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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2019~~2020


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File Number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware		65-1295427
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

811 Louisiana Street, Suite 2100, Houston, Texas		77002
(Address of principal executive offices)		(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		Trading Symbol(s)		Name of each exchange on which registered
9.0% Series A Fixed-to-Floating Rate Cumulative RedeemablePerpetual Preferred Units		NGLS/PA		New York Stock Exchange

Title of each class		Trading Symbol(s)		Name of each exchange on which registered
None		None		None

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	☐	Accelerated filer	☐
Non-accelerated filer	☑	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of February 1712, ~~2020~~2021, there were ~~5,000,000~~no 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

PART I
Item 1. Business.		4
Item 1A. Risk Factors		2829
Item 1B. Unresolved Staff Comments.		5051
Item 2. Properties.		5051
Item 3. Legal Proceedings.		5051
Item 4. Mine Safety Disclosures.		5052
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.		5153
Item 6. Selected Financial Data.		5254
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		5355
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.		7172
Item 8. Financial Statements and Supplementary Data.		7475
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.		7475
Item 9A. Controls and Procedures.		7475
Item 9B. Other Information.		7475
PART III
Item 10. Directors, Executive Officers and Corporate Governance.		7576
Item 11. Executive Compensation.		8182
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.		~~109~~82
Item 13. Certain Relationships and Related Transactions, and Director Independence.		~~111~~84
Item 14. Principal Accounting Fees and Services.		~~115~~88
PART IV
Item 15. Exhibits, Financial Statement Schedules		~~116~~89
Item 16. Form 10-K Summary		~~124~~97
SIGNATURES
Signatures		~~125~~98

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or the “Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:

•

the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and transportation facilities and our success in connecting our facilities to transportation services and markets;

•

the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for our services;

•

our ability to access the capital markets, which will depend on general market conditions and the credit ratings for our debt obligations and demand for our senior notes;

•

the impact of outbreaks of illnesses, pandemics (like COVID-19) or any other public health crises;

•

the amount of collateral required to be posted from time to time in our transactions;

•

our success in risk management activities, including the use of derivative instruments to hedge commodity price risks;

•

the level of creditworthiness of counterparties to various transactions with us;

•

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

•

weather and other natural phenomena;

•

industry changes, including the impact of consolidations and changes in competition;

•

our ability to timely obtain and maintain necessary licenses, permits and other approvals;

• our ability to grow through internal growth capital projects or acquisitions and the successful integration and future performance of such assets;

•

general economic, market and business conditions; and

•

the risks described elsewhere in “Item 1A. Risk Factors” in this Annual Report and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

~~Although~~Additionally, while we ~~believe~~have ~~that~~not ~~the~~been ~~assumptions~~previously ~~underlying~~materially ~~our~~impacted ~~forward-looking~~by ~~statements~~prior ~~are~~outbreaks ~~reasonable~~of illnesses, ~~any~~pandemics ofor ~~the~~other ~~assumptions~~public ~~could~~health ~~be inaccurate~~crises, ~~and,~~there ~~therefore,~~are wepotential ~~cannot~~risks ~~assure~~to ~~you~~us ~~that~~from the ~~forward-looking~~continued ~~statements~~impact ~~included~~on inglobal ~~this~~demand ~~Annual~~for ~~Report~~energy ~~will~~commodities ~~prove~~related to bethe ~~accurate~~COVID-19 pandemic. ~~Some~~The ofCOVID-19 ~~these~~pandemic ~~and~~reduced ~~other~~economic ~~risks~~activity and ~~uncertainties~~the ~~that~~related ~~could~~demand ~~cause~~for ~~actual~~energy ~~results~~commodities, towhich ~~differ~~contributed ~~materially~~to ~~from~~weakened ~~such~~commodity ~~forward-looking~~prices ~~statements~~compared ~~are~~to ~~more~~historical ~~fully~~levels ~~described~~and inprice ~~“Item~~volatility ~~1A.~~during ~~Risk~~the ~~Factors”~~year inended ~~this~~December ~~Annual Report. Except as may be required by applicable law~~31, we2020 ~~undertake~~and nois ~~obligation~~expected to ~~publicly~~continue ~~update~~to orimpact ~~advise~~demand ofover ~~any~~the ~~change in any forward~~short-~~looking~~to-medium ~~statement, whether as a result of new information, future events or otherwise~~term.

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.

As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:


Bbl	Barrels (equal to 42 U.S. gallons)
BBtu	Billion British thermal units
Bcf	Billion cubic feet
Btu	British thermal units, a measure of heating value
/d	Per day
GAAP	Accounting principles generally accepted in the United States of America
gal	U.S. gallons
LIBOR	London Interbank Offered Rate
LPG	Liquefied petroleum gas
MBbl	Thousand barrels
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
MMgal	Million U.S. gallons
NGL(s)	Natural gas liquid(s)
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
SCOOP	South Central Oklahoma Oil Province
STACK	Sooner Trend, Anadarko, Canadian and Kingfisher
VLGC	Very large gas carrier

PART I

Item 1. Business.

The following section of this Form 10-K generally refers to business developments during the year ended December 31, 2020. 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, 2019.

Overview

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”), to own, operate, acquire and develop a diversified portfolio of complementary domestic midstream ~~energy~~infrastructure assets. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 were redeemed in December 2020 and are no longer outstanding as of the end of the year. Prior to the redemption, the Preferred Units were limited partner interests in us and were traded on the NYSE under the symbol “NGLS/PA.”

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”), by and among us, Targa Resources GP LLC (our “general partner”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”) pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

As used herein, "units" refers to our units representing limited partner interests in the Partnership and not to the Preferred Units (as defined herein) and "unitholders" refers to the holders of units. Unless the context requires otherwise, the term "limited partner interests" refers to the units and the Preferred Units, collectively, and “limited partners” refers to the holders of limited partner interests.

The following should be read in conjunction with our audited consolidated financial statements and the notes thereto. We have prepared our accompanying consolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars and all references to dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive offices is 811 Louisiana Street, Suite 2100, Houston, Texas 77002, and our telephone number at this address is (713) 584-1000.

Our Operations

We are engaged primarily in the business of:

• gathering, compressing, treating, processing, transporting and purchasing and selling natural gas;

• transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and

• gathering, storing, terminaling and purchasing and selling crude oil.

To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business).

InOur Gathering and Processing segment includes assets used in the ~~fourth~~gathering ~~quarter~~and/or purchase and sale of ~~2019~~natural gas produced from oil and gas wells, weremoving ~~made~~impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the ~~following~~gathering ~~changes~~and toterminaling and/or purchase and sale of crude oil. The Gathering and Processing segment's assets are located in the ~~presentation~~Permian Basin of ~~our~~West ~~reportable~~Texas ~~segments:~~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 ~~Renamed~~Logistics and Transportation segment includes the ~~Logistics~~activities and ~~Marketing~~assets ~~segment~~necessary asto ~~“Logistics~~convert mixed NGLs into NGL products and ~~Transportation.”~~also ~~The~~includes ~~updated~~other ~~name~~assets ~~better~~and ~~describes~~value-added ~~the~~services ~~business~~such ~~composition~~as transporting, storing, fractionating, terminaling, and ~~activity~~marketing of ~~the~~NGLs ~~segment~~and ~~given~~NGL ~~the~~products, ~~recent~~including ~~completion~~services to LPG exporters and certain natural gas supply and marketing activities in support of our ~~common~~other ~~carrier~~businesses. The Logistics and Transportation segment also includes the Grand Prix NGL Pipeline (“Grand Prix”), ~~that~~which ~~transports~~connects ~~NGLs~~our togathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our ~~fractionation~~downstream ~~assets~~facilities in Mont Belvieu., ~~The~~Texas, ~~change~~as well as our equity interest in ~~naming~~Gulf ~~convention~~Coast ~~did~~Express ~~not~~Pipeline ~~impact~~LLC ~~previously~~(“GCX”), ~~reported~~a ~~results~~natural ~~for~~gas pipeline connecting the ~~segment~~Waha hub in West Texas and other receipt points, including many of our Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points. ~~This~~The ~~segment~~associated isassets, ~~also~~including ~~referred~~these pipelines, are generally connected to asand supplied in part by our Gathering and Processing segment and, except for the ~~Downstream~~pipelines ~~Business~~and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

• Due to changes in how our executive team evaluates segment performance, results of commodity derivative activities related to our equity volume hedges that are designated as accounting hedges are now reported in the Gathering and Processing segment. These hedge activities were previously reported in Other. Our prior period segment information has been updated to reflect the change. There was no impact to our Consolidated Statements of Operations.

~~Our~~Other ~~Gathering~~contains ~~and Processing segment includes assets used in~~ the ~~gathering~~unrealized ofmark-to-market ~~natural~~gains/losses ~~gas~~related ~~produced~~to ~~from~~derivative ~~oil~~contracts ~~and~~that ~~gas~~were ~~wells~~not ~~and~~designated ~~processing~~as ~~this~~cash ~~raw~~flow ~~natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling~~hedges. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes Grand Prix, as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix integrates 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, including these pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Acquisitions and Organic Growth Projects

Our midstream natural gas and NGL services footprint was initially established through several acquisitions from Targa, totaling $3.1 billion, that occurred from 2007 through 2010. Since the completion of the final acquisitions from Targa in 2010, we have expanded our midstream services footprint substantially. The expansion of our business has been fueled by a combination of third-party acquisitions and major organic growth investments in our businesses. Third-party acquisitions included our 2012 acquisition of Saddle Butte Pipeline LLC’s crude oil pipeline and terminal system and natural gas gathering and processing operations in North Dakota (referred to by us as “Badlands”), our 2015 acquisition of Atlas Pipeline Partners L.P. (“APL,” renamed by us as Targa Pipeline Partners LP or “TPL”), and our 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin (referred to by us as the “Permian Acquisition”). As a result of these transactions, we acquired natural gas gathering, processing and treating assets in West Texas, South Texas, North Texas, Oklahoma, North Dakota, New Mexico and the Louisiana Gulf Coast, crude oil gathering and terminal assets in North Dakota and West Texas, and NGL assets consisting of fractionation, transport, storage and terminaling facilities, low sulfur natural gas treating facilities (“LSNG”), pipeline transportation and distribution assets, propane storage and truck terminals primarily located near Houston, Texas and in Lake Charles, Louisiana.

We also continue to invest capital in our businesses to enhance our competitive advantage as an integrated midstream services provider. We have invested approximately $8.4 billion in growth capital expenditures since 2015, including approximately $2.6 billion in 2019 (approximately $2.3 billion of net growth capital). These expansion investments are distributed across our businesses, with 52% to Gathering and Processing and 48% related to Logistics and Transportation. We expect to continue to invest in both large and small organic growth projects in 2020 and currently estimate that we will invest approximately $1.2 to $1.3 billion in net organic growth capital expenditures in 2020.

The map below highlights our more significant assets:

Recent Developments

~~Gathering~~Response ~~and~~to ~~Processing~~Current ~~Segment~~Market ~~Expansion~~Conditions

~~Permian~~During ~~Midland~~2020, ~~Processing~~global ~~Expansions~~commodity prices declined due to factors that significantly impacted both supply and demand. As the COVID-19 pandemic spread and travel and other restrictions were implemented globally, the demand for commodities declined substantially. Additionally, certain major oil producing nations significantly increased their oil and gas production late in the first quarter which further contributed to the surplus production of commodities. Despite these nations subsequently agreeing to reduce global commodity supplies and global economies beginning to re-open, commodity prices remained weak relative to historical levels and continued to be volatile. Reduced economic activity due to the COVID-19 pandemic, combined with uncertainty around global commodity supply and demand, contributed to lower commodity prices.

InFurthermore, ~~response~~the decline in commodity prices led many exploration and production companies to ~~increasing~~reduce planned capital expenditures for drilling and production activities and toalso ~~meet~~led ~~the~~to ~~infrastructure~~some ~~needs~~companies ofshutting ~~producers,~~in wewells ~~have~~primarily ~~recently~~in ~~completed~~the ~~construction~~first half of or2020. ~~are~~Such ~~constructing~~price ~~three~~and ~~new~~activity ~~250~~declines ~~MMcf/d~~negatively ~~cryogenic~~impacted ~~natural~~our ~~gas~~operations ~~processing~~by ~~plants~~(i) reducing investments by third parties in the ~~Midland~~development ~~Basin.~~of ~~The~~new ~~first~~oil ~~plant~~and gas reserves, ~~the~~therefore ~~Hopson~~reducing ~~Plant~~volumes coming onto our systems in the future, ~~began~~(ii) ~~operations~~decreasing volumes processed in our facilities and transported on our pipelines and (iii) reducing the ~~second~~prices ~~quarter~~we receive from the sale of ~~2019~~commodities. ~~The~~While ~~second~~commodity ~~plant,~~prices remain low relative to historical levels and uncertainties associated with the ~~Pembrook~~impacts ~~Plant~~of COVID-19 continue, ~~began~~production ~~operations~~from wells that were previously shut-in during the ~~third~~first ~~quarter~~half of ~~2019.~~2020 Inacross ~~August~~our ~~2019,~~operating weareas ~~announced~~has ~~the~~largely ~~Gateway~~resumed ~~Plant,~~and ~~which~~energy isdemand ~~expected~~and commodity prices continued to ~~begin~~recover ~~operations~~compared into the ~~fourth~~first ~~quarter~~half of 2020.

There has been, and likely will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. We are uncertain of what pricing and market demand, and the associated impact to demand for our services, will be throughout 2021. Across our operations, particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services. 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. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

In response to market conditions, we continue to work through numerous internal initiatives to respond to current market conditions, including identifying and implementing cost reduction measures such as reducing or deferring non-essential operating and general and administrative expenses.

We believe that our long-term strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows across commodity price environments. Geographic, business and customer diversity enhances our ability to generate sufficient cash flows to fund our requirements. Our assets are positioned in strategic oil and gas producing areas across multiple basins and provide services under attractive contract terms to a diverse mix of customers across our operational areas. Our contract portfolio has attractive rates and term characteristics, including a significant fee-based component, especially in our Downstream Business. 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.

We are currently experiencing no material issues with potential workforce disruptions, and we remain focused on safeguarding employee health and safety and ensuring safe and reliable operations in response to COVID-19. Additionally, we are currently experiencing no material supply chain disruptions as a result of the COVID-19 pandemic, and our relationships with our major customers continue to be strong. However, if any of these circumstances change, our business could be adversely affected. Additionally, although significant progress has been made towards the development, distribution and administration of various COVID-19 vaccines, their potential safety and efficacy and timing around when they will become widely available is uncertain at this point. Further, as there is significant uncertainty around the breadth and duration of the disruptions to global energy markets related to the aforementioned current events, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.

Gathering and Processing Segment Expansions

Permian Midland Processing Expansion

In November 2020, we announced the transfer of an existing cryogenic natural gas processing plant from our North Texas system (the “Longhorn Plant”), to our Permian Midland system. The plant will be relocated to, and installed in Reagan County, Texas, in 2021 as a new 200 MMcf/d cryogenic natural gas processing plant (the “Heim Plant”). The Heim Plant will process natural gas production from the Permian Basin and is expected to begin operations in the fourth quarter of 2021.

In August 2019, we announced that we began construction of a new 250 MMcf/d cryogenic natural gas processing plant in the Midland Basin (the “Gateway Plant”), which commenced operations in the third quarter of 2020.

Permian Delaware Processing Expansions

In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements are underpinned by the customer'’s dedication of significant acreage within a large, well-defined area in the Delaware Basin. WeIn ~~constructed~~addition ~~approximately 220 miles of 12-~~ to ~~24-inch~~ high-pressure rich gas gathering pipelines ~~across~~and ~~the~~a ~~Delaware~~natural ~~Basin~~gas ~~that~~processing ~~are~~plant ~~operational.~~(the We“Falcon ~~have~~Plant”), ~~recently~~which ~~completed~~were ~~construction~~placed ofinto orservice ~~are~~in ~~currently~~2019, ~~constructing~~we ~~two~~commenced ~~new~~operations of a second 250 MMcf/d cryogenic natural gas processing ~~plants in the Delaware Basin. The first~~ plant, (the ~~Falcon~~“Peregrine Plant”), ~~began operations late~~ in the ~~third~~second quarter of ~~2019~~2020. ~~The second plant, the Peregrine~~

We provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLs from the Falcon and Peregrine plants.

Plant, is expected to begin operations in the second quarter of 2020. We will provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLs from the Falcon and Peregrine Plants.

Badlands

In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP under which Targa would construct and operate a new 200 MMcf/d natural gas processing plant (“LM4 Plant”) at Targa’s existing Little Missouri facility. The LM4 Plant began operations in the third quarter of 2019.

Logistics and Transportation Segment Expansion

Grand Prix NGL Pipeline Extension

In February 2019, we announced an extension of Grand Prix (the ~~third~~“Central ~~quarter~~Oklahoma Extension”), extending from Southern Oklahoma to the STACK region of ~~2019~~Central Oklahoma where it connects with The Williams Companies, weInc. ~~began~~(“Williams”) ~~full~~Bluestem ~~service~~Pipeline, ~~into~~linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix, and fractionate at our ~~new~~Mont ~~common~~Belvieu ~~carrier~~facilities. ~~NGL~~The ~~pipeline~~Central ~~that~~Oklahoma ~~transports~~Extension ~~NGLs~~began ~~from~~operations late in the ~~Permian~~fourth ~~Basin,~~quarter ~~North~~of ~~Texas,~~2020. ~~and~~Transportation ~~Southern~~volumes on the Central Oklahoma Extension accrue solely to ~~our~~Targa’s ~~fractionation~~benefit and ~~storage~~are ~~complex~~not included in ~~the~~Grand ~~NGL~~Prix ~~market~~Pipeline ~~hub~~LLC at(“Grand ~~Mont~~Prix ~~Belvieu~~Joint Venture”), ~~Texas.~~a ~~The~~consolidated ~~pipeline~~subsidiary isof ~~comprised~~which ofTarga ~~three~~owns ~~primary~~a ~~segments:~~56% interest.

•Fractionation Permian Basin Segment – Connects our Gathering and Processing positions (as well as third-party positions) throughout the Delaware and Midland Basins to North Texas. The capacity of the 24-inch diameter pipeline segment from the Permian Basin is approximately 300 MBbl/d, expandable to 550 MBbl/d.Expansions

•In ~~Southern~~November ~~Oklahoma~~2018, ~~Extension~~we –announced ~~Connects~~plans ~~our~~to ~~SouthOK~~construct ~~and~~two ~~North~~new 110 MBbl/d fractionation trains in Mont Belvieu, Texas ~~Gathering~~(“Train 7” and ~~Processing~~“Train ~~positions~~8”). ~~(as~~Train ~~well~~7 ascommenced operations in the first quarter of 2020 and Train 8 commenced operations in the third~~-party~~ ~~positions)~~quarter toof ~~our~~2020. ~~North~~In ~~Texas~~January to2019, Williams committed significant volumes which Targa will transport on Grand Prix and fractionate at Targa’s Mont Belvieu ~~Segment~~facilities (including Train 7). ~~The~~Williams ~~extension~~was ~~varies~~also granted an option to purchase a 20% equity interest in ~~capacity~~the ~~based~~fractionation ontrain, ~~telescoping~~which ~~pipe~~was ~~size~~originally wholly owned by Targa. Williams exercised its initial option and executed a joint venture agreement with us with respect to Train 7 in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, such as storage caverns and brine handling, was funded and is owned 100% by Targa. Train 8 is owned 100% by Targa.

• North Texas to Mont Belvieu Segment – The Permian Basin Segment and Southern Oklahoma Extension connect to a 30-inch diameter pipeline segment in North Texas, which connects Permian, North Texas and Oklahoma volumes to Mont Belvieu. The North Texas to Mont Belvieu Segment has a capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d.

In February 2019, we announced an additional extension:

• Central Oklahoma Extension – Extends from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with The Williams Companies, Inc. (“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. The Central Oklahoma Extension is expected to be completed in the first quarter of 2021.

Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest, owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas. Volumes flowing on the pipeline from the Permian Basin to Mont Belvieu, Texas, accrue to the Grand Prix Joint Venture, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targa’s benefit.

Fractionation Expansion

In February 2018, we announced plans to construct a new 100 MBbl/d fractionation train (“Train 6”) in Mont Belvieu, Texas, which began operations in the second quarter of 2019. Targa Train 6 LLC (“Train 6 JV”), a joint venture between Targa and Stonepeak Infrastructure Partners (“Stonepeak”), owns a 100% interest in the fractionation train. Certain fractionation-related infrastructure for Train 6, such as storage caverns and brine handling, were funded and are owned 100% by Targa.

In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7 and Train 8”), which are expected to begin operations by the end of the first quarter of 2020 and the end of the third quarter of 2020, respectively. In January 2019, Williams committed to Targa significant volumes which Targa will transport on Grand Prix and fractionate at Targa’s Mont Belvieu facilities (including Train 7). Williams was also granted an option to purchase a 20% equity interest in the fractionation train, which was originally wholly owned by Targa. Williams exercised its initial option and executed a joint venture agreement with us in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, such as storage caverns and brine handling, will be funded and owned 100% by Targa.

LPG Export Expansion

In February 2019, we announced plans to further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by increasing refrigeration capacity and associated load rates. The expansion was complete and began operation in the third quarter of 2020. With the additional infrastructure, we increased our effective export capacity up to 15 MMBbl per month in the third quarter of 2020, 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.

effective export capacity will increase to up to 15 MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. The expansion is expected to be fully completed in the third quarter of 2020.

