targa, (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. Certain
fractionation-related infrastructure for 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 are also constructing Train 9 at our Mont Belvieu operated facility, which is expected to begin operations in the second quarter of 2024.
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 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. In January 2023, we reached an agreement with our partners to reactivate GCF. The facility is expected to be operational
during the first quarter of 2024.
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, with a capacity of 35.0 MBbl/d that removes sulfur from natural gasoline,
allowing customers to meet stringent fuel content standards.
The following table details the Logistics and Transportation segment’s fractionation and treating facilities:
Facility
Cedar Bayou Fractionators (2)
Train 6 Fractionator
Train 7 Fractionator
Train 8 Fractionator
Lake Charles Fractionator (3)
Fractionation Total
Gulf Coast Fractionator (4)
Targa LSNG Hydrotreater
Location
Mont Belvieu, TX
Mont Belvieu, TX
Mont Belvieu, TX
Mont Belvieu, TX
Lake Charles, LA
Mont Belvieu, TX
Mont Belvieu, TX
% Owned
88.0
100.0
80.0
100.0
100.0
38.8
100.0
Capacity
(MBbl/d) (1)
Throughput
2022 (MBbl/d)
493.0
110.0
120.0
120.0
55.0
898.0
135.0
35.0
731.7
—
31.6
(1)
(2)
(3)
(4)
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, and includes 40 MBbl/d of additional back-end butane/gasoline fractionation capacity.
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.
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.
16
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 these wells 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
Harris County, TX
Chambers County, TX
Cameron Parish, LA
Description
NGL import/export terminal
Transport and storage terminal
Storage terminal
Throughput
for 2022
(MMgal)
Number of
Operational
Wells
Storage
Capacity
(MMBbl)
6,172.0
29,559.5
393.0
N/A
22 (2)
12 (3)
0.7
54.9
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.
NGL Distribution and Marketing
We market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. We also purchase
product for resale in our Logistics and Transportation segment.
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, refiners 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.
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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, 2022, we lease and manage 606 railcars and 122 tractors, and own six vacuum trucks and two pressurized NGL barges.
The following table details the Logistics and Transportation segment’s raw NGL, propane and butane terminaling facilities:
Facility
Greenville Terminal
Port Everglades Terminal
Calvert City Terminal
Chattanooga Terminal
Hattiesburg Terminal (2)
Sparta Terminal
Tyler Terminal
Winona Terminal
Eagle Lake Transload (3)
Indianapolis Transload
% Owned
100
100
100
100
50
100
100
100
100
100
Location
Washington County, MS
Broward County, FL
Marshall County, KY
Hamilton County, TN
Forrest County, MS
Sparta County, NJ
Smith County, TX
Flagstaff County, AZ
Polk County, FL
Marion County, IN
Description
Marine propane terminal
Marine propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane terminal
Propane transload
Propane transload
(1)
(2)
(3)
Throughputs include volumes related to exchange agreements and third-party storage agreements.
Throughput volume reflects 100% of the facility capacity.
Rail-to-truck transload equipment.
Natural Gas Marketing
Throughput
for 2022
(MMgal) (1)
Usable Storage
Capacity
(MMgal)
23.8
22.6
17.0
11.1
255.3
12.2
11.2
15.3
8.5
—
1.5
1.6
0.1
0.9
179.8
0.2
0.2
0.3
—
0.1
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
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
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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 and available capacity 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. Our gathering and processing operations competitors are other natural gas
gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers.
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, available capacity, reputation, efficiency, flexibility, and reliability. Our NGL pipeline competitors are 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, trading organizations
and petrochemical operators.
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, 2022, we employed approximately 2,850 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. For more information on the laws and regulations we are subject to with regard to employee, contractor, and community safety, please see our
section below titled Environmental and Occupational Health and Safety Matters.
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
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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.
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 and
regulations in the states in which we operate, which generally require us to give pipeline access or to purchase, process, or take gas without undue
discrimination. These statutes, rules, and regulations can restrict 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). In addition, 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 subject to Order No. 704. 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.” We are 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, in addition to civil penalties, 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 export customers.
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 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.
Pursuant to 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, as well as the ceiling levels for the period July 1, 2022 to June
30, 2023, and the resulting rates currently in effect for certain of Targa’s liquids pipelines, were computed to account for the appropriate index factor. Some
parties sought rehearing of the January 20 order with FERC, which was denied on May 6, 2022. Certain parties have appealed the January 20 and May 6
FERC orders, and the appeals remain pending before the DC Circuit.
On July 27, 2018, Targa NGL submitted a petition for declaratory order to FERC requesting approval of a proposed rate structure and terms of service for
the portions of Grand Prix that Targa NGL operates from Oklahoma to Mont Belvieu, Texas. On March 11, 2019, the Commission granted Targa NGL’s
petition for declaratory order (“March 19 Order”) subject to certain conditions, including that Targa NGL meet the requirements under the Commission’s
regulations to establish an initial rate either by filing a sworn affidavit that the rate has been agreed to by at least one non-affiliate shipper or by providing a
cost-of-service justification for the initial rate. Targa NGL requested rehearing on April 10, 2019, seeking Commission approval of Targa NGL’s contract
rate with an affiliated shipper as a settlement rate as opposed to establishing an initial rate by the methods described in the March 2019 Order. On
December 16, 2022, FERC denied Targa NGL’s rehearing request.
Targa has multiple NGL pipelines that are also considered common carrier pipelines but 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 operates under
such a waiver, but this waiver is subject to a pending FERC proceeding as described below.
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 regulated services to all potential shippers without undue discrimination. For example,
on December 16, 2022, FERC initiated an investigation and established hearing procedures in FERC Docket No. OR23-2-000 to determine whether Targa’s
Badland assets continue to qualify for the waiver of applicable FERC regulatory requirements and whether Targa is providing jurisdictional transportation
service on this system.
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.
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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 2022, TPL SouthTex Transmission
Company LP. Targa Midland Gas Pipeline LLC, Midland-Permian Pipeline LLC, Targa SouthTex Mustang Transmission Ltd., and Targa SouthTex
Transmission LP 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
We operate intrastate NGL pipelines in Texas that transport mixed and purity NGL streams between Targa’s Mont Belvieu and Galena Park, Texas
facilities. Grand Prix and Targa NGL provide transportation of mixed NGLs from points within Texas to other points within Texas, including 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. LPSC regulations require that common carrier pipelines charge rates that are just and reasonable and not unreasonably
discriminatory.
EP Act of 2005
The EP Act of 2005 amended 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 2023 equals approximately $1.5 million per
violation per day for violations of the NGA or 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.
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FERC Market Transparency Rules
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. 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. 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.”
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:
•
•
•
•
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;
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•
•
•
•
•
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.
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 fines or 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
physical risks, or 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 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. Recently,
PHMSA finalized adjustments to the repair criteria for pipelines in HCAs, created new criteria for pipelines in non-HCAs, and strengthened integrity
management assessment requirements. 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 $4.1 million
between 2023 and 2025 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 material. 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.
Corporation Tax Matters
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. In November
2022, the IRS notified us that it completed the examination of Targa's NOL carryback and associated refund previously claimed under the CARES Act with
no exceptions and had forwarded its report to the Joint Committee of Taxation. In January 2023, the Company was notified that the Joint Committee of
Taxation had completed its review with no exceptions.
On October 6, 2021 and April 7, 2022, we received notice from the IRS that it intends to audit three direct and indirectly wholly-owned subsidiaries of the
Company (Targa Resources Partners LP, Targa Downstream LLC and Targa Midstream Services LLC) treated as partnerships for federal tax purposes for
the 2019 and 2020 tax years. We are responding to the information requests from the IRS on these audits. Additionally, in January 2023, we received notice
from the IRS that it intends to audit an indirectly wholly-owned subsidiary of the Company (Targa Badlands Holdings LLC), which is treated as a
partnership for U.S. federal income tax purposes for the 2020 tax year. The Company is not aware of any potential audit findings that would give rise to
adjustments to taxable income and does not anticipate material changes related to these audits.
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All federal statutes of limitations for returns filed in 2019 (for calendar year 2018) have expired. For Texas, the statute of limitations has expired for 2018
returns (for calendar year 2017). Similarly, the statute of limitations expired on substantially all 2018 state income tax returns that were filed prior to
October 15, 2019. However, tax authorities have the ability to review and adjust carryover attributes (e.g., net operating losses) generated in a closed tax
year if utilized in an open tax year.
On August 16, 2022, President Biden signed into law the IRA which, among other things, introduced a corporate alternative minimum tax (the “CAMT”),
imposed a 1% excise tax on stock buybacks, and provided tax incentives to promote clean energy. Under the CAMT, a 15% minimum tax will be imposed
on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which
the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $1
billion.
On December 27, 2022, the Department of the Treasury and the IRS issued guidance on the application of the CAMT which may be relied upon until final
regulations are released. Based on our interpretation of the IRA, the CAMT and related guidance, and a number of operational, economic, accounting and
regulatory assumptions, we do not anticipate qualifying as an “applicable corporation” in the near term, but we are likely to become an applicable
corporation in a subsequent tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax
liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash
available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for the future year. As a result, our
current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA and CAMT, we
will continue to monitor and evaluate the potential future impact to our financial statements.
Financial Information by Reportable Segment
See “Segment Information” included under Note 24 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
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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.
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 or increase the costs 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 global and domestic hostilities 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.
We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
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.
Risks Related to our Capital Projects and Future Growth
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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.
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.
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Risks Related to our Financial Condition
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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.
Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our
goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.
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
successfully challenge certain of our tax positions.
Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes may adversely affect our financial condition, results of operations
and cash flows.
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.
Risks Related to the Ownership of our Common Stock
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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.
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.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Risks Related to our Indebtedness
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Continued increases in interest rates, due to associated Federal Reserve policies or otherwise, 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
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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 stakeholder and market 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 (i) cause our revenues to decline and operating expenses to increase or (ii) 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.
We are or may become subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing of personal information.
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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:
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the impact of seasonality and weather, including severe weather conditions and other natural disasters, such as flooding, droughts and winter
storms, the frequency, severity and impact of which could be increased by the effects of climate change;
general economic conditions and economic conditions impacting our primary markets, including the impact of continued inflation and rising
interest rates and associated changes in monetary policy;
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 and the related transition to a low carbon economy, as a result of the IRA or otherwise;
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.”
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, including the IRA, 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, increased
competition from petroleum-based feedstocks due to pricing
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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.
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
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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.
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.
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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.
Climatic events may damage our pipelines and other facilities, limit our ability or increase the costs 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 or our customers 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, among other disruptive weather patterns,
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.
Moreover, we could incur significant costs to weatherize or upgrade weatherization of our facility equipment in anticipation of future climatic events. For
example, following Texas Governor Greg Abbott's direction to adopt rules related to weather resiliency, in August 2022, the Texas Railroad Commission
adopted the Weather Emergency Preparedness Standards rule, which requires critical gas facilities on the state’s Electricity Supply Chain Map (including
gas pipelines that directly serve electricity generation) to (i) weatherize to help ensure sustained operations during a weather emergency, (ii) correct known
issues that caused weather-related forced stoppages and (iii) contact the Texas Railroad Commission if a facility sustains a weather-related forced stoppage
during a weather emergency. Inspectors from the Critical Infrastructure Division of the Texas Railroad Commission began inspections on December 1,
2022. If, upon inspection,
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we are required to further weatherize or update weatherization of certain facilities, we may incur significant costs to complete any additional
weatherization. Additionally, issues beyond our control, such as grid reliability or the severity of any such weather event, might undermine any
winterization or emergency weather preparedness efforts we make. Furthermore, our operations in western Texas and New Mexico may be sensitive to
drought and restrictions on water use.
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:
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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;
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 against 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.
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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 global and domestic hostilities 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 global and domestic hostilities 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.
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.
We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
We have experienced, and may 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. Similar actions pursued against our oil and
gas customers could result in interruptions or limitations to their businesses, which could reduce demand for our services. Any such event that restricts,
delays or prevents the expansion of our or our customers’ businesses, interrupts the revenues generated by our or our customers’ operations or causes us or
our customers to make significant expenditures not covered by insurance could adversely affect our business, results of operations, and financial condition,
as well as reduce the demand for our services. Increased regulatory attention to environmental justice matters at the federal and state level may also provide
communities opposed to our operations with greater opportunities to challenge or delay the permitting approval process.
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 and moderate
consequence risk areas, known as HCAs and MCAs, which are areas where a release could have the most significant adverse consequences. Among other
things, these regulations require operators of covered pipelines to:
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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.
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With adoption of 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 the Protecting Our Infrastructure of Pipelines and Enhancing Safety
(“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. For example, more recently, in November 2021, PHMSA issued a final rule
establishing two new classes of onshore gas gathering pipelines—Type R and Type C—and imposed safety regulations on approximately 400,000 miles of
previously unregulated onshore gas gathering lines that, among other things, established criteria for inspection and repair of fugitive emissions, extended
reporting requirements to all gas gathering operators and applied 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, were expected to commence inspection of operator plans in 2022. In August 2022, PHMSA
finalized additional pipeline safety rules, which adjusted the repair criteria for pipelines in HCAs, created new criteria for pipelines in non-HCAs, and
strengthened integrity management assessment requirements, among other items. 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.
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 material 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 cybersecurity 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. In May 2021, a ransomware attack on a major U.S. refined products pipeline forced the operator to temporarily shut down the pipeline, resulting
in disruption of fuel supplies along the East Coast. The U.S. government has issued public warnings that indicate that energy assets might be specific
targets of cybersecurity threats. Our technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may
become the target of cyber-attacks 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 cybersecurity 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 cyber-attacks may not be sufficient to cover
all the losses we may experience as a result of a cyber incident.
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. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and
gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions
taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity.
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Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded.
However, we continue to monitor the effects of the pandemic on our operations. Our results of operations and financial condition have been and may
continue to be adversely affected by the COVID-19 pandemic. The extent to which our operating and financial results are affected by COVID-19 will
depend on various factors and consequences beyond our control, such as the emergence of more contagious and harmful variants of the COVID-19 virus,
the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of
responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the
other risk factors that we identify herein. While the effects of the COVID-19 pandemic have lessened recently in the United States, we cannot predict the
duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may materially adversely
affect our results of operations and financial condition in a manner that is not currently known to us or that we do not currently consider to present
significant risks to our operations.
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. If we are unable to develop accretive growth projects or make accretive acquisitions because we are unable to (1) develop growth projects
economically or identify attractive acquisition candidates and negotiate acceptable acquisition agreements or, (2) obtain financing for these projects or
acquisitions on economically acceptable terms, or (3) compete successfully for growth projects or acquisitions, then our future growth and ability to return
increasing capital to our shareholders may be limited.
Any growth project or acquisition involves potential risks, including, among other things:
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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;
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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 fail to successfully integrate such businesses, including the Delaware Basin Acquisition and
South Texas Acquisition, with our operations. 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.
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.
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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 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.
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Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost
of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.
The U.S. inflation rate increased in 2021, 2022 and into 2023. These inflationary pressures have resulted in and may result in additional increases to the
costs of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have
likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022. The U.S. Federal Reserve has raised and
may continue to raise benchmark interest rates in 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which
could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could negatively impact
the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations,
including services, labor costs and equipment if our operating activity increases.
Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of
inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues, would negatively
impact our business, financial condition 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.
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 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.”
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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.
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
successfully challenge certain of our tax positions.
As of December 31, 2022, we have U.S. federal NOL carryforwards of $6.8 billion, some of which expire between 2036 to 2037 while others have no
expiration date. Subject to the CAMT discussed below, 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 (subject to the
CAMT discussed below), 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.
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Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes may adversely affect our financial condition, results of
operations and cash flows.
U.S. federal and state legislation is periodically proposed that would, if enacted into law, make significant changes to tax laws and could materially increase
our tax obligations, adversely affecting our financial condition, results of operations and cash flows. For example, on August 16, 2022, President Biden
signed into law the IRA which includes, among other things, the CAMT. Under the CAMT, a 15% minimum tax will be imposed on certain financial
statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which the “average annual
adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $1 billion.
Based on our current interpretation of the IRA, the CAMT and related guidance and a number of operational, economic, accounting and regulatory
assumptions, we do not anticipate being an applicable corporation in the near term, but we are likely to become an applicable corporation in a subsequent
tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax
year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that
year, but provide an offsetting credit against our regular U.S. federal income tax liability for a future year. As a result, our current expectation is that the
impact of the CAMT is limited to timing differences in future tax years.
The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA, the CAMT and related guidance. In the future the
U.S. Department of the Treasury and the Internal Revenue Service are expected to release regulations and additional interpretive guidance relating to such
legislation, and any significant variance from our current interpretation could result in a change in our analysis of the application of the CAMT to us.
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 in July 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 have not experienced a
material impediment to, and do not expect these regulations to materially impede, our hedging activity at this time.
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.
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Risks Related to the Ownership of our Common Stock
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, 2022, we had 226,042,229 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:
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a classified board of directors, so that only approximately one-third of our directors are elected each year;
limitations on the removal of directors; and
limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and
nominations for elections to the board of directors to be acted upon at meetings of stockholders.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who
beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder,
unless various conditions are met, such as approval of the transaction by our board of directors.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of
preferred stock having such designations and powers, preferences, including preferences over our common stock respecting dividends and distributions,
rights, qualifications, limitations and restrictions as our board of directors may determine. The terms of one or more classes or series of preferred stock
could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some
number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or
redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.
Risks Related to Our Indebtedness
Continued increases in interest rates, due to associated Federal Reserve policies or otherwise, 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, 2022, our total indebtedness was $11,610.4 million, excluding $8.4 million
of unamortized discounts and $65.6 million of debt issuance costs, of which $7,784.4 million was at fixed interest rates, $3,598.7 million was at variable
interest rates and $227.3 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 consolidated annual interest expense by $36.0 million based on our December 31, 2022 debt balances. We additionally had $1.4 billion
of additional borrowing capacity available under the TRGP Revolver after accounting for $33.2 million of letters of credit, 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, due to associated Federal Reserve policies or otherwise.
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.
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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, 2022, we had $2.8 billion outstanding TRGP senior unsecured notes, excluding $8.4
million of unamortized discounts and $5.0 billion outstanding of the Partnership’s senior unsecured notes. We also had $800.0 million outstanding under
the Securitization Facility. In addition, we had (i) $1.5 billion of borrowing outstanding under the Term Loan Facility, and (ii) $290.0 million of borrowings
outstanding under the TRGP Revolver, $33.2 million of letters of credit outstanding, $1,008.7 million of borrowings outstanding under the Commercial
Paper Program and $1.4 billion of additional borrowing capacity available under the TRGP Revolver. For the years ended December 31, 2022, 2021 and
2020, our consolidated interest expense, net was $446.1 million, $387.9 million and $391.3 million.