Gulf Coast Express Pipeline

In December 2017, we entered into definitive joint venture agreements to form GCX with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) for the purpose of developing the Gulf Coast Express Pipeline (“GCX Pipeline”), a natural gas pipeline from the Waha hub, including direct connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South Texas. The pipeline provides an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Targa GCX Pipeline LLC (“GCX DevCo JV”), a joint venture between us and Stonepeak, and DCP each own a 25% interest, KMTP owns a 34% interest, and Altus Midstream Company owns the remaining 16% interest in GCX. KMTP serves as the operator of GCX Pipeline. We have committed significant volumes to GCX Pipeline. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin assets, also committed volumes to GCX Pipeline. GCX Pipeline is designed to transport up to 1.98 Bcf/d of natural gas and commenced operations late in the third quarter of 2019.

Badlands Interest Sale

In April 2019, we closed on the sale of a 45% interest in Targa Badlands LLC (“Targa Badlands”), the entity that holds substantially all of the assets previously wholly owned by Targa in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “Blackstone”) for $1.6 billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital program. We continue to be the operator of Targa Badlands and hold majority governance rights. Future growth capital of Targa Badlands is expected to be funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would 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.

Asset Sales

WeIn ~~continue~~the tofourth ~~evaluate~~quarter ~~and~~of ~~execute asset sales to reduce leverage and focus on our core operations. During 2019~~2020, we closed on the sale of anassets ~~equity-method~~in ~~investment for $73.8 million. In November 2019~~Channelview, weTexas ~~executed agreements to sell our crude gathering and storage business in the Permian Delaware~~ for approximately $~~134~~58 million. ~~The sale closed early in the first quarter of 2020.~~

WeIn ~~have also engaged Jefferies LLC to evaluate~~ the ~~potential~~first ~~divestiture~~quarter of ~~our~~2020, ~~crude~~we ~~gathering~~closed ~~business~~on in the ~~Permian~~sale ~~Midland,~~of ~~which~~the ~~includes~~Delaware crude ~~gathering~~system, ~~and~~which ~~storage~~was ~~assets.~~effective ~~The~~December ~~sale~~1, ~~process is ongoing~~2019, ~~and the potential divestiture is predicated on third party valuations adequately capturing our forward growth expectations~~ for ~~the~~approximately ~~assets.~~$134 ~~No assurance can be made that a sale will be consummated~~million.

Financing Activities

In ~~January~~February ~~2019~~2021, we issued $~~750~~1.0 ~~million~~billion of 6½4% Senior Notes due ~~July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029~~2032, resulting in ~~total~~ net proceeds of approximately $~~1,486.6~~992 million. ~~The~~A portion of the net proceeds from the issuance were used to ~~redeem~~fund inthe ~~full~~concurrent ~~our~~cash ~~4⅛%~~tender ~~Senior~~offer ~~Notes~~and ~~due~~subsequent ~~2019,~~redemption atpayment ~~par~~for ~~value~~our ~~plus~~5⅛% ~~accrued~~Senior ~~interest~~Notes ~~through~~due 2025 (the ~~redemption~~“5⅛% ~~date~~Notes”), with the remainder used for ~~general partnership purposes, which included~~ repayment of borrowings under our senior secured revolving credit ~~facilities~~facility (the “TRP Revolver”) and Targa’s senior secured revolving credit facility (the “TRC Revolver”).

InAdditionally, ~~November~~Targa ~~2019,~~Pipeline wePartners LP (“TPL”) issued ~~$1.0~~notices ~~billion~~of ~~aggregate~~redemption ~~principal~~for ~~amount~~all of 5½the outstanding TPL 4¾% Senior Notes due ~~March~~2021 ~~2030,~~and ~~resulting~~TPL in5⅞% ~~net~~Senior ~~proceeds~~Notes ofdue ~~$990~~2023.8 ~~million.~~These ~~The~~notes ~~net~~will ~~proceeds~~be ~~from~~redeemed ~~the~~on ~~issuance~~February ~~were~~22, ~~used~~2021 towith ~~repay~~available ~~borrowings~~liquidity under ~~our~~the ~~credit~~TRP ~~facilities and for general partnership purposes~~Revolver.

OnIn December 62020, ~~2019,~~ we ~~amended~~redeemed all of our ~~accounts~~5,000,000 ~~receivable~~issued ~~securitization~~and ~~facility~~outstanding (Preferred Units at a redemption price of $25.00 per unit, plus an amount equal to all unpaid distributions up to the ~~“Securitization~~date ~~Facility”~~of redemption. The difference between the consideration paid (including unpaid distributions of $0.5 million) and the net carrying value of the units redeemed was $4.9 million, which was recorded as an increase to ~~extend~~net income attributable to the ~~facility~~preferred ~~through~~limited apartners ~~termination~~for ~~date~~the ofyear ended December 431, 2020. The redemption of the Preferred Units is consistent with our ongoing efforts to simplify our capital structure and to identify opportunities to generate additional cash flow by enabling us to realize significant annual cash savings associated with the elimination of Preferred Unit distributions.

In August 2020, we issued $1.0 billion of 4⅞% Senior Notes due 2031, 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”) and redemption payments for our 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the TRP Revolver.

We accepted for purchase all the 6¾% Notes that were validly tendered as of the early tender date, which totaled $262.1 million and redeemed the remaining aggregate principal amount of the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs. In November 2020, we redeemed the $559.6 million remaining balance of our 5¼% Senior Notes due 2023 with available liquidity under the TRP Revolver. We recorded a loss due to debt extinguishment of $1.8 million comprised of a write-off of debt issuance costs.

Additionally, during the first half of 2020, we repurchased a portion of our outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes. The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs.

We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such 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.

In the second quarter of 2020, we amended our accounts receivable securitization facility (the “Securitization Facility”) to decrease the facility size from $400.0 million to $250.0 million and extended the facility termination date to April 21, 2021. Subsequently, in the fourth quarter of 2020, we amended our Securitization Facility to increase the facility size to $350 million to more closely align with the borrowing base availability under the Securitization Facility.

Organization Structure

On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership, effective as of December 1, 2016. As a result of the TRC/TRP Merger, Targa owns all of the outstanding TRP common units. Targa also maintains a 2% general partner interest in us. The Partnership Agreement with us governs our relationship regarding certain reimbursement and indemnification matters. See “Item 13. Certain Relationships and Related Transactions and Director Independence.”

Targa has used us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL, crude oil and other complementary energy businesses and assets as evidenced by our acquisitions of businesses from Targa. However, Targa is not prohibited from competing with us and may evaluate acquisitions and dispositions that do not involve us. In addition, through our relationship with Targa, we have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to Targa’s broad operational, commercial, technical, risk management and administrative infrastructure.

We do not have any employees to carry out our operations. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than its direct support costs of being a separate reporting company and its cost of providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa for cost allocations to the extent that they have required a current cash outlay by Targa. See “—~~Employees~~Human Capital” for further information.

~~The diagram below shows our corporate structure as of February 17, 2020:~~8

~~________________~~The diagram below shows our corporate structure as of February 12, 2021:

~~(1) Common shares outstanding as of February 17, 2020.~~_______________

(1)	Common shares outstanding as of February 12, 2021.

Growth Drivers

We believe that our near-term growth will be driven by organic projects being placed into service, as well as the level of producer activity in the basins where our gathering and processing infrastructure is located and the level of demand for services provided by our logistics and transportation assets. 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. Grand Prix ~~integrates~~connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas and further increases our competitive capabilities to provide reliable, integrated midstream services to customers. Over the longer term, we expect our growth will continue to be driven by our integrated midstream service offering and the strong position of our quality assets which will benefit from production from shale plays and by the deployment of shale exploration and production technologies in both liquids-rich natural gas and crude oil resource plays that will also provide additional opportunities for our Downstream Business. We expect that organic growth and third-party acquisitions will continue to be a part of our long-term growth strategy.

Attractive Asset Positions

We believe that our ~~positioning~~position in some of the most attractive basins will allow us to capture increased natural gas supplies for gathering, processing and/or ~~processing~~purchase and sale, increased NGLs for transportation and fractionation and increased crude oil supplies for gathering, terminaling and/or ~~terminaling~~purchase and sale. Producers continue to focus drilling activity on their most attractive acreage, especially in the Permian Basin where we have a large and well -positioned interconnected footprint and are benefiting from rig activity in and around our systems.

The continued development of shale and unconventional resource plays has resulted in increasing NGL supplies that continue to generate demand for our transportation services on Grand Prix, fractionation services at the Mont Belvieu market hub and for LPG export services at our Galena Park Marine Terminal on the Houston Ship Channel. In response to increasing demand, we added 320 MBbl/d of additional fractionation capacity with the recent completions of Trains 6, 7 and 8, which began operations in the second quarter of 2019, first quarter of 2020 and third quarter of 2020. We believe that the higher volumes of fractionated NGLs will also result in increased demand for other related fee-based services provided by our logistics and transportation assets. Additionally, we added LPG export infrastructure in the third quarter of 2020, which increased our effective export capacity 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. Continued demand for fractionation and export capacity is expected to lead to other future growth opportunities.

~~The~~As ~~development~~domestic ofproducers ~~shale~~have ~~and~~focused ~~unconventional~~their ~~resource~~drilling ~~plays has resulted~~ in ~~increasing~~crude ~~NGL~~oil ~~supplies~~and ~~that~~liquids-rich ~~continue~~areas, tonew ~~generate~~gas ~~demand~~processing ~~for~~facilities ~~our~~are ~~transportation~~being ~~services~~built onto ~~Grand~~accommodate ~~Prix~~liquids-rich gas, ~~fractionation~~which ~~services~~contributes atto the ~~Mont~~increasing ~~Belvieu~~supply ~~market~~of ~~hub~~NGLs ~~and~~produced ~~for LPG export services at our Galena Park Marine Terminal on the Houston Ship Channel~~domestically. ~~Since~~As ~~2010,~~drilling in ~~response~~these toareas ~~increasing demand~~continues, ~~we added 378 MBbl/d of additional fractionation capacity with~~ the ~~additions~~supply of ~~Cedar~~NGLs ~~Bayou~~requiring ~~Fractionator~~transportation ~~(“CBF”) Trains 3, 4,~~ and 5,fractionation ~~and~~to ~~Train~~market 6,hubs ~~and~~is ~~have~~expected ~~additional~~to ~~capacity~~continue ofto ~~220 MBbl/d under construction~~grow. WeAs ~~believe that~~ the ~~higher~~supply ~~volumes~~ of ~~fractionated~~ NGLs ~~will~~increases, ~~also~~our ~~result~~integrated inMont ~~increased~~Belvieu ~~demand~~and ~~for~~Galena ~~other~~Park ~~related~~Marine ~~fee-based~~Terminal ~~services~~assets ~~provided~~allow byus ~~our~~to ~~logistics~~provide ~~and~~the ~~transportation~~raw ~~assets.~~product, ~~Continued~~fractionation, ~~demand~~storage, ~~for~~interconnected ~~fractionation~~terminaling, ~~capacity~~refrigeration isand ~~expected~~ship toloading ~~lead~~capabilities to ~~other~~support ~~future~~exports ~~growth~~by ~~opportunities~~third-party customers.

As domestic producers have focused their drilling in crude oil and liquids-rich areas, new gas processing facilities are being built to accommodate liquids-rich gas, which contributes to the increasing supply of NGLs produced domestically. As drilling in these areas continues, the supply of NGLs requiring transportation and fractionation to market hubs is expected to continue to grow. As the supply of NGLs increases, 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. Grand Prix transports volumes from the Permian Basin and our North Texas and southern Oklahoma systems to our fractionation and storage complex in the NGL market hub at Mont Belvieu further enhancing the integration of our gathering and processing assets with our logistics and transportation assets. Grand Prix positions us to offer an integrated midstream service across the NGL value chain to our customers by linking supply to key markets.

Drilling and production activity from liquids-rich natural gas shale plays and similar crude oil resource plays

We are actively pursuing natural gas gathering and processing and NGL transportation and fractionation opportunities associated with liquids-rich natural gas from shale and other resource plays and are ~~also~~ actively pursuing crude gathering and/or purchases and sales, natural gas gathering, processing and/or ~~processing~~purchases and sales and NGL transportation and fractionation opportunities from active crude oil resource plays. We believe that our leadership position in the Downstream Business, which includes our transportation, fractionation and export services, provides us with a competitive advantage relative to other midstream companies without these capabilities.

Organic growth and third-party acquisitions

We have a demonstrated track record of completing organic growth and third-party acquisitions. ~~Since~~and ~~2015,~~expect weto ~~have~~continue ~~executed~~to oninvest capital in our businesses to enhance our competitive advantage as an integrated midstream infrastructure company. We invested approximately $~~8.4~~617 ~~billion~~million ofin growth capital ~~projects~~expenditures ~~and~~in 2020, or approximately $~~6.0~~598 ~~billion~~million, net of contributions from noncontrolling interests and including net contributions to investments in ~~third-party~~unconsolidated ~~acquisitions~~affiliates. WeThese ~~expect~~expansion toinvestments ~~continue~~are distributed across our businesses, with 39% to ~~grow~~Gathering ~~both~~and ~~organically~~Processing and ~~through~~61% ~~third-party~~related ~~acquisitions~~to Logistics and Transportation. We currently estimate that we will invest approximately $350 to $450 million in net organic growth capital expenditures in 2021.

Competitive Strengths and Strategies

We believe that we are well positioned to execute our business strategies due to the following competitive strengths:

Strategically located gathering and processing asset base

Our gathering and processing businesses are strategically located in attractive oil and gas producing basins and are 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. Activity levels for most of our gathering and processing assets are driven by commodity prices, primarily crude oil prices. IfActivity ~~drilling~~levels ~~and~~can ~~production~~impact ~~activities in these areas continue,~~ the volumes of natural gas and crude oil available to ~~our~~us for gathering, processing and/or ~~processing~~purchase and sale on our systems. ~~will~~Despite ~~likely~~volatile ~~increase~~and low commodity prices relative to historical levels, producers continue to focus drilling activity on their most attractive acreage, especially in the Permian Basin, where we have a large and well-positioned integrated footprint and are benefiting from rig activity in and around our systems.

Leading fractionation, LPG export and NGL infrastructure position

We are one of the largest fractionators of NGLs in the Gulf Coast. Our fractionation assets are primarily located in Mont Belvieu, Texas, and to a lesser extent Lake Charles, Louisiana, which are key market centers for NGLs. Our logistics operations at Mont Belvieu, the major U.S. hub of NGL infrastructure, include connections to a number of mixed NGL (“mixed NGLs” or “Y-grade”) supply pipelines, storage, interconnection and takeaway pipelines and other transportation infrastructure. Our logistics assets, including fractionation facilities, storage wells, low ethane propane de-ethanizer, and our Galena Park Marine Terminal and related pipeline systems and interconnects, are also located near and connected to key consumers of NGL products including the petrochemical and industrial markets. Grand Prix is one of the Y-grade supply pipelines that connects the very active Permian Basin to Mont Belvieu. The location and interconnectivity of these assets are not easily replicated, and we have additional capability to expand their capacity. We have extensive experience in operating these assets and developing, permitting and constructing new ~~midstream~~ assets.

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. Both Grand Prix and ~~the~~ GCX ~~Pipeline~~ further enhance our position to offer an integrated midstream service across the NGL and natural gas value chain by linking supply to key markets. 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 comprehensive services in the midstream sector.

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. Such improvements in the past have included new production and acreage commitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. 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 $~~126~~129 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 ~~assets,~~ and ~~operating our~~ new assets, in a prudent, safe and cost-effective manner.

Large, diverse business mix with favorable contracts and increasing fee-based business

We maintain gas gathering and processing positions in strategic oil and gas producing areas across multiple basins and provide these and other services under attractive contract terms, predominantly fee-based, to a diverse mix of producers across our areas of operation. Consequently, we are not dependent on any one oil and gas basin or counterparty. Our Logistics and Transportation assets are typically located near key market hubs and near most of our NGL customers. They also serve must-run portions of the natural gas and natural gas liquids value chain, are ~~primarily~~predominantly fee-based and have a diverse mix of customers.

Our contract portfolio has attractive rate and term characteristics including a significant fee-based component, especially in our Downstream Business. Our expected continued growth of the fee-based Downstream Business may result in increasing fee-based cash flow. ~~The~~Our ~~Permian~~Gathering ~~Acquisition~~and ~~resulted~~Processing insegment ~~increased~~contract mix also has significant components of fee-based ~~cash~~margin, ~~flow~~such as ~~the~~fee ~~entities~~floors ~~acquired~~and ~~have~~other ~~primarily~~ fee-based ~~gathering~~services which help mitigate against low commodity prices and ~~processing~~may ~~contracts~~increase fee-based cash flow. Additionally, the long-term agreements with the investment grade energy company in the Delaware Basin for natural gas gathering and processing services and logistics and transportation services is fee-based. We ~~also~~continue ~~have~~to anadvance our initiative ~~underway~~ to reduce our commodity price exposure across our gathering and processing business by amending contracts or entering into new contracts with ~~primarily~~predominantly fee-based components and/or protections.

Financial flexibility

We have historically maintained sufficient liquidity and have funded our growth investments with a mix of 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 and enable us to pursue ~~strategic acquisitions and~~ large growth projects and strategic acquisitions.

Experienced and long-term focused management team

Our current executive management team possesses breadth and depth of experience working in the midstream energy business. Many members of our executive management team have ~~been with us since the Partnership was formed in 2006,~~ managed ~~many of~~ our businesses prior to acquisition by Targa, or joined shortly thereafter. Other officers and key employees have significant experience in the industry and with our assets and businesses.

Attractive cash flow characteristics

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. 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) ~~essentially fully~~ fee-based ~~crude~~gas ~~oil~~ gathering and ~~gas~~processing ~~gathering~~ and ~~processing~~crude oil gathering contracts. Contracts in our Coastal 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 ~~predominately~~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. These transactions include swaps, futures, purchased puts (or floors) and costless collars. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. 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 similar hedge transactions. We also monitor and manage our inventory levels with a view to mitigate losses related to downward price exposure.

Asset base well-positioned for organic growth

We believe that our asset platform and strategic locations allow us to maintain and potentially grow our volumes and related cash flows as our supply areas benefit from continued exploration and development over time. Technology advances have resulted in increased domestic oil and liquids-rich gas drilling and production activity. The location of our assets provides us with access to natural gas and crude oil supplies and proximity to end-user markets and liquid market hubs while positioning us to capitalize on drilling and production activity in those areas. We believe that as global supply and demand for natural gas, crude oil and NGLs, and services for each grows over the long term, our infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that growing supply and demand.

While we have set forth our strategies and competitive strengths above, our business involves numerous risks and uncertainties which may prevent us from executing our strategies. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices, the supply of or demand for these commodities, and our inability to access sufficient additional production 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.”

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, ~~dehydrating,~~ treating, ~~conditioning,~~ processing, transporting and ~~marketing~~purchasing and selling natural gas and gathering, storing, terminaling and purchasing and selling crude oil. The gathering or purchase of natural gas consists of aggregating natural gas produced from various wells through varying diameter gathering lines to processing plants. Natural gas has a widely varying composition depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas, commonly referred to as residue gas, and (ii) a stream of mixed NGLs. Once processed, the residue gas is transported to markets through ~~pipelines~~residue ~~that~~gas ~~are owned by third parties and the GCX Pipeline~~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 ~~primarily~~ through ~~gathering~~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

The Gathering and Processing segment'’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays) and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately 28,~~900~~700 miles of natural gas pipelines and include 4642 owned and operated processing plants. During ~~2019~~2020, we processed an average of 4,~~438~~398.23 MMcf/d of natural gas and produced an average of ~~505~~528.49 MBbl/d of NGLs. In addition to our natural gas gathering and processing, the Badlands operations include a crude oil gathering system and four terminals with crude oil operational storage capacity of 205 MBbl, and our Permian operations include a crude oil gathering system and ~~two~~one ~~terminals~~terminal with crude oil operational storage capacity of 2010 MBbl. In January 2020, we closed on the sale of ~~our crude gathering and storage business in~~ the ~~Permian~~ Delaware crude system, see “—Recent Developments—Asset Sales” above. During ~~2019~~2020, we purchased or gathered an aggregate average of ~~255~~199.98 MBbl/d of crude oil in the Badlands and Permian.

The Gathering and Processing segment’s operations consist of (i) Permian Midland, and Permian Delaware (also referred to as “Permian”), (ii) SouthTX, North Texas, SouthOK, WestOK (also referred to as “Central”), (iii) Coastal and (iv) Badlands each as described below:

Permian Midland

The Permian Midland system consists of approximately 67,~~600~~000 miles of natural gas gathering pipelines and ~~fourteen~~fifteen processing plants with an aggregate nameplate capacity of 2,~~129~~399 MMcf/d, all located within the Permian Basin in West Texas. Ten of these plants and 4,~~800~~900 miles of gathering pipelines belong to a joint venture (“WestTX”), in which we have an approximate 72.8% ownership. Pioneer, a major producer in the Permian Basin, owns the remaining interest in the WestTX system.