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:
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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, Moody’s and S&P. As of December 31, 2022, Targa’s senior unsecured debt was rated “BBB-” by
Fitch, “Baa3” by Moody’s and “BBB-” 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 International Swaps and Derivatives Association (“ISDA”) agreements contain credit-risk related contingent features. Following the release of the
collateral securing our TRGP Revolver as a result of our credit rating, our derivative positions are no longer secured. As of December 31, 2022, we have
outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $266.7 million. If our credit
rating is downgraded below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of December 31, 2022, we would be
required to post $31.4 million of collateral to certain counterparties per the terms of our ISDAs.
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 TRGP 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.
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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:
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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;
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. 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 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 emissions of GHGs.
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, though recent laws such as the IRA advance
numerous climate-related objectives. 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
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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. Additionally, in August 2022, the IRA was signed into law, which appropriates significant federal funding
for renewable energy initiatives and amends the federal Clean Air Act to impose a first-time fee on the emission of methane from sources required to report
their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source
categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for
2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA. The methane emissions fee and renewable and low
carbon energy funding provisions of the law could increase our and our customers’ operating costs and accelerate the transition away from fossil fuels,
which could in turn reduce demand for our products and services and adversely affect our business and results of operations.
In recent years, there has been considerable uncertainty surrounding regulation of methane emissions. In response to President Biden's executive order
calling on the EPA to revisit federal regulations regarding methane in November 2021, the EPA issued a proposed rule that, if finalized, would make the
existing regulations in Subpart OOOOa more stringent and establish Subpart OOOOb to expand emissions reduction requirements for new, modified and
reconstructed oil and gas sources, including certain source types not previously regulated under Subpart OOOOa. In addition, the proposed rule would
create a new Subpart OOOOc which would require states to develop plans to reduce methane and volatile organic compound emissions from existing
sources that must be at least as effective as presumptive standards set by the EPA. 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
requirements, operations and maintenance requirements, and so-called green well completion requirements. In November 2022, the EPA published a
supplemental methane proposal, which, among other items, sets forth specific revisions strengthening the first nationwide emission guidelines for states to
limit methane emissions from existing crude oil and natural gas facilities. The proposal also revises requirements for fugitive emissions monitoring and
repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions
events, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce
methane emissions. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that these
requirements will be subject to legal challenges. While we cannot predict the final scope or compliance costs of these proposed regulatory requirements,
any such requirements have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows.
Various states and groups of states have also adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on
areas of coverage similar to what the federal government has or may consider, including 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. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from
COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The US also announced, in conjunction with the
European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for
low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be
no guarantees that countries will not seek to implement such a phase out in the future. The impacts of these actions, orders, pledges, agreements and any
legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, or other international
conventions cannot be predicted at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects on
our operations.
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 or restrict new or existing leases for production of minerals on federal properties. President Biden has issued several executive orders
and strategies focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas. 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. For example, in November 2022 the BLM proposed
a rule that
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would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if BLM finds that an operator’s methane waste
minimization plan is insufficient. The Biden Administration has also called for revisions and restrictions to the leasing and permitting programs for oil and
gas development on federal lands and, for a time, suspended federal oil and gas leasing activities. The U.S. Department of the Interior’s comprehensive
review of the federal leasing program resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate. Any regulatory
changes that restrict or require modifications to our or our suppliers’ existing operations or future expansions plans could reduce the demand for the
products and services we provide, increase our operating costs and may have a negative impact on our financial condition.
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. Should we be targeted by any similar litigation, involvement in such a case could have adverse financial and reputational
impacts and an unfavorable ruling could significantly impact our operations and adversely impact our financial condition.
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 to quantify and reduce those emissions. 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 and, in September 2022, the Federal Reserve announced that six of the U.S.’ largest banks will participate in a pilot climate scenario
analysis exercise to enhance the ability of firms and supervisors to measure and mange climate-related financial risk. The Federal Reserve released its pilot
exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the
banks’ portfolios. While we cannot predict what policies may result from these developments, 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 and our suppliers’ and customers’ businesses and operations. In addition, in March 2022, the SEC released a proposed rule that would establish
a framework for the reporting of climate risks, targets, and metrics. A final rule is anticipated to be released by Q2 2023. Although the final form and
substance of this rule and its requirements are not yet known and its ultimate impact on our business is uncertain, the proposed rule, if finalized, may result
in increased legal, accounting and financial compliance costs for us and our suppliers and customers related to the assessment and disclosure of climate-
related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced
climate disclosure requirements could accelerate the trend of certain stakeholders and lenders in restricting or seeking more stringent conditions with
respect to their investments in our customers in the energy industry and companies like ours that support the energy industry. Separately, the SEC has also
announced that it 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.
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 GHGs 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 those of our suppliers and customers and
thus could have an adverse effect on our operations and supply chain, including resulting in changes to costs associated with maintaining or insuring our
assets. 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
46
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 stakeholder and market 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 or our customers’ hydrocarbon products and additional governmental investigations and private litigation against us or
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. We have also appointed a senior vice president of sustainability, who reports directly to our CEO and also regularly provides reports on
relevant ESG matters to our Board of Directors. We also published our 2021 Sustainability Report, which provides updates on our performance related to
certain ESG topics and sets certain ESG goals, such as reductions in methane intensity in line with the ONE Future goals. While we may elect to seek out
various additional 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, or at all, including as a result of unforeseen costs or technical difficulties associated with achieving such results. Moreover, ESG-
related actions or statements that we may make or take are sometimes based on expectations, assumptions, or third-party information that we currently
believe to be reasonable, but which may subsequently be determined to be erroneous or be subject to misinterpretation. Moreover, 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. However, we cannot guarantee that there will be sufficient offsets for purchase or that, notwithstanding our reliance on any
reputable third party registries, that the offsets we do purchase will successfully achieve the emissions reductions they represent. 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.
Increasingly, investors, lenders, and other stakeholders are focusing on issues related to environmental justice, which may result in increased scrutiny of our
applicable regulatory processes and additional costs of compliance.
Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments
addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of
potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. Certain non-governmental organizations and
other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals, or standards
were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related
to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and
diversion of investments. Additionally, we expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG
matters, and we could face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny.
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
47
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 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 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.
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 August 2022, a U.S. District Court issued a permanent injunction that blocked President Biden’s order
suspending new leases. Litigation concerning this issue remains pending. 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,
48
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.
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 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, a decision on which is not expected until 2023. 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. Most recently, in December 2022, the EPA and Corps released a final
revised definition of “waters of the United States” founded upon the pre-2015 regulations and including updates to incorporate existing Supreme Court
decisions and recognizing regional and geographic differences. However, the new rule has already been challenged, with the State of Texas and industry
groups filing separate suits in federal court in Texas on January 18, 2023. Moreover, the EPA and the Corps have announced an intent to develop a
subsequent rule further revising the definition. Judicial developments further add to this uncertainty. In October 2022, the U.S. Supreme Court heard
arguments in Sackett v. EPA which involves issues relating to the legal tests used to determine whether wetlands are “waters of the United States.” The
Supreme Court is expected to release an opinion in this case in 2023, which could impact the regulatory definition and its implementation. The
implementation of the final rule and the resultant expansion of the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct
operations, could lead to delays, restrictions or cessation of 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.
Separately, Nationwide Permit (“NWP”) 12, which is available under the Clean Water Act for certain oil and gas activities, has been subject to legal
challenges and regulatory revision in recent years. Following legal challenges to NWP 12 in the federal district court for the District of Montana, the Corps
reissued NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, an October 2021
decision by the District Court for the Northern District of California resulted in a vacatur of a 2020 rule revising the Clean Water Act Section 401
certification process. The U.S. Supreme Court has since stayed this vacatur and the EPA has proposed a rule to update and replace the relevant regulations,
public comment on which closed in August 2022. While the Corps has resumed permitting decisions for such NWPs, the Corps has advised that, as part of
the permitting decision process, the Corps will coordinate with certifying authorities on Section 401 certifications as needed, which may result in permit
delays or otherwise impact our operations or those of our customers. Additionally, in March 2022, the Corps announced that it was seeking stakeholder
input on a formal review of NWP 12. While the full extent and impact of these actions is unclear at this time, any disruption in our ability to obtain
coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the
Corps. This in turn could have an adverse effect on our business, financial condition and results of operation.
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 (i) cause our revenues to decline and operating expenses to increase or (ii) delay or
increase the cost of expansion projects.
With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, Targa Midland Gas Pipeline LLC, Midland-Permian Pipeline
LLC, Targa SouthTex Mustang Transmission Ltd., and Targa SouthTex Transmission LP, which are each subject to FERC regulation under the NGPA or
limited FERC regulation under the NGA, 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.
49
Targa NGL, Targa Gulf Coast, and Grand Prix Joint Venture have pipelines that are considered common carrier pipelines subject to regulation by FERC
under the 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 regulated services 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 and liquids 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 and liquids markets. In recent years, FERC has pursued
pro-competitive policies in its regulation of interstate natural gas and liquids 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 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act and, most recently, the 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, PHMSA issued final rules in November 2021 and August 2022, respectively,
imposing a number of additional requirements. For further details, please see the risk factor entitled “We may incur significant costs and liabilities resulting
from performance of pipeline integrity testing programs and related repairs.”
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.
50
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 2023 equals approximately $1.5 million per violation per day, 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
Company LP, TPL SouthTex Pipeline Company LLC, Targa Midland Gas Pipeline LLC, Midland-Permian Pipeline LLC, Targa SouthTex Mustang
Transmission Ltd., and Targa SouthTex Transmission LP, 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. 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 2023 was up to approximately $15,662 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.” Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from
time to time.
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.
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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 appealed the award 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.
On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but
modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on crude oil. We have filed a petition for review with
the Supreme Court of Texas, and the appeal remains pending. The cumulative amount of interest on the award through December 31, 2022, if accrued,
would have been approximately $42.6 million.
Additional information required for this item is provided in Note 18 – 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.
52
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
PART II
Our common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, 2022, there were 182 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 17, 2023, there were 226,639,398 shares of common stock outstanding.
Stock Performance Graph
On October 12, 2022, we were added to the Standard & Poor's 500 Stock Index (the "S&P 500 Index"). We replaced the NYSE Composite Index (the
“NYSE Index”) with the S&P 500 Index, as we believe this index is a more relevant benchmark to measure the Company's performance. We have
continued to present the NYSE Index in this Annual Report for 2022 as a transitional measure.
The graph below compares the cumulative total return to holders of Targa Resources Corp.’s common stock, the NYSE Index, the S&P 500 Index and the
Alerian US Midstream Energy Index (the “AMUS Index”) during the period beginning on December 31, 2017 and ending on December 31, 2022. 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 the
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.
53
Targa Resources Corp.
NYSE Index
S&P 500 Index
AMUS Index
2017
2018
Year Ended December 31,
2020
2019
2021
2022
$
$
$
$
100.00
100.00
100.00
100.00
$
$
$
$
80.09
91.05
95.62
89.09
$
$
$
$
99.46
114.28
125.72
102.95
$
$
$
$
66.93
122.26
148.85
77.26
$
$
$
$
133.87
147.54
191.58
112.04
$
$
$
$
192.20
133.75
156.88
145.15
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. For a discussion of
restrictions on our and our subsidiaries’ ability to pay dividends or make distributions, please see Note 8 – Debt Obligations 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, 2022.
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)
135,863
165,697
168,511
$
$
$
62.51
72.53
71.22
61,845
165,442
168,511
$
$
$
167,765
155,763
173,762
October 1, 2022 - October 31, 2022
November 1, 2022 - November 30, 2022
December 1, 2022 - December 31, 2022
_________________________________
(1)
Includes 395,798 shares purchased under our $500 million common share repurchase program, as well as 74,273 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.
54
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 2020 items and year-to-year comparisons between 2021 and 2020 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, 2021.
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 natural gas, NGL and crude oil
prices. The volatility and uncertainty of natural gas, NGL and crude oil 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)
2022
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2022 Average
2021
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2021 Average
$
$
$
$
6.27
8.19
7.17
4.92
6.64
5.84
4.01
2.83
2.70
3.85
$
$
0.72
0.94
1.09
1.04
0.95
0.94
0.86
0.66
0.65
0.78
82.63
91.64
108.42
94.38
94.27
77.17
70.55
66.06
57.80
67.90
(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:
2022: 43% ethane, 32% propane, 12% normal butane, 4% isobutane and 9% natural gasoline
2021: 45% ethane, 31% propane, 11% 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.
55
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. Volatility in commodity prices 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.
56
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 2023 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 stakeholder and market
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).
57
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 measures most directly comparable to these non-GAAP measures are income (loss) from
operations, Net income (loss) attributable to Targa Resources Corp. 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.
58
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 certain 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 Targa Resources Corp. 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 cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital
expenditures (net of any reimbursements of project costs). 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.
59
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 Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow
and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.
Interest (income) expense, net
Income tax expense (benefit)
Depreciation and amortization expense
Impairment of long-lived assets
(Gain) loss on sale or disposition of assets
Write-down of assets
(Gain) loss from financing activities (1)
(Gain) loss from sale of equity method investment
Transaction costs related to business acquisition (2)
Equity (earnings) loss
Distributions from unconsolidated affiliates and preferred partner interests, net
Change in contingent considerations
Compensation on equity grants
Risk management activities
Noncontrolling interests adjustments (3)
Adjusted EBITDA
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,
2022
2021
(In millions)
$
$
$
$
1,195.5
446.1
131.8
1,096.0
—
(9.6 )
9.8
49.6
(435.9 )
23.9
(9.1 )
27.2
—
57.5
302.5
15.8
2,901.1
(447.6 )
(168.1 )
(6.7 )
2,278.7
(1,177.2 )
1,101.5
$
$
$
$
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)
(2)
(3)
(4)
(5)
Gains or losses on debt repurchases or early debt extinguishments.
Includes financial advisory, legal and other professional fees, and other one-time transaction costs.
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.
60
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
Operating expenses
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
Gain (loss) from sale of equity method investment
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.
Premium on repurchase of noncontrolling interests, net of tax
Dividends on Series A Preferred Stock
Deemed dividends on Series A Preferred Stock
Net income (loss) attributable to common shareholders
Financial data:
Adjusted EBITDA (1)
Distributable cash flow (1)
Adjusted free cash flow (1)
Year Ended December 31,
2022
2021
(In millions)
2022 vs. 2021
$
$
$
$
$
$
19,066.0
1,863.8
20,929.8
16,882.1
912.8
1,096.0
309.7
—
0.2
1,729.0
(446.1 )
9.1
(49.6 )
435.9
(15.1 )
(131.8 )
1,531.4
335.9
1,195.5
53.2
30.0
215.5
896.8
2,901.1
2,278.7
1,101.5
$
$
$
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 )
—
0.5
(14.8 )
422.1
350.9
71.2
—
87.3
—
(16.1 )
2,052.0
1,541.4
1,133.7
3,463.5
516.5
3,980.0
3,152.6
165.8
225.4
36.5
(452.3 )
(12.2 )
864.2
(58.2 )
33.0
(33.0 )
435.9
(15.6 )
(117.0 )
1,109.3
(15.0 )
1,124.3
53.2
(57.3 )
215.5
912.9
849.1
737.3
(32.2 )
22 %
38 %
23 %
23 %
22 %
26 %
13 %
(100 %)
(98 %)
100 %
15 %
138 %
199 %
100 %
NM
NM
263 %
(4 %)
NM
100 %
(66 %)
100 %
NM
41 %
48 %
(3 %)
(1)
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.”
NM Due to a low denominator, the noted percentage change is disproportionately high and, as a result, is not considered meaningful.
2022 Compared to 2021
The increase in commodity sales reflects higher natural gas, NGL and condensate prices ($3,116.3 million) and higher NGL, natural gas and condensate
volumes ($615.9 million), partially offset by the unfavorable impact of hedges ($264.1 million).
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees including the impact of the acquisition of certain
assets in the Delaware Basin, and transportation and fractionation volumes, partially offset by lower export fees.
The increase in product purchases and fuel reflects higher natural gas, NGL and condensate prices and higher NGL, natural gas and condensate volumes.
The increase in operating expenses is primarily due to increased activity and system expansions, the acquisition of certain assets in South Texas and the
Delaware Basin, and inflation, partially offset by the impact of a major winter storm that affected regions across Texas, New Mexico, Oklahoma and
Louisiana during the first quarter of 2021.
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and South Texas, the
shortening of depreciable lives of certain assets that have been, or will be, idled and the impact of system expansions on our asset base, partially offset by a
lower depreciable base associated with assets that were impaired during the fourth quarter of 2021.
The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.
61
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.
See Note 5 - Property, Plant and Equipment and Intangible Assets for further discussion.
Other operating (income) expense in 2021 consisted primarily of the write-down of certain assets to their recoverable amounts.
The increase in interest expense, net is primarily due to higher net borrowings, partially offset by the change in fair value of the mandatorily redeemable
preferred interests, higher capitalized interest resulting from higher growth capital investments, and lower commitment fees.
The increase in equity earnings is primarily due to lower losses resulting from the purchase of our remaining interests in the two joint ventures in South
Texas that we previously held as investments in unconsolidated affiliates and lower losses from GCF, partially offset by lower earnings resulting from the
impact of the GCX Sale and lower earnings from our investment in Little Missouri 4 LLC. See Note 7 – Investments in Unconsolidated Affiliates for
further discussion.
During 2022, the Partnership redeemed the 5.375% Senior Notes due 2027 and the 5.875% Senior Notes due 2026. In addition, we terminated the Previous
TRGP Revolver and the Partnership Revolver. These transactions resulted in a net loss from financing activities. During 2021, the Partnership redeemed
the 5.125% Senior Notes due 2025 and the 4.250% Senior Notes due 2023 and Targa Pipeline Partners LP redeemed its TPL 4.750% Senior Notes due
2021 and TPL 5.875% Senior Notes due 2023, resulting in a net loss from financing activities.
During 2022, we completed the GCX Sale resulting in a gain from sale of an equity method investment. See Note 4 - Acquisitions and Divestitures for
further discussion.
The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a larger release of the valuation allowance in
2022 compared to 2021, the impact of statutory rate changes in Oklahoma and Louisiana in 2021 and the correction of a state tax error in 2021.