In addition, we are constructing the ~~Gateway~~Heim Plant, a ~~new~~200 ~~250~~ MMcf/d cryogenic natural gas processing plant, ~~included~~which aswas ~~part~~relocated offrom ~~WestTX~~our inNorth ~~the~~Texas system to our Permian Midland ~~Basin~~system. The ~~Gateway~~Heim Plant is expected to begin operations in the fourth quarter of ~~2020~~2021.

Permian Delaware

The Permian Delaware system consists of approximately 56,~~900~~100 miles of natural gas gathering pipelines and eight processing plants with an aggregate capacity of 1,~~050~~240 MMcf/d, all within the Delaware Basin in West Texas and Southeastern New Mexico. ~~One additional plant, the 250 MMcf/d Peregrine Plant, is currently being constructed and expected to be completed in the second quarter of 2020.~~

The Permian Midland and Permian Delaware systems are interconnected and volumes may flow from one system to the other providing increased operational flexibility and redundancy.

SouthTX

The South Texas system contains approximately ~~900~~870 miles of high-pressure and low-pressure gathering and transmission pipelines and three natural gas processing plants in the Eagle Ford Shale. The South Texas system processes natural gas through the Silver Oak I, Silver Oak II and Raptor gas processing plants. The Silver Oak I and II Plants (the “Silver Oak Plants”) are each 200 MMcf/d cryogenic plants. The Raptor Plant is a 260 MMcf/d cryogenic plant.

We participate in, and serve as operator for, two joint ventures in South Texas with a subsidiary of Southcross Energy Partners LLC, which consist of our 75% share in T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and our 50% share in T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”). T2 LaSalle owns approximately 60 miles of high-pressure gathering pipeline and T2 Eagle Ford owns approximately 120 miles of high-pressure gathering pipelines. Together, these two pipelines gather and transport gas to the Silver Oak Plants. T2 Eagle Ford also owns the residue gas delivery pipelines downstream of the Silver Oak Plants. ~~On April 1, 2019, we assumed the operatorship of T2 LaSalle and T2 Eagle Ford.~~

We also participate in a third joint venture in South Texas, ~~which~~with isSanchez ~~with~~Midstream Partners LP (“Sanchez Midstream”). We own a 50% interest in the Carnero Joint Venture (“Carnero”) and Sanchez Midstream owns the remaining 50% interest. Carnero owns and Targa operates the Silver Oak II Plant, the Raptor Plant and approximately 45 miles of high-pressure gathering pipeline located in La Salle, Dimmitt and Webb Counties, Texas which connects ~~Sanchez~~Mesquite Energy’s Catarina Ranch gathering system and Comanche Ranch acreage to the Raptor Plant.

North Texas

North Texas includes ~~two~~the ~~interconnected~~Chico gathering ~~systems~~system in the Fort Worth Basin, ~~Chico~~which ~~and~~gathers ~~Shackelford, and includes~~ gas from the Barnett Shale and Marble Falls plays for the Chico plant. The ~~systems~~system ~~consist~~consists of approximately 4,700 miles of pipelines gathering wellhead natural gas. The Chico plant has an aggregate processing capacity of 265 MMcf/d and an integrated fractionation capacity of 15 MBbl/d.

The Chico gathering system gathers natural gas for the Chico and Longhorn plants. The Chico Plant has an aggregate processing capacity of 265 MMcf/d and an integrated fractionation capacity of 15 MBbl/d. The Longhorn Plant has processing capacity of 200 MMcf/d. The Shackelford gathering system gathers wellhead natural gas largely for the Shackelford Plant, which has processing capacity of 13 MMcf/d. Natural gas gathered from the northern and eastern portions of the Shackelford gathering system is typically transported to the Chico Plant for processing.

SouthOK

The SouthOK gathering system is located in the Ardmore and Anadarko Basins and includes the Golden Trend, SCOOP, and Woodford Shale areas of southern Oklahoma. The gathering system has approximately 2,~~300~~000 miles of pipelines.

The SouthOK system includes six separate operational processing plants with a total nameplate 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 (“MPLX”).

WestOK

The WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin and includes the Woodford shale and the STACK. The gathering system expands into 1314 counties with approximately 6,600 miles of natural gas gathering pipelines.

The WestOK system has a total nameplate capacity of ~~458~~400 MMcf/d with ~~three~~two separate cryogenic natural gas processing plants ~~located~~known atas the Waynoka I and Waynoka II ~~and Chester~~ facilities~~, and one refrigeration plant at the Chaney Dell facility~~.

Coastal

Our Coastal assets, located in and offshore South Louisiana, gather and process natural gas produced from shallow-water central and western Gulf of Mexico natural gas wells and from deep shelf and deep-water Gulf of Mexico production via connections to third-party pipelines or through pipelines owned by us. Coastal consists of approximately 32,~~295~~075 MMcf/d of natural gas processing capacity, 11 MBbl/d of integrated fractionation capacity, ~~980~~1,000 miles of onshore gathering system pipelines, and 170 miles of offshore gathering system pipelines. The processing plants are comprised of ~~five~~three wholly-owned and operated plants, one partially owned and operated plant, and ~~two~~one partially owned ~~plants~~plant which ~~are~~is non-operated. ~~Toca, a partially owned, non-operated plant, was shut down in January 2019 and has been excluded from the preceding statistics.~~ 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 ~~Barracuda,~~ Lowry and Gillis plants.

Badlands

The Badlands operations are located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota and include approximately 510 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 280 miles of natural gas gathering pipelines and the Little Missouri I-III natural gas processing plants, which have a gross processing capacity of approximately 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 GSO Capital Partners and Blackstone Tactical Opportunities (collectively, ~~which~~ ~~was~~“GSO”). ~~completed~~The injoint 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 GSO and Targa, with GSO having a priority right to the ~~third~~MQDs. ~~quarter~~Additionally, GSO’s capital contributions have a liquidation preference upon a sale of ~~2019~~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.

In April 2019, we closed on the sale of a 45% interest in Targa Badlands to Blackstone. Targa continues to be the operator of Badlands and holds majority governance rights.

The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, ~~2019~~2020:

Facility

~~Process Type (1)~~

~~Operated /Non-Operated~~

~~% Owned~~

Process Type (1)

Operated /Non-Operated

~~Location~~

~~Gross Processing Capacity (MMcf/d) (2)~~

% Owned

~~Gross Plant Natural Gas Inlet Throughput Volume (MMcf/d) (3) (4) (5)~~

~~Gross NGL Production (MBbl/d) (3) (4) (5)~~

Location

Gross Processing Capacity (MMcf/d) (2)

Gross Plant Natural Gas Inlet Throughput Volume (MMcf/d) (3) (4) (5)

Gross NGL Production (MBbl/d) (3) (4) (5)

Permian Midland

Consolidator (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Reagan County, TX~~

~~150.0~~

72.8

Reagan County, TX

150.0

Midkiff (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Reagan County, TX~~

~~80.0~~

72.8

Reagan County, TX

80.0

Driver (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Midland County, TX~~

~~200.0~~

72.8

Midland County, TX

200.0

Benedum (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Upton County, TX~~

~~45.0~~

72.8

Upton County, TX

45.0

Edward (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Upton County, TX~~

~~200.0~~

72.8

Upton County, TX

200.0

Buffalo (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Martin County, TX~~

~~200.0~~

72.8

Martin County, TX

200.0

Joyce (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Upton County, TX~~

~~200.0~~

72.8

Upton County, TX

200.0

Johnson (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Midland County, TX~~

~~200.0~~

72.8

Midland County, TX

200.0

Hopson (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Midland County, TX~~

~~250.0~~

72.8

Midland County, TX

250.0

Pembrook (6)

~~Cryo~~

~~Operated~~

~~72.8~~Cryo

Operated

~~Upton County, TX~~

~~250.0~~

72.8

Upton County, TX

250.0

Mertzon

~~Cryo~~

~~Operated~~

~~100.0~~Cryo

Operated

~~Irion County, TX~~

~~52.0~~

100.0

Irion County, TX

52.0

Sterling

~~Cryo~~

~~Operated~~

~~100.0~~Cryo

Operated

~~Sterling County, TX~~

~~92.0~~

100.0

Sterling County, TX

92.0

Tarzan

~~Cryo~~

~~Operated~~

~~100.0~~Cryo

Operated

~~Martin County, TX~~

~~10.0~~

100.0

Martin County, TX

10.0

High Plains

~~Cryo~~

~~Operated~~

~~100.0~~Cryo

Operated

~~Midland County, TX~~

~~200.0~~

100.0

Midland County, TX

220.0

Area Total

2,129.0

1,489.1

209.1

Gateway (7)

Cryo

Operated

100.0

Reagan County, TX

250.0

Permian Delaware

Area Total

2,399.0

1,745.6

250.8

Sand Hills

Cryo

Operated

100.0

Crane County, TX

165.0

Permian Delaware

Loving

Cryo

Operated

100.0

Loving County, TX

70.0

Sand Hills

Cryo

Operated

100.0

Crane County, TX

165.0

Oahu

Cryo

Operated

100.0

Pecos County, TX

60.0

Loving

Cryo

Operated

100.0

Loving County, TX

70.0

Wildcat

Cryo

Operated

100.0

Winkler County, TX

250.0

Oahu

Cryo

Operated

100.0

Pecos County, TX

60.0

Falcon

Cryo

Operated

100.0

Culberson County, TX

250.0

Wildcat

Cryo

Operated

100.0

Winkler County, TX

250.0

Saunders (7)

Cryo

Operated

100.0

Lea County, NM

60.0

Falcon

Cryo

Operated

100.0

Culberson County, TX

250.0

Eunice (7)

Cryo

Operated

100.0

Lea County, NM

110.0

Eunice (8)

Cryo

Operated

100.0

Lea County, NM

110.0

Monument (7) (16)

Cryo

Operated

100.0

Lea County, NM

85.0

Monument (8) (9)

Cryo

Operated

100.0

Lea County, NM

85.0

Area Total

1,050.0

599.7

78.6

Peregrine

Cryo

Operated

100.0

Culberson County, TX

250.0

SouthTX

Area Total

1,240.0

729.4

99.1

Silver Oak I

Cryo

Operated

100.0

Bee County, TX

200.0

SouthTX

Silver Oak II

Cryo

Operated

50.0

Bee County, TX

200.0

Silver Oak I

Cryo

Operated

100.0

Bee County, TX

200.0

Raptor

Cryo

Operated

50.0

La Salle County, TX

260.0

Silver Oak II

Cryo

Operated

50.0

Bee County, TX

200.0

Area Total

660.0

321.2

41.6

Raptor

Cryo

Operated

50.0

La Salle County, TX

260.0

North Texas

Area Total

660.0

248.1

26.1

Chico (8)

Cryo

Operated

100.0

Wise County, TX

265.0

North Texas

Shackelford

Cryo

Operated

100.0

Shackelford County, TX

13.0

Chico (10)

Cryo

Operated

100.0

Wise County, TX

265.0

Longhorn

Cryo

Operated

100.0

Wise County, TX

200.0

Longhorn (11)

Cryo

Operated

100.0

Wise County, TX

200.0

~~Area Total~~

~~478.0~~

~~226.9~~

~~26.8~~

Area Total

465.0

201.6

23.9

SouthOK (9)

SouthOK (12)

Coalgate

Cryo

Operated

60.0

Coal County, OK

80.0

Coalgate (13)

Cryo

Operated

60.0

Coal County, OK

80.0

Stonewall

~~Cryo~~

~~Operated~~

~~60.0~~Cryo

Operated

~~Coal County, OK~~

~~200.0~~

60.0

Coal County, OK

200.0

Tupelo

~~Cryo~~

~~Operated~~

~~60.0~~Cryo

Operated

~~Coal County, OK~~

~~120.0~~

60.0

Coal County, OK

120.0

Hickory Hills

~~Cryo~~

~~Operated~~

~~60.0~~Cryo

Operated

~~Hughes County, OK~~

~~150.0~~

60.0

Hughes County, OK

150.0

Velma

Cryo

Operated

100.0

Stephens County, OK

100.0

Velma (13)

Cryo

Operated

100.0

Stephens County, OK

100.0

Velma V-60

~~Cryo~~

~~Operated~~

~~100.0~~Cryo

Operated

~~Stephens County, OK~~

~~60.0~~

100.0

Stephens County, OK

60.0

~~Area Total~~

~~710.0~~

~~606.1~~

~~67.1~~

Area Total

710.0

443.0

52.4

WestOK (9)

WestOK (12)

Waynoka I

~~Cryo~~

~~Operated~~

~~100.0~~Cryo

Operated

~~Woods County, OK~~

~~200.0~~

100.0

Woods County, OK

200.0

Waynoka II

~~Cryo~~

~~Operated~~

~~100.0~~Cryo

Operated

~~Woods County, OK~~

~~200.0~~

100.0

Woods County, OK

200.0

Chaney Dell (10)

Operated

100.0

Major County, OK

30.0

Area Total

400.0

249.5

20.3

Chester (10)

Cryo

Operated

100.0

Woodward County, OK

28.0

Coastal

Area Total

458.0

330.2

21.6

Gillis (14)

Cryo

Operated

100.0

Calcasieu Parish, LA

180.0

Coastal (11)

Big Lake (13)

Cryo

Operated

100.0

Calcasieu Parish, LA

180.0

Gillis (12)

Cryo

Operated

100.0

Calcasieu Parish, LA

180.0

VESCO

Cryo

Operated

76.8

Plaquemines Parish, LA

750.0

Acadia (10)

Cryo

Operated

100.0

Acadia Parish, LA

80.0

Lowry

Cryo

Operated

100.0

Cameron Parish, LA

265.0

Big Lake (13)

Cryo

Operated

100.0

Calcasieu Parish, LA

180.0

Sea Robin

Cryo

Non-operated

0.9

Vermillion Parish, LA

700.0

VESCO

Cryo

Operated

76.8

Plaquemines Parish, LA

750.0

Area Total

2,075.0

643.3

40.0

Barracuda

Cryo

Operated

100.0

Cameron Parish, LA

190.0

Badlands

Lowry (14)

Cryo

Operated

100.0

Cameron Parish, LA

265.0

Little Missouri I-III (15)

Cryo/RA

Operated

55.0

McKenzie County, ND

90.0

Terrebone (15)

Non-operated

8.4

Terrebonne Parish, LA

950.0

Little Missouri IV

Operated

27.5

McKenzie County, ND

200.0

Toca (17)

Cryo/RA

Non-operated

12.6

St. Bernard Parish, LA

1,150.0

Area Total

290.0

137.8

16.3

Sea Robin

Cryo

Non-operated

0.9

Vermillion Parish, LA

700.0

Segment System Total

8,239.0

4,398.3

528.9

Area Total

4,445.0

748.3

46.8

Badlands

Little Missouri I-III (18)

Cryo/RA

Operated

55.0

McKenzie County, ND

90.0

Little Missouri IV

Operated

27.5

McKenzie County, ND

200.0

Area Total

290.0

116.7

13.8

Segment System Total

10,220.0

4,438.2

505.4

(1)	Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.

(2)	Gross processing capacity represents 100% of ownership interests and may differ from nameplate processing capacity due to multiple factors including items such as compression limitations, and quality and composition of the gas being processed.

(3) 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 ~~gathered~~ volume.

(4)

Plant natural gas inlet and NGL production volumes represent 100% of ownership interests for our consolidated VESCO joint venture, Silver Oak II, Raptor, Coalgate, Stonewall, Tupelo, and Hickory Hills plants and our ownership share of volumes for other partially owned plants that we proportionately consolidate based on our ownership interest which may be adjustable subject to an annual redetermination based on our proportionate share of plant production.

(5) Per day Gross Plant Natural Gas Inlet and NGL Production statistics for plants listed above are based on the number of calendar days during ~~2019~~2020.

(6)	Gross plant natural gas inlet throughput volumes and gross 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.

(7) ~~Includes~~As ~~throughput~~a ~~other~~result ~~than~~of ~~plant~~a ~~inlet~~non-consent election made by the joint owner in our WestTX Permian Basin assets, ~~primarily~~the ~~from~~Gateway ~~compressor~~plant ~~stations~~is 100% owned and consolidated by Targa until payout.

(8) ~~The~~Includes ~~Chico~~throughput ~~plant~~other ~~has~~than ~~fractionation~~plant ~~capacity~~inlet, ofprimarily ~~approximately~~from 15compressor ~~MBbl/d~~stations.

(9) ~~Certain~~The ~~processing~~Monument ~~facilities~~plant inhas ~~these~~fractionation ~~business~~capacity ~~units are capable~~ of ~~processing~~approximately ~~more than their nameplate capacity and when capacity is exceeded the facilities will off-load volumes to other processors, as needed~~1.8 ~~The gross plant natural gas inlet throughput volume includes these off-loaded volumes~~MBbl/d.

(10) ~~Plant~~The isChico ~~idle~~plant has fractionation capacity of approximately 15 MBbl/d.

(11) ~~Coastal~~The ~~also~~Longhorn ~~includes~~Plant ~~two~~was ~~offshore~~shut ~~gathering~~down ~~systems~~in ~~which~~October ~~have~~2020 aand ~~combined~~will ~~length~~be ofrelocated ~~approximately~~to ~~200~~our ~~miles~~Permian Midland system as the Heim Plant. The Heim plant is expected to begin operations in the fourth quarter of 2021.

(12) ~~The~~Certain ~~Gillis~~processing ~~plant~~facilities ~~has~~in ~~fractionation~~these ~~capacity~~business units are capable of ~~approximately~~processing 11more ~~MBbl/d~~than their nameplate capacity and when capacity is exceeded the facilities will off-load volumes to other processors, as needed.

(13)	Plant is available and operates subject to market conditions.

(14) ~~Plant~~The ~~restarted~~Gillis ~~operation~~plant inhas ~~March~~fractionation ~~2019~~capacity of approximately 11 MBbl/d.

(15) ~~Plant~~Little isMissouri ~~anticipated~~Trains toI ~~shutdown~~and onII ~~March~~are ~~31,~~refrigeration ~~2020~~plants and Little Missouri Train III is a Cryo plant.

(16) The Monument plant has fractionation capacity of approximately 1.8 MBbl/d.

(17) The Toca plant was shut down in January 2019, but has been retained in this table to include its volumes for 2019.

(18) Little Missouri Trains I and II are refrigeration plants and Little Missouri Train III is a Cryo plant.

Logistics and Transportation Segment

Our Logistics and Transportation segment is also referred to as our Downstream Business. Our Downstream Business includes the activities and assets necessary to transport and convert mixed NGLs into NGL products and also includes other assets and value-added services described below. The Logistics and Transportation segment includes Grand Prix, as well as our equity interest in GCX. The associated assets, including these pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Our fractionation, pipeline transportation, storage and terminaling businesses include approximately 2,~~000~~100 miles of company-owned pipelines to transport mixed NGLs and specification products.

The Logistics and Transportation segment also transports, distributes, purchases and sells and markets NGLs via terminals and transportation assets across the U.S. We own or ~~commercially~~market ~~manage~~products at terminal facilities in a number of states, including ~~Texas~~Alabama, ~~Oklahoma, Louisiana,~~ Arizona, California, Florida, ~~Alabama~~Kentucky, Louisiana, Mississippi, ~~Tennessee~~New Jersey, ~~Kentucky~~Tennessee and ~~New Jersey~~Texas. The geographic diversity of our assets provides direct access to many NGL customers as well as markets via trucks, barges, ships, rail cars and open-access regulated NGL pipelines owned by third parties.

Additional description of the Logistics and Transportation segment assets and business activities associated with Pipelines, Fractionation, NGL Storage and Terminaling, ~~Petroleum Logistics,~~ NGL Distribution and Marketing, Wholesale Domestic Marketing, Refinery Services, Commercial Transportation and Natural Gas Marketing follows below.

Pipelines

Our primary pipeline assets are Grand Prix and our equity interest in GCX.

Grand Prix connects our gathering and processing positions throughout the Permian Basin, North Texas, and Southern Oklahoma (as well as third-party positions) to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix transports NGLs from the Permian Basin on a 24-inch diameter pipeline with a capacity of ~~300~~410 MMBbl/d, expandable to 550 MMBbl/d, and from North Texas and Southern Oklahoma via pipeline of varying capacity, which both connect to a 30-inch diameter segment into Mont Belvieu. The final segment has a 450 MMBbl/d capacity, which is expandable to 950 MMBbl/d. We own a 56% interest in the Permian and Mont Belvieu segments of Grand Prix through the Grand Prix Joint Venture. Volumes flowing on the pipeline from the Permian Basin to Mont Belvieu accrue to the Grand Prix Joint Venture, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targa’s benefit.

GCX ~~Pipeline~~connects ~~transports natural gas from~~ the Waha hub in West Texas and other receipt points, including many of our Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points, and has a capacity of 12.980 Bcf/d. GCX DevCo JV, of which we own a 20% interest, owns a 25% interest in GCX ~~Pipeline~~, which is operated by ~~KMTP~~Kinder Morgan Texas Pipeline LLC.

Additionally, through our 50% ownership interest in Cayenne Pipeline, LLC, we operate the Cayenne pipeline, which transports mixed NGLs from VESCO in Venice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana.

Fractionation

After being extracted in the field, mixed NGLs are typically transported to a centralized facility for fractionation where the mixed NGLs are separated into discrete NGL products: ethane, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.

Contracts for our NGL fractionation services are fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results of our NGL fractionation business are dependent upon the volume of mixed NGLs fractionated, the level of fractionation fees charged and product gains/losses from fractionation.