The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the DevCo JV Repurchase, partially offset by impairment
losses in 2021 allocated to noncontrolling interest holders in the Carnero Joint Venture, higher income allocation to noncontrolling interests holders in the
Grand Prix Joint Venture and Centrahoma Processing, LLC., and an increase in noncontrolling interest for a joint venture partner in WestTX.
The decrease in dividends on Series A Preferred is due to the full redemption of all of our issued and outstanding shares of Series A Preferred during 2022.
See Note 11 – Preferred Stock for further discussion.
Results of Operations—By Reportable Segment
Our operating margins by reportable segment are:
Year Ended:
December 31, 2022
December 31, 2021
Gathering and
Processing
Logistics and Transportation
(In millions)
Other
$
1,981.0
1,325.3
$
1,456.3
1,264.3
$
(302.4 )
(115.9 )
62
Gathering and Processing Segment
Operating margin
Operating expenses
Adjusted operating margin
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)
Permian Delaware (5)
Total Permian
SouthTX (6)
North Texas
SouthOK (6)
WestOK
Total Central
Badlands (6) (7)
Total Field
Coastal
Total
NGL production, MBbl/d (3)
Permian Midland (4)
Permian Delaware (5)
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 (3)
NGL sales, MBbl/d (3)
Condensate sales, MBbl/d
Average realized prices - inclusive of hedges (8):
Natural gas, $/MMBtu
NGL, $/gal
Condensate, $/Bbl
Year Ended December 31,
2022
2021
(In millions, except operating statistics and price amounts)
2022 vs. 2021
$
$
1,981.0
611.8
2,592.8
$
$
1,325.3
476.2
1,801.5
$
$
2,223.6
1,536.1
3,759.7
276.5
187.0
406.8
208.7
1,079.0
134.9
4,973.6
537.6
5,511.2
321.7
193.9
515.6
31.2
21.2
47.6
14.6
114.6
16.1
646.3
32.0
678.3
117.6
29.5
2,320.6
438.7
15.5
5.35
0.75
88.26
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
655.7
135.6
791.3
295.2
696.3
991.5
98.8
8.1
0.9
(3.9 )
103.9
(4.9 )
1,090.5
49 %
28 %
44 %
15 %
83 %
56 %
5 %
—
(2 %)
(4 %)
(49.6 )
(8 %)
1,040.9
43.8
79.8
123.6
9.0
1.1
(1.9 )
(1.9 )
6.3
(0.1 )
129.8
(1.9 )
127.9
(23.3 )
(5.5 )
112.9
44.1
0.6
2.08
0.14
28.24
23 %
16 %
70 %
41 %
5 %
(4 %)
(12 %)
(1 %)
(6 %)
23 %
(17 %)
(16 %)
5 %
11 %
4 %
64 %
23 %
47 %
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
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% undivided interest, 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.
Includes operations from the acquisition of certain assets in the Delaware Basin for the period effective August 1, 2022.
Operations include facilities that are not wholly owned by us. SouthTX operating statistics include the impact of the South Texas Acquisition for the period effective April 21, 2022. 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.
63
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:
Natural gas (BBtu)
NGL (MMgal)
Crude oil (MBbl)
Year Ended December 31, 2022
Year Ended December 31, 2021
(In millions, except volumetric data and price amounts)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
$
74.8
717.6
2.2
(2.13 ) $
(0.30 )
(31.73 )
$
(159.2 )
(213.0 )
(69.8 )
(442.0 )
$
76.8
581.5
2.1
(1.41 ) $
(0.26 )
(14.33 )
$
(108.0 )
(153.1 )
(30.1 )
(291.2 )
(1)
The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
2022 Compared to 2021
The increase in adjusted operating margin was due to higher realized commodity prices, higher natural gas inlet volumes, and higher fees resulting in
increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets
in the Delaware Basin during the third quarter of 2022, higher producer activity and the addition of the Legacy and Red Hills VI plants during the third
quarter of 2022. The decrease in volumes in the Coastal region was due to lower producer activity.
The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and the Delaware Basin in the second and
third quarters of 2022, which included one-time acquisition costs. Additionally, higher volumes in the Permian, the addition of the Legacy and Red Hills VI
plants during the third quarter of 2022 and the Heim plant in the third quarter of 2021, and inflation impacts, resulted in increased costs.
Logistics and Transportation Segment
Operating margin
Operating expenses
Adjusted operating margin
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)
Fractionation volumes
Export volumes (3)
NGL sales
$
$
Year Ended December 31,
2022
2021
2022 vs. 2021
(In millions, except operating statistics)
1,456.3
300.2
1,756.5
$
$
488.6
731.7
314.5
866.3
1,264.3
273.0
1,537.3
$
$
396.2
616.0
316.9
834.9
192.0
27.2
219.2
92.4
115.7
(2.4 )
31.4
15%
10%
14%
23%
19%
(1%)
4%
(1)
(2)
(3)
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.
2022 Compared to 2021
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing margin, partially offset
by lower LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian
Gathering and Processing systems and higher fees. Marketing margin increased due to greater optimization opportunities. LPG export margin decreased
primarily due to higher fuel and power costs.
The increase in operating expenses was primarily due to higher repairs and maintenance.
Other
Operating margin
Adjusted operating margin
Year Ended December 31,
2022
2021
(In millions)
2022 vs. 2021
$
$
(302.4 )
(302.4 )
$
$
(115.9 )
(115.9 )
$
$
(186.5 )
(186.5 )
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
64
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, 2022, inclusive of our consolidated joint venture accounts, we had $219.0 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 TRGP Revolver, Commercial Paper Program, 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, see “Recent Developments.”
Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership's liquidity as well as the ability to
contribute capital to the Partnership. The actual amount we declare as dividends 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.
Short-term Liquidity
Our principal sources of short-term liquidity consist of internally generated cash flow, borrowings available under the TRGP Revolver, as well as our right
to request additional commitment increases under the TRGP 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.
Our short-term liquidity on a consolidated basis as of February 17, 2023, was:
Cash on hand (1)
Total availability under the Securitization Facility
Total availability under the TRGP Revolver and Commercial Paper Program
Less: Outstanding borrowings under the Securitization Facility
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program
Outstanding letters of credit under the TRGP Revolver
Total liquidity
(1)
Includes cash held in our consolidated joint venture accounts.
Consolidated Total
(In millions)
209.5
800.0
2,750.0
3,759.5
(800.0 )
(432.5 )
(35.2 )
2,491.8
$
$
Other potential capital resources associated with our existing arrangements include our right to request an additional $500.0 million in commitment
increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 17, 2027.
A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of December 31, 2022, we had
$33.2 million in letters of credit outstanding under the TRGP Revolver. The letters of credit 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, which we closely manage, and valuation; (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
65
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, 2022 decreased $181.4 million compared to December 31, 2021. The decrease was primarily due to higher net
borrowing on the Securitization Facility, and higher accounts payable and accruals related to growth projects in the Permian, partially offset by an increase
to NGL inventory, higher net assets from hedging activities, and an increase in receivables resulting from higher commodity prices.
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 TRGP Revolver, Term Loan Facility, the Securitization Facility, and the potential for variable rate
borrowing under the Commercial Paper Program. 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, 2022, 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 2022, we entered into the TRGP Revolver. The TRGP 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
TRGP Revolver, including a swing line sub-facility of up to $100.0 million. The TRGP Revolver matures in February 2027. In connection with our entry
into the TRGP Revolver, we terminated the Previous TRGP Revolver and the Partnership Revolver. In February 2022, TRGP and the Partnership received
a corporate investment grade credit rating from S&P and Fitch, and in March 2022, the Partnership received a corporate investment grade credit rating from
Moody’s. As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations
thereunder. As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss of $0.8 million due to a write-
off of debt issuance costs.
In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees,
jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the
Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of December 31, 2022,
$5.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.
In March 2022, the Partnership redeemed all of the 5.375% Notes with available liquidity under the TRGP Revolver. As a result of the redemption of the
5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million comprised of $12.6 million of premiums paid and a write-off of $2.4 million
of debt issuance costs.
In April 2022, we completed an underwritten public offering of the 4.200% Notes and the 4.950% Notes, resulting in net proceeds of approximately $1.5
billion. A portion of the net proceeds from the issuance was used to fund the concurrent March Tender Offer and the subsequent redemption of the
Partnership’s 5.875% Notes, with the remainder of the net proceeds used for repayment of the outstanding borrowings under the TRGP Revolver. As a
result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we recorded a loss due to debt extinguishment of $33.8 million
comprised of $29.3 million of premiums paid and a write-off of $4.5 million of debt issuance costs.
In April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023 and replace
the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR. In September 2022, the
Partnership amended the Securitization Facility to, among other things, increase the facility size from $400.0 million to $800.0 million and extend the
facility termination date to September 1, 2023.
In May 2022, we redeemed all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per
share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. Following the
redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. See Note 11 -
Preferred Stock in our Consolidated Financial Statements beginning on page F-1 in this Form 10-K.
66
In July 2022, we completed an underwritten public offering of the 5.200% Notes and the 6.250% Notes, resulting in net proceeds of approximately $1.2
billion. We used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition.
In July 2022, we entered into the Term Loan Facility. The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility and
matures in July 2025. We used the proceeds to fund a portion of the Delaware Basin Acquisition.
In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time,
unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued,
repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. We
maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper
Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. As of December 31, 2022, we
had $1.0 billion outstanding under the Commercial Paper Program.
In January 2023, we completed the underwritten public offering of the 6.125% Notes and the 6.500% Notes, resulting in net proceeds of approximately
$1.7 billion. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining net proceeds for general
corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.
In the future, we or the Partnership may redeem, purchase or exchange certain of our and/or the Partnership’s outstanding debt through redemption calls,
cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases,
exchanges or redemptions, 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.
Compliance with Debt Covenants
As of December 31, 2022, 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
2022
Year Ended December 31,
2021
(In millions)
2022 vs. 2021
$
2,380.8
$
2,302.9
$
77.9
The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs and natural gas, 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.
Cash Flows from Investing Activities
2022
Year Ended December 31,
2021
(In millions)
2022 vs. 2021
$
(4,149.7 )
$
(473.2 )
$
(3,676.5 )
The increase in net cash used in investing activities was primarily due to the outlays for the Delaware Basin Acquisition and the South Texas Acquisition.
Additionally, there were higher outlays for property, plant and equipment resulting from construction activities in the Permian, partially offset by proceeds
from the GCX Sale. See “Recent Developments” for further details on our 2022 expansions.
67
Cash Flows from Financing Activities
Source of Financing Activities, net
Debt, including financing costs
Redemption of Series A Preferred Stock
Repurchase of noncontrolling interests
Dividends
Contributions from (distributions to) noncontrolling interests
Repurchase of shares
Net cash provided by (used in) financing activities
Year Ended December 31,
2022
2021
(In millions)
$
$
4,651.5
(965.2 )
(926.3 )
(379.7 )
(290.3 )
(260.6 )
1,829.4
$
$
(1,189.1 )
—
—
(187.5 )
(484.2 )
(53.2 )
(1,914.0 )
The change in net cash provided by (used in) financing activities was primarily due to net borrowings of debt in 2022, as compared to net repayments of
debt in 2021, partially offset by the redemption of the Series A Preferred and repurchases of non-controlling interests in the DevCo JVs and common stock
during 2022. Additionally, higher dividends were paid in 2022 due to the increase in our common stock dividends from $0.10 to $0.35 per common share
in January 2022.
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
Our subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and
severally, the payment of TRGP’s and the Partnership Issuers’ senior notes, the payment of the notes under the Commercial Paper Program and our
obligations under the Term Loan Facility, subject to certain limited exceptions.
In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance
Sheet and Statement of Operations information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The
Obligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial
information. Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries
(referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information.
Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group follows:
Summarized Combined Balance Sheet Information
ASSETS
December 31, 2022
(In millions)
Current assets
Current assets - affiliates
Long-term assets
Long-term assets - affiliates
Total assets
Current liabilities
Current liabilities - affiliates
Long-term liabilities
Targa Resources Corp. stockholders' equity
Total liabilities and owners' equity
Summarized Combined Statement of Operations Information
Revenues
Operating income (loss)
Net income (loss)
Dividends on Series A Preferred
LIABILITIES AND OWNERS' EQUITY
68
$
$
$
$
$
1,386.9
6.0
10,163.5
10.5
11,566.9
1,779.3
64.2
11,315.6
(1,592.2 )
11,566.9
21,264.0
205.3
101.6
30.0
Year Ended
December 31, 2022
(In millions)
Common Stock Dividends
The following table details the dividends declared and/or paid by us to common shareholders for 2022:
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, 2022
September 30, 2022
June 30, 2022
March 31, 2022
February 15, 2023
November 15, 2022
August 15, 2022
May 16, 2022
$
80.5 $
80.5
80.7
81.2
79.3 $
79.2
79.3
79.8
1.2 $
1.3
1.4
1.4
0.35000
0.35000
0.35000
0.35000
(In millions, except per share amounts)
(1)
Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
Preferred Dividends
Series A Preferred Redemption
In May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87
per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The
difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed
was $223.7 million, of which $215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of
2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated.
See Note 11 - Preferred Stock to our Consolidated Financial Statements.
Prior to the redemption of our Series A Preferred in May 2022, our Series A Preferred bore a cumulative 9.5% fixed dividend payable at the end of each
fiscal quarter. During the year ended December 31, 2022, we paid $51.8 million of dividends to preferred shareholders.
Capital Expenditures
The following table details cash outlays for capital projects for the years ended December 31, 2022 and 2021:
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,
2022
2021
(In millions)
$
$
$
1,219.0
175.4
1,394.4
—
(60.1 )
1,334.3
$
421.9
138.6
560.5
(2.4 )
(53.0 )
505.1
(1)
(2)
Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $1,177.2 million and
$407.7 million for the years ended December 31, 2022 and 2021.
Maintenance capital expenditures, net of contributions from noncontrolling interests, were $168.1 million and $131.7 million for the years ended December 31, 2022 and 2021.
The increase in total growth capital expenditures was primarily due to system expansions in the Permian in response to forecasted production growth and
higher activity levels, and expansions in our downstream business. The increase in total maintenance capital expenditures was primarily due to our growing
infrastructure footprint.
With our announced natural gas processing additions currently under construction in the Permian region, coupled with the construction of our Daytona
NGL Pipeline and Train 9 fractionator in Mont Belvieu, we currently estimate that in 2023 we will invest between $1.8 to $1.9 billion in net growth capital
expenditures for announced projects. Future growth capital expenditures may vary based on
69
investment opportunities. We expect that 2023 maintenance capital expenditures, net of noncontrolling interests, will be approximately $175 million.
Off-Balance Sheet Arrangements
As of December 31, 2022, there were $243.2 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
Within 12 Months
(in millions)
$
$
10,583.1
4,869.6
47.1
265.3
247.6
2,437.8
133.4
18,583.9
$
$
—
570.9
15.7
42.5
6.9
1,341.4
41.7
2,019.1
Total
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Represents scheduled future maturities of long-term debt obligation. See Note 8 - Debt Obligations for more information.
Represents interest expense on long-term debt obligations based on both fixed debt interest rates and prevailing December 31, 2022 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 compressors, substations, vehicles and tractors. See Note 10 - Leases for more information.
Land site lease and rights of way provide for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These
agreements expire at various dates with varying terms, some of which are perpetual. See Note 17 - 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, 2022.
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.
Business Acquisitions
For business acquisitions, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at
their estimated fair values on the acquisition date. Goodwill results when the cost of a business acquisition exceeds the fair value of the net identifiable
assets of the acquired business. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with
respect to projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates,
expectations regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated
fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest in the investee, the duration of each liability, and any resulting
goodwill can materially impact the financial statements in periods after acquisition. See Note 4 – Acquisitions and Divestitures in our Consolidated
Financial Statements.
70
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.
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.
71
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 2027. 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, 2022, 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 operations 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 values 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. While we have no current obligation
to post cash, letters of credit or other additional collateral to secure these hedges so long as we maintain our current credit rating, we could be obligated to
post collateral to secure the hedges in the event of an adverse change in our creditworthiness where a counterparty’s exposure to our credit increases over
the term of the hedge as a result of higher commodity prices. 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.
72
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, 2022:
Natural gas
NGLs
Crude oil
Total
Fair Value
Result of 10% Price Decrease
Result of 10% Price Increase
$
$
(267.6 )
34.2
(22.4 )
(255.8 )
$
$
(In millions)
(185.1 )
123.1
5.7
(56.3 )
$
$
(350.1 )
(54.7 )
(50.5 )
(455.3 )
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, 2022 and 2021, our operating revenues decreased by $(754.7) million and $(490.6) 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 $316.7 million at
December 31, 2021 to $255.8 million at December 31, 2022. Forward commodity prices have increased relative to the fixed prices on our derivative
contracts, creating the 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 TRGP Revolver, the Commercial Paper
Program, the Securitization Facility, and the Term Loan Facility. As of December 31, 2022, 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 TRGP Revolver, the Commercial Paper Program, the Securitization Facility and the Term Loan Facility will also increase.
As of December 31, 2022, we had $3.6 billion in outstanding variable rate borrowings. A hypothetical change of 100 basis points in the rate of our variable
interest rate debt would impact our consolidated annual interest expense by $36.0 million based on our December 31, 2022 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 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, and would reduce our maximum loss
due to counterparty credit risk by $19.1 million as of December 31, 2022. The range of losses attributable to our individual counterparties as of December
31, 2022 would be between $1.9 million and $16.4 million, depending on the counterparty in default.
73
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 $2.2 million and $0.1 million as of December 31, 2022 and December 31, 2021, respectively. The change in the
allowance for doubtful accounts was primarily due to the Delaware Basin Acquisition.
No customer comprised 10% or greater of our consolidated revenues during the years ended December 31, 2022 and 2021, respectively.
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, 2022, 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, 2022.
In July 2022, we completed the Delaware Basin Acquisition. The Delaware Basin Acquisition constituted approximately 2% of total consolidated revenues
for the year ended December 31, 2022 and approximately 10% of total consolidated assets at December 31, 2022. Management’s assessment of and
conclusion on the effectiveness of internal control over financial reporting as of December 31, 2022 excluded the Delaware Basin Acquisition. This
exclusion is in accordance with the SEC guidance that an assessment of recent business
74
combinations may be omitted from management’s assessment of internal control over financial reporting for one year following the acquisition.
(b)
Changes in Internal Control Over Financial Reporting
Other than as set forth above, there have been no changes in our internal control over financial reporting during our most recent fiscal quarter ended
December 31, 2022 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.
75
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 2023 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 2023 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 2023 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 2023 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 2023 annual meeting of stockholders and is
incorporated herein by reference.
76
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
2.1
3.1
3.2
3.3
3.4
3.5
3.6
4.1
4.2
4.3
4.4
4.5
Purchase and Sale Agreement, dated as of June 16, 2022 by and among Lucid Energy Group II Holdings, LLC, Lasso Acquiror LLC
and Lucid Energy Group II LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Corp.’s Current Report on Form 8-K
filed June 17, 2022 (File No. 001-34991)).
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)).
Second Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.4 to Targa Resources Corp.’s
Quarterly Report on Form 10-Q filed May 5, 2022 (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)).
77
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
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)).
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)).
Parent Guarantee dated as of February 18, 2022, by and among Targa Resources Corp. and certain of its subsidiaries (incorporated by
reference to Exhibit 4.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 23, 2022 (File No. 001-34991)).
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 filed October 17, 2017 (File
No. 001-33303)).
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 (incorporated by reference to Exhibit 10.42 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
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 (incorporated by reference to Exhibit 10.43 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
78
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
Supplemental Indenture dated June 17, 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 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 4,
2022 (File No. 001-34991)).
Supplemental Indenture dated August 2, 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 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3,
2022 (File No. 001-34991)).
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 filed January 23, 2019 (File
No. 001-33303)).
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)).
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 (incorporated by reference to Exhibit 10.60 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
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 (incorporated by reference to Exhibit 10.61 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
Supplemental Indenture dated June 17, 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 (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 4,
2022 (File No. 001-34991)).
Supplemental Indenture dated August 2, 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 (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3,
2022 (File No. 001-34991)).
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 filed December 3, 2019 (File
No. 001-33303)).
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)).
79
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
4.42
4.43
4.44
4.45
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 (incorporated by reference to Exhibit 10.67 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
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 (incorporated by reference to Exhibit 10.68 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
Supplemental Indenture dated June 17, 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 (incorporated by reference to Exhibit 10.3 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 4,
2022 (File No. 001-34991)).
Supplemental Indenture dated August 2, 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 (incorporated by reference to Exhibit 10.3 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3,
2022 (File No. 001-34991)).
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 filed August 21, 2020 (File No. 001-
33303)).
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)).
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 (incorporated by reference to Exhibit 10.73 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
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 (incorporated by reference to Exhibit 10.74 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
Supplemental Indenture dated June 17, 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
(incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 4, 2022 (File No.
001-34991)).
Supplemental Indenture dated August 2, 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 (incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3,
2022 (File No. 001-34991)).
80
4.46
4.47
4.48
4.49
4.50
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
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 filed February 5, 2021 (File
No. 001-33303)).
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 (incorporated by reference to Exhibit 10.79 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
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 (incorporated by reference to Exhibit 10.80 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24,
2022 (File No. 001-34991)).
Supplemental Indenture dated June 17, 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 (incorporated by reference to Exhibit 10.5 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 4,
2022 (File No. 001-34991)).
Supplemental Indenture dated August 2, 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 (incorporated by reference to Exhibit 10.5 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3,
2022 (File No. 001-34991)).
Indenture, dated as of April 6, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust
Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Current Report on
Form 8-K filed April 6, 2022 (File No. 001-34991)).
First Supplemental Indenture, dated as of April 6, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and
U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s
Current Report on Form 8-K filed April 6, 2022 (File No. 001-34991)).
Form of Notes (included in Exhibit 4.53 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report
on Form 8-K filed April 6, 2022 (File No. 001-34991)).
Second Supplemental Indenture dated as of June 22, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and
U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.9 to Targa Resources Corp.’s Post-
Effective Amendment No. 1 to Form S-3 filed June 22, 2022 (Registration No. 333-263730)).
Third Supplemental Indenture, dated as of July 7, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and
U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s
Current Report on Form 8-K filed July 7, 2022 (File No. 001-34991)).
Form of Notes (included in Exhibit 4.56 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report
on Form 8-K filed July 7, 2022 (File No. 001-34991)).
Fourth Supplemental Indenture dated as of August 2, 2022, among Targa Resources Corp., as issuer, the guarantors named therein and
U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 10.6 to Targa Resources Corp.’s
Quarterly Report on Form 10-Q filed November 3, 2022 (File No. 001-34991)).
Fifth Supplemental Indenture, dated as of January 9, 2023, among Targa Resources Corp., as issuer, the guarantors named therein and
U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s
Current Report on Form 8-K filed January 9, 2023 (File No. 001-34991)).
Form of Notes (included in Exhibit 4.59 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report
on Form 8-K filed January 9, 2023 (File No. 001-34991)).
81
10.1
10.2+
10.3+
10.4+
10.5+
10.6+
10.7+
10.8+
10.9+
10.10+
10.11+
10.12+
10.13+
10.14+
10.15+
10.16+
10.17
10.18
Credit Agreement dated as of February 17, 2022, 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 February
23, 2022 (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)).
Form of Performance Share Unit Grant Agreement, dated as of January 20, 2022 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 24, 2022
(File No. 001-34991)).
Omnibus Amendment to Performance Share Unit Grant Agreements, dated as of December 15, 2021 (incorporated by reference to
Exhibit 10.13 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).
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)).
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)).
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).
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
82
10.19
10.20
10.21
10.22
10.23+
10.24+
10.25+
10.26+
10.27+
10.28+
10.29+
10.30+
10.31+
10.32+
10.33+
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).
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.
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).
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 filed February 5, 2021 (File No. 001-33303)).
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)).
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)).
83
10.34+
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)).
10.35+
10.36
10.37
10.38
10.39
10.40
10.41
10.42
10.43
10.44
10.45
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)).
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
84
10.46
10.47
10.48
10.49
10.50
10.51
(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 (incorporated by reference to Exhibit
10.104 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 24, 2022 (File No. 001-34991)).
Twelfth Amendment to Receivables Purchase Agreement, dated April 19, 2022, 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 22, 2022 (File No. 001-34991)).
Thirteenth Amendment to Receivables Purchase Agreement, dated as of September 2, 2022, 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 September 6, 2022 (File No. 001-34991)).
Term Loan Agreement, dated as of July 12, 2022, among Targa Resources Corp., Mizuho Bank, Ltd., as administrative agent and a
lender, and the other lenders parties thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on
Form 8-K filed July 12, 2022 (File No. 001-34991)).
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.
22.1*
23.1*
31.1*
31.2*
32.1**
32.2**
101.INS*
101.SCH*
101.CAL*
101.DEF*
101.LAB*
101.PRE*
List of Subsidiary Guarantors.
Consent of Independent Registered Public Accounting Firm.
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
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.
Inline XBRL Instance Document
Inline XBRL Taxonomy Extension Schema Document
Inline XBRL Taxonomy Extension Calculation Linkbase Document
Inline XBRL Taxonomy Extension Definition Linkbase Document
Inline XBRL Taxonomy Extension Label Linkbase Document
Inline XBRL Taxonomy Extension Presentation Linkbase Document
104
Cover Page Interactive Data File (embedded within the Inline XBRL document).
* Filed herewith
** Furnished herewith
85
+ Management contract or compensatory plan or arrangement
Item 16. Form 10-K Summary
None.
86
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 22, 2023
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 22, 2023.
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.
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
87
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, 2022 and December 31, 2021
Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021, and 2020
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
Notes to Consolidated Financial Statements
Note 1 ― Organization and Operations
Note 2 ― Basis of Presentation
Note 3 ― Significant Accounting Policies
Note 4 ― Acquisitions 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 ― Earnings Per Common Share
Note 14 ― Derivative Instruments and Hedging Activities
Note 15 ― Fair Value Measurements
Note 16 ― Related Party Transactions
Note 17 ― Commitments
Note 18 ― Contingencies
Note 19 ― Revenue
Note 20 ― Other Operating (Income) Expense
Note 21 ― Income Taxes
Note 22 ― Supplemental Cash Flow Information
Note 23 ― Compensation Plans
Note 24 ― Segment Information
F-1
F-2
F-3
F-6
F-7
F-8
F-9
F-11
F-12
F-12
F-12
F-12
F-20
F-23
F-24
F-25
F-27
F-32
F-34
F-35
F-36
F-37
F-37
F-40
F-42
F-43
F-43
F-44
F-44
F-44
F-46
F-46
F-48
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.
In July 2022, we completed the Delaware Basin Acquisition. The Delaware Basin Acquisition constituted approximately 2% of total consolidated revenues
for the year ended December 31, 2022 and approximately 10% of total consolidated assets at December 31, 2022. Management’s assessment of and
conclusion on the effectiveness of internal control over financial reporting as of December 31, 2022 excluded the Delaware Basin Acquisition. This
exclusion is in accordance with the SEC guidance that an assessment of recent business combinations may be omitted from management’s assessment of
internal control over financial reporting for one year following the acquisition.
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, 2022.
The effectiveness of our internal control over financial reporting as of December 31, 2022 has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears on page F-3.
/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
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, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period
ended December 31, 2022 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, 2022, 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.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Lucid Energy Delaware, LLC
(“Delaware Basin Acquisition”) from its assessment of internal control over financial reporting as of December 31, 2022 because it was
acquired by the Company in a purchase business combination during 2022. We have also excluded Delaware Basin Acquisition from our
audit of internal control over financial reporting. Delaware Basin Acquisition is a wholly-owned subsidiary whose total assets and total
revenues excluded from management’s assessment and our audit of internal control over financial reporting represent approximately 10%
and 2%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022.
Definition and Limitations of Internal Control over Financial Reporting
F-3
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.
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.
Delaware Basin Acquisition – Valuation of the Customer Relationships Intangible Asset
As described in Note 4 to the consolidated financial statements, the Company completed the acquisition of all of the interests in Lucid Energy
Delaware, LLC (“Lucid”) for approximately $3.5 billion in cash (the “Delaware Basin Acquisition”). The acquisition resulted in a $1,882.0
million customer relationships intangible asset being recorded. The fair value of customer relationships was determined at the date of
acquisition based on the present value of estimated future cash flows using the multi-period excess earnings method. The significant
assumptions used by management in determining the fair value of customer relationships intangible assets include future revenues, discount
rate, and customer attrition rates.
The principal considerations for our determination that performing procedures relating to the valuation of the customer relationships
intangible asset acquired in the Delaware Basin Acquisition is a critical audit matter are (i) the significant judgment by management when
developing the fair value estimate of the customer relationships intangible asset; (ii) a high degree of auditor judgment, subjectivity, and
effort in performing procedures and evaluating management’s significant assumptions related to future revenues, discount rate, and
customer attrition rates; 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 acquisition accounting,
including controls over management’s valuation of the acquired customer relationships intangible asset and controls over the development of
the significant assumptions used by management related to future revenues, discount rate, and customer attrition rates. These procedures
also included, among others (i) reading the purchase agreement; (ii) testing management’s process for developing the fair value estimate of
the customer relationships intangible asset; (iii) evaluating the appropriateness of the multi-period excess earnings method; (iv) testing the
completeness and accuracy of underlying data used in the multi-period excess earnings method; and (v) evaluating the reasonableness of
significant assumptions related to future revenues, discount rate, and customer attrition rates. Evaluating the reasonableness of
management’s significant assumptions related to future revenues involved considering the past performance of the acquired business,
consistency with economic and industry forecasts, and whether these assumptions were consistent with evidence obtained in other areas of
the audit. Professionals with specialized skill and knowledge were used to assist in the evaluation of the appropriateness of the Company’s
multi-period excess earnings method and the reasonableness of discount rate and customer attrition rates significant assumptions.
F-4
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 22, 2023
We have served as the Company’s auditor since 2005.
F-5
Item 1. Financial Statements.
PART I – FINANCIAL INFORMATION
TARGA RESOURCES CORP.
CONSOLIDATED BALANCE SHEETS
Current assets:
Cash and cash equivalents
Trade receivables, net of allowances of $2.2 million and $0.1 million at December 31, 2022 and December 31, 2021
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
Current liabilities:
Accounts payable
Accrued liabilities
Distributions payable
Interest payable
Liabilities from risk management activities
Current debt obligations
Total current liabilities
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Long-term debt
Long-term liabilities from risk management activities
Deferred income taxes, net
Other long-term liabilities
Commitments and Contingencies (see Notes 17 and 18)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, zero and 919,300 shares issued and outstanding
as of December 31, 2022 and December 31, 2021), 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, 2022 and December 31, 2021)
Issued Outstanding
December 31, 2022 237,939,058 226,042,229
December 31, 2021 236,105,293 228,221,122
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, zero shares issued and outstanding)
Additional paid-in capital
Retained earnings (deficit)
Accumulated other comprehensive income (loss)
Treasury stock, at cost (11,896,829 shares as of December 31, 2022 and 7,884,171 shares as of December 31, 2021)
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.
F-6
December 31, 2022
December 31,
2021
(In millions)
$
$
$
$
$
$
$
219.0
1,408.4
393.8
179.9
155.5
2,356.6
14,214.6
2,734.6
24.5
131.3
98.4
19,560.0
1,448.8
273.3
16.2
174.0
320.1
834.3
3,066.7
10,702.1
140.1
327.7
341.2
158.5
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
—
749.7
0.2
0.2
—
3,702.3
(626.8 )
54.7
(464.7 )
2,665.7
2,316.5
4,982.2
19,560.0
$
—
4,268.9
(1,822.3 )
(230.9 )
(204.1 )
2,011.8
3,166.9
5,178.7
15,208.2
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
2022
Year Ended December 31,
2021
(In millions, except per share amounts)
2020
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
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.
Premium on repurchase of noncontrolling interests, net of tax
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
$
$
$
$
$
19,066.0
1,863.8
20,929.8
16,882.1
912.8
1,096.0
309.7
—
0.2
1,729.0
(446.1 )
9.1
(49.6 )
435.9
(15.1 )
1,663.2
(131.8 )
1,531.4
335.9
1,195.5
53.2
30.0
215.5
896.8
$
3.95
3.88
$
$
227.3
231.1
$
$
$
$
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 )
—
0.5
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
—
3.7
(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
See notes to consolidated financial statements.
F-7
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value
Settlements reclassified to revenues
Other comprehensive income (loss)
Comprehensive income (loss)
Less: Comprehensive income (loss) attributable to
noncontrolling interests
Comprehensive income (loss) attributable to Targa
Resources Corp.
Year Ended December 31,
2022
Related
Income
Tax
Pre-Tax
After Tax
Pre-Tax
2021
Related
Income
Tax
(In millions)
After Tax Pre-Tax
2020
Related
Income
Tax
After Tax
$ 1,531.4
$
422.1
$
(1,325.0 )
$
$
(5.6 )
373.0
367.4
1.3
(83.1 )
(81.8 )
$
(534.6 ) $
417.3
128.4
(100.2 )
(117.3 )
28.2
(4.3 )
289.9
285.6
1,817.0
335.9
$ 1,481.1
$
(406.2 ) $
317.1
(89.1 )
333.0
350.9
(17.9 )
(218.3 ) $
(90.8 )
(309.1 )
51.5
23.3
74.8
(166.8 )
(67.5 )
(234.3 )
(1,559.3 )
228.9
$
(1,788.2 )
See notes to consolidated financial statements.
F-8
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK
Common Stock
Additional
Paid in
Retained
Earnings
(Accumulated
Shares
Amount
Capital
Deficit)
Accumulated
Other
Comprehensive
Income
(Loss)
Treasury
Shares
Noncontrolling
Total
Series A
Owner's Preferred
Shares
Amount
Interests
Equity
Stock
(In millions, except shares in thousands)
Balance, December 31, 2019
Compensation on equity grants
Distribution equivalent rights
Shares issued under compensation program
Shares 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
$
232,844
—
—
939
(235 )
(5,486 )
$
0.2
—
—
—
—
—
—
—
—
—
$
5,221.2
66.2
(5.4 )
—
—
—
—
(91.7 )
$
(339.6 )
—
—
—
—
—
(91.7 )
91.7
—
—
(39.2 )
—
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
Impact of accounting standard adoption
Compensation on equity grants
Distribution equivalent rights
Shares issued under compensation program
Shares tendered for tax withholding obligations
Repurchases of common stock
Series A Preferred Stock dividends
—
—
—
—
—
—
—
—
228,062
—
—
—
1,312
(397 )
(756 )
—
—
—
—
—
—
—
—
0.2
—
—
—
—
—
—
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
—
—
—
—
—
—
—
—
—
—
228,221
—
—
—
—
—
—
0.2
$
$
—
(282.0 )
(29.2 )
—
—
—
—
—
4,839.9
(448.3 )
59.2
(3.1 )
—
—
—
—
(87.3 )
—
(91.5 )
—
—
—
—
4,268.9
$
(282.0 )
282.0
—
—
—
—
—
(1,553.9 )
(1,893.5 )
—
—
—
—
—
—
(87.3 )
87.3
(91.5 )
91.5
—
—
—
71.2
(1,822.3 )
$
92.5
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(234.3 )
—
(141.8 )
—
—
—
—
—
—
—
—
—
—
—
—
(89.1 )
—
(230.9 )
$
1,010
—
—
—
235
5,486
$ (53.5)
—
—
—
(5.9 )
(91.5)
$
3,522.1
—
—
—
—
$ 8,442.9
66.2
(5.4 )
—
(5.9 )
(91.5 )
—
—
—
—
—
—
(91.7 )
—
278.8
—
—
—
—
—
—
—
—
—
(39.2 )
37.6
—
—
—
—
—
—
—
—
6,731
—
—
—
—
397
756
—
—
—
—
—
—
—
—
(150.9)
—
—
—
—
(13.2)
(40.0)
—
—
—
(570.7 )
41.5
27.5
—
228.9
3,249.3
—
—
—
—
—
—
(282.0 )
—
(29.2 )
(570.7 )
41.5
27.5
(234.3 )
(1,325.0 )
5,903.2
(448.3 )
59.2
(3.1 )
—
(13.2 )
(40.0 )
—
—
—
—
—
—
(87.3 )
—
—
—
—
—
—
—
7,884
—
—
—
—
—
—
$ (204.1)
$
—
—
(449.1 )
15.8
—
350.9
3,166.9
(91.5 )
—
(449.1 )
15.8
(89.1 )
422.1
$ 5,178.7
$
—
—
(15.0 )
—
—
—
—
—
301.4
448.3
—
—
—
—
—
—
—
—
—
—
—
—
—
749.7
See notes to consolidated financial statements.