We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the foreseeable future due to historical increases in NGL production from shale plays and other shale-technology-driven resource plays in areas of the U.S. that include Texas, New Mexico, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from conventional production of NGLs in areas such as the Permian Basin, Mid-Continent, East Texas, South Louisiana and shelf and deep-water Gulf of Mexico. Hydrocarbon dew point specifications implemented by individual natural gas pipelines and the Policy Statement on Provisions Governing Natural Gas Quality and Interchangeability in Interstate Natural Gas Pipeline Company Tariffs enacted in 2006 by the Federal Energy Regulatory Commission (“FERC”) should result in volumes of mixed NGLs being available for fractionation because natural gas requires processing or conditioning to meet pipeline quality specifications. These requirements establish a base volume of mixed NGLs during periods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of mixed NGLs are contractually committed to our NGL fractionation facilities.

Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor. This ability is a function of the existence of storage infrastructure and supply and market connectivity necessary to conduct such operations. We believe that the location, scope and capability of 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.

~~Our~~At our Mont Belvieu operated facility, we have eight fractionation ~~assets~~trains, ~~include~~representing ~~ownership~~a ~~interests~~gross incapacity ~~three~~of ~~stand-alone~~813.0 MBbl/d, including: (1) five fractionation ~~facilities~~trains with an aggregate capacity of 493.0 MBbl/d that are ~~located~~part onof ~~the~~our ~~Gulf~~88%-owned ~~Coast~~Cedar Bayou Fractionators, ~~two~~(2) ofTrain ~~which~~6, wea ~~operate~~100 atMBbl/d ~~Mont~~fractionation ~~Belvieu~~train (“Train 6”), ~~Texas~~a joint venture between Targa and atStonepeak ~~Lake~~Infrastructure ~~Charles~~Partners (“Stonepeak”), ~~Louisiana.~~in Wewhich ~~have~~Targa anowns ~~equity~~a ~~investment~~20% interest, (3) Train 7, a 110 MBbl/d fractionation train, a joint venture between Targa and Williams which began operations in the ~~third~~first ~~fractionation~~quarter ~~facility~~2020, ~~Gulf~~in ~~Coast~~which ~~Fractionators~~Targa LPowns an 80% equity interest, and (~~“GCF”~~4) Train 8, ~~also~~a ~~located~~110 atMBbl/d ~~Mont~~fractionation ~~Belvieu.~~train, Inwhich ~~addition~~began tooperations late in the ~~three~~third ~~stand~~quarter 2020 and is wholly-~~alone~~owned ~~facilities~~by ~~included~~Targa. inCertain ~~the~~fractionation-related ~~Logistics~~infrastructure for Train 6 and ~~Transportation~~Train ~~segment~~7, wesuch ~~also~~as ~~own~~storage ~~fractionation~~caverns ~~assets~~and atbrine ~~Chico~~handling, ~~Monument~~were funded and ~~Gillis~~are ~~included~~owned in100% by Targa. Our fractionation trains are fully integrated with our ~~Gathering~~existing Gulf Coast NGL storage, terminaling and ~~Processing~~delivery ~~segment~~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.

~~Five~~We ofadditionally ~~the~~have ~~six~~a ~~existing~~wholly-owned ~~fractionation~~and ~~trains~~operated atfractionation ~~the~~facility ~~Mont~~in ~~Belvieu~~Lake ~~facility~~Charles, Louisiana, representing a gross capacity of ~~493~~55.0 MBbl/d ~~are part of our 88%-owned Cedar Bayou Fractionators~~. A 100 MBbl/d fractionation train, Train 6, began operations in the second quarter of 2019. Train 6 JV, a joint venture between Targa and Stonepeak, owns 100% interest in the fractionation train. Certain fractionation-related infrastructure for Train 6, such as storage caverns and brine handling, were funded and are owned 100% by Targa.

~~Two~~In ~~additional~~addition ~~fractionation~~to ~~trains,~~our ~~which~~operated ~~are~~facilities, ~~currently~~we ~~under~~hold ~~construction~~an atequity ~~the~~investment ~~Mont Belvieu facility~~in, ~~are not part of CBF or the Train 6 JV. The additional fractionation trains are being fully integrated with our existing~~ Gulf Coast ~~NGL~~Fractionators ~~storage,~~LP ~~terminaling and delivery infrastructure~~(“GCF”), ~~which~~also ~~includes~~located ~~an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal~~ at ~~Galena~~Mont ~~Park on the Houston Ship Channel~~Belvieu. ~~The~~In ~~additional~~January ~~fractionation~~2021, ~~trains are: (1)~~ the ~~110~~GCF ~~MBbl/d~~facility ~~Train~~was 7temporarily idled, abut ~~joint~~is ~~venture~~available ~~with~~for ~~Williams~~reactivation, ~~which~~subject ~~is expected~~ to ~~begin~~prevailing ~~operations~~market byconditions ~~the end of the first quarter 2020~~ and ~~(2)~~agreement ~~the~~with ~~110~~our ~~MBbl/d~~partners. ~~Train~~We 8,will ~~which~~assume isoperatorship ~~expected~~of toGCF ~~begin~~in ~~operations by~~ the ~~end~~first half of ~~the third quarter 2020~~2021.

We also own fractionation assets at Chico, Monument and Gillis, which are included in our Gathering and Processing segment. In addition, we have a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet stringent fuel content standards. The facility has a capacity of 35 MBbl/d and is supported by long-term fee-based contracts that have certain guaranteed volume commitments and/or provisions for deficiency payments.

The following table details the Logistics and Transportation segment’s fractionation and treating facilities:

Facility	% Owned		Gross Capacity (MBbl/d) (1)		Gross Throughput ~~2019~~2020 (MBbl/d)
Operated Facilities:
Lake Charles Fractionator (Lake Charles, LA) (2)		100.0		55.0		4.6
Cedar Bayou Fractionators (Mont Belvieu, TX) (2)		88.0		493.0		359.4
Train 6 Fractionator (Mont Belvieu, TX) (3)		20.0		100.0		73.5
Train 6 Fractionator (Mont Belvieu, TX)		20.0		100.0		109.0
Cedar Bayou Fractionators (Mont Belvieu, TX) (4)		88.0		493.0		430.8
Train 7 Fractionator (Mont Belvieu, TX) (3)		80.0		110.0		94.7
Targa LSNG Hydrotreater (Mont Belvieu, TX)		100.0		35.0		35.8
Train 8 Fractionator (Mont Belvieu, TX) (4)		100.0		110.0		27.5
Lake Charles Fractionator (Lake Charles, LA) (5)		100.0		55.0		12.3
Targa LSNG Hydrotreater (Mont Belvieu, TX)		100.0		35.0		38.9
Non-operated Facilities:
Gulf Coast Fractionator (Mont Belvieu, TX)		38.8		125.0		125.4
Gulf Coast Fractionator (Mont Belvieu, TX) (6)		38.8		135.0		68.2

________________

(1) Actual fractionation capacities may vary due to the ~~Y-grade~~ composition of the ~~gas~~NGLs being processed and does not contemplate ethane rejection.

(2) ~~Lake~~Gross ~~Charles~~capacity ~~Fractionator~~represents ~~runs~~100% ~~in a mode~~ of ~~ethane/propane~~the ~~splitting~~volume. ~~for~~Capacity aincludes ~~local~~40 ~~petrochemical~~MBbl/d ~~customer~~of ~~and~~additional isback-end ~~configured~~butane/gasoline tofractionation ~~handle raw product~~capacity.

(3) Train 67 began operations in the ~~second~~first quarter of ~~2019~~2020.

(4) ~~Gross~~Train ~~capacity~~8 ~~represents~~began ~~100%~~operations oflate in the ~~volume.~~third ~~Capacity~~quarter ~~includes 40 MBbl/d~~ of ~~additional back-end butane/gasoline fractionation capacity~~2020.

(5)	Lake Charles Fractionator runs in a mode of ethane/propane splitting for a local petrochemical customer and is configured to handle raw product.

(6)	GCF was temporarily idled in January 2021. Targa will assume operatorship of GCF in the first half of 2021. The facility is available for reactivation, subject to prevailing market conditions and agreement with our partners.

NGL Storage and Terminaling

In general, our NGL storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal of such products at various times in order to meet supply and demand cycles. Similarly, our terminaling operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and petrochemical products in above-ground storage tanks. Our NGL underground storage and terminaling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the Mont Belvieu and Galena Park facilities have extensive pipeline connections for mixed NGL supply and delivery of component NGLs, including Grand Prix. In addition, some of our facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to our customers. We provide long and short-term storage and terminaling services and throughput capability to third-party customers for a fee.

Across the Logistics and Transportation segment, we own 34 storage wells at our facilities with a gross NGL storage capacity of approximately 7275 MMBbl, and operate 67 non-owned wells, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.

We operate our storage and terminaling facilities to support our key fractionation facilities at Mont Belvieu and Lake Charles for receipt of mixed NGLs and storage of fractionated NGLs to service the petrochemical, refinery, export and heating customers/markets as well as our wholesale domestic terminals that focus on logistics to service the heating market customer base. Our international export assets include our facilities at both Mont Belvieu and the Galena Park Marine Terminal near Houston, Texas, which have the capability to load propane, ~~butane~~butanes and international grade low ethane propane. The facilities ~~currently~~ have ~~the~~an effective export capacity toof ~~export~~up ~~approximately~~to 1015 MMBbl per month, but given the mix of propane and~~/or~~ 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

% Owned

Location

Description

Throughput for ~~2019~~2020 (MMgal)

Number of Operational Wells

Gross Storage Capacity (MMBbl)

Galena Park Marine Terminal (1)

100

Harris County, TX

NGL import/export terminal

5,~~162~~912.87

N/A

0.87

Mont Belvieu Terminal & Storage

100

Chambers County, TX

Transport and storage terminal

2135,~~860~~922.0

(2)

5054.81

Hackberry Terminal & Storage

100

Cameron Parish, LA

Storage terminal

~~1,623~~312.0

(3)

20.9

Patriot

100

Harris County, TX

Dock and land for expansion (Not in service)

N/A

________________

(1)	Volumes reflect total import and export across the dock/terminal and may include volumes that have also been handled at the Mont Belvieu Terminal.

(2) Excludes ~~six~~seven non-owned wells which we operate on behalf of Chevron Phillips Chemical Company LLC ~~and one additional non-owned well that is being prepared for operations~~. One additional well has been drilled and is being prepared for operations. One additional well is permitted.

(3) Five of 12 owned wells leased to Citgo Petroleum Corporation under a long-term ~~leases~~lease.

Petroleum Logistics

Our Petroleum Logistics business owns and operates a storage and terminaling facility in Channelview, Texas, including a 35,000 Bbl/d nameplate capacity crude oil and condensate splitter (the “Channelview Splitter”). This facility serves the refined petroleum products, crude oil, LPG, and petrochemicals markets. The Channelview storage and terminaling facility’s throughput for the year ended December 31, 2019, was 219.7 MMgal and the gross storage capacity was 0.6 MMBbl. The Channelview Splitter splits crude oil and condensate into its various components, including naphtha, distillate, gas oil, kerosene/jet fuel and liquefied petroleum gas and has segregated storage for the crude and condensate and each of the components.

NGL Distribution and Marketing

We market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. Additionally, we also purchase product for resale in our Logistics and Transportation segment, including exports. During the year ended December 31, ~~2019~~2020, our distribution and marketing services business sold an average of ~~651~~752.05 MBbl/d of NGLs.

We generally purchase mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these component products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which we earn margins from purchasing and selling NGL products from customers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward physical markets. To effectively serve our distribution and marketing customers, we contract for and use many of the assets included in our Logistics and Transportation segment.

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~~Logistics and ~~transportation~~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 margin 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 to purchase and/or market propane and to supply butanes. We use our commercial transportation assets (discussed below) and contract for and use the storage, transportation and distribution assets included in our Logistics and Transportation segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGLs produced by other refining processes. Under typical netback purchase contracts, we generally retain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under netback sales contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee per gallon.

Key factors impacting the results of our refinery services business include production volumes, prices of propane and butanes, as well as our ability to perform receipt, delivery and transportation services in order to meet refinery demand.

Commercial Transportation

Our NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements of our marketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. Our assets are also deployed to serve our wholesale domestic distribution terminals, fractionation facilities, underground storage facilities and pipeline injection terminals. These distribution assets provide a variety of ways to transport products to and from our customers.

Our transportation assets, as of December 31, ~~2019~~2020, include ~~approximately~~694 ~~698~~ railcars that we lease and manage, ~~approximately~~124 ~~138~~ leased and managed transport tractors and 2 company-owned pressurized NGL barges.

The following table details the Logistics and Transportation segment’s raw NGL, propane and butane terminaling facilities:

Facility	% Owned	Location	Description	Throughput for ~~2019~~2020 (MMgal) (1)		Usable Storage Capacity (MMgal)
Calvert City Terminal	100	Marshall County, KY	Propane terminal		11.3		0.1
Fort Lauderdale Transload (2)	100	Broward County, FL	Butane transload		0.3		—
Greenville Terminal	100	Washington County, MS	Marine propane terminal		23.7		1.5
Jacksonville Transload (2)	100	Duval County, FL	Butane transload		0.3		—
Port Everglades Terminal	100	Broward County, FL	Marine propane terminal		17.3		1.6
Eagle Lake Transload (2)	100	Polk County, FL	Butane/propane transload		4.7		—
Tyler Terminal	100	Smith County, TX	Propane terminal		14.5		0.2
Greenville Terminal	100	Washington County, MS	Marine propane terminal		20.8		1.5
Abilene Transport (2)	100	Taylor County, TX	Raw NGL transport terminal		15.7		0.1
Port Everglades Terminal	100	Broward County, FL	Marine propane terminal		14.0		1.6
Bridgeport Transport (2)	100	Jack County, TX	Raw NGL transport terminal		116.0		0.1
Calvert City Terminal	100	Marshall County, KY	Propane terminal		5.9		0.1
Gladewater Transport (2)	100	Gregg County, TX	Raw NGL transport terminal		3.6		0.3
Chattanooga Terminal	100	Hamilton County, TN	Propane terminal		15.0		0.9
Chattanooga Terminal	100	Hamilton County, TN	Propane terminal		16.8		0.9
Hattiesburg Terminal (3)	50	Forrest County, MS	Propane terminal		351.5		179.8
Sparta Terminal	100	Sparta County, NJ	Propane terminal		13.50		0.2
Hattiesburg Terminal (3)	50	Forrest County, MS	Propane terminal		352.8		179.8
Tyler Terminal	100	Smith County, TX	Propane terminal		16.3		0.2
Winona Terminal	100	Flagstaff County, AZ	Propane terminal		1213.29		0.3
Jacksonville Transload (4)	100	Duval County, FL	Butane transload		1.6		—
Abilene Transport (4)	100	Taylor County, TX	Raw NGL transport terminal		—		0.1
Fort Lauderdale Transload (4)	100	Broward County, FL	Butane transload		1.8		—
Bridgeport Transport (4)	100	Jack County, TX	Raw NGL transport terminal		29.2		0.1
Eagle Lake Transload (4)	100	Polk County, FL	Butane/propane transload		4.6		—
Gladewater Transport (4)	100	Gregg County, TX	Raw NGL transport terminal		5.1		0.3

________________

(1)	Throughputs include volumes related to exchange agreements and third-party storage agreements.

(2) ~~Volumes~~Rail-to-truck ~~reflect~~transload ~~total transport and injection volumes~~equipment.

(3)	Throughput volume reflects 100% of the facility capacity.

(4) ~~Rail-to-truck~~Volumes ~~transload~~reflect ~~equipment~~total transport and injection volumes.

Natural Gas Marketing

We also market natural gas available to us from the Gathering and Processing segment, purchase and resell natural gas in selected U.S. markets and manage the scheduling and logistics for these activities.

Seasonality

Overall, parts of our business are impacted by seasonality. Our downstream marketing business can be significantly impacted by seasonal and weather-driven demand, which can impact the price and volume of product sold in the markets we serve, as well as the level of inventory we hold in order to meet anticipated demand. See further discussion of the extent to which our business is affected by seasonality in “Item 1A. Risk Factors.”

Operational Risks and Insurance

We are subject to all risks inherent in the midstream natural gas, NGLs and crude oil businesses. These risks include, but are not limited to, explosions, fires, mechanical failure, cyber attacks, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights of way. These risks could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or environmental pollution, as well as curtailment or suspension of operations at the affected facility. Targa maintains, on behalf of us and our subsidiaries, general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles or self-insured retentions that we consider reasonable and not excessive given the current insurance market environment.

The occurrence of a significant loss that is not insured, fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates considered commercially reasonable, particularly named windstorm coverage and contingent business interruption coverage for our onshore operations, and potentially excess liability insurance given the current insurance market environment.

Competition

We face strong competition in acquiring new natural gas or crude oil supplies. Competition for natural gas and crude oil supplies is primarily based on the location of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, treating capabilities (as applicable), reliability and access to end-use markets or liquid marketing hubs. Competitors to our gathering and processing operations include other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. Our major competitors for natural gas supplies in our current Permian and Central operating regions include DCP Midstream Partners (“DCP”), Enable Midstream Partners, L.P., Energy Transfer ~~Equity~~, L.P. (“Energy Transfer”), Enlink Midstream, ~~Partners LP~~LLC, Enterprise Products Partners L.P. (“Enterprise”), Kinder Morgan, Inc. (“Kinder Morgan”), MPLX, ONEOK, Inc. (“ONEOK”), WTG Gas Processing, L.P, Western Midstream Partners, L.P., and several other pipeline companies. Our competitors for ~~crude~~the ~~oil~~ gathering ~~services~~and/or purchase and sale of crude oil in North Dakota include Crestwood Equity Partners LPL.P., Kinder Morgan, MPLX, ~~and~~Hess Midstream, L.P., Summit Midstream Partners, ~~LLC~~L.P., ~~Our~~Paradigm ~~competitors~~Energy ~~may~~Partners ~~have~~LLC, ~~greater~~and ~~financial~~Oasis ~~resources~~Midstream ~~than~~Partners ~~we possess~~L.P.

We also compete for NGL supplies for Grand Prix. Competition for NGL supplies is primarily based on the ~~location~~proximity of gathering and processing facilities ~~and~~in relation to one or more NGL pipelines, their connectivity to NGL pipeline takeaway options, access to end-use markets or liquid marketing hubs, pricing and contractual arrangements, reputation, efficiency, flexibility, and reliability. Competitors to our NGL pipeline include other midstream providers with NGL transportation capabilities, such as major interstate and intrastate pipeline companies, master limited partnerships and midstream natural gas and NGL companies. Our major competitors for NGL supplies in our current operating regions include DCP, Energy Transfer, Enterprise, ONEOK and ~~ONEOK~~EPIC Midstream Holdings, L.P.

Additionally, we face competition for mixed NGLs supplies at our fractionation facilities. ~~Our competitors include large oil, natural gas and petrochemical companies.~~ 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. Among the primary competitors are Enterprise, ~~LoneStar~~Energy ~~NGL~~Transfer ~~LLC (“LoneStar”)~~ and ONEOK. 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. Our primary competitors in providing export services to our customers are Enterprise, LoneStar and Phillips 66.

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, including BP p.l.c., DCP, Energy Transfer, Enterprise and ONEOK.

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.

We do not have any employees. To carry out our operations, Targa employed approximately 2,372 people as of December 31, 2020, that primarily support our operations. None of these employees are covered by collective bargaining agreements, and Targa considers its employee relations to be good.

Employee Health and Safety

Safety is a core value of ours and begins with the protection and safety of our employees, contractors and communities where we operate. We value people above all else and remain committed to making safety and health our top priority. We believe that “Zero is Achievable”, and our goal is to operate and deliver our products without any injuries. We continually seek to maintain and deepen our safety culture by providing a safe working environment that encourages active employee engagement, including implementing safety programs to achieve improvements in our safety culture.

To protect our employees, contractors, and surrounding community from workplace hazards and risks, we implement and maintain an integrated system of policies, practices, and controls, including requirements to complete regular detailed safety and regulatory compliance training for all applicable individuals.

In response to the ongoing COVID-19 pandemic, we moved early and quickly to protect the health and safety of our employees and are continuing to proactively manage our response to an evolving national and global situation. We took several strategic and proactive measures in response to information from the Centers for Disease Control and the local, state and national authorities to try to minimize the risk of business disruption and to protect our ability to deliver reliable services to our customers. Some of these actions include forming a COVID-19 task force of senior management to collaborate, review and execute our business response to the pandemic by instituting various safety protocols including tracking and managing the impact of COVID-19 positive employees and COVID-19 exposed employees, providing and requiring personal protective equipment at all facility locations, social distancing practices, work place build-out modifications, routine cleaning protocols at all facility locations to reduce virus contagion risk, protecting our workforce by providing our non-field employees with technology and equipment to perform their work duties remotely, where applicable, and implementing plans for safely returning to our offices over time.

Diversity and Inclusion

We are committed to fostering a work environment in which all employees treat each other with dignity and respect. This commitment extends to providing equal employment and advancement opportunities based on merit and experience. We believe this to be a fundamental principle and is defined in our Equal Employment Opportunity Policy and our Code of Conduct. We continually strive to attract a diverse workforce by partnering with local organizations to identify potential candidates to advance and strengthen our human capital management program.

Our employee demographic profile allows us to promote inclusion of thought, skill, knowledge, and culture across our operations to attract and maintain a high-quality workforce.

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. 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 plans, which are 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 ~~Pipeline~~and Processing Regulation

Our natural gas gathering operations are typically subject to open access ratable take and/or common purchaser statutes (and implementing rules) in the states in which we operate. The common purchaser statutes generally require gathering pipelines to purchase or take without undue discrimination, aswhile toopen ~~source~~access ofgathering ~~supply~~requirements orgenerally ~~producer.~~give ~~These~~producers ~~statutes~~access ~~are~~to ~~designed~~gathering toservices ~~prohibit~~on ~~discrimination~~terms inthat ~~favor~~are ofnot unduly discriminatory. In one ~~producer~~instance, ~~over~~the ~~another~~governing orlaw ~~one~~prohibits ~~source~~undue ofdiscrimination ~~supply~~with ~~over~~respect ~~another~~to purchase or processing of natural gas. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering and processing facilities to decide with whom (and on what terms) we contract to gather or process natural gas with similarly situated customers (subject, in each case, to the limitations and requirements of each jurisdiction). The states in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to ~~gathering~~ access and rate discrimination. ~~The rates we charge for gathering are deemed just and reasonable unless challenged in a complaint.~~ We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and, 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, including the gas gathering systems that are part of the Badlands and of the Pelican and Seahawk gathering systems, meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to Order No. 704. See “—Regulation of Operations—FERC Market Transparency Rules.”22

21Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to Order No. 704. See “—Regulation of Operations—FERC Market Transparency Rules.”

~~Natural~~Our ~~Gas~~natural ~~Processing~~gas gathering and processing operations are not presently subject to FERC regulation. However, since May 2009, we have been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERC Market Transparency Rules.”

Our natural gas gathering and processing operations are not presently subject to FERC regulation. However, since May 2009, we have been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERC Market Transparency Rules.” There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.

Sales of Natural Gas, NGLs and Crude Oil

The price at which we buy and sell natural gas, NGLs and crude oil is currently not subject to federal rate regulation and, for the most part, is not subject to state rate regulation. However, with regard to our physical purchases and sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See “—Regulation of Operations—EP Act of 2005.” Since May 2009, we have been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERC Market Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

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 ~~just~~approximately ~~over~~ ten miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. We have obtained a ~~waiver~~certificate ~~from FERC~~ of ~~the~~public ~~requirements~~convenience ~~pertaining to the filing of an initial rate for service, the filing of a tariff~~ and ~~compliance~~necessity ~~with~~from ~~specified accounting and reporting requirements for the Driver Residue Pipeline. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirements~~ FERC ~~imposes~~waiving oncertain ~~“open~~of ~~access” interstate natural gas pipelines; to~~ the ~~obligation~~Commission’s ~~to file and maintain a~~ tariff; ~~or to the obligation to conform to certain business practices~~ and torate ~~file certain reports~~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”), ~~has~~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”). ~~More~~Targa ~~specifically,~~Gulf Coast leases from Targa NGL ~~owns~~certain anpipelines ~~eight-inch~~that ~~diameter~~run ~~pipeline,~~between aMont ~~20-inch~~Belvieu, ~~diameter pipeline~~Texas, and aGalena ~~12-inch~~Park, ~~diameter~~Texas ~~pipeline~~and ~~that run~~ between Mont Belvieu, Texas, and ~~Galena~~Lake ~~Park~~Charles, ~~Texas~~Louisiana. Each of these pipelines is ~~regulated under the ICA and is~~ part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers.

~~Additionally,~~In in 2019, Targa NGL began operating portions of Grand Prix that transports NGLs from Oklahoma to Mont Belvieu, Texas. On July 27, 2018, Targa NGL submitted a petition for declaratory order to FERC on a proposed rate structure and terms of service for such portions of Grand Prix. The Commission granted Targa NGL’s petition for declaratory order subject to certain conditions on March 11, 2019. Targa NGL requested rehearing on April 10, 2019, which is pending at FERC. On August 6, 2020, Targa NGL submitted a petition for declaratory order to FERC on a proposed rate structure and terms of service related to the Central Oklahoma Extension of Grand Prix, and on October 1, 2020, FERC issued an order granting Targa NGL’s petition in full. Additionally, Grand Prix entered full service during the third quarter of 2019, providing transportation for mixed NGLs from the Permian Basin, including points in New Mexico, to Mont Belvieu, Texas.

~~Additionally,~~Unless ~~Grand~~covered ~~Prix~~by ~~entered~~a ~~full~~waiver, ~~service~~as ~~during~~described below, the ~~third~~ICA ~~quarter~~requires that we maintain tariffs on file with FERC for interstate movements of ~~2019,~~liquids on our pipelines. Those tariffs set forth the rates we charge for providing transportation ~~for~~services ~~mixed~~as ~~NGLs~~well ~~from~~as the ~~Permian~~rules ~~Basin,~~and ~~including~~regulations ~~points~~governing inthese ~~New~~services. ~~Mexico~~The ICA requires, toamong ~~Mont~~other ~~Belvieu~~things, ~~Texas~~that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory.

~~The~~Targa ~~ICA~~has ~~requires~~multiple ~~that~~NGL wepipelines ~~maintain~~that ~~tariffs~~have onqualified ~~file with FERC~~ for ~~each~~a waiver of ~~these~~applicable ~~pipelines~~FERC ~~described~~regulatory ~~above.~~requirements ~~Those~~under ~~tariffs set forth~~ the ~~rates~~ICA webased ~~charge~~on ~~for~~current ~~providing~~circumstances. ~~transportation~~Additionally, ~~services as well as~~ the ~~rules~~crude ~~and~~oil ~~regulations~~pipeline ~~governing~~system ~~these services. The ICA requires, among other things,~~ that ~~rates~~is onpart ~~interstate~~of ~~common~~the ~~carrier~~Badlands ~~pipelines~~assets bealso ~~“just~~qualifies ~~and~~for ~~reasonable”~~such ~~and~~a ~~non-discriminatory~~waiver.

Targa NGL also owns a twenty-inch diameter pipeline that runs between Mont Belvieu, Texas, and Galena Park, Texas and a twelve-inch diameter pipeline that runs between Mont Belvieu, Texas and Lake Charles, Louisiana, each of which transport NGLs and that have qualified for a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. Additionally, the crude oil pipeline system that is part of the Badlands assets also qualifies for such a waiver. 23

All such waivers are subject to revocation, however, should a particular pipeline’s circumstances change. FERC could, either at the request of other entities or on its own initiative, assert that some or all of these pipelines no longer qualify for a waiver. In the event that FERC were to determine that one more of these pipelines no longer qualified for waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s) and delivery point(s), provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination.

Many existing pipelines, including Grand Prix and some of Targa NGL’s pipelines, may utilize the FERC oil pipeline indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index. FERC’s indexing methodology is subject to review every five years. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating, among other things, that with respect to oil and refined products pipelines subject to FERC jurisdiction, the impacts of the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the costs of FERC-regulated oil and NGL pipelines will be reflected in FERC’s next five-year review of the oil pipeline index, which will generate the index level to be effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act of 2017 may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates.

Tribal Lands

Our intrastate natural gas pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencies within the U.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”), Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. Please see “Other State and Local Regulation of Operations” below.

Intrastate Natural Gas

Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may be subject to certain FERC-imposed reporting requirements depending on the volume of natural gas purchased or sold in a given year. See “—Regulation of Operations—FERC Market Transparency Rules.”

Our intrastate pipelines located in Texas are regulated by the Railroad Commission of Texas (the “RRC”). ~~Our~~and ~~Texas~~are ~~intrastate~~required ~~pipeline,~~to ~~Targa~~have ~~Intrastate~~tariffs ~~Pipeline~~on ~~LLC~~file ~~(“Targa~~with ~~Intrastate”),~~the ~~owns~~RRC. ~~the~~Some of these Texas intrastate ~~pipeline~~pipelines ~~that~~also ~~transports~~transport natural gas ~~from~~in ~~our~~interstate ~~Shackelford~~commerce ~~processing~~pursuant ~~plant~~ to anSection ~~interconnect~~311 ~~with~~of ~~Atmos Pipeline-Texas that in turn delivers gas to~~ the ~~West~~Natural ~~Texas~~Gas ~~Utilities~~Policy ~~Company’s~~Act ~~Paint~~of ~~Creek~~1978 ~~Power Station~~(“NGPA”). ~~Targa~~Under ~~Intrastate~~Sections ~~also~~311 ~~owns~~and a601 ~~1.65-mile,~~of ~~ten-inch~~the ~~diameter~~NGPA, an intrastate pipeline ~~that~~may ~~transports~~transport natural gas ~~from~~in ainterstate ~~third-party~~commerce ~~gathering~~without ~~system~~becoming ~~into~~subject ~~the~~to ~~Chico~~FERC ~~system~~regulation inas ~~Denton County, Texas. Targa Intrastate is~~ a “natural-gas ~~utility~~company” ~~subject~~under ~~to regulation by~~ the ~~RRC~~NGA, ~~and~~but ~~has~~must ~~a tariff on~~ file ~~with~~the ~~such~~terms ~~agency.~~and ~~Our~~conditions ~~other~~of ~~Texas~~transportation ~~intrastate~~of ~~pipeline,~~natural ~~Targa~~gas ~~Gas~~under ~~Pipeline~~authority ~~LLC,~~of ~~owns~~Section a311 ~~multi-county~~with ~~intrastate~~FERC, ~~pipeline~~and ~~that~~these ~~transports~~terms ~~gas~~and inconditions ~~Crane,~~must ~~Ector,~~be ~~Midland,~~“fair and ~~Upton~~equitable.” ~~Counties~~Specifically, ~~Texas,~~TPL asSouthTex ~~well~~Transmission asCompany ~~some~~LP ~~lines~~(“TPL inSouthTex ~~North~~Transmission”) ~~Texas.~~and Targa Midland Gas Pipeline LLC is(“Targa aMidland”) ~~gas~~provide ~~utility~~NGPA ~~subject~~Section to311 ~~regulation by the RRC and has a tariff on file with such agency~~service.

Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC, owns an approximately 60-mile intrastate pipeline system that receives all of the natural gas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and ~~since~~ the ~~pipeline’s~~ 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”)~~, the pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from most FERC regulation~~.

We ~~have~~also anoperate ~~ownership interest of 50% of the capacity in a 50-mile long intrastate~~ natural gas ~~transmission~~pipelines ~~pipeline,~~that ~~which~~extend ~~extends~~ from the tailgate of ~~three~~our ~~natural gas~~ processing plants ~~located near Pettus, Texas~~ to interconnections with ~~existing~~both intrastate and interstate natural gas pipelines. ~~near~~We ~~Refugio,~~believe ~~Texas.~~these ~~The~~pipelines ~~capacity~~are isexempt ~~held~~from byFERC’s ~~our~~jurisdiction ~~subsidiary,~~under ~~TPL~~the ~~SouthTex~~Natural ~~Transmission~~Gas ~~Company~~Act LPunder ~~(“TPL~~FERC’s ~~SouthTex Transmission~~“stub”), ~~which~~line isexemption. ~~entitled~~Texas toand ~~transport~~Louisiana ~~natural~~have ~~gas~~adopted ~~through~~complaint-based ~~its~~regulation ~~capacity on behalf~~ of ~~third parties to both~~ intrastate ~~and~~natural ~~interstate~~gas ~~markets.~~transportation ~~Because~~activities, ~~the~~which ~~jointly~~allows ~~owned~~natural ~~pipeline~~gas ~~system~~producers ~~was~~and ~~initially~~shippers ~~interconnected~~to ~~only~~file complaints with ~~intrastate~~state ~~markets,~~regulators ~~each~~in ~~of the capacity holders qualified as~~ an ~~“intrastate~~effort ~~pipeline” within the meaning of the Natural Gas Policy Act of 1978 (“NGPA”) and therefore is able~~ to ~~provide~~resolve ~~transportation~~grievances ofrelating ~~natural gas~~ to ~~interstate~~pipeline ~~markets~~access ~~under~~and ~~Section~~rate ~~311 of the NGPA~~discrimination. ~~Under~~The ~~Sections~~rates ~~311~~we ~~and~~charge ~~601~~for ofintrastate ~~the~~transportation ~~NGPA,~~are andeemed ~~intrastate~~just ~~pipeline~~and ~~may~~reasonable ~~transport~~unless ~~natural~~challenged ~~gas~~ in ~~interstate commerce without becoming subject to FERC regulation as~~ a ~~“natural-gas company” under the NGA~~complaint. ~~Transportation~~A ofcomplaint ~~natural~~also ~~gas~~can ~~under authority of Section 311 must~~ be filed with FERC ~~and~~regarding ~~must~~the berates, ~~shown~~terms, ~~to be “fair~~ and ~~equitable.”~~conditions ~~TPL SouthTex Transmission has a Statement~~ of ~~Operating~~service ~~Conditions~~ on ~~file~~our ~~with~~pipelines ~~FERC.~~providing ~~TPL~~service ~~SouthTex~~pursuant ~~Transmission has existing rates applicable~~ to ~~NGPA~~ Section 311 ~~service.~~of ~~The~~the ~~GCX~~NGPA. ~~Pipeline,~~We ~~which~~cannot ~~went~~predict ~~into~~whether ~~service~~such ina ~~late~~complaint ~~third~~will ~~quarter~~be ~~2019,~~filed ~~transports~~against ~~natural~~us ~~gas~~in ~~from~~ the ~~Permian~~future. ~~and~~Failure ~~Midland Basin~~ to ~~markets~~comply onwith ~~the~~state ~~Texas~~or ~~Gulf~~FERC ~~Coast.~~regulations ~~GCX~~can isresult ~~subject~~in ~~to regulation by~~ the ~~RRC~~imposition ~~and under Section 311~~ of ~~the~~administrative, ~~NGPA~~civil and, oncriminal ~~October 25, 2019, petitioned for rate approval, requesting an effective date of September 25, 2019~~penalties.

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. Although these “plant tailgate” pipelines may operate at transmission pressure levels and may transport “pipeline quality” natural gas, we believe they are generally exempt from FERC’s jurisdiction under the Natural Gas Act under FERC’s “stub” line exemption. However, Targa Midland Gas Pipeline LLC (“Targa Midland”) operates our Tarzan plant residue gas pipeline, which provides NGPA Section 311 service and falls outside of the “stub” line exemption. Targa Midland maintains a Statement of Operating Conditions on file with FERC.

FERC issued Order No. 849 on July 18, 2018, which became effective September 13, 2018, establishing new regulations that, among other things, require pipelines providing NGPA Section 311 service to file a new rate election for its interstate rates if the intrastate pipeline’s rates on file with the state regulatory agency are reduced to reflect the reduced income tax rates adopted in the Tax Cuts and Jobs Act. If an NGPA Section 311 pipeline’s interstate service rates are established pursuant to a rate filing with FERC, the pipeline is exempt from filing a new rate election if FERC has approved the interstate rates after December 22, 2017, or the pipeline has a pending rate petition at FERC on the effective date of the reduced intrastate rates. Any such petitions may reduce the rates we are permitted to charge for NGPA Section 311 service.

Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge for intrastate transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

Intrastate Liquids

Our intrastate NGL pipelines in Texas transport mixed and purity NGL streams between Targa’s Mont Belvieu and Galena Park, Texas facilities. Grand Prix went into service during the third quarter of 2019, and provides transportation of mixed NGLs from the Permian Basin to Mont Belvieu, Texas. Further, we operate crude gathering pipelines in the Permian Basin. With respect to intrastate movements, these pipelines are not subject to FERC regulation, but are subject to rate regulation by the RRC. ~~They are also subject to U.S. Department of Transportation (“DOT”) safety regulations.~~

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 Pipeline, LLC, 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~~, but are subject to DOT safety regulations~~. On May 9, 2019, the Louisiana Public Service Commission (“LPSC”) approved applications to register certain pipelines of Cayenne Pipeline, LLC and Targa Downstream LLC in accordance with the LPSC 2015 General Order, Docket No. R-33390.

Other Federal Laws and Regulations Affecting Our Industry

EP Act of 2005

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to a maximum amount that is adjusted annually for inflation, which for 2021 equals approximately $1.293 million per violation per day, ~~adjusted annually~~ for ~~inflation, for~~ violations of the NGA and approximately $1.293 million per violation per day, ~~adjusted annually~~ for ~~inflation, for~~ violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce as well as entities that are otherwise subject to the NGA or NGPA. In 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (Order No. 704), and the quarterly reporting requirement under Order No. 735. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

FERC Market Transparency Rules

Beginning in 2007, FERC has issued a number of rules intended to provide for greater marketing transparency in the natural gas industry, including Order Nos. 704, 720, and 735. Under Order No. 704, wholesale buyers and sellers of more than 2.2 Bcf of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.

Under Order No. 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, are required to post on a daily basis certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu/d and interstate pipelines are required to post information regarding the provision of no-notice service. In October 2011, Order No. 720 as clarified was vacated by the Court of Appeals for the Fifth Circuit. We take the position that, at this time, all of our entities are exempt from Order No. 720 as currently effective.

Under Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA are required to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 also extends FERC’s periodic review of the rates charged by the subject pipelines from three years to five years. On rehearing, FERC reaffirmed Order No. 735 with some modifications. As currently written, this rule does not apply to our Hinshaw pipelines.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.

Other State and Local Regulation of Operations

Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including operations, marketing, production, pricing, community right-to-know, protection of the environment, safety, marine traffic and other matters. In addition, the Three Affiliated Tribes promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business, see “Risk Factors—Risks Related to Our Business.”

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 selling NGLs and NGL products, including services to LPG exporters; and (iii) gathering, storing, terminaling and ~~selling~~purchasing ~~crude oil;~~ and ~~(iv) storing, terminaling and~~ selling ~~refined~~crude ~~petroleum~~oil ~~products~~ 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, disposers and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

•

the Resource Conservation and Recovery Act ("RCRA"), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

•

the Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities, pipelines and other facilities, as well as lessees or permittees of areas in which offshore facilities are located, that are the site of an oil spill in waters of the United States, to liability for removal costs and damages;

•

the Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;

•

the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;

•

the National Environmental Policy Act (NEPA), 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 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.

WeThese ~~own,~~environmental ~~lease,~~and oroccupational ~~operate~~health ~~numerous~~and ~~properties~~safety laws and regulations generally restrict the level of substances generated as a result of our operations that ~~have~~may ~~been~~be ~~used~~emitted ~~for~~to ~~crude~~ambient ~~oil~~air, discharged to surface water, and ~~natural~~disposed ~~gas~~or ~~midstream~~released ~~services~~to ~~for~~surface ~~many~~and ~~years~~below-ground soils and ground water. Additionally, ~~some~~there ofexist ~~our~~tribal, ~~properties~~state ~~have~~and ~~been~~local ~~operated~~jurisdictions byin ~~third~~the ~~parties~~United orStates bywhere ~~previous~~we ~~owners~~operate that also have, or ~~operators~~are ~~whose~~developing ~~treatment~~or considering developing, similar environmental and ~~disposal~~occupational ofhealth ~~hazardous~~and ~~substances,~~safety ~~wastes,~~laws orand ~~petroleum~~regulations ~~hydrocarbons~~governing ~~was~~many ~~not~~of ~~under~~these ~~our~~same ~~control~~types of activities. ~~Under~~ ~~environmental~~Any ~~laws~~failure ~~such~~by asus ~~CERCLA~~to comply with these laws and ~~RCRA,~~regulations wemay ~~could~~result ~~incur~~in ~~strict~~the ~~joint~~assessment of sanctions, including administrative, civil, and ~~several~~criminal ~~liability~~penalties; ~~for~~the ~~remediating~~imposition ~~hydrocarbons~~of investigatory, ~~hazardous~~remedial, ~~substances~~and corrective action obligations or ~~wastes~~the ~~disposed~~incurrence of orcapital ~~released~~expenditures; bythe usoccurrence orof ~~prior~~restrictions, ~~owners~~delays or ~~operators.~~cancellations Wein ~~also~~the ~~could~~permitting, ~~incur~~development ~~costs~~or ~~related~~expansion toof projects; and the ~~clean-up~~issuance of ~~third-party~~injunctions ~~sites~~restricting toor ~~which~~prohibiting wesome ~~sent~~or ~~regulated~~all ~~substances~~of ~~for~~our ~~disposal~~activities orin toa ~~which~~particular wearea. ~~sent~~Certain ~~equipment~~environmental laws also provide for ~~cleaning~~citizen suits, ~~and~~which ~~for~~allow ~~damages~~individuals or organizations to ~~natural~~act ~~resources~~in orplace ~~other~~of ~~claims~~the ~~related~~government toand ~~releases~~sue operators for alleged violations of ~~regulated~~environmental ~~substances~~law. atThe orultimate financial impact arising from ~~such~~environmental ~~third-party~~laws ~~sites~~and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.