F-9
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK
Common Stock
Additional
Paid in
Retained
Earnings
(Accumulated
Shares
Amount
Capital
Deficit)
Accumulated
Other
Comprehensive
Income
(Loss)
Treasury
Shares
Series A
Noncontrolling Owner's Preferred
Total
Shares Amount
Interests
Equity
Stock
Balance, December 31, 2021
Compensation on equity grants
Distribution equivalent rights
Shares issued under compensation program
Shares tendered for tax withholding
obligations
Repurchases of common stock
Series A Preferred Stock dividends
Dividends - $47.50 per share
Dividends in excess of retained earnings
Deemed dividends - redemption of Series A
Preferred Stock
Common stock dividends
Dividends - $1.40 per share
Dividends in excess of retained earnings
Redemption of Series A Preferred Stock
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Repurchase of noncontrolling interests, net of
tax
Other comprehensive income (loss)
Net income (loss)
Balance, December 31, 2022
(In millions, except shares in thousands)
$
228,221
—
—
1,834
$
0.2
—
—
—
$
4,268.9
57.5
(7.1 )
—
$
(1,822.3 )
—
—
—
(230.9 )
—
—
—
7,884
—
—
—
$ (204.1) $
—
—
—
3,166.9
—
—
—
$
$ 5,178.7
57.5
(7.1 )
—
749.7
—
—
—
(601 )
(3,412 )
—
—
—
—
—
—
—
—
—
(30.0 )
—
—
(215.5 )
—
—
—
—
—
—
—
—
226,042
—
—
—
—
—
—
—
—
0.2
$
$
—
(318.3 )
—
—
—
(53.2 )
—
—
3,702.3
$
—
—
(30.0 )
30.0
—
(318.3 )
318.3
—
—
—
—
—
1,195.5
(626.8 )
—
—
—
—
—
—
—
—
—
—
601
3,412
(35.8)
(224.8)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(354.5 )
26.1
(35.8 )
(224.8 )
(30.0 )
—
(215.5 )
(318.3 )
—
—
(354.5 )
26.1
—
285.6
—
54.7
—
—
—
11,897
—
—
—
$ (464.7) $
$
(857.9 )
—
335.9
2,316.5
(911.1 )
285.6
1,531.4
$ 4,982.2
$
—
—
—
—
—
—
—
(749.7 )
—
—
—
—
—
—
See notes to consolidated financial statements.
F-10
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
2022
Year Ended December 31,
2021
(In millions)
2020
$
1,531.4
$
422.1
$
(1,325.0 )
Cash flows from operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense
Compensation on equity grants
Depreciation and amortization expense
Impairment of long-lived assets
(Gain) loss on sale or disposition of assets
Write-downs of assets
Accretion of asset retirement obligations
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, net of acquisitions:
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
Outlays for business acquisition, net of cash acquired
Outlays for asset acquisition, net of cash acquired
Proceeds from sale of assets
Investments in unconsolidated affiliates
Proceeds from sale of equity method investment
Return of capital from unconsolidated affiliates
Other, net
Net cash provided by (used in) investing activities
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities
Repayments of credit facilities
Proceeds from borrowings of commercial paper notes
Repayments of commercial paper notes
Proceeds from borrowings under term loan facility
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
Repurchase of shares
Contributions from noncontrolling interests
Redemption of Preferred Units
Distributions to noncontrolling interests
Repurchase of noncontrolling interests
Redemption of Series A Preferred Stock
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-11
10.5
57.5
1,096.0
—
(9.6 )
9.8
4.8
125.1
(9.1 )
12.2
302.5
49.6
(435.9 )
—
219.7
(236.2 )
(383.0 )
35.5
2,380.8
(1,334.3 )
(3,503.9 )
(205.2 )
23.0
(1.5 )
857.0
16.8
(1.6 )
(4,149.7 )
5,845.0
(5,555.0 )
30,504.3
(29,495.6 )
1,500.0
1,230.0
(580.0 )
2,741.4
(1,473.2 )
(19.7 )
(45.7 )
(260.6 )
26.1
—
(316.4 )
(926.3 )
(965.2 )
—
—
(379.7 )
1,829.4
60.5
158.5
219.0
$
10.3
59.2
870.6
452.3
2.0
10.3
4.0
12.1
23.9
84.0
116.0
16.6
—
0.1
(392.4 )
40.6
565.3
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
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. (NYSE: TRGP) 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,” “Targa” or "TRGP" are intended to mean our
consolidated business and operations. TRGP 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.” Targa consolidated the Partnership and its subsidiaries under GAAP, and
prepared accompanying consolidated financial statements under the rules and regulations of the SEC. Targa’s consolidated financial statements include
differences from the consolidated financial statements of the Partnership. The most noteworthy differences are:
•
•
•
•
•
the inclusion of the TRGP senior revolving credit facility and term loan facility;
the inclusion of the TRGP senior notes;
the inclusion of the TRGP commercial paper notes;
the inclusion of Series A Preferred Stock (“Series A Preferred”) prior to full redemption in May 2022; and
the impacts of TRGP’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 24 – 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, 2022 and 2021, and the results
of operations, comprehensive income (loss), cash flows, and changes in owners’ equity for the years ended December 31, 2022, 2021 and 2020. 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.
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, except in the case of undivided interest ownership. 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-12
As of December 31, 2022, our consolidated joint ventures include the following:
Gathering and Processing Segment
•
•
•
•
•
50% ownership interest in the Carnero G&P LLC;
60% ownership interest in Centrahoma Processing LLC;
55% ownership interest in Targa Badlands LLC;
72.8% undivided interest in the assets of Targa Pipeline Mid-Continent WestTex LLC; and
76.8% ownership interest in Venice Energy Services Company, LLC.
Logistics and Transportation Segment
•
•
•
88% ownership interest in Cedar Bayou Fractionators, L.P.;
75% ownership interest in Grand Prix Pipeline LLC through the Grand Prix Joint Venture (prior to the Grand Prix Transaction, as defined in
Note 4 – Acquisitions and Divestitures); and
80% ownership interest in Targa Train 7 LLC.
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.
As of December 31, 2022, our investments in unconsolidated affiliates include the following:
Gathering and Processing Segment
•
50% ownership interest in Little Missouri 4 LLC (“Little Missouri 4”).
Logistics and Transportation Segment
•
•
50% ownership interest in Cayenne Pipeline, LLC (“Cayenne”); and
38.8% ownership interest in Gulf Coast Fractionators (“GCF”).
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, (i) estimating unbilled revenues, product purchases and operating and general and administrative
cost accruals, (ii) developing fair value assumptions, including estimates of future cash flows and discount rates, (iii) analyzing long-lived assets for
possible impairment, (iv) estimating the useful lives of assets, (v) estimating contingencies, guarantees and indemnifications and (vi) 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.
F-13
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.
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.
F-14
The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements:
Derivative Treatment
Normal Purchases and Normal Sales
Mark-to-Market
Cash Flow Hedge
Recognition and Measurement
Balance Sheet
Fair value not recorded
Recorded at fair value
Income Statement
Earnings recognized when volumes are physically delivered or
received
Change in fair value recognized currently in earnings
Recorded at fair value with changes in fair value deferred in
Accumulated Other Comprehensive Income ("AOCI")
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.
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.
F-15
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 and commercial paper notes 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.
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.
F-16
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, which represent our joint venture partners’ interests in two joint ventures, have been included in other long-
term liabilities on our Consolidated Balance Sheets, and such interests with multiple or indeterminate redemption dates were reported at their estimated
redemption value as of the reporting dates. These point-in-time values did not represent the amount that ultimately would be redeemed in the future.
Changes in the redemption value have been included in interest expense, net in our Consolidated Statements of Operations.
Effective September 1, 2022, we redeemed our joint venture partner's mandatorily redeemable preferred interests in the two joint ventures that, separately,
owned 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.
Prior to the redemption, the joint ventures collectively held $1.9 billion face value in notes receivable from our partner, which were due July 2042. The
interest rate payable under the notes receivable was a variable LIBOR-based rate. For the years ended December 31, 2022, 2021 and 2020, interest income
(expense) on the notes receivable was $(1.8) million, $12.3 million and $8.6 million, net of the return paid to our partner, which was reflected within
Interest expense, net in our Consolidated Statements of Operations.
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.
F-17
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.
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 the reporting period.
F-18
Share-Based Compensation
We award share-based compensation to employees and non-employee 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.
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
Revenue Contract Assets and Liabilities Acquired in a Business Combination
In October 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2021-08, Business Combinations
(Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. Amendments in this update require application of
Accounting Standards Codification 606, Revenue from Contracts with Customers ("ASC 606") to recognize and measure contract assets and contract
liabilities from contracts with customers acquired in a business combination. These amendments are effective for fiscal years, and interim periods within
those years, beginning after December 15, 2022, with early adoption permitted. However, an entity that elects to early adopt must apply the amendments to
all business combinations that occurred during the fiscal year that includes the interim period. We early adopted the amendments on April 1, 2022 and have
applied them to business combinations in 2022. We applied the amendments to the Delaware Basin Acquisition, as defined in Note 4 – Acquisitions and
Divestitures, by recognizing contract liabilities from contracts with customers in accordance with ASC 606.
F-19
Recently issued accounting pronouncements not yet adopted
Supplier Finance Programs
In September 2022, the FASB issued ASU 2022-04, Liabilities—Supplier Finance Programs (Subtopic 405-50). Amendments in this update require annual
and interim disclosure of the key terms of outstanding supplier finance programs and a rollforward of the related obligations. These amendments do not
affect the recognition, measurement or financial statement presentation of the supplier finance program obligations. These amendments are effective for
fiscal years beginning after December 15, 2022, except for the rollforward requirements, which is effective for fiscal years beginning after December 15,
2023. We have evaluated the effect of the amendments on our consolidated financial statements and will disclose the required information beginning in the
Quarterly Report on Form 10-Q for the quarter ended March 31, 2023.
Note 4 – Acquisitions and Divestitures
Acquisitions
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 NGL Pipeline (“Grand Prix”), Gulf Coast Express Pipeline (“GCX”) and a 110 MBbl/d fractionator in Mont
Belvieu, Texas (“Train 6”). 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.
In January 2022, we exercised the DevCo JV Call Right and closed on the purchase of all of Stonepeak’s interests in the DevCo JVs for $926.3 million (the
“DevCo JV Repurchase”). Following the DevCo JV Repurchase, we owned a 75% interest in the Permian to Mont Belvieu segment of Grand Prix through
Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”) (prior to the Grand Prix Transaction, as defined below), a 100% interest in Train 6 and a 25%
equity interest in GCX (prior to the GCX Sale as defined below in February 2022). The changes in our ownership interests were accounted for as equity
transactions representing the acquisitions of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax was
$53.2 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss)
attributable to common shareholders. In addition, the DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our
Consolidated Balance Sheets.
Subsequent Event
On January 9, 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in Grand Prix Joint Venture (the “Grand Prix Transaction”)
for aggregate consideration of $1.05 billion, subject to certain closing adjustments. Following the closing of the Grand Prix Transaction, we own 100% of
the interest in Grand Prix.
South Texas Acquisition
In April 2022, we completed the acquisition of Southcross Energy Operating LLC and its subsidiaries (“Southcross”) for a purchase price of $201.9 million
(the “South Texas Acquisition”), subject to customary closing adjustments. We made a final net working capital adjustment payment of approximately $1.5
million in the fourth quarter of 2022. We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been
integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the two joint ventures in South Texas that we
previously held as investments in unconsolidated affiliates and that have been consolidated beginning in the second quarter of 2022. We accounted for the
purchase as an asset acquisition and have capitalized $1.8 million of acquisition-related costs and assumed liabilities of $1.8 million as components of the
cost of assets acquired. We allocated $28.1 million to our purchase of Southcross’ interest in the two joint ventures for purposes of consolidation and
$169.7 million, $3.9 million and $5.3 million of the residual cost to property, plant and equipment, current assets and liabilities, net and other non-current
assets, respectively.
Delaware Basin Acquisition
In July 2022, we completed the acquisition of all of the interests in Lucid Energy Delaware, LLC (“Lucid”) from Riverstone Holdings LLC and Goldman
Sachs Asset Management for approximately $3.5 billion in cash (the “Delaware Basin Acquisition”), subject to customary closing adjustments. We
received a final net working capital adjustment payment of approximately $11.4 million in the fourth
F-20
quarter of 2022. We funded the acquisition with (i) $1.5 billion in proceeds drawn under our Term Loan Agreement with Mizuho Bank, Ltd. (“Mizuho”) as
the Administrative Agent and a lender, and other lenders party thereto (the “Term Loan Facility”), (ii) $750.0 million in aggregate principal amount of our
5.200% Senior Notes due 2027 (the “5.200% Notes”) and $500.0 million in aggregate principal amount of our 6.250% Senior Notes due 2052 (the
“6.250% Notes”) pursuant to an underwritten public offering that closed in July 2022 and (iii) $800.0 million drawn on our $2.75 billion TRGP revolving
credit facility (the “TRGP Revolver”). We recorded $16.9 million of debt issuance costs related to the Term Loan Facility, the 5.200% Notes and the
6.250% Notes in our Consolidated Balance Sheets. See Note 8 – Debt Obligations for further details on our financing activities.
The assets acquired in the Delaware Basin Acquisition provide natural gas gathering, treating, and processing services in the Delaware Basin, through
owning and operating approximately 1,050 miles of natural gas pipelines and approximately 1.4 billion cubic feet per day (“Bcf/d”) of cryogenic natural
gas processing capacity primarily in Eddy and Lea counties of New Mexico. The Delaware Basin Acquisition assets increase our footprint in the Delaware
Basin and are integrated into our Permian Delaware operations.
The Delaware Basin Acquisition was accounted for under the acquisition method in accordance with ASC 805, Business Combinations, which requires,
among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The valuation of the acquired assets
and liabilities was prepared using fair value methods and assumptions, including projections of future production volumes, commodity prices, and other
cash flows, market-participant assumptions (e.g., discount rate and exit multiple), expectations regarding customer contracts and relationships, tangible
asset replacement costs, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that
are not observable in the market and therefore represent Level 3 inputs, as defined in Note 15 – Fair Value Measurements. These inputs require judgments
and estimates at the time of valuation.
The following table summarizes the purchase price allocation based on the final fair values assigned to assets acquired and liabilities assumed (in millions):
Cash and cash equivalents
Trade receivables, net of allowances (1)
Other current assets
Property, plant and equipment, net
Intangible assets, net
Other long-term assets
Current liabilities
Other long-term liabilities
Purchase price
$
$
9.9
211.0
3.5
1,669.0
1,882.0
57.3
(236.7 )
(100.7 )
3,495.3
(1)
The fair value of the assets acquired includes trade receivables of $211.0 million. The gross amount due under contract was $213.4 million, of which $2.4 million was expected to be
uncollectible. Trade receivables, net of allowances, excludes $18.5 million that was due from Targa. We reflected this settlement of a preexisting relationship as a reduction of the
purchase price in accordance with ASC 805.
The value of property, plant and equipment is determined using the cost approach and is primarily comprised of Gathering and Processing assets that will
be depreciated on a straight-line basis over an estimated weighted-average useful life of 20 years. The associated useful lives of property, plant and
equipment were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows.
The value of intangible assets is comprised of customer relationships, which represent estimated value of long-term contracts with customers, that will be
amortized in a manner that closely resembles the expected benefit pattern of the intangible assets over an estimated useful life of 14 years. The associated
useful lives of intangible assets were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows. The
fair value of customer relationships was determined at the date of acquisition based on the present value of estimated future cash flows using the multi-
period excess earnings method. The significant assumptions used by management in determining the fair value of customer relationships intangible assets
include future revenues, discount rate, and customer attrition rates.
The fair values of the tangible and intangible assets are Level 3 measurements in the fair value hierarchy. The fair value of the intangible assets was
determined by applying a discounted cash flow approach, which utilized a discount rate of approximately 19% based on our estimate of the risk that a
theoretical market participant would assign to the respective intangible assets, and customer attrition rates of approximately 5%.
F-21
The results of operations attributable to the assets and liabilities acquired in the Delaware Basin Acquisition have been included in our consolidated
financial statements as part of our Permian Delaware operations in the Gathering and Processing segment since the date of the acquisition. Revenue and
Net Income attributable to the assets acquired for the period August 1, 2022 through December 31, 2022 were $374.1 million and $7.9 million,
respectively. As of December 31, 2022, we had incurred $14.4 million of acquisition-related costs.
Unaudited Pro Forma Financial Information
The following unaudited pro forma summary presents the consolidated results of operations for the years ended December 31, 2022 and 2021 as if the
Delaware Basin Acquisition had occurred on January 1, 2021. The unaudited pro forma financial information is presented for informational purposes only
and is not necessarily indicative of our results of operations that would have occurred had the transaction been consummated at the beginning of the period
presented, nor is it necessarily indicative of future results.
Revenues
Net income (loss)
Year Ended December 31,
2022
2021
$
21,268.9
1,477.4
$
17,464.7
215.7
The summarized unaudited pro forma information has been calculated after applying our accounting policies and reflects adjustments for the following:
•
•
•
•
•
•
•
•
Reflects depreciation and amortization based on the fair values of property, plant and equipment and intangible assets, respectively. Property,
plant and equipment are depreciated utilizing a straight-line approach. Intangible assets are amortized in a manner that closely resembles their
expected benefit pattern;
Excludes $14.4 million of acquisition-related costs incurred as of December 31, 2022 from pro forma net income for the year ended
December 31, 2022. Pro forma net income for the year ended December 31, 2021 was adjusted to include those costs;
Excludes the impact of operations previously sold by Lucid, prior to Targa’s acquisition of Lucid;
Excludes the impact of historical activity between Targa and Lucid, prior to Targa’s acquisition of Lucid;
Excludes general and administrative expense related to Lucid’s former parent company, which Targa did not acquire;
Excludes amortization of interest expense and debt issuance costs associated with Lucid’s debt, which was not assumed by Targa;
Includes interest expense and debt issuance cost amortization associated with Targa’s borrowings to finance the Delaware Basin Acquisition;
and
Reflects the income tax effects of the above pro forma adjustments.
Divestitures
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.
Sale of Targa GCX Pipeline LLC
In May 2022, we completed the sale of Targa GCX Pipeline LLC, which held a 25% equity interest in GCX, to a third party for $857.0 million (the “GCX
Sale”). As a result of the GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated
Statements of Operations in 2022.
See Note 7 – Investments in Unconsolidated Affiliates for further discussion on South Texas Acquisition and GCX Sale.