~~Over~~We ~~time~~own, ~~the~~lease, ~~trend~~or inoperate ~~environmental~~numerous ~~and~~properties ~~occupational~~that ~~health~~have ~~and~~been ~~safety~~used ~~regulation~~for iscrude tooil ~~typically place more restrictions~~ and ~~limitations~~natural ongas ~~activities~~midstream ~~that~~services ~~may~~for ~~adversely~~many ~~affect~~years. ~~the~~Additionally, ~~environment~~some orof ~~expose~~our ~~workers~~properties tohave ~~injury~~been ~~and~~operated ~~thus,~~by ~~any~~third ~~changes~~parties ~~in environmental~~ or ~~occupational~~by ~~health~~previous ~~and~~owners ~~safety laws and regulations~~ or ~~reinterpretation~~operators ofwhose ~~enforcement~~treatment ~~policies that may arise in the future~~ and ~~result~~disposal inof ~~more~~hazardous ~~stringent or costly waste management or disposal~~substances, ~~pollution control~~wastes, ~~remediation~~ or ~~occupational~~petroleum ~~health~~hydrocarbons ~~and~~was ~~safety-related~~not ~~requirements~~under ~~could have a material adverse effect on~~ our ~~business, results of operations and financial position~~control. WeUnder ~~may~~environmental ~~not~~laws ~~have~~such ~~insurance~~as orCERCLA ~~be fully covered by insurance against all environmental~~ and ~~occupational health and safety risks~~RCRA, ~~and~~ we ~~may~~could beincur ~~unable~~strict tojoint ~~pass~~and onseveral ~~increased~~liability ~~compliance~~due ~~costs~~to ~~arising~~damages ~~out of such risks~~ to ~~our~~natural ~~customers.~~resources ~~We review regulatory and environmental issues~~ as ~~they~~well ~~pertain to us and we consider regulatory and environmental issues~~ as ~~part~~for ofremediating ~~our general risk management approach. For more information on environmental and occupational health and safety matters~~hydrocarbons, ~~see~~hazardous ~~the~~substances ~~following~~or ~~Risk~~wastes ~~Factors~~disposed ~~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 anreleased ~~accidental~~by ~~release into the environment may cause~~ us toor ~~incur~~prior ~~significant~~owners ~~costs~~or ~~and~~operators. ~~liabilities,” “~~We also could incur ~~significant~~ costs inrelated ~~complying~~to ~~with~~the ~~stringent~~clean-up ~~occupational~~of ~~safety~~third-party ~~and~~sites ~~health~~to ~~requirements,”~~which ~~“Laws~~we ~~and~~sent ~~regulations~~regulated ~~regarding~~substances ~~hydraulic~~for ~~fracturing~~disposal ~~could result in restrictions, delays~~ or ~~cancellations~~to inwhich ~~drilling~~we ~~and~~sent ~~completing~~equipment ~~new~~for ~~oil~~cleaning, and ~~natural~~for ~~gas~~damages ~~wells~~to ~~by our customers, which could adversely impact our revenues by decreasing the volumes of~~ natural ~~gas,~~resources ~~NGLs~~ or ~~crude~~other ~~oil~~claims ~~through~~related ~~our facilities and reducing the utilization of our assets,” and “Our and our customers’ operations are subject~~ to areleases ~~series~~ of ~~risks~~regulated ~~arising~~substances ~~out~~at ~~of the threat of climate change (including legislation~~ or ~~regulation~~from tosuch ~~address~~third-party ~~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~~sites.”

~~Pipeline~~Over ~~Safety~~time, ~~Matters~~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 more 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,” and “Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change (including legislation or regulation to address climate change) that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.”

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 DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline design, maximum operating pressures, pipeline patrols and leak surveys, public awareness, operation and maintenance procedures, operator qualification, minimum depth requirements and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCAs”) and moderate consequence areas (“MCAs”) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas pipelines are predicated on high-population areas (which, for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crude oil, NGL and condensate pipelines is based on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA is attributable to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. 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. 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.

Pipeline Safety Matters

Many of our natural gas, NGL and crude oil pipelines are subject to regulation by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency of the U.S. Department of Transportation (“DOT”), under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline design, maximum operating pressures, pipeline patrols and leak surveys, public awareness, operation and maintenance procedures, operator qualification, minimum depth requirements and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCAs”) and moderate consequence areas (“MCAs”) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas, crude oil, NGL and condensate pipelines impose increasing safety-related requirements as the population density or ecological sensitivity increases. An MCA is defined in relation to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. Various states have also adopted regulations, similar to existing PHMSA regulations for, and may have established agencies analogous to PHMSA to regulate, intrastate gathering and transmission lines. 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.

Employees

We do not have any employees. To carry out our operations, Targa employs approximately 2,680 people who primarily support our operations. None of those employees are covered by collective bargaining agreements. Targa considers its employee relations to be good.

Financial Information by Reportable Segment

See “Segment Information” included under Note 2523 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.

Item 1A. Risk Factors.

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. 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.

We have a substantial amount of indebtedness which may adversely affect our financial position.

We have a substantial amount of indebtedness. As of December 31, 2019, we had $6,973.6 million outstanding of our senior unsecured notes and $54.6 million of outstanding senior notes of TPL, excluding $0.3 million of unamortized net discounts and premiums. We also had $370.0 million outstanding under our Securitization Facility. In addition, we had $88.2 million of letters of credit outstanding and $2,111.8 million of additional borrowing capacity available under the TRP Revolver. Our $2.2 billion TRP Revolver allows us to request increases in commitments up to an additional $500 million. For the years ended December 31, 2019, 2018 and 2017, our consolidated interest expense, net was $320.8 million, $170.0 million and $217.8 million.

In November 2019, we issued $1.0 billion of 5½% Senior Notes due March 2030, resulting in total net proceeds of approximately $990.8 million. The net proceeds from the issuance were used to repay borrowings under our credit facilities and for general partnership purposes.

This substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;

•Item we1A. ~~will~~Risk ~~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;~~Factors.

•The nature of our ~~debt~~business ~~level~~activities ~~may~~subjects ~~influence~~us ~~how~~to ~~counterparties~~certain ~~view~~hazards ~~our~~and ~~creditworthiness,~~risks. ~~which~~You ~~could~~should ~~limit~~consider ~~our~~carefully ~~ability~~the tofollowing ~~enter~~risk ~~into~~factors ~~commercial~~together ~~transactions~~with atall ~~favorable~~the ~~rates~~other orinformation ~~require~~contained usin this report. If any of the following risks were to ~~post~~occur, ~~additional~~then ~~collateral~~our inbusiness, ~~commercial~~financial ~~transactions;~~condition, cash flows and results of operations could be materially adversely affected.

•Summary ~~our~~Risk ~~debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and~~Factors

•Risks ~~our~~Related ~~debt level may limit flexibility in planning for, or responding~~ to, ~~changing~~our ~~business~~Results ~~and~~of ~~economic conditions.~~Operations

• Our ~~long-term~~cash ~~unsecured~~flow ~~debt~~ is ~~currently~~affected ~~rated~~ by ~~Standard~~supply ~~& Poor’s Corporation (“S&P”)~~ and ~~Moody’s~~demand ~~Investors~~for ~~Service,~~natural ~~Inc. (“Moody’s”). As of December 31~~gas, ~~2019,~~NGL ~~Targa’s~~products ~~senior~~and ~~unsecured~~crude ~~debt~~oil ~~was~~and ~~rated “BB”~~ by ~~S&P.~~natural ~~As of December 31~~gas, ~~2019~~NGL, ~~Targa’s~~crude ~~senior~~oil ~~unsecured~~and ~~debt~~condensate ~~was~~prices, ~~rated~~and ~~“Ba3”~~decreases ~~by Moody’s. Any future downgrades~~ in ~~our~~commodity ~~credit~~prices ~~ratings could negatively impact our cost of raising capital,~~ and/or aactivity ~~downgrade~~levels could ~~also~~ adversely affect our ~~ability~~results ~~to effectively execute aspects~~ of ~~our~~operations ~~strategy~~ and tofinancial ~~access capital in the public markets~~condition.

~~Our~~• ~~ability~~The towidespread ~~service~~outbreak ~~our~~of ~~debt~~pandemics ~~will~~(like ~~depend~~COVID-19) ~~upon,~~or ~~among~~any other ~~things,~~public ~~our~~health ~~future~~crisis ~~financial~~that ~~and~~impacts ~~operating~~the ~~performance,~~global ~~which~~demand ~~will~~for beenergy ~~affected~~commodities bymay ~~prevailing~~have ~~economic~~material ~~conditions~~adverse ~~and~~effects ~~financial,~~on ~~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~~, ~~acquisitions,~~financial ~~investments or capital expenditures~~position, ~~selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such~~ results ~~may adversely affect our ability to make cash distributions. We may not be able to affect any~~ of ~~these~~operations ~~actions on satisfactory terms,~~ and/or atcash ~~all~~flows.

~~Despite~~• ~~current~~A ~~indebtedness~~reduction ~~levels~~in demand for NGL products by the petrochemical, werefinery ~~may~~or ~~still~~other beindustries ~~able~~or toby ~~incur~~the ~~substantially~~fuel ~~more~~or ~~debt.~~export ~~This~~markets, ~~could~~or a significant increase ~~the~~in ~~risks~~NGL ~~associated~~product ~~with~~supply ~~compliance~~relative ~~with~~to this demand, could materially adversely affect our business, results of operations and financial ~~covenants~~condition.

We• ~~may~~The benatural ~~able~~decline toin ~~incur~~production ~~substantial additional indebtedness~~ in ~~the~~our ~~future.~~operating ~~The~~regions ~~TRP~~and ~~Revolver~~in ~~allows~~other usregions tofrom ~~request~~which ~~increases~~we insource ~~commitments~~NGL upsupplies tomeans anour ~~additional~~long-term ~~$500~~success ~~million.~~depends ~~Although~~on our ~~debt~~ability ~~agreements~~to ~~contain~~obtain ~~restrictions~~new onsources ~~the~~of ~~incurrence~~supplies of ~~additional~~natural ~~indebtedness~~gas, ~~these~~NGLs ~~restrictions~~and ~~are~~crude ~~subject~~oil, towhich adepends ~~number~~on ofcertain ~~significant~~factors ~~qualifications~~beyond ~~and~~our ~~exceptions,~~control. ~~and~~Any ~~any~~decrease ~~indebtedness incurred~~ in ~~compliance~~supplies ~~with~~of ~~these~~natural ~~restrictions~~gas, ~~could~~NGLs beor ~~substantial.~~crude Ifoil ~~we incur additional debt, this~~ could ~~increase~~adversely ~~the~~affect ~~risks~~our ~~associated~~business ~~with~~and ~~compliance~~operating ~~with our financial covenants~~results.

~~Increases~~• inOur ~~interest~~industry ~~rates~~is highly competitive and increased competitive pressure could adversely affect our business and operating results.

• We ~~have~~operate ~~significant exposure to increases~~ in ~~interest~~areas ~~rates. As~~ of ~~December~~high ~~31,~~industry ~~2019~~activity, ~~our total indebtedness was $7,436.2 million, excluding $0.3 million of net premiums and $49.1 million of net debt issuance costs, of~~ which ~~$7,028.2~~may ~~million~~affect ~~was at fixed interest rates, $370.0 million was at variable interest rates and $38.0 million of finance lease liabilities. A one percentage point increase in the interest rate on~~ our ~~variable~~ability ~~interest~~to ~~rate debt would have increased our consolidated annual interest expense by approximately $3.7 million based on our December 31~~hire, ~~2019~~train ~~debt~~or ~~balances.~~retain Asqualified apersonnel ~~result~~needed ofto ~~this~~manage ~~amount~~and ofoperate ~~variable interest rate debt,~~ our ~~results of operations could be adversely affected by increases in interest rates~~business.

~~The~~• ~~terms~~If ofthird-party ~~our~~pipelines ~~debt~~and ~~agreements~~other ~~may~~facilities ~~restrict~~interconnected to our ~~current~~natural gas and ~~future~~crude ~~operations~~oil gathering systems, ~~particularly~~terminals ~~our~~and ~~ability~~processing tofacilities ~~respond~~become partially or fully unavailable to ~~changes~~transport innatural ~~business~~gas, orNGLs toand ~~take~~crude ~~certain~~oil, ~~actions~~our revenues could be adversely affected.

~~The~~• ~~agreements~~We ~~governing~~typically ~~our~~do ~~outstanding~~not ~~indebtedness~~obtain ~~contain,~~independent ~~and~~evaluations ~~any~~of ~~future~~natural ~~indebtedness~~gas weor ~~incur~~crude ~~will~~oil ~~likely~~reserves ~~contain,~~dedicated ato ~~number~~our ofgathering ~~restrictive~~pipeline ~~covenants~~systems; ~~that impose significant operating and financial restrictions~~therefore, ~~including~~volumes ~~restrictions~~ on our ~~ability~~systems ~~to engage~~ in ~~acts~~the ~~that~~future ~~may~~could be inless ~~our~~than ~~best~~we ~~long-term interests~~anticipate. ~~These agreements include covenants that, among other things, restrict our ability to:~~

• ~~incur~~We ordo ~~guarantee~~not ~~additional~~own ~~indebtedness~~most orof ~~issue~~the ~~additional~~land ~~preferred~~on ~~units;~~which our pipelines, terminals and compression facilities are located, which could disrupt our operations.

• ~~pay~~If ~~distributions on~~ our ~~equity~~general ~~securities~~partner orloses toany ~~our~~of ~~equity~~its ~~holders~~named orexecutive ~~redeem~~officers, ~~repurchase or retire~~ our ~~equity~~business ~~securities~~may orbe ~~subordinated~~adversely ~~indebtedness;~~affected.

• ~~make~~Weather ~~investments~~may limit our ability to operate our business and ~~certain~~could ~~acquisitions;~~adversely affect our operating results.

• ~~sell~~Rising orsea ~~transfer~~levels, ~~assets~~subsidence and erosion could damage our pipelines and the facilities that serve our customers, ~~including~~particularly ~~equity~~along ~~securities~~the ofGulf Coast and offshore, which could adversely affect our ~~subsidiaries;~~business, results of operations and financial condition.

• ~~engage~~Our inbusiness ~~affiliate~~involves ~~transactions~~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.

• ~~consolidate~~Unexpected volume changes due to production variability or ~~merge;~~to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.

• ~~incur~~Portions ~~liens;~~of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, which expenditures or resulting loss of revenue due to pipeline age or condition could have a material adverse effect on our business and results of operations.

•

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East, other sustained military campaigns and civil unrest in the United States may adversely impact our results of operations.

•

We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.

•

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Risks Related to our Capital Projects and Future Growth

•

Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

•

If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations. 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.

• ~~prepay,~~Our ~~redeem~~growth and ~~repurchase~~acquisition ~~certain~~strategy ~~debt,~~requires ~~subject~~access to ~~certain~~new ~~exceptions;~~capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow through growth projects or acquisitions.

• ~~enter~~We ~~into~~may ~~sale~~be ~~and~~unable ~~lease~~to cause our majority-~~back~~owned ~~transactions~~joint ventures to take or not to take- certain actions unless some or~~-pay~~ ~~contracts;~~all of our joint venture participants agree and certain of our joint venture partners may fail or refuse to fund their respective portions of capital projects that we believe are necessary to expand or maintain such joint venture’s business.

•Risks ~~change~~Related ~~business~~to ~~activities~~our ~~conducted~~Financial ~~by us.~~Condition

In• ~~addition,~~If ~~certain~~we offail ~~our debt agreements require us~~ to ~~satisfy and~~ maintain ~~specified~~an ~~financial~~effective ~~ratios~~system ~~and~~of ~~other~~internal ~~financial~~controls, ~~condition~~we ~~tests.~~may ~~Our~~not ~~ability~~be able to ~~meet~~accurately ~~those~~report our financial ~~ratios~~results ~~and~~or ~~tests~~prevent ~~can~~fraud. beIn ~~affected~~addition, bypotential ~~events~~changes ~~beyond~~in ~~our~~accounting ~~control,~~standards ~~and~~might wecause ~~cannot~~us ~~assure~~to ~~you~~revise ~~that~~our wefinancial ~~will~~results ~~meet~~and ~~those~~disclosure ~~ratios~~in ~~and~~the ~~tests~~future.

A• ~~breach~~We ofare ~~any~~exposed 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~~risks be terminated. For example, if we are unable to repay the accelerated debt under the TRP Revolver, the lenders under the TRP Revolver could proceed against the collateral granted to them to secure that indebtedness. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the assets and equity of ~~certain of~~ our ~~subsidiaries~~customers, ~~as collateral under the TRP Revolver~~ and ~~the~~any ~~accounts~~material ~~receivables~~nonpayment ofor ~~Targa~~nonperformance ~~Receivables~~by ~~LLC under the Securitization Facility. If the indebtedness under~~ our ~~debt~~key ~~agreements~~customers iscould 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~~cash toflow ~~finance~~and ~~future~~results ~~operations~~of ~~or capital needs or to engage in other business activities~~operations.

~~Our~~• ~~cash~~Changes ~~flow~~in isfuture ~~affected~~business byconditions ~~supply~~could ~~and~~have ~~demand~~a ~~for~~negative ~~natural~~impact ~~gas,~~on ~~NGL~~the ~~products~~demand ~~and~~for ~~crude~~our ~~oil~~services and bycould ~~natural~~cause ~~gas,~~recorded ~~NGL,~~long-lived ~~crude~~assets ~~oil~~to ~~and~~become ~~condensate~~further ~~prices~~impaired, and ~~decreases~~our infinancial ~~these~~condition ~~prices~~and results of operations could ~~adversely~~suffer ~~affect~~if ~~our~~there ~~results~~is ofa ~~operations~~negative impact on the demand for our services and ~~financial~~an ~~condition~~additional impairment of long-lived assets.

• Our ~~operations~~hedging ~~can~~activities bemay ~~affected~~not bybe ~~the~~effective ~~level~~in ofreducing ~~natural gas, NGL and crude oil prices and~~ the ~~relationship~~variability ~~between these prices. The prices~~ of ~~crude~~our ~~oil,~~cash ~~natural~~flows ~~gas~~ and ~~NGLs~~may, ~~have~~in ~~been~~certain ~~volatile~~circumstances, ~~and~~increase wethe ~~expect~~variability ~~this~~of ~~volatility~~our tocash ~~continue~~flows. ~~Our~~Moreover, ~~future~~our ~~cash~~hedges ~~flow~~ may benot ~~materially~~fully ~~adversely~~protect ~~affected~~us ifagainst wevolatility ~~experience~~in ~~significant,~~basis ~~prolonged price deterioration~~differentials. ~~The markets and prices for crude oil~~Finally, ~~natural~~the ~~gas~~percentage ~~and~~of ~~NGLs depend upon factors beyond~~ our ~~control.~~expected ~~These~~equity ~~factors~~commodity ~~include~~volumes ~~supply~~that ~~and~~are ~~demand~~hedged ~~for~~decreases ~~these~~substantially ~~commodities,~~over ~~which fluctuates with changes in market and economic conditions, and other factors, including:~~time.

•

If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.

Risks Related to our Indebtedness

•

Increases in interest rates could adversely affect 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.

•

The credit and business risk profile of our general partner could adversely affect our credit ratings and profile.

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 (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.

•

Increasing attention to environmental, social and governance (ESG) matters may impact our business.

•

We could incur significant costs in complying with more 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 operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the environment may cause us to incur significant costs and liabilities.

•

A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects.

•

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more rigorous enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

•

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Risks Related to our Results of Operations

Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in commodity prices and/or activity levels could adversely affect our results of operations and financial condition.

Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The prices of natural gas, NGLs and crude oil have been volatile, and we expect this volatility to continue. Our future cash flows may be materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:

•

the impact of seasonality and weather;

•

general economic conditions and economic conditions impacting our primary markets;

•

the economic conditions of our customers;

•

the level of domestic crude oil and natural gas production and consumption;

•

the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;

• actions taken by major foreign oil and gas producing nations;

•

the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;

•

the availability of domestic storage for crude oil;

•

the availability and marketing of competitive fuels and/or feedstocks;

•

the impact of energy conservation efforts;

• stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil and natural gas; and

• the extent and nature of governmental regulation and taxation, including those related to the prorationing of oil and gas production.

Additionally, we have been and may continue to be adversely affected by the continued impact on global demand for energy commodities related to the COVID-19 pandemic. The COVID-19 pandemic has reduced economic activity and the related demand for energy commodities. These effects, combined with a period of increased production from major oil producing nations and decreasing availability of crude oil storage, have contributed to lower commodity prices compared to historical levels and are expected to continue to impact demand over the short-to-medium-term.

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.”

Changes in future business conditions could cause recorded long-lived assets to become further impaired, and our financial condition and results of operations could suffer if there is an additional impairment of property, plant and equipment 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, have declined substantially as compared to the peak of pricing in mid-2014 and 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. Any additional impairment charges that we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of long-lived assets. For a further discussion of our asset impairments, see Note 6 — Property, Plant and Equipment and Intangible Assets of the “Consolidated Financial Statements” included in this Annual Report.

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. Financial problems experienced by our customers could result in the impairment of our 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 make distributions to our unitholders.

Because of the natural decline in production in our operating regions and in other regions from which we source NGL supplies, 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 process, NGL products delivered to our fractionation facilities or crude oil that we gather. 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~~The inwidespread ~~energy~~outbreak ~~prices~~pandemics ~~can~~(like ~~greatly~~COVID-19) ~~affect~~or ~~production~~any ~~rates~~other ~~and~~public ~~investments~~health bycrisis ~~third~~that ~~parties~~impacts in the ~~development~~global ofdemand ~~new~~for ~~oil~~energy ~~and~~commodities ~~natural~~may ~~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~~material ~~historically~~adverse ~~volatile,~~effects ~~and~~on ~~we expect this volatility to continue. Consequently, even if new natural gas or crude oil reserves are discovered in areas served by~~ our ~~assets~~business, ~~producers~~financial ~~may choose not to develop those reserves. For example~~position, ~~current~~results ~~low prices for natural gas combined with relatively high levels~~ of ~~natural~~operations ~~gas in storage could result in curtailment or shut-in of natural gas production. Reductions in exploration~~ and ~~production activity, competitor actions~~ /or ~~shut-ins~~cash 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 and fractionation assetsflows.