F-22
Note 5 — Property, Plant and Equipment and Intangible Assets
Property, Plant and Equipment and Intangible Assets
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
$
$
$
December 31, 2022
December 31, 2021
$
10,403.1
7,421.2
1,341.6
2,919.3
387.6
163.3
1,011.0
266.1
23,913.2
(9,698.6 )
14,214.6
$
4,379.7
(1,645.1 )
2,734.6
$
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
Estimated Useful Lives (In Years)
5 to 20
5 to 25
5 to 25
10 to 50
3 to 50
—
—
5 to 14
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.
For each of the years ended December 31, 2022, 2021 and 2020 depreciation expense was $853.8 million, $739.6 million and $721.1 million, respectively.
Intangible Assets
Intangible assets consist of customer relationships acquired in the Delaware Basin Acquisition, and 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.
For each of the years ended December 31, 2022, 2021 and 2020, amortization expense for our intangible assets was $242.2 million, $131.0 million and
$144.0 million, respectively. The estimated annual amortization expense for intangible assets is approximately $384.0 million, $373.2 million, $326.0
million, $279.8 million and $252.2 million for each of the years 2023 through 2027. As of December 31, 2022, the weighted average amortization period
for our intangible assets was approximately 12.4 years.
The changes in our intangible assets are as follows:
Balance at beginning of period
Additions from Delaware Basin Acquisition
Impairment
Amortization
Balance at end of period
Impairments of Long-Lived Assets
$
$
December 31, 2022
December 31, 2021
$
1,094.8
1,882.0
—
(242.2 )
2,734.6
$
1,382.4
—
(156.6 )
(131.0 )
1,094.8
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.
F-23
2021
In the fourth quarter of 2021, we recorded a non-cash pre-tax impairment charge of $452.3 million, comprised of $295.7 million for the impairment of
certain gas processing facilities and gathering systems, and $156.6 million related to the impairment of intangible customer relationships associated with
our Central operations in the 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.
2020
In the first quarter of 2020, we recorded a non-cash pre-tax impairment charge of $2,442.8 million, comprised of $2,234.2 million related to the impairment
of certain gas processing facilities and gathering systems associated with our Central operations and our Coastal operations in the Gathering and Processing
segment, and $208.6 million related to the impairment of intangible customer relationships associated with our Central operations in the 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.
For the 2021 and 2020 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% and 14.0% when deriving the fair value of the asset groups impaired during 2021 and 2020, 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.
Note 6 – Goodwill
As of December 31, 2022, we had $45.2 million of goodwill included in Other long-term assets on the Consolidated Balance Sheets related to the March
2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin.
Permian Midland
Permian Delaware
Goodwill
December 31, 2022
December 31, 2021
$
$
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 2022, 2021 and 2020 annual evaluations,
F-24
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.
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 15 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of
valuation.
Note 7 – Investments in Unconsolidated Affiliates
Our investments in unconsolidated affiliates consist of the following:
Gathering and Processing Segment
•
50% operated ownership interest in Little Missouri 4.
Logistics and Transportation Segment
•
•
38.8% operated ownership interest in GCF; and
50% operated ownership interest in 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.
In April 2022, we completed the South Texas Acquisition. Prior to closing the South Texas Acquisition, we had 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”
and, together with T2 LaSalle, the “T2 Joint Ventures”). Following the closing of the South Texas Acquisition, we own 100% of the interest in the T2 Joint
Ventures.
In May 2022, we completed the GCX Sale. Prior to the GCX Sale, we owned a 25% non-operated ownership interest in GCX. Following the
announcement of the GCX Sale in February 2022, we ceased recognizing equity earnings (loss) due to the terms of the sales agreement. As a result of the
GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations in
2022.
F-25
The following table shows the activity related to our investments in unconsolidated affiliates:
Balance at December
31, 2019
Equity Earnings
(Loss)
Cash Distributions
$
Contributions
$
$
$
447.5
103.7
89.6
44.8
37.2
15.9
738.7
Balance at December
31, 2020
$
$
435.2
104.7
79.8
39.6
38.5
16.2
714.0
Balance at December
31, 2021
$
$
421.0
98.1
28.8
21.9
4.2
12.5
586.5
$
$
$
$
$
$
66.3
10.8
(8.9 )
(4.8 )
2.9
6.3
72.6
$
63.4
10.9
(57.0 )
(35.0 )
(8.6 )
2.4
(23.9 ) $
5.7
5.5
(3.2 )
(0.6 )
(0.3 )
2.0
9.1
$
Equity Earnings
(Loss)
Cash Distributions
$
Contributions
$
Disposition/
Consolidation
Disposition/
Consolidation
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(81.3 ) $
(9.8 )
(0.9 )
(0.4 )
(1.6 )
(6.0 )
(100.0 ) $
(78.1 ) $
(17.5 )
(1.0 )
(0.4 )
(1.1 )
(6.1 )
(104.2 ) $
$
$
Balance at December
31, 2020
$
$
435.2
104.7
79.8
39.6
38.5
16.2
714.0
Balance at December
31, 2021
$
$
421.0
98.1
21.9
4.2
28.8
12.5
586.5
2.7
—
—
—
—
—
2.7
0.5
—
0.1
—
—
—
0.6
Equity Earnings
(Loss)
Cash Distributions
$
Disposition/
Consolidation
Contributions
Balance at December
31, 2022
(412.4 ) $
—
—
(20.5 )
(3.9 )
—
(436.8 ) $
—
—
1.5
—
—
—
1.5
$
$
—
90.7
27.1
—
—
13.5
131.3
(14.3 ) $
(12.9 )
—
(0.8 )
—
(1.0 )
(29.0 ) $
GCX
Little Missouri 4
T2 Eagle Ford
T2 LaSalle
GCF
Cayenne
Total
GCX
Little Missouri 4
T2 Eagle Ford
T2 LaSalle
GCF (1)
Cayenne
Total
GCX
Little Missouri 4
GCF (1)
T2 Eagle Ford (2)
T2 LaSalle (2)
Cayenne
Total
(1)
(2)
In January 2021, GCF was temporarily idled and Targa assumed operatorship in the first half of 2021. In January 2023, we reached an agreement with our partners to reactivate GCF. The
facility is expected to be operational during the first quarter of 2024.
Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100% owned and consolidated by Targa.
Our equity loss for the year ended December 31, 2021 included the effect of impairments in the carrying values of our investments in the T2 Joint Ventures.
As a result of the decrease in current and expected future utilization of the underlying assets, we determined that factors indicated that a decrease in the
value of our investments occurred that was other than temporary. As a result of the 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
represented our proportionate share of impairment charges recorded by the joint ventures, as well as 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.
F-26
Note 8 — Debt Obligations
Current:
Partnership accounts receivable securitization facility, due September 2023 (1)
Finance lease liabilities
Current debt obligations
Long-term:
Term loan facility, variable rate, due July 2025
TRGP senior revolving credit facility, variable rate, due February 2027 (2)
Senior unsecured notes issued by TRGP:
5.200% fixed rate, due July 2027
4.200% fixed rate, due February 2033
4.950% fixed rate, due April 2052
6.250% fixed rate, due July 2052
Unamortized discount
Senior unsecured notes issued by the Partnership: (3)
5.875% fixed rate, due April 2026
5.375% fixed rate, due February 2027
6.500% fixed rate, due July 2027
5.000% fixed rate, due January 2028
6.875% fixed rate, due January 2029
5.500% fixed rate, due March 2030
4.875% fixed rate, due February 2031
4.000% fixed rate, due January 2032
Debt issuance costs, net of amortization
Finance lease liabilities
Long-term debt
Total debt obligations
Irrevocable standby letters of credit: (2)
Letters of credit outstanding under the TRGP senior revolving credit facility
Letters of credit outstanding under the Partnership senior
secured revolving credit facility
December 31, 2022
December 31, 2021
$
$
$
$
$
800.0
34.3
834.3
1,500.0
1,298.7
750.0
750.0
750.0
500.0
(8.4 )
—
—
705.2
700.3
679.3
949.6
1,000.0
1,000.0
10,574.7
(65.6 )
193.0
10,702.1
11,536.4
$
33.2
$
—
33.2
$
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
(1)
(2)
(3)
As of December 31, 2022, the Partnership had $800.0 million of qualifying receivables under its $800.0 million Securitization Facility, resulting in zero availability.
In February 2022, we entered into the TRGP Revolver which matures in February 2027, and terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP
Revolver”) and the Partnership’s senior secured revolving credit facility (the “Partnership Revolver”). In July 2022, we established an unsecured commercial paper note program (the
“Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under our TRGP Revolver equal to the aggregate
amount outstanding under the Commercial Paper Program. As of December 31, 2022, the TRGP Revolver had $290.0 million borrowings outstanding and the Commercial Paper
Program had $1.0 billion borrowings outstanding, resulting in approximately $1.4 billion of available liquidity, after accounting for outstanding letters of credit. As of December 31,
2021, we had no balance outstanding under the Previous TRGP Revolver or the Partnership Revolver.
As of February 2022, we guarantee all of the Partnership’s outstanding senior unsecured notes.
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, 2022:
TRGP Revolver and Commercial Paper Program
Securitization Facility
Term Loan Facility
Compliance with Debt Covenants
Range of Interest Rates Incurred
1.5% - 5.9%
1.1% - 5.2%
4.1% - 5.8%
Weighted Average Interest Rate
Incurred
3.6%
3.0%
4.6%
As of December 31, 2022, we were in compliance with the covenants contained in our various debt agreements.
In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees,
jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the
Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of December 31, 2022,
$5.0 billion of the Partnership Issuers' senior unsecured notes was outstanding.
F-27
Debt Obligations
Partnership’s Accounts Receivable Securitization Facility
In April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023 and replace
the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR. In September 2022, the
Partnership amended the Securitization Facility to, among other things, increase the facility size from $400.0 million to $800.0 million and extend the
facility termination date to September 1, 2023.
The Securitization Facility provides up to $800.0 million of borrowing capacity at SOFR rates plus a margin through September 1, 2023. 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.
TRGP Credit Agreement
In February 2022, the Company entered into the TRGP Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing
Line Lender, and the other lenders party thereto. The TRGP 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 TRGP
Revolver) and a swing line sub-facility of up to $100.0 million. The TRGP Revolver matures on February 17, 2027.
In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC (“S&P”)
and Fitch Ratings Inc., and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc.
(“Moody’s”). As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our
obligations thereunder.
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 TRGP Revolver rate plus 1.0% (subject in each case to a floor of 0.0%), plus an
applicable margin 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 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 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 TRGP Revolver are guaranteed by substantially all material wholly-owned domestic subsidiaries of the Company, including by
the Partnership.
The TRGP Revolver requires the Company to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA (the “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.
The TRGP Revolver restricts the Company’s ability to make dividends to stockholders if a default or an event of default (as defined in the TRGP Revolver)
exists or would result from such distribution. In addition, the TRGP 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.
Term Loan Facility
In July 2022, we entered into the Term Loan Facility. The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility and
matures in July 2025. We used the proceeds from the Term Loan Facility to fund a portion of the Delaware Basin Acquisition.
F-28
The Term Loan Facility bears interest at the Company’s option at: (a) the Base Rate (as defined in the Term Loan Facility), which is the highest of the (i)
federal funds rate plus 0.5%, (ii) Mizuho’s prime rate, and (iii) the Term SOFR (as defined in the Term Loan Facility) rate plus 1.0% (subject in each case
to a floor of 0.0%), plus an applicable margin 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 plus 0.10% plus an applicable margin ranging from 1.125% to 1.75% dependent on the Debt
Rating.
Our obligations under the Term Loan Facility are guaranteed by substantially all material wholly-owned domestic restricted subsidiaries of the Company,
including the Partnership.
The Term Loan Facility requires the Company to maintain a Consolidated Leverage Ratio (as defined in the Term Loan Facility), 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. For any four-fiscal-quarter-period
during which a material acquisition or disposition occurs, the total leverage ratio 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 Term Loan Facility limits the Company’s ability to make dividends to stockholders if an event of default (as defined in the Term Loan Facility) exists
or would result from such distribution. In addition, the Term Loan Facility contains various covenants that may limit, among other things, the Company’s
ability to incur subsidiary indebtedness, grant liens, make investments, merge or consolidate, and engage in transactions with affiliates.
Commercial Paper Program
In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time,
unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued,
repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. We
maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper
Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. The commercial paper notes are
presented in Long-term debt on our Consolidated Balance Sheets.
TRGP’s Senior Unsecured Notes
All issues of our senior unsecured notes (the “TRGP Notes”) rank pari passu with our existing and future senior indebtedness, including debt issued under
the TRGP Revolver, the Commercial Paper Program and the Term Loan Facility, and rank senior in right of payment to any of our future subordinated
indebtedness. The TRGP Notes are unconditionally guaranteed by certain of our subsidiaries that guarantee the TRGP Revolver. Each guarantee ranks
equally in right of payment with all of such guarantor’s existing and future unsecured senior debt and other unsecured guarantees of senior debt. The notes
and the guarantees are effectively junior to any secured indebtedness of ours or any guarantor to the extent of the value of the assets securing such
indebtedness and structurally subordinated to all indebtedness and other obligations of our subsidiaries that do not guarantee the notes. Interest on all issues
of TRGP’s Notes are payable semi-annually.
The indenture governing the TRGP Notes restricts (i) our ability and the ability of our subsidiaries to incur liens and (ii) TRGP’s ability to merge or
consolidate with or sell, lease, convey transfer or otherwise dispose of all or substantially all of its assets to another company. These covenants are subject
to a number of important exceptions and qualifications.
We may redeem the TRGP Notes, in whole or in part, at any time prior to the applicable par call date at a redemption price equal to the principal amount
plus an applicable make-whole premium, plus accrued and unpaid interest, to the redemption date, as specified in the indenture of each series. After the
applicable par call date, the TRGP Notes may be redeemed at a price equal to par, plus accrued and unpaid interest to the redemption date, as specified in
the indenture of each series.
In the future, we may redeem, purchase or exchange certain of our outstanding debt through redemption calls, cash purchases and/or exchanges for other
debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases or exchanges, if any, will depend on prevailing
market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
F-29
Partnership’s Senior Unsecured Notes
All issues of the Partnership's 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 TRGP 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 (i) the Partnership’s ability and the ability of certain of its
subsidiaries to incur liens and (ii) the Partnership's ability to merge or consolidate with or sell, lease, convey transfer or otherwise dispose of all or
substantially all of its assets to another company. These covenants are subject to a number of important exceptions and qualifications.
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.
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.
In the future, we or the Partnership may redeem, purchase or exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash
purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases or exchanges,
if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be
material.
Senior Unsecured Notes Issuances
In August 2020, the Partnership issued $1.0 billion aggregate principal amount of 4.875% 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 6.750% Senior Notes due 2024 (the “6.750% Notes”) and redeem any 6.750% Notes that remained outstanding
after consummation of the August Tender Offer, with the remainder used for repayment of borrowings under the Previous TRGP 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 4.000% Senior Notes due 2032 (the “February 2021 Offering”),
resulting in net proceeds of approximately $991 million. The 4.000% 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 for the Partnership’s 5.125% Senior Notes due 2025 (the “5.125% Notes”), with the remainder used for repayment of borrowings
under the Partnership Revolver and Previous TRGP Revolver. See “Debt Repurchases and Extinguishments” for further details of the February Tender
Offer.
In April 2022, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Senior Notes due 2033 (the
“4.200% Notes”) and (ii) $750.0 million aggregate principal amount of our 4.950% Senior Notes due 2052 (the “4.950% Notes”), resulting in net proceeds
of approximately $1.5 billion. The 4.200% Notes and the 4.950% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior
unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The 4.200% Notes
and the 4.950% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain First Supplemental Indenture, dated
as of April 6, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. A portion of the net proceeds
from the issuance was used to fund the concurrent cash tender offer (the “March Tender Offer”) and the subsequent redemption of the Partnership’s 5.875%
Senior Notes due April 2026 (the “5.875% Notes”), with the remainder of the net proceeds used for repayment of the outstanding borrowings under the
TRGP Revolver. See “Debt Repurchases and Extinguishments” for further details of the March Tender Offer.
In July 2022, we completed an underwritten public offering of the 5.200% Notes and the 6.250% Notes, resulting in net proceeds of approximately $1.2
billion. The 5.200% Notes and the 6.250% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our
subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain
F-30
conditions. The 5.200% Notes and the 6.250% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain
Third Supplemental Indenture, dated as of July 7, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as
trustee. We used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition.
Debt Repurchases & Extinguishments
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.
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 6.750% 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 6.750% 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.
In November 2020, the Partnership redeemed the $559.6 million remaining balance of its 5.250% Senior Notes due 2023. As a result, we recorded a loss
due to debt extinguishment of $1.8 million.
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 5.125% Notes. As a result of the February Tender Offer and the subsequent redemption of the 5.125% Notes, we recorded a loss
due to debt extinguishment of $14.9 million.
Additionally, Targa Pipeline Partners LP (the “TPL”) redeemed all of the outstanding TPL 4.750% Senior Notes due 2021 and TPL 5.875% Senior Notes
due 2023 (collectively, the “TPL Notes”) in February 2021 with available liquidity under the Partnership 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 4.250% Senior Notes due 2023 (the “4.250% Senior Notes”) in May 2021 with available liquidity under
the Partnership Revolver. As a result of the redemption of the 4.250% Senior Notes, we recorded a loss due to debt extinguishment of $1.9 million.
In February 2022, in connection with entering into the TRGP Revolver, we terminated the Previous TRGP Revolver and Partnership Revolver. As a result
of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss of $0.8 million due to a write-off of debt issuance
costs.
The Partnership redeemed all of the outstanding 5.375% Senior Notes due 2027 (the “5.375% Notes”) in March 2022 with available liquidity under the
TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million.
Concurrent with the 4.200% Notes and the 4.950% Notes offering, we commenced the March Tender Offer to redeem subject to certain terms and
conditions, any and all of the Partnership's outstanding 5.875% Notes. As a result of the March Tender Offer and the subsequent redemption of the 5.875%
Notes, we recorded a loss due to debt extinguishment of $33.8 million.
F-31
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:
TPL Notes
5.125% Senior Notes due 2025
6.750% Senior Notes due 2024
5.875% Senior Notes due 2026
5.375% Senior Notes due 2027
5.000% Senior Notes due 2028
6.500% Senior Notes due 2027
6.875% Senior Notes due 2029
5.500% Senior Notes due 2030
Write-off of debt issuance costs:
Previous TRGP Revolver and Partnership Revolver
5.125% Senior Notes due 2025
4.250% Senior Notes due 2023
5.250% Senior Notes due 2023
6.750% Senior Notes due 2024
5.875% Senior Notes due 2026
5.375% Senior Notes due 2027
5.000% Senior Notes due 2028
6.500% Senior Notes due 2027
6.875% Senior Notes due 2029
5.500% Senior Notes due 2030
Gain (loss) from financing activities
2022
2021
2020
—
—
—
(29.3 )
(12.6 )
—
—
—
—
(0.8 )
—
—
—
—
(4.5 )
(2.4 )
—
—
—
—
(49.6 )
$
$
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
$
$
The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2022, for the next five years, and in
total thereafter:
Total
2023
2024
2025
2026
2027
Thereafter
Scheduled Maturities of Debt
TRGP Revolver and Commercial Paper Program
TRGP Senior unsecured notes
Term Loan Facility
Partnership's Senior unsecured notes
Securitization Facility
Total
$
$
1,298.7
2,741.6
1,500.0
5,034.4
800.0
11,374.7
$
$
—
—
—
—
800.0
800.0
$
$
—
—
—
—
—
—
$
$
—
—
1,500.0
—
—
1,500.0
$
$
—
—
—
—
—
—
$
$
1,298.7
749.0
—
705.2
—
2,752.9
$
$
—
1,992.6
—
4,329.2
—
6,321.8
Subsequent Event
In January 2023, we completed an underwritten public offering of (i) $900.0 million in aggregate principal amount of our 6.125% Senior Notes due 2033
and (ii) $850.0 million in aggregate principal amount of our 6.500% Senior Notes due 2053, resulting in net proceeds of approximately $1.7 billion. We
used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining net proceeds for general corporate purposes,
including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.
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 other long-term liabilities
December 31, 2022
December 31, 2021
198.8
97.9
28.6
15.9
341.2
$
$
171.8
72.1
34.5
23.2
301.6
$
$
F-32
Deferred Revenue
Deferred revenue as of December 31, 2022 and 2021 was $198.8 million and $171.8 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. See Note 18 - Contingencies for more information.
Deferred revenue 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 through the end of the agreement’s term in 2035.
Deferred revenue also includes contributions in aid of construction received from customers for which revenue is recognized over the expected contract
term.
For the years ended December 31, 2022, 2021 and 2020, we recognized $7.5 million, $3.9 million and $3.8 million of revenue for these transactions,
respectively.
The following table shows the components of deferred revenue:
Splitter agreement
Gas contract amendment
Contributions in aid of construction (1)
Other
Total deferred revenue
(1)
Amount reflects additions of deferred revenue related to the Delaware Basin Acquisition.
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, 2022
December 31, 2021
129.0
32.3
31.7
5.8
198.8
$
$
2022
2021
171.8
34.5
(7.5 )
198.8
$
$
$
$
$
$
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
Additions (1)
Accretion expense
Change in cash flow estimate
End of period
(1)
Amount reflects additions of ARO related to the Delaware Basin Acquisition.
$
$
F-33
2022
2021
72.1
20.2
4.8
0.8
97.9
$
$
129.0
34.8
—
8.0
171.8
168.5
7.2
(3.9 )
171.8
68.3
—
4.0
(0.2 )
72.1
Note 10 – Leases
We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, storage and terminal assets. We have finance
leases primarily associated with our substations, compressors, tractors and vehicles. Our leases have remaining lease terms of 1 to 10 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 (1)
Lease liabilities
Current:
Operating leases
Finance leases (1)
Non-current:
Operating leases
Finance leases (1)
Balance Sheet Location
2022
2021
December 31,
Other long-term assets
Property, plant and equipment
Accrued liabilities
Current debt obligations
Other long-term liabilities
Long-term debt
$
$
$
57.3
266.1
14.4
34.3
28.6
193.0
$
$
$
50.8
55.6
11.7
12.8
34.5
13.7
(1)
The December 31, 2022 balance includes $171.2 million of assets and $167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were
subsequently amended and extended.
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 expense, net 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
$
$
$
2022
Year Ended December 31,
2021
2020
17.7
35.0
17.9
20.3
3.5
94.4
$
$
12.2
20.4
5.7
13.3
1.1
52.7
$
$
2022
Year Ended December 31,
2021
2020
$
18.8
2.7
19.7
$
14.1
1.0
12.5
11.6
20.7
5.5
13.6
1.4
52.8
12.3
1.4
12.4
The weighted-average remaining lease terms for operating leases and finance leases are 5 years and 7 years, respectively. The weighted-average discount
rates for operating leases and finance leases are 4.0% and 4.8%, respectively.
The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2022:
Operating Leases
Finance Leases
2023
2024
2025
2026
2027
Thereafter
Total undiscounted cash flows
Less imputed interest
Total lease liabilities
$
$
F-34
15.7
9.9
5.2
4.5
4.0
7.8
47.1
(4.1 )
43.0
$
$
42.5
38.5
37.1
35.4
30.9
80.9
265.3
(38.0 )
227.3
Note 11 – Preferred Stock
Preferred Stock
Prior to the redemption in May 2022, our Series A Preferred had a liquidation value of $1,000 per share and bore a cumulative 9.5% fixed dividend payable
quarterly 45 days after the end of each fiscal quarter. The Series A Preferred had no mandatory redemption date, but was 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.
The Series A Preferred ranked 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 had voting rights in certain circumstances, subject to certain exceptions, which included:
•
•
•
•
•
the issuance or the increase by the Company of any specific class or series of stock that was 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 have materially and adversely affected the
Preferred Stock holder,
the issuance of stock on parity with the Series A Preferred, subject to certain exceptions, if the Company had exceeded a stipulated fixed
charge coverage ratio or an aggregate amount of net proceeds from all future issuances of Parity Stock, or would have used 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 TRGP
Revolver (or replacement commercial bank facilities) in an aggregate amount up to $2.75 billion.
The Series A Preferred did not qualify as a liability instrument because it was 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 have
forced the Company to redeem the Series A Preferred. A maximum of 44,260,953 common shares would have been issued upon conversion of the Series A
Preferred.
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.
Preferred Stock Redemption
In May 2022, we redeemed all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per
share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The
difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed
was $223.7 million, of which $215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of
2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated.
Preferred Stock Dividends
During the year ended December 31, 2022, we paid $51.8 million of dividends to preferred shareholders. During the years ended December 31, 2021 and
2020 we paid $87.3 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 for the year ended December 31, 2020, attributable to accretion of the preferred discount resulting from the beneficial
conversion feature accounting model. Such accretion was included in the book value of the Series A Preferred. After adoption of 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 in 2021, we no longer recognize such accretion.
F-35
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.
In March 2022, 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 “March 2022 Shelf”). The March 2022 Shelf will expire in March 2025.
During 2020, 2021 and 2022, 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, 2022.
Common Share Repurchase Program
In October 2020, our board of directors approved a share repurchase program (the "Share Repurchase Program") for the repurchase of up to $500.0 million
of our outstanding common stock.
For the year ended December 31, 2022, we repurchased 3,412,354 shares of our common stock at a weighted average price of $65.87 for a total net cost of
$224.8 million. For the year ended December 31, 2021, we repurchased 756,478 shares of our common stock at a weighted average price of $52.81 for a
total net cost of $40.0 million. There was $143.8 million remaining under the Share Repurchase Program as of December 31, 2022.
Common Stock Dividends
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.
The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2022, 2021 and 2020:
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)
2022
2021
2020
December 31, 2022
September 30, 2022
June 30, 2022
March 31, 2022
December 31, 2021
September 30, 2021
June 30, 2021
March 31, 2021
December 31, 2020
September 30, 2020
June 30, 2020
March 31, 2020
February 15, 2023
November 15, 2022
August 15, 2022
May 16, 2022
February 15, 2022
November 15, 2021
August 16, 2021
May 14, 2021
February 16, 2021
November 16, 2020
August 17, 2020
May 15, 2020
$
$
$
80.5 $
80.5
80.7
81.2
81.4 $
23.3
23.3
23.3
23.3 $
23.8
23.7
23.7
79.3 $
79.2
79.3
79.8
80.1 $
22.9
22.9
22.9
22.9 $
23.3
23.3
23.3
1.2 $
1.3
1.4
1.4
1.3 $
0.4
0.4
0.4
0.4 $
0.5
0.4
0.4
0.35000
0.35000
0.35000
0.35000
0.35000
0.10000
0.10000
0.10000
0.10000
0.10000
0.10000
0.10000
(1)
Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
F-36
Note 13 — 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: Premium on repurchase of noncontrolling interests, net of tax (1)
Less: Dividends on Series A Preferred (2)
Less: Deemed dividends on Series A Preferred (3)
Net income (loss) attributable to common shareholders for basic earnings per share
Weighted average shares outstanding - basic
Dilutive effect of unvested stock awards (4)
Weighted average shares outstanding - diluted
Net income (loss) available per common share - basic
Net income (loss) available per common share - diluted
Year Ended December 31,
2022
2021
(In millions, except per share amounts)
2020
$
$
$
$
1,195.5
53.2
30.0
215.5
896.8
$
$
227.3
3.8
231.1
3.95
3.88
$
$
$
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 )
(1)
(2)
(3)
(4)
Represents premium paid on the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures.
Includes $8.2 million and $1.1 million attributable to the dividends paid upon the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively.
Includes $215.5 million and $1.6 million attributable to the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. See Note 11 – Preferred Stock
for further discussion.
For the years ended December 31, 2021 and 2020, all unvested restricted stock awards and Series A Preferred were antidilutive because a net loss existed for each of those 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)
Year Ended December 31,
2022
2021
2020
—
14.9
3.3
44.3
2.3
46.4
(1)
The Series A Preferred had no mandatory redemption date, but was redeemable at our election for a 5% premium to the liquidation preference subsequent to March 16, 2022. In May
2022, we redeemed all of our issued and outstanding Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid
dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. See Note 11 – Preferred Stock for further discussion.
Note 14 — 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.
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.
F-37
At December 31, 2022, 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
2023
175,687
591,610
43,115
21,512
6,427
2024
105,377
298,407
21,134
383
3,232
2025
28,334
244,267
4,813
—
853
2026
—
82,500
—
—
—
2027
—
25,000
—
—
—
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. The master netting provisions reduced our maximum loss due to counterparty credit risk by $19.1
million as of December 31, 2022. The range of losses attributable to our individual counterparties would be between $1.9 million and $16.4 million,
depending on the counterparty in default. 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, 2022
Fair Value as of December 31, 2021
Balance Sheet
Location
Derivative
Assets
Derivative
Liabilities
Derivative
Assets
Derivative
Liabilities
158.7
24.2
182.9
21.2
0.3
21.5
179.9
24.5
204.4
$
$
$
$
$
$
(93.8 ) $
(30.9 )
(124.7 ) $
(226.3 ) $
(109.2 )
(335.5 ) $
(320.1 ) $
(140.1 )
(460.2 ) $
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 )
Current
Long-term
Current
Long-term
$
$
$
$
$
$
F-38
The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:
Current Position
December 31, 2022
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, 2021
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
Asset
Gross Presentation
Liability
Collateral
Pro Forma Net Presentation
Liability
Asset
$
$
$
$
162.2
17.7
—
179.9
24.5
—
—
24.5
186.7
17.7
—
204.4
$
$
(316.7 ) $
—
(3.4 )
(320.1 )
(137.4 )
—
(2.7 )
(140.1 )
(454.1 )
—
(6.1 )
(460.2 ) $
12.2
—
—
12.2
22.4
—
—
22.4
34.6
—
—
34.6
Asset
Gross Presentation
Liability
Collateral
39.2
3.9
—
43.1
7.4
0.3
—
7.7
46.6
4.2
—
50.8
$
$
(241.9 ) $
—
(16.3 )
(258.2 )
(95.1 )
—
(14.2 )
(109.3 )
(337.0 )
—
(30.5 )
(367.5 ) $
5.0
—
—
5.0
3.1
—
—
3.1
8.1
—
—
8.1
$
$
$
$
27.2
17.7
—
44.9
7.3
—
—
7.3
34.5
17.7
—
52.2
$
$
(169.5 )
—
(3.4 )
(172.9 )
(97.8 )
—
(2.7 )
(100.5 )
(267.3 )
—
(6.1 )
(273.4 )
Pro Forma Net Presentation
Liability
Asset
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 )
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 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. Our derivative instruments
other than our futures contracts are executed under International Swaps and Derivatives Association (“ISDA”) agreements, which govern the key terms
with our counterparties. Our ISDA agreements contain credit-risk related contingent features. Following the release of the collateral securing our TRGP
Revolver, our derivative positions are no longer secured. As of December 31, 2022, we have outstanding net derivative positions that contain credit-risk
related contingent features that are in a net liability position of $266.7 million. We have not been required to post any collateral related to these positions
due to our credit rating. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs,
we estimate that as of December 31, 2022, we would be required to post $31.4 million of collateral to certain counterparties per the terms of our ISDAs.
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 $255.8 million as of December 31, 2022. 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.
F-39
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)
2022
2021
2020
(5.6 ) $
(534.6 ) $
(218.3 )
Gain (Loss) Reclassified from OCI into Income (Effective Portion)
2022
2021
2020
(373.0 ) $
(417.3 ) $
90.8
$
$
Based on valuations as of December 31, 2022, we expect to reclassify commodity hedge related deferred gains of $63.4 million included in accumulated
other comprehensive income (loss) into earnings before income taxes through the end of 2025, with $70.1 million of gains 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, 2022, 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
2021
2020
2022
$
(381.7 )
$
(73.3 )
$
206.1
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Note 15 – Fair Value Measurements and Note 24 – Segment Information for
additional disclosures related to derivative instruments and hedging activities.
Note 15 — 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 derivatives at December
31, 2022, represent a net liability of $255.8 million, and 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 $455.3 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 $56.3 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 TRGP Revolver, commercial paper notes, Securitization Facility and Term Loan Facility are based on carrying value, which
approximates fair value as their interest rates are based on prevailing market rates; and
the TRGP senior unsecured notes and the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the
debt.
F-40
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
TRGP Revolver and Commercial Paper Program
TRGP Senior unsecured notes
Term Loan Facility
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
Partnership's Senior unsecured notes
Securitization Facility
Carrying
Value
December 31, 2022
Fair Value
Total
Level 1
Level 2
Level 3
$
201.6
457.4
$
$
201.6
457.4
219.0
1,298.7
2,741.6
1,500.0
5,034.4
800.0
219.0
1,298.7
2,452.6
1,500.0
4,711.3
800.0
—
—
—
—
—
—
—
—
$
$
201.6
457.4
—
1,298.7
2,452.6
1,500.0
4,711.3
800.0
—
—
—
—
—
—
—
—
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
—
—
—
—
—
(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 14 – 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 report 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, for which the primary input to the valuation model is the forward commodity basis curve, and is based on observable or
public data sources and extrapolated when observable prices are not available.
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, 2022 and December 31, 2021, we had no derivative contracts categorized as Level 3.
F-41
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 at acquisition or whenever impairment
indicators are present. 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 the
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. For disclosures related to valuation techniques, see Note 4 – Acquisitions and Divestitures and
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 16 — Related Party Transactions
Transactions with Unconsolidated Affiliates
The following table summarizes transactions with unconsolidated affiliates:
2022:
Revenues
Product purchases and fuel
Operating expenses
General and administrative expenses
2021:
Revenues
Product purchases and fuel
Operating expenses
General and administrative expenses
2020:
Revenues
Product purchases and fuel
Operating expenses
General and administrative expenses
GCF
T2 Joint
Ventures (1)
Cayenne
GCX (2)
Little Missouri 4
Total
$
$
$
— $
—
(1.7 )
—
— $
—
(1.1 )
—
0.4 $
—
(16.0 )
—
1.2 $
—
(0.7 )
—
4.4 $
—
(2.3 )
—
4.5 $
—
(1.2 )
—
— $
(4.7 )
(0.3 )
—
— $
(4.8 )
(0.2 )
—
— $
(5.9 )
(0.2 )
—
— $
(25.0 )
—
—
— $
(66.5 )
—
—
0.2 $
(67.2 )
—
—
8.5 $
—
(2.6 )
(0.9 )
10.6 $
—
(2.5 )
(0.8 )
12.6 $
—
(2.2 )
(0.8 )
9.7
(29.7 )
(5.3 )
(0.9 )
15.0
(71.3 )
(6.1 )
(0.8 )
17.7
(73.1 )
(19.6 )
(0.8 )
(1)
(2)
Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100% owned and consolidated by Targa.
Following the closing of the GCX Sale in May 2022, Targa no longer has an ownership interest in GCX.
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.
F-42
Note 17 — 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)
$
247.6
$
6.9
$
6.7
$
7.4
$
9.4
$
8.6
$
208.6
In Aggregate
2023
2024
2025
2026
2027
Thereafter
(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
$
5.8
$
5.9
$
6.5
2022
2021
2020
Note 18 – 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.
On December 26, 2018, 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 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 appealed the award 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. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with
regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on
crude oil. We have filed a petition for review with the Supreme Court of Texas, and the appeal remains pending. The cumulative amount of interest on the
award through December 31, 2022, if accrued, would have been approximately $42.6 million.
F-43
Note 19 – 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 17 years.
Fixed consideration to be recognized as of December 31, 2022
2023
2024
2025 and after
$
449.9
$
451.4
$
2,163.0
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 24 – Segment Information.
Note 20 – Other Operating (Income) Expense
Other operating (income) expense is comprised of the following:
(Gain) loss on sale or disposition of business and assets (1)
Write-down of assets (2)
Other
Total other operating (income) expense
$
$
2022
Year Ended December 31,
2021
2020
(9.6 )
9.8
—
0.2
$
$
2.0
10.3
0.1
12.4
$
$
58.4
55.6
2.6
116.6
(1)
(2)
Primarily related to the sale of assets in Channelview, Texas in 2020. See Note 4 – Acquisitions and Divestitures for further discussion regarding these sales.
Related to the write-down of certain assets to their recoverable amounts.
Note 21 – Income Taxes
Components of the federal and state income tax provisions for the periods indicated are as follows:
Current expense (benefit)
Deferred expense (benefit)
Total income tax expense (benefit)
2022
2021
2020
$
$
6.7
125.1
131.8
$
$
2.7
12.1
14.8
$
$
(15.4 )
(232.7 )
(248.1 )
Our deferred income tax assets and liabilities as of December 31, 2022 and 2021 consist of recognition differences related to certain types of costs as
follows:
Deferred tax assets:
Net operating loss
Disallowed business interest expense carryforward
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
2022
2021
1,568.5
10.3
1,578.8
(36.9 )
1,541.9
(1,842.0 )
(4.2 )
(23.4 )
(1,869.6 )
(327.7 )
(290.5 )
(37.2 )
(327.7 )
$
$
$
$
1,411.3
3.8
1,415.1
(214.4 )
1,200.7
(1,323.0 )
(4.1 )
(9.6 )
(1,336.7 )
(136.0 )
(106.7 )
(29.3 )
(136.0 )
$
$
$
$
F-44
(1)
Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership.