IfWe weface dorisks ~~not~~related ~~make~~to ~~acquisitions~~the oroutbreak ~~develop~~of ~~growth~~illnesses, ~~projects~~pandemics ~~for~~and ~~expanding~~other ~~existing~~public ~~assets~~health orcrises ~~constructing~~that ~~new~~are ~~midstream~~outside ~~assets~~of onour ~~economically~~control ~~acceptable~~and ~~terms,~~could orsignificantly ~~fail~~disrupt toour ~~efficiently~~operations and ~~effectively~~adversely ~~integrate~~affect ~~acquired~~our orfinancial ~~developed~~condition. ~~assets~~For ~~with~~example, ~~our~~the ~~asset~~global ~~base~~spread of COVID-19 has caused business disruption, ~~our~~including ~~future~~disruption ~~growth~~to ~~will~~the beoil ~~limited~~and gas industry. InThe COVID-19 pandemic has ~~addition~~negatively impacted the global economy, ~~any~~disrupted ~~acquisitions~~global wesupply ~~complete~~chains, ~~are~~reduced ~~subject~~global todemand ~~substantial~~for ~~risks~~oil ~~that~~and ~~could~~gas, ~~adversely~~and ~~affect~~created ~~our~~significant ~~financial~~volatility ~~condition~~and disruption of financial and ~~results~~commodity markets. The full extent of ~~operations~~the impact of the COVID-19 pandemic on our operational and ~~reduce~~financial performance, including our ability to ~~make~~execute ~~distributions~~our tobusiness ~~our~~strategies ~~limited~~and ~~partners.~~initiatives Inin ~~addition~~the expected time frame, weis ~~may~~uncertain ~~not~~and ~~achieve~~depends on various factors, including the ~~expected~~demand ~~results~~for ofnatural ~~any~~gas, ~~acquisitions~~NGLs and ~~any~~crude ~~adverse~~oil ~~conditions~~(including orthe ~~developments~~impact ~~related~~that toreductions ~~such~~in ~~acquisitions~~travel, ~~may~~manufacturing and consumer product demand have ahad ~~negative~~and ~~impact~~will have on the demand for energy commodities), the availability of personnel, equipment and services critical to our ~~operations~~ability to operate our assets and ~~financial~~the ~~condition~~impact of potential governmental restrictions on travel, transportation and operations.

~~Our~~The ~~ability~~degree to ~~grow~~which the COVID-19 pandemic or ~~depends,~~any inother ~~part,~~public onhealth ~~our~~crisis ~~ability~~adversely toimpacts ~~make~~our ~~acquisitions~~results orwill ~~develop~~also ~~growth~~depend ~~projects~~on ~~that~~future ~~result~~developments, inwhich anare ~~increase~~highly inuncertain ~~cash~~and ~~generated~~cannot ~~from~~be ~~operations~~predicted. WeThese ~~are~~developments ~~unable~~include, tobut ~~acquire~~are ~~businesses~~not ~~from~~limited ~~Targa in order~~ to, ~~grow~~the ~~because~~duration ~~Targa’s~~and spread of ~~only~~the ~~assets~~outbreak, ~~currently~~its ~~are~~severity, the ~~interests~~actions into uscontain ~~that~~the ~~Targa~~virus ~~owns.~~or Astreat aits ~~result~~impact, weits ~~will~~impact ~~need to focus~~ on ~~third-party~~the ~~acquisitions~~economy and ~~organic~~market ~~growth.~~conditions, Ifand wehow ~~are~~quickly ~~unable~~and to ~~make~~what ~~accretive~~extent ~~acquisitions~~normal oreconomic ~~develop accretive growth projects because we are (1) unable to identify attractive acquisition candidates~~ and ~~negotiate~~operating ~~acceptable~~conditions ~~acquisition~~can ~~agreements~~resume. ~~or develop growth projects economically~~Therefore, ~~(2)~~while ~~unable~~we toexpect ~~obtain~~this ~~financing~~matter ~~for~~will ~~these~~continue ~~acquisitions~~to ordisrupt ~~projects~~our onoperations ~~economically~~in ~~acceptable~~some ~~terms~~way, orthe ~~(3)~~degree ~~unable~~of tothe ~~compete~~adverse ~~successfully~~financial ~~for~~impact ~~acquisitions~~cannot orbe ~~growth~~reasonably ~~projects,~~estimated ~~then~~at ~~our~~this ~~future growth and ability to increase distributions will be limited~~time.

~~Any~~Refer ~~acquisition~~to orNote ~~growth~~5 ~~project~~- ~~involves~~Property, ~~potential~~Plant ~~risks,~~and ~~including,~~Equipment ~~among~~and ~~other~~Intangible ~~things:~~Assets of the “Consolidated Financial Statements” included in this Annual Report for further discussion regarding the impact of COVID-19 and non-cash pre-tax impairments recorded by the Company in 2020.

•A ~~operating~~reduction ain ~~significantly~~demand ~~larger~~for ~~combined~~NGL ~~organization~~products ~~and~~by ~~adding~~the ~~new~~petrochemical, refinery or ~~expanded~~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 ~~difficulties~~NGL inproducts ~~the~~we ~~assimilation~~produce have a variety of ~~the~~applications, ~~assets~~including heating fuels, petrochemical feedstocks and ~~operations~~refining blend stocks. A reduction in demand for NGL products, whether because of general or industry-specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the ~~acquired~~automobile ~~businesses~~and construction industries), reduced demand for propane or ~~growth~~butane ~~projects~~exports whether for price or other reasons, ~~especially~~reduced ifdemand due to the ~~assets~~effects ~~acquired~~of ~~are~~the COVID-19 pandemic, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a ~~new~~decline ~~business~~in ~~segment~~the ~~and/~~volume of NGL products we handle or ~~geographic~~reduce ~~area;~~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 ~~risk~~petrochemical ~~that~~industry ~~crude~~as ~~oil~~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 ~~reserves~~prices ~~expected~~increase significantly in relation to ~~support~~NGL product prices or if the ~~acquired~~demand ~~assets~~for ~~may~~ethylene ~~not~~falls, it may be ofmore profitable for natural gas processors to leave the ~~anticipated~~ethane ~~magnitude~~in orthe ~~may~~natural ~~not~~gas bestream, ~~developed~~thereby asreducing ~~anticipated;~~the volume of NGLs delivered for fractionation and marketing.

•Propane. Propane is used as a petrochemical feedstock in the ~~failure~~production toof ~~realize~~ethylene ~~expected~~and ~~volumes~~propylene, ~~revenues~~as a heating, ~~profitability~~engine orand 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 ~~failure~~production toof ~~realize~~isobutane, ~~any~~as ~~expected~~a ~~synergies~~refined petroleum product blending component, as a fuel gas (either alone or in a mixture with propane) and ~~cost~~in ~~savings;~~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.

• 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;

• 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.

IfIsobutane. ~~these~~Isobutane ~~risks~~is ~~materialize,~~predominantly ~~any~~used ~~acquired~~in ~~assets~~refineries orto ~~growth~~produce ~~project~~alkylates ~~may inhibit our growth, fail~~ to ~~deliver~~enhance ~~expected~~octane ~~benefits and/or add further unexpected costs~~levels. ~~Challenges may arise whenever businesses with different operations or management are combined~~Accordingly, ~~and~~any weaction ~~may~~that ~~experience~~reduces ~~unanticipated~~demand ~~delays~~for inmotor ~~realizing~~gasoline ~~the benefits of an acquisition~~ or ~~growth~~demand ~~project.~~for Ifisobutane ~~we consummate any future acquisition or growth project, our capitalization and results of operations may change significantly and you may not have the opportunity~~ to ~~evaluate~~produce ~~the~~alkylates ~~economic,~~for ~~financial~~octane ~~and~~enhancement ~~other~~might ~~relevant~~reduce ~~information~~demand ~~that~~for ~~we will consider in evaluating future acquisitions or growth projects~~isobutane.

~~Our~~Natural ~~acquisition~~Gasoline. ~~and~~Natural ~~growth~~gasoline ~~strategy~~ is ~~based,~~used inas ~~part,~~a onblending ~~our~~component ~~expectation~~for ofcertain ~~ongoing~~refined ~~divestitures~~petroleum ofproducts ~~energy~~and ~~assets~~as bya ~~industry~~feedstock ~~participants~~used ~~and~~in ~~new~~the ~~opportunities~~production ~~created~~of byethylene ~~industry~~and ~~expansion~~propylene. AChanges ~~material decrease~~ in ~~such~~the ~~divestitures~~mandated orcomposition inof ~~opportunities~~motor ~~for~~gasoline ~~economic~~resulting ~~commercial~~from ~~expansion~~governmental ~~would~~regulation, ~~limit~~and ~~our~~in ~~opportunities~~demand for ~~future~~ethylene ~~acquisitions or growth projects~~ and propylene, could adversely affect ~~our~~demand ~~operations and cash flows available~~ for ~~distribution~~natural ~~to our limited partners~~gasoline.

~~Acquisitions~~NGLs ~~may~~and ~~significantly~~products ~~increase~~produced ~~our~~from ~~size~~NGLs ~~and~~also ~~diversify~~compete ~~the~~with ~~geographic~~products ~~areas~~from inglobal ~~which~~markets. weAny ~~operate~~reduced ~~and~~demand ~~growth~~or ~~projects~~increased ~~may~~supply ~~increase~~for ~~our~~ethane, ~~concentration~~propane, normal butane, isobutane or natural gasoline in athe ~~line~~markets we access for any of ~~business~~the orreasons ~~geographic~~stated ~~region.~~above Wecould ~~may~~adversely ~~not~~affect ~~achieve~~both demand for the ~~desired~~services ~~effect~~we ~~from~~provide ~~any~~and ~~future~~NGL ~~acquisitions~~prices, orwhich ~~growth~~could ~~projects~~negatively impact our results of operations and financial condition.

~~Our~~The ~~expansion~~natural ordecline ~~modification~~in ofproduction ~~existing~~in ~~assets~~our oroperating ~~the~~regions ~~construction~~and ofin ~~new~~other ~~assets~~regions ~~may~~from ~~not~~which ~~result~~we insource ~~revenue~~NGL ~~increases~~supplies ~~and~~means isour ~~subject~~long-term success depends on our ability to ~~regulatory,~~obtain ~~environmental,~~new ~~political~~sources of supplies of natural gas, ~~legal~~NGLs and ~~economic~~crude ~~risks~~oil, which ~~could~~depends ~~adversely~~on ~~affect~~certain factors beyond our ~~results~~control. Any decrease in supplies of ~~operations~~natural gas, NGLs or crude oil could adversely affect our business and ~~financial~~operating ~~condition~~results.

~~The~~Our ~~construction~~gathering ofsystems ~~additions~~are orconnected ~~modifications~~ to ~~our~~crude ~~existing~~oil ~~systems~~ and ~~the~~natural ~~construction~~gas ofwells ~~new~~from ~~midstream~~which ~~assets~~production ~~involve~~will ~~numerous~~naturally ~~regulatory,~~decline ~~environmental~~over time, ~~political~~which ~~and~~means ~~legal~~that ~~uncertainties~~the ~~beyond~~cash ~~our~~flows ~~control~~associated ~~and~~with ~~may~~these ~~require~~sources ~~the expenditure~~ of ~~significant~~natural ~~amounts~~gas ofand ~~capital.~~crude Ifoil wewill ~~undertake~~likely ~~these~~also ~~projects,~~decline ~~they~~over ~~may~~time. ~~not~~Our belogistics ~~completed~~assets onare ~~schedule,~~similarly atimpacted ~~the~~by ~~budgeted~~declines ~~cost~~in orNGL atsupplies ~~all.~~in ~~For example,~~ the ~~construction~~regions ofin ~~additional~~which ~~systems~~we ~~may~~operate beas ~~delayed~~well oras ~~require~~other ~~greater~~regions ~~capital~~from ~~investment~~which ifwe ~~the~~source ~~commodity~~NGLs. ~~prices~~To ofmaintain ~~certain~~or ~~supplies, such as steel pipe,~~ increase ~~due~~throughput tolevels ~~imposed~~on ~~tariffs. Moreover,~~ our ~~revenues~~gathering ~~may~~systems ~~not~~and ~~increase~~the ~~immediately~~utilization ~~upon~~rate ~~the~~at ~~expenditure~~our ofprocessing ~~funds~~plants onand aour ~~particular~~treating ~~project.~~and ~~For~~fractionation ~~instance~~facilities, if we ~~build~~must acontinually obtain new ~~pipeline,~~natural ~~fractionation facility or~~ gas ~~processing plant~~, ~~the~~NGL ~~construction may occur over an extended period of time~~ and wecrude ~~will~~oil ~~not~~supplies. ~~receive~~A ~~any~~ material ~~increases~~decrease in ~~revenues~~natural ~~until~~gas ~~the~~or ~~project~~crude isoil ~~completed.~~production ~~Moreover,~~from weproducing ~~may~~areas ~~construct~~on ~~pipelines~~which orwe ~~facilities~~rely, toas ~~capture anticipated future growth in production in~~ a ~~region~~result inof ~~which~~depressed ~~such~~commodity ~~growth~~prices ~~does~~or ~~not~~otherwise, ~~materialize.~~could ~~Since~~result wein ~~are~~a ~~not~~decline ~~engaged~~ in the ~~exploration~~volume ~~for and development~~ of natural gas ~~and~~or crude oil ~~reserves,~~that we dogather ~~not~~and ~~possess~~process, ~~reserve~~NGLs ~~expertise~~that ~~and~~ we ~~often~~transport door ~~not~~NGL ~~have~~products ~~access~~delivered to ~~third-party~~our ~~estimates~~fractionation offacilities. ~~potential~~Our ~~reserves~~ability into anobtain ~~area~~additional ~~prior~~sources toof ~~constructing~~natural ~~pipelines~~gas, orNGLs ~~facilities~~and incrude ~~such~~oil ~~area.~~depends, Toin ~~the~~part, ~~extent~~on wethe ~~rely~~level onof ~~estimates~~successful ofdrilling ~~future~~and production inactivity ~~any~~near ~~decision~~our togathering ~~construct~~systems ~~additions~~and, toin ~~our systems~~part, ~~such~~on ~~estimates~~the ~~may~~level ~~prove~~of tosuccessful bedrilling ~~inaccurate~~and ~~because~~production ~~there are numerous uncertainties inherent~~ in ~~estimating~~other ~~quantities~~areas offrom ~~future~~which ~~production.~~we Assource aNGL ~~result,~~and ~~new~~crude ~~pipelines~~oil orsupplies. ~~facilities~~We ~~may~~have ~~not~~no becontrol ~~able~~over tothe ~~attract~~level ~~enough~~of ~~throughput~~such toactivity ~~achieve~~in ~~our~~the ~~expected~~areas ~~investment~~of ~~return, which could adversely affect~~ our ~~results of~~ operations ~~and financial condition. In addition~~, the ~~construction~~amount of ~~additions~~reserves toassociated ~~our~~with ~~existing~~the ~~gathering~~wells ~~and~~or ~~transportation~~the ~~assets~~rate ~~may~~at ~~require~~which usproduction tofrom ~~obtain~~a ~~new~~well ~~rights~~will ofdecline. ~~way~~In ~~prior~~addition, towe ~~constructing~~have ~~new~~no ~~pipelines.~~control Weover ~~may~~producers beor ~~unable~~their todrilling, ~~obtain~~completion or ~~renew~~production ~~such~~decisions, ~~rights~~which ofare ~~way~~affected toby, ~~connect~~among ~~new~~other ~~natural~~things, ~~gas~~prevailing and ~~crude~~projected ~~oil~~energy ~~supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally~~prices, itdemand ~~may become more expensive~~ for ushydrocarbons, tothe ~~obtain~~level ~~new rights~~ of ~~way~~reserves, orgeological toconsiderations, ~~renew~~governmental ~~existing~~regulations, ~~rights of way. If~~ the ~~cost~~availability of ~~renewing~~drilling orrigs, ~~obtaining~~other ~~new~~production ~~rights~~and ofdevelopment ~~way~~costs ~~increases,~~and ~~our~~the ~~cash~~availability ~~flows~~and ~~could~~cost beof ~~adversely affected~~capital.

~~Our~~Fluctuations ~~acquisition~~in energy prices can greatly affect production rates and ~~growth~~investments ~~strategy~~by ~~requires~~third ~~access~~parties toin the development of new ~~capital~~oil and natural gas reserves. ~~Tightened~~Drilling ~~capital~~and ~~markets~~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 ~~increased~~crude ~~competition~~oil reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. For example, current low prices for ~~investment~~natural ~~opportunities~~gas combined with relatively high levels of natural gas in storage could ~~impair~~result ~~our~~in ~~ability~~curtailment or shut-in of natural gas production similar to ~~grow~~the ~~through~~production ~~acquisitions~~shut-ins we experienced in 2020 due to the impacts of the COVID-19 pandemic. Furthermore, in response to depressed commodity prices, many operators have announced substantial reductions in their estimated capital expenditures, rig count and completion crews. Reductions in exploration and production activity, competitor actions or ~~growth~~shut-ins ~~projects~~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.

WeOur ~~continuously~~industry ~~consider~~is ~~and~~highly ~~enter~~competitive ~~into discussions regarding potential acquisitions~~ and ~~growth~~increased ~~projects.~~competitive ~~Any~~pressure ~~limitations~~could onadversely ~~our~~affect ~~access to capital will impair~~ our ~~ability~~business ~~to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic~~ and ~~accretive~~operating ~~assets will be limited~~results. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our acquisition and growth strategy.

InWe ~~addition,~~compete wewith similar enterprises in our respective areas of operation. Some of our competitors are ~~experiencing~~large ~~increased~~crude ~~competition~~oil, ~~for~~natural ~~the~~gas ~~types~~and NGL companies that have greater financial resources and access to supplies of ~~assets~~natural gas, NGLs and crude oil than we ~~contemplate~~do. ~~purchasing~~Some of these competitors may expand or ~~developing.~~construct ~~Current~~gathering, ~~economic~~processing, ~~conditions~~storage, terminaling and transportation systems that would create additional competition for ~~asset~~the ~~purchases~~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 ~~development~~transportation ~~opportunities~~systems ~~could~~in ~~limit~~lieu ~~our~~of using those operated by us. Our ability to ~~fully~~renew ~~execute~~or replace existing contracts with our ~~acquisition~~customers at rates sufficient to maintain current revenues and ~~growth~~cash ~~strategy~~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.

If our general partner loses any of its named executive officers, our business may be adversely affected.

Our success is dependent upon the efforts of the named executive officers of our general partner. The named executive officers of our general partner are responsible for executing our business strategies. There is substantial competition for qualified personnel in the midstream oil and gas industry. Our general partner may not be able to retain its existing named executive officers or fill new positions or vacancies created by expansion or turnover. Our general partner has not entered into employment agreements with any of

its named executive officers. In addition, it does not maintain “key man” life insurance on the lives of any of its named executive officers. A loss of one or more of the named executive officers of our general partner could harm our business and prevent us from implementing our business strategies.

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 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.

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.

Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.

We have entered into derivative transactions related to only a portion of our equity volumes, future commodity purchases and sales, and transportation basis risk. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity. The percentages of our expected equity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. The derivative instruments we utilize for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGL and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. Market and economic conditions may adversely affect our hedge counterparties’ ability to meet their obligations. Given volatility in the financial and commodity markets, we may experience defaults by our hedge counterparties. In addition, our exchange traded futures are subject to margin requirements, which creates variability in our cash flows as commodity prices fluctuate.

As a result of these and other factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

If 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.

~~Our~~We ~~industry~~typically isdo ~~highly~~not ~~competitive,~~obtain ~~and~~independent ~~increased~~evaluations ~~competitive~~of ~~pressure~~natural ~~could~~gas ~~adversely~~or ~~affect~~crude oil reserves dedicated to our ~~business~~gathering ~~and~~pipeline ~~operating~~systems; ~~results~~therefore, volumes on our systems in the future could be less than we anticipate.

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 typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems; therefore, supply 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.

A reduction in demand for NGL products by the petrochemical, refining 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 as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry-specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), reduced demand for propane or butane exports whether for price or other reasons, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Also, increased supply of NGL products could reduce the value of NGLs handled by us and reduce the margins realized. Our NGL products and their demand are affected as follows:

Ethane. Ethane is typically supplied as purity ethane and as part of an ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream, thereby reducing the volume of NGLs delivered for fractionation and marketing.

Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is increasingly driven by international exports supplying a growing global demand for the product. Domestically in the U.S., propane is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of slow global economic growth and warmer-than-normal weather.

Normal Butane. Normal butane is used in the production of isobutane, as a refined petroleum product blending component, as a fuel gas (either alone or in a mixture with propane) and in the production of ethylene and propylene. Changes in the composition of refined petroleum products resulting from governmental regulation, changes in feedstocks, products and economics, and demand for heating fuel, ethylene and propylene could adversely affect demand for normal butane. The volume of butane sold is increasingly driven by international exports supplying a growing demand for the product.

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.

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.