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.
On October 6, 2021 and April 7, 2022, we received notice from the IRS that it intends to audit three direct and indirectly wholly-owned subsidiaries of the
Company (Targa Resources Partners LP, Targa Downstream LLC and Targa Midstream Services LLC) treated as partnerships for federal tax purposes for
the 2019 and 2020 tax years. We are responding to the information requests from the IRS on these audits. The Company is not aware of any potential audit
findings that would give rise to adjustments to taxable income and does not anticipate material changes related to these audits.
All federal statutes of limitations for returns filed in 2019 (for calendar year 2018) have expired. For Texas, the statute of limitations has expired for 2018
returns (for calendar year 2017). Similarly, the statute of limitations expired on substantially all 2018 state income tax returns that were filed prior to
October 15, 2019. However, tax authorities have the ability to review and adjust carryover attributes (e.g., NOLs) generated in a closed tax year if utilized
in an open tax year.
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.
As of December 31, 2022, we have total NOL carryforwards of $6.8 billion, $1.4 billion of which will expire between 2036 and 2037. The remaining $5.4
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. As of December 31, 2022, our tax effected valuation allowance was $36.9 million, a decrease of
$177.5 million from December 31, 2021. Of this valuation allowance, $6.4 million of the valuation allowance is federal, and the remaining $30.5 million is
state.
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 Targa Resources Corp. 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
State tax provision error correction
Return-to-provision
Change in statutory income tax rate
Permanent adjustments
Stock compensation shortfall/(windfall)
Other, net
Income tax provision (benefit)
2022
2021
2020
$
$
$
1,663.2
(335.9 )
1,327.3
21 %
278.7
(177.5 )
33.6
—
—
(0.6 )
(1.7 )
5.6
(6.3 )
—
131.8
$
$
436.9
(350.9 )
86.0
21 %
18.1
(46.2 )
(5.4 )
—
23.3
(1.3 )
21.0
4.1
1.4
(0.2 )
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 )
We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not
anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves
for uncertain income tax positions have been recorded.
On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”) which, among other things, introduced a corporate
alternative minimum tax (the “CAMT”), imposed a 1% excise tax on stock buybacks and tax incentives to promote clean energy. Under the CAMT, a 15%
minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation
in for any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior
to such taxable year exceeds $1 billion.
F-45
On December 27, 2022, the Department of the Treasury and the IRS issued guidance on the application of the CAMT which may be relied upon until final
regulations are released. Based on our interpretation of the IRA, the CAMT and related guidance and a number of operational, economic, accounting and
regulatory assumptions, we do not anticipate qualifying as an “applicable corporation” in the near term, but we are likely to become an applicable
corporation in a subsequent tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax
liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash
available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for a future year. As a result, our
current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA and the CAMT,
we will continue to monitor and evaluate the potential future impact to our financial statements.
Subsequent Events
In January 2023, the IRS notified us that it completed the examination of Targa’s NOL carryback and associated refund previously claimed under the
CARES Act with no exceptions.
Additionally, in January 2023, we received notice from the IRS that it intends to audit an indirectly wholly-owned subsidiary of the Company (Targa
Badlands Holdings LLC) which is treated as a partnership for federal tax purposes for the 2020 tax year.
Note 22 - 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:
Non-cash distributions to noncontrolling interests (2)
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
Lease liabilities arising from recognition of right-of-use assets:
Operating lease
Finance lease (3)
$
$
$
$
2022
Year Ended December 31,
2021
2020
$
$
401.3
1.6
(3.8 )
60.1
—
0.8
64.2
(26.1 )
$
7.1
—
9.7
220.7
$
356.0
1.3
(15.0 )
53.0
2.4
(0.2 )
—
(50.9 )
3.1
—
20.1
24.7
$
$
$
$
374.1
43.7
5.3
(226.9 )
2.1
(1.8 )
—
(5.2 )
5.4
37.6
13.2
6.0
Interest capitalized on major projects was $16.3 million, $4.1 million and $33.0 million for the years ended December 31, 2022, 2021 and 2020.
(1)
(2) Represents the transfer of an undivided interest in certain gas gathering and processing facilities to a joint owner upon Targa's recovery of a specified payout amount for our initial full
funding of the facilities.
(3) The December 31, 2022 balance includes $171.2 million related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.
Note 23 – Compensation Plans
2010 Targa Resources Corp. Stock Incentive Plan
In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan (the “2010 TRGP Plan”) for employees, consultants and non-
employee directors of the Company. In May 2017, the 2010 TRGP Plan was amended and restated. 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 TRGP
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.
F-46
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. The Compensation Committee of the Targa
board of directors (the “Compensation Committee”) awarded our common stock to our outside directors. In 2022, 2021 and 2020, we issued 31,117, 67,591
and 31,621 shares of director grants with weighted average grant-date fair values of $56.32, $30.33 and $39.85, respectively.
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 to six years. In 2022, 2021 and 2020, we issued 943,352, 848,630 and 1,299,592 shares of RSUs
with weighted average grant-date fair values of $63.87, $37.94 and $24.64.
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 certain of our
executives at the weighted average grant-date fair value of $41.39 and $42.83. The 2020 and 2019 grants vested in 2021 and 2022, respectively.
The following table summarizes the restricted stock and RSUs under the 2010 TRGP Plan in shares and in dollars for the year indicated.
Outstanding at December 31, 2021
Granted
Forfeited
Vested
Outstanding at December 31, 2022
Performance Share Units
Number
of shares
Weighted Average
Grant-Date Fair Value
3,690,828
$
974,469
(83,372 )
(1,353,507 )
3,228,418
37.42
63.63
38.80
44.12
42.60
During 2022, 2021 and 2020, we granted 173,011, 319,320 and 291,365 performance share units (“PSUs”) to executive management for the 2022, 2021
and 2020 compensation cycle that will vest/have vested in January 2025, January 2024 and January 2023. The PSUs granted under the 2010 TRGP 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 2020, 2021 and 2022, the TSR performance factor is determined by the Compensation Committee based
on relative TSR over a cumulative three-year performance period. 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 80%, 80%
and 32% for PSUs granted in 2022, 2021 and 2020.
F-47
The following table summarizes the PSUs under the 2010 TRGP Plan in shares and in dollars for the years indicated.
Outstanding at December 31, 2021
Granted
Forfeited
Vested
Outstanding at December 31, 2022
Stock Compensation Expenses
Number
of shares
Weighted Average
Grant-Date Fair Value
867,209
$
173,011
(13,779 )
(256,524 )
769,917
63.24
108.55
74.75
64.46
72.81
Stock compensation expense under our plans totaled $57.5 million, $59.2 million, and $66.3 million for the years ended December 31, 2022, 2021 and
2020. As of December 31, 2022, we have $88.8 million of unrecognized compensation expense associated with share-based awards and an approximate
remaining weighted average vesting periods of 2.3 years related to our various compensation plans.
The fair values of share-based awards vested in 2022, 2021 and 2020 were $93.0 million, $73.8 million and $62.7 million. Cash dividends paid for the
vested awards were $9.6 million, $8.7 million and $9.4 million for 2022, 2021 and 2020.
In relation to our equity compensation plans, we recognized $6.7 million in windfall tax benefits for the year ended December 31, 2022, $1.6 million and
$2.0 million of tax deficiencies for the years ended December 31, 2021 and 2020, respectively.
Subsequent Events
In January 2023, the Compensation Committee made the following awards under the 2010 TRGP Plan.
•
•
•
23,518 shares of restricted stock to our outside directors that will vest in January 2024.
140,020 shares of RSUs to executive management for the 2023 compensation cycle that will vest in January 2026.
140,020 shares of PSUs to executive management for the 2023 compensation cycle that will vest in January 2026.
In January 2023, 31,117 shares of director grants vested with no shares withheld to satisfy tax withholding obligations.
In January 2023, 472,265 shares of RSUs vested with 165,203 shares withheld to satisfy tax withholding obligations.
In January 2023, 728,417 shares of 2021 PSUs vested with 272,681 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 $26.6 million, $21.8 million and $16.2 million during 2022, 2021 and 2020.
Note 24 — 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.
F-48
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 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
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
Gathering and
Processing
Logistics and
Transportation
Other
Corporate
and
Eliminations
Total
Year Ended December 31, 2022
$
919.7
1,157.3
2,077.0
9,169.4
0.6
9,170.0
11,247.0
1,981.0
12,133.6
45.2
918.1
$
$
$
$
$
$
18,448.7
706.5
19,155.2
541.7
45.2
586.9
19,742.1
1,456.3
7,175.7
—
453.0
$
$
$
$
$
(302.4 ) $
—
(302.4 )
—
—
—
(302.4 ) $
(302.4 )
—
—
—
$
$
$
$
—
—
—
(9,711.1 )
(45.8 )
(9,756.9 )
(9,756.9 ) $
250.7
—
23.3
$
$
$
Gathering and
Processing
Logistics and
Transportation
Other
Corporate
and
Eliminations
Total
Year Ended December 31, 2021
$
15,111.6
600.0
15,711.6
409.5
38.6
448.1
16,159.7
1,264.3
7,041.9
—
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
$
$
$
$
606.8
747.3
1,354.1
6,067.9
3.5
6,071.4
7,425.5
1,325.3
7,998.1
45.2
471.7
$
$
$
$
$
F-49
$
$
$
$
$
$
$
$
$
$
$
$
19,066.0
1,863.8
20,929.8
—
—
—
20,929.8
19,560.0
45.2
1,394.4
15,602.5
1,347.3
16,949.8
—
—
—
16,949.8
15,208.2
45.2
560.5
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
Gathering and
Processing
Logistics and
Transportation
Other
Corporate
and
Eliminations
Total
Year Ended December 31, 2020
$
$
$
$
$
$
$
659.9
487.2
1,147.1
2,173.2
6.5
2,179.7
3,326.8
1,017.7
8,743.5
45.2
293.9
$
$
$
$
$
$
6,281.4
602.1
6,883.5
205.9
31.5
237.4
7,120.9
1,128.0
6,860.0
—
414.0
$
$
$
$
$
229.7
—
229.7
—
—
—
229.7
229.7
86.3
—
—
$
$
$
$
$
$
—
—
—
(2,379.1 )
(38.0 )
(2,417.1 )
(2,417.1 ) $
185.9
—
18.9
$
$
$
(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.
The following table shows our consolidated revenues disaggregated by product and service for the periods presented:
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
2022
Year Ended December 31,
2021
2020
$
$
5,470.2
13,785.2
565.3
—
19,820.7
(373.0 )
(381.7 )
(754.7 )
19,066.0
1,137.2
285.1
372.2
69.3
1,863.8
$
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
Total revenues
$
20,929.8
$
16,949.8
$
(1)
Represents derivative activities that are not designated as hedging instruments under ASC 815.
F-50
7,171.0
1,089.3
8,260.3
—
—
—
8,260.3
15,875.7
45.2
726.8
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
8,260.3
The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the periods presented:
2022
Year Ended December 31,
2021
2020
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 assets
Write-down of assets
Gain (loss) from financing activities
Gain (loss) from sale of equity method investment
Other, net
Income (loss) before income taxes
$
$
1,981.0
1,456.3
(302.4 )
(1,096.0 )
(309.7 )
—
(446.1 )
9.1
9.6
(9.8 )
(49.6 )
435.9
(15.1 )
$
1,663.2
$
F-51
$
1,325.3
1,264.3
(115.9 )
(870.6 )
(273.2 )
(452.3 )
(387.9 )
(23.9 )
(2.0 )
(10.3 )
(16.6 )
—
—
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
—
1.1
(1,573.1 )
TARGA RESOURCES CORP.
LIST OF SIGNIFICANT SUBSIDIARIES
Exhibit 21.1
Legal Name
Cedar Bayou Frac onators, L.P.
Centrahoma Processing LLC
Grand Prix Pipeline LLC
Targa Badlands LLC
Targa Delaware LLC
Targa Downstream LLC
Targa Gas Marke ng LLC
Targa GP Inc.
Targa Liquids Marke ng and Trade LLC
Targa LP Inc.
Targa Midland LLC
Targa Midkiff LLC
Targa Midstream Services LLC
Targa NGL Pipeline Company LLC
Targa Northern Delaware LLC
Targa Pipeline Mid-Con nent Holdings LLC
Targa Pipeline Mid-Con nent LLC
Targa Pipeline Mid-Con nent WestOk LLC
Targa Pipeline Mid-Con nent WestTex LLC
Targa Receivables LLC
Targa Resources GP LLC
Targa Resources LLC
Targa Resources Opera ng LLC
Targa Resources Partners LP
Targa Train 6 LLC
Targa Train 7 LLC
Targa Train 8 LLC
Targa Train 9 LLC
TPL SouthTex Processing Company LP
Versado Gas Processors, L.L.C.
WestTex Processing Company LLC
Jurisdic on
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Delaware
Delaware
List of Subsidiary Guarantors
Exhibit 22.1
Name
FCPP Pipeline, LLC
Flag City Processing Partners, LLC
Grand Prix Development LLC
Midland-Permian Pipeline LLC
Slider WestOk Gathering, LLC
Targa Capital LLC
Targa Cayenne LLC
Targa Chaney Dell LLC
Targa Cogen LLC
Targa Delaware LLC
Targa Downstream LLC
Targa Energy GP LLC
Targa Energy LP
Targa Frio LaSalle GP LLC
Targa Frio LaSalle Pipeline LP
Targa Gas Marketing LLC
Targa Gas Pipeline LLC
Targa Gas Processing LLC
Targa GP Inc.
Targa Gulf Coast NGL Pipeline LLC
Targa Intrastate Pipeline LLC
Targa LA Holdings LLC
Targa LA Operating LLC
Targa Liquids Marketing and Trade LLC
Targa Louisiana Intrastate LLC
Targa LP Inc.
Targa Midkiff LLC
Targa Midland Crude LLC
Targa Midland LLC
Targa Midstream Services LLC
Targa MLP Capital LLC
Targa NGL Pipeline Company LLC
Targa Permian Condensate Pipeline LLC
Targa Pipeline Mid-Continent Holdings LLC
Targa Pipeline Mid-Continent LLC
Targa Pipeline Operating Partnership LP
Targa Pipeline Partners GP LLC
Targa Pipeline Partners LP
Targa Resources Finance Corporation
Targa Resources GP LLC
Targa Resources LLC
Targa Resources Operating GP LLC
Targa Resources Operating LLC
Targa Resources Partners LP
Targa Rich Gas Services GP LLC
Targa Rich Gas Services LP
Targa Rich Gas Utility GP LLC
Targa Rich Gas Utility LP
Targa Southern Delaware LLC
Targa SouthOk NGL Pipeline LLC
Targa SouthTex Energy GP LLC
Targa SouthTex CCNG Gathering Ltd.
Targa SouthTex Energy LP LLC
Targa SouthTex Energy Operating LLC
State of Incorporation
or Organization
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Texas
Texas
Delaware
Oklahoma
Delaware
Texas
Delaware
Delaware
Targa SouthTex Gathering Ltd.
Targa SouthTex Midstream Company LP
Targa SouthTex Midstream Marketing Company Ltd.
Targa SouthTex Midstream T/U GP LLC
Targa SouthTex Midstream Utility LP
Targa SouthTex Mustang Transmission Ltd.
Targa SouthTex NGL Pipeline Ltd.
Targa SouthTex Processing LLC
Targa SouthTex Transmission LP
Targa Train 6 LLC
Targa Train 8 LLC
Targa Transport LLC
TPL Arkoma Holdings LLC
TPL Arkoma LLC
TPL Arkoma Midstream LLC
TPL Gas Treating LLC
TPL SouthTex Gas Utility Company LP
TPL SouthTex Midstream Holding Company LP
TPL SouthTex Midstream LLC
TPL SouthTex Pipeline Company LLC
TPL SouthTex Processing Company LP
TPL SouthTex Transmission Company LP
T2 Eagle Ford Gathering Company LLC
T2 Gas Utility LLC
T2 LaSalle Gas Utility LLC
T2 LaSalle Gathering Company LLC
Velma Gas Processing Company, LLC
Velma Intrastate Gas Transmission Company, LLC
Versado Gas Processors, L.L.C.
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Delaware
Texas
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Delaware
Texas
Texas
Texas
Delaware
Texas
Texas
Delaware
Delaware
Delaware
Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Exhibit 23.1
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-218212, No. 333-211655, No. 333-
209873, No. 333-202503 and No. 333-171082) and Form S-3 (No. 333-263730) of Targa Resources Corp. of our report dated February 22,
2023 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 22, 2023
Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Matthew J. Meloy, certify that:
1. I have reviewed this Annual Report on Form 10-K of Targa Resources Corp. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to
adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 22, 2023
By: /s/ Matthew J. Meloy
Name: Matthew J. Meloy
Title: Chief Executive Officer of Targa Resources Corp.
(Principal Executive Officer)
Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Jennifer R. Kneale, certify that:
1. I have reviewed this Annual Report on Form 10-K of Targa Resources Corp. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to
adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 22, 2023
By: /s/ Jennifer R. Kneale
Name: Jennifer R. Kneale
Title: Chief Financial Officer of Targa Resources Corp.
(Principal Financial Officer)
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
Exhibit 32.1
In connection with the Annual Report on Form 10-K of Targa Resources Corp., for the year ended December 31, 2022 as filed with the Securities and
Exchange Commission on the date hereof (the “Report”), Matthew J. Meloy, as Chief Executive Officer of Targa Resources Corp., hereby certifies,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Targa Resources
Corp.
By: /s/ Matthew J. Meloy
Name: Matthew J. Meloy
Title: Chief Executive Officer of Targa Resources Corp.
Date: February 22, 2023
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature
that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Targa and will be retained
by Targa and furnished to the Securities and Exchange Commission or its staff upon request.
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
Exhibit 32.2
In connection with the Annual Report on Form 10-K of Targa Resources Corp. for the year ended December 31, 2022 as filed with the Securities and
Exchange Commission on the date hereof (the “Report”), Jennifer R. Kneale, as Chief Financial Officer of Targa Resources Corp., hereby certifies,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to her knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Targa Resources
Corp.
By: /s/ Jennifer R. Kneale
Name: Jennifer R. Kneale
Title: Chief Financial Officer of Targa Resources Corp.
Date: February 22, 2023
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature
that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Targa and will be retained
by Targa and furnished to the Securities and Exchange Commission or its staff upon request.