WeIf ~~may be unable to cause~~ our ~~majority-owned~~general ~~joint~~partner ~~ventures~~loses toany ~~take or not to take certain actions unless some or all~~ of ~~our~~its ~~joint~~named ~~venture~~executive ~~participants~~officers, ~~agree and certain of~~ our ~~joint~~business ~~venture partners~~ may ~~fail~~be oradversely ~~refuse to fund their respective portions of capital projects that we believe are necessary to expand or maintain such joint venture’s business~~affected.

WeOur ~~participate~~success inis ~~several~~dependent ~~majority-owned~~upon ~~joint~~the ~~ventures~~efforts ~~whose~~of ~~corporate~~the ~~governance~~named ~~structures~~executive ~~require~~officers atof ~~least~~our ageneral ~~majority~~partner. inThe ~~interest~~named ~~vote~~executive toofficers ~~authorize~~of ~~many~~our ~~basic~~general ~~activities~~partner ~~and~~are ~~require~~responsible afor ~~greater~~executing ~~voting~~our ~~interest~~business ~~(sometimes~~strategies. upThere tois ~~100%)~~substantial tocompetition ~~authorize~~for ~~more~~qualified ~~significant~~personnel ~~activities.~~in ~~Examples~~the ofmidstream ~~these~~oil ~~more~~and ~~significant~~gas ~~activities~~industry. ~~include,~~Our ~~among~~general ~~others,~~partner ~~large~~may ~~expenditures~~not orbe ~~contractual~~able ~~commitments,~~to ~~the~~retain ~~construction~~its orexisting ~~acquisition~~named ofexecutive ~~assets,~~officers ~~borrowing money~~ or ~~otherwise~~fill ~~raising~~new ~~capital,~~positions ~~making~~or ~~distributions,~~vacancies ~~transactions~~created ~~with~~by ~~affiliates~~expansion ofor aturnover. ~~joint~~Our ~~venture~~general ~~participant,~~partner ~~litigation~~has ~~and~~not ~~transactions~~entered ~~not~~into inemployment ~~the~~agreements ~~ordinary~~with ~~course~~any of ~~business.~~its ~~Without~~named ~~the~~executive ~~concurrence~~officers. ofIn ~~joint~~addition, ~~venture~~our ~~participants~~general ~~with~~partner ~~enough~~does ~~voting~~not ~~interests,~~maintain we“key ~~may~~man” belife ~~unable~~insurance toon ~~cause~~the lives of any of ~~our~~its ~~joint~~named ~~ventures~~executive toofficers. ~~take~~A orloss ~~not~~of ~~take~~one ~~certain~~or ~~actions,~~more ~~even~~of ~~though~~the ~~taking~~named orexecutive ~~preventing~~officers ~~those~~of ~~actions~~our ~~may~~general bepartner incould harm our ~~best~~business ~~interests~~and orprevent ~~the~~us ~~particular~~from ~~joint~~implementing ~~venture~~our business strategies.

Certain of our joint venture partners may fail, refuse or elect not to fund their respective portions of capital projects that we believe are necessary to effectively expand or maintain such joint venture’s business. Such failure or election not to fund may impact the operations of the joint venture and may increase the capital that could be required from us if we were to fund such projects without the full participation of our joint venture partners. We may not achieve an acceptable rate of return for any such additional expenditures. 34

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.

We may operate a portion of our business with one or more joint venture partners where we own a minority interest and/or are not the operator, which may restrict our operational and corporate flexibility. Actions taken by the other partner or third-party operator may materially impact our financial position and results of operations, and we may not realize the benefits we expect to realize from a joint venture.

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.

Weather may limit our ability to operate our business and could adversely affect our operating results.

The weather in the areas in which we operate can cause disruptions and in some cases suspension of our operations and development activities. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes may cause a loss of throughput from temporary cessation of activities or lost or damaged 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. Some forecasters expect that potential climate changes may have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events and could have ana material adverse effect on our operations. Any unusual or prolonged severe weather or increased frequency thereof, such as freezing rain, earthquakes, hurricanes, droughts, or floods in our or our oil and gas exploration and production customers’ areas of operations or markets, whether due to climate change or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

Rising sea levels, subsidence and erosion could damage our pipelines and the facilities that serve our customers, particularly along the Gulf Coast and offshore, which could adversely affect our business, results of operations and financial condition.

Our operations along the Gulf Coast and offshore could be impacted by rising sea levels, subsidence and erosion. Subsidence issues are also a concern for our pipelines at major river crossings. Rising sea levels, subsidence and erosion could cause serious damage to our pipelines and other facilities, which could affect our ability to provide services or result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater or to the Gulf of Mexico, which could result in liability, remedial obligations and/or otherwise have a negative impact on continued operations. Additionally, such 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. Rising sea levels, subsidence and erosion could also expose our operations to increased risks associated with severe weather conditions and other adverse events and conditions, such as hurricanes and flooding. As a result, we may incur ~~significant~~ costs to repair and preserve our pipeline infrastructure and other facilities. Such costs could adversely affect our business, financial condition, results of operations and cash flows. In addition, local governments and landowners have filed lawsuits in recent years in Louisiana against energy companies, alleging that their operations contributed to increased coastal rising seas and erosion and seeking substantial damages.

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~~; and storing and terminaling refined petroleum products~~, including:

•

damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;

•

inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment;

•

damage that is the result of our negligence or any of our employees’ negligence;

•

leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;

•

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 35

37These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural resource damage, and may result in delay, curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. Additionally, while we are insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example, following the occurrence of severe hurricanes along the U.S. Gulf Coast in recent years, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes, with some coverage unavailable at any cost.

related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. Additionally, while we are insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes. Insurance market conditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike. As a result, we experienced further increases in deductibles and premiums, and further reductions in coverage and limits, 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.

~~Our~~Portions ~~operations~~of ~~are~~our ~~subject~~pipeline tosystems ~~environmental~~may ~~laws~~require ~~and~~increased ~~regulations~~expenditures for maintenance and arepair ~~failure~~owing to ~~comply~~the orage anof ~~accidental~~some ~~release~~of ~~into~~our ~~the~~systems, ~~environment~~which ~~may~~expenditures ~~cause~~or usresulting loss of revenue due to ~~incur~~pipeline ~~significant~~age ~~costs~~or condition could have a material adverse effect on our business and ~~liabilities~~results of operations.

~~Our~~Some ~~operations~~portions ~~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~~pipeline orsystems ~~otherwise~~that ~~relating~~we tooperate ~~environmental~~have ~~protection.~~been ~~These~~in ~~laws~~service ~~and~~for ~~regulations~~several ~~may~~decades ~~impose~~prior ~~numerous obligations that are applicable~~ to our ~~operations~~purchase ~~including acquisition~~ of athem. ~~permit or other approval before conducting regulated activities~~Consequently, ~~restrictions~~there onmay ~~the types, quantities and concentration of materials that can~~ be ~~released~~historical ~~into~~occurrences ~~the environment; limitation~~ or ~~prohibition~~latent ofissues ~~construction~~regarding ~~and~~our ~~operating~~pipeline ~~activities~~systems inthat ~~environmentally~~our ~~sensitive~~executive ~~areas~~management ~~such~~may asbe ~~wetlands,~~unaware ~~urban~~of ~~areas, wilderness regions~~ and ~~other~~that ~~protected~~may ~~areas;~~have ~~requiring~~a ~~capital~~material ~~expenditures~~adverse toeffect ~~comply~~on ~~with~~our ~~pollution~~business ~~control requirements,~~ and ~~imposition~~results of ~~substantial liabilities for pollution resulting from our~~ operations. ~~Numerous~~The ~~governmental~~age ~~authorities, such as the EPA~~ and ~~BLM,~~condition ~~and~~of ~~analogous~~some ~~state~~of ~~agencies,~~our ~~have~~pipeline ~~the~~systems ~~power~~could toalso ~~enforce~~result ~~compliance~~in ~~with~~increased ~~these~~maintenance ~~laws~~or ~~and~~repair ~~regulations and the permits and approvals issued under them~~expenditures, ~~which can often require difficult~~ and ~~costly~~any ~~actions.~~downtime ~~Failure~~associated ~~to comply~~ with ~~these~~increased ~~laws~~maintenance and ~~regulations~~repair oractivities ~~any~~could ~~newly~~materially ~~adopted~~reduce ~~laws~~our orrevenue. ~~regulations~~Any ~~may~~significant ~~result~~increase in ~~assessment~~maintenance ~~of sanctions including administrative, civil~~ and ~~criminal~~repair ~~penalties,~~expenditures ~~the imposition of investigatory, remedial and corrective action obligations~~ or ~~the~~loss ~~incurrence~~ of ~~capital~~revenue ~~expenditures;~~due ~~the~~to ~~occurrence of restrictions, delays or cancellations in~~ the ~~permitting~~age or ~~performance~~condition of ~~projects, and the issuance of orders enjoining or conditioning performance of~~ some orportions ~~all~~ of our ~~operations~~pipeline insystems acould ~~particular~~adversely ~~area.~~affect ~~Certain~~our ~~environmental~~business ~~laws impose strict, joint~~ and ~~several~~results 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~~operations.

~~The~~Terrorist ~~risk~~attacks ~~of incurring environmental costs~~ and ~~liabilities~~the inthreat ~~connection with our operations is significant due to our handling~~ of ~~natural~~terrorist ~~gas,~~attacks ~~NGLs,~~have ~~crude~~resulted ~~oil~~in ~~and~~increased ~~other~~costs ~~petroleum~~to ~~products, because of air emissions and product-related discharges arising out of~~ our ~~operations, and as a result of historical industry operations and waste disposal practices~~business. ~~For~~Continued ~~example,~~hostilities anin ~~accidental~~the ~~release~~Middle ~~from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs~~East, ~~claims~~other ~~made~~sustained bymilitary ~~neighboring~~campaigns ~~landowners~~ and ~~other~~civil ~~third~~unrest ~~parties~~in ~~for~~the ~~personal~~United ~~injury,~~States ~~natural~~may ~~resource~~adversely ~~and~~impact ~~property~~our ~~damages~~results ~~and fines or penalties for related violations~~ of ~~environmental laws or regulations~~operations.

~~Moreover,~~The ~~stricter~~long-term ~~laws,~~impact ~~regulations~~of orterrorist ~~enforcement~~attacks, ~~policies~~such ~~could~~as ~~significantly increase our operational or compliance costs and~~ the ~~cost~~attacks ~~of any remediation~~ that ~~may~~occurred ~~become~~on ~~necessary.~~September ~~For example~~11, ~~in 2015~~2001, ~~the~~and ~~EPA issued a final rule under~~ the ~~CAA,~~threat ~~lowering~~of ~~the~~future ~~National~~terrorist ~~Ambient~~attacks ~~Air~~on ~~Quality~~our ~~Standard~~industry ~~(“NAAQS”)~~in ~~for~~general ~~ground-level ozone to 70 parts per billion under both the primary~~ and ~~secondary~~on ~~standards~~us toin ~~provide~~particular ~~requisite~~is ~~protection~~not ofknown ~~the~~at ~~public~~this ~~health and welfare~~time. ~~Since that time~~However, ~~the~~resulting ~~EPA~~regulatory ~~has issued area designations with respect to ground-level ozone and final~~ requirements ~~that apply to state, local~~ and/or ~~tribal~~related ~~air~~business ~~agencies~~decisions ~~for~~associated ~~implementing~~with ~~the~~security ~~2015~~are ~~NAAQS~~likely ~~for~~to ~~ground-level~~increase ~~ozone.~~our ~~Also in 2015, the EPA and U~~costs.S. ~~Army~~Increased ~~Corps~~security ofmeasures ~~Engineers~~taken ~~(“Corps”)~~by ~~under~~us ~~the~~as ~~Obama administration released~~ a ~~final~~precaution ~~rule~~against ~~outlining~~possible ~~federal~~terrorist ~~jurisdictional~~attacks ~~reach~~have ~~under~~resulted ~~the~~in ~~Clean~~increased ~~Water~~costs ~~Act~~to ~~over~~our ~~waters of the United States, including wetlands~~business. InUncertainty ~~2017,~~surrounding ~~the~~continued ~~EPA~~hostilities ~~and~~in the ~~Corps~~Middle ~~under~~East ~~the~~or ~~Trump~~other ~~administration~~sustained ~~agreed~~military tocampaigns ~~reconsider~~may ~~the~~affect ~~2015~~our ~~rule~~operations ~~and,~~in ~~thereafter,~~unpredictable ~~on October 22~~ways, ~~2019,~~including ~~the~~disruptions ~~agencies~~of ~~published~~crude aoil ~~final~~supplies ~~rule~~and ~~made~~markets ~~effective~~for onour ~~December 23~~products, ~~2019, rescinding the 2015 rule~~ and ~~re-codifying~~ the ~~regulatory~~possibility ~~text~~ that ~~governed~~infrastructure ~~waters~~facilities ofcould ~~the~~be ~~United~~direct ~~States~~targets, ~~prior~~or toindirect ~~promulgation~~casualties, of ~~the~~an ~~2015~~act ~~rule~~of ~~until~~terror. ~~such~~Additionally, ~~time~~recent asacts aof ~~final~~protest ~~rule~~and ~~re-defining~~civil ~~the~~unrest ~~Clean~~have ~~Water~~caused ~~Act’s~~economic ~~jurisdiction~~and ~~over~~political ~~water~~disruption ofin the United States ~~was made effective in replacement of~~ .

38Changes 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.

the 2015 rule. On January 23, 2020, the two agencies issued a final rule re-defining such jurisdiction. Upon being published in the Federal Register and the passage of 60 days thereafter, the January 23, 2020 final rule will become effective in replacement of the October 22, 2019 final rule. Under the new January 23, 2020 final rule, the EPA has narrowed the federal government’s jurisdictional permitting authority under the Clean Water Act relative to the 2015 final rule. The 2015 final rule has been the subject of legal challenges by various factions in federal district court and implementation of the 2015 rule has been enjoined in slightly over half of the states pending resolution of the various federal district court challenges. Upon the effectiveness of the January 23, 2020 rule, the United States will be covered under a single regulatory scheme as it relates to federal jurisdictional reach over waters of the United States. However, there remains the expectation that the January 23, 2020 final rule also will be legally challenged in federal district court. To the extent that any challenge to the January 23, 2020 final rule is successful and the 2015 rule or a revised rule expands the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, such developments could delay, restrict or halt the development of projects, result in longer permitting timelines, or increased compliance expenditures or mitigation costs for our and our oil and natural gas customers’ operations, which may reduce the rate of production of natural gas or crude oil from operators with whom we have a business relationship and, in turn, have a material adverse effect on our business, results of operations and cash flows. 36

We ~~could~~face ~~incur~~opposition ~~significant~~to ~~costs~~operation inand ~~complying~~expansion ~~with~~of ~~stringent~~our ~~occupational~~pipelines ~~safety~~ and ~~health~~facilities ~~requirements~~from various individuals and groups.

We ~~are~~have ~~subject~~experienced, ~~to stringent federal~~ and ~~state~~we ~~laws~~anticipate ~~and~~that ~~regulations,~~we ~~including~~will ~~the~~encounter ~~federal~~from ~~Occupational~~time ~~Safety~~to ~~and Health Act and comparable state statutes~~time, ~~whose~~opposition ~~purpose is~~ to ~~protect~~ the ~~health~~operation and ~~safety~~expansion of ~~workers,~~our ~~both~~pipelines ~~generally~~ and ~~within~~facilities ~~the~~from ~~pipeline~~governmental ~~industry. In addition~~officials, ~~the~~non-governmental ~~federal~~environmental ~~Occupational~~organizations ~~Safety~~ and ~~Health~~groups, ~~Administration’s~~landowners, ~~(“OSHA”)~~tribal ~~hazard communication standard~~groups, ~~the~~local ~~EPA~~groups ~~community~~and ~~right-to-know~~other ~~regulations~~advocates. ~~under~~In ~~Title~~some ~~III~~instances, ofwe ~~the~~encounter ~~Federal~~opposition ~~Superfund~~which ~~Amendment~~disfavors ~~and~~hydrocarbon-based ~~Reauthorization~~energy ~~Act~~supplies ~~and~~regardless ~~comparable~~of ~~state~~practical ~~statutes~~implementation ~~require~~or ~~that~~financial ~~information~~considerations. beOpposition ~~maintained~~to ~~concerning hazardous materials used or produced in~~ our ~~operations~~operation and ~~that~~expansion ~~this~~can ~~information~~take bemany ~~provided to employees~~forms, ~~state~~including ~~and~~the ~~local~~delay, ~~government~~denial ~~authorities~~or ~~and~~termination ~~citizens.~~of Werequired ~~and~~governmental ~~the~~permits ~~entities~~or inapprovals, ~~which~~organized weprotests, ~~own~~attempts ~~an interest are subject~~ to ~~OSHA~~block ~~Process~~or ~~Safety~~sabotage ~~Management~~our ~~regulations~~operations, ~~which~~intervention ~~are~~in ~~designed~~regulatory ~~to prevent~~ or ~~minimize~~administrative ~~the~~proceedings ~~consequences~~involving ofour ~~catastrophic~~assets ~~releases~~or oflawsuits ~~toxic, reactive, flammable~~ or ~~explosive~~other ~~chemicals.~~actions ~~The~~designed ~~regulations apply~~ to ~~any~~prevent, ~~process~~disrupt, ~~that~~delay ~~(1) involves a listed chemical in a quantity at~~ or ~~above~~terminate the ~~threshold~~operation ~~quantity~~or ~~specified~~expansion inof ~~the~~our ~~regulation~~assets ~~for~~and ~~that~~business. ~~chemical~~In addition, ordestructive ~~(2)~~forms ~~involves~~of ~~certain~~protest ~~flammable gases~~ or ~~flammable~~opposition ~~liquids~~by ~~present~~activists, onincluding ~~site~~acts ~~in one location in a quantity~~ of ~~10,000~~sabotage ~~pounds~~ or ~~more.~~eco ~~Flammable~~terrorism ~~liquids~~could ~~stored~~cause insignificant ~~atmospheric~~damage ~~tanks~~or ~~below~~injury ~~their~~to ~~normal~~people, ~~boiling~~property ~~point~~or ~~without~~ the ~~benefit~~environment ~~of chilling~~ or ~~refrigeration~~lead ~~are exempt. Failure~~ to ~~comply~~extended ~~with~~interruptions ~~these~~of ~~laws~~our ~~and~~operations. ~~regulations~~Any orsuch ~~any~~event ~~newly~~that ~~adopted~~restricts, ~~laws~~delays or ~~regulations~~prevents ~~may~~the ~~result~~expansion ~~in assessment~~ of ~~sanctions~~our ~~including administrative~~business, ~~civil~~interrupts ~~and criminal penalties,~~ the ~~imposition~~revenues ofgenerated ~~investigatory,~~by ~~remedial~~our ~~and~~operations ~~corrective action obligations~~ or ~~the~~causes ~~incurrence~~us ofto ~~capital~~make significant expenditures, ~~any~~not ofcovered ~~which~~by insurance could ~~have~~adversely aaffect ~~material adverse effect on~~ our business, ~~financial condition and~~ results of operations, and financial condition.

While we do not conduct hydraulic fracturing, many of our oil and gas exploration and production customers do perform such activities. Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion of certain oil and natural gas wells whereby water, sand or alternative proppant, and chemical additives are injected under pressure into subsurface formations to stimulate the flow of certain oil and natural gas, increasing the volumes that may be recovered. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over, proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the process, including the EPA. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. Additionally, certain candidates seeking the office of President of the United States in 2020 have pledged to ban hydraulic fracturing of oil and natural gas wells. Moreover, some states have adopted, and others are considering adopting, legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, assess more taxes, fees or royalties on natural gas production, or otherwise limit the use of the technique. For example, in April 2019, the Governor of Colorado signed Senate Bill 19-181 into law, which legislation, among other things, revises the mission of the state oil and gas agency from fostering energy development in the state to instead focusing on regulating the industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties to regulate oil and natural gas operations within their jurisdiction as they do other developments. States could elect to prohibit hydraulic fracturing or high volume hydraulic fracturing altogether, following the approach taken by states of Vermont, Maryland, and New York. Local 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. Additionally, non-governmental organizations may seek to restrict hydraulic fracturing; notwithstanding the adoption of Colorado Senate Bill 19-181 in 2019, one or more interest groups in the state have already filed new ballot initiatives with the state in January 2020, in hopes of extending drilling setbacks from oil and natural gas development. New or more stringent laws, regulations 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.

With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission pipeline and Tarzan 311 residue line, which are each subject to limited FERC regulation under either the NGA or NGPA, our natural gas pipeline operations are generally exempt from FERC regulation, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in a given year. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. We also operate natural gas pipelines that extend from some of our processing plants to interconnections with both intrastate and interstate natural gas pipelines. Those facilities, known in the industry as “plant tailgate” pipelines, typically operate at transmission pressure levels and may transport “pipeline quality” natural gas. Because our plant tailgate pipelines are relatively short, we treat them as “stub” lines, which are exempt from FERC’s jurisdiction under the Natural Gas Act.

Targa NGL and Grand Prix Joint Venture have pipelines that are considered common carrier pipelines subject to regulation by FERC under ICA. The ICA requires that we maintain tariffs on file with FERC for each of the Targa NGL and Grand Prix Joint Venture pipelines that have not been granted a waiver. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. With respect to pipelines that have been granted a waiver of the ICA and related regulations by FERC, should a particular pipeline’s circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that FERC were to determine that one or more of these pipelines no longer qualified for a waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s), provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on these pipelines could adversely affect our results of operations.

In addition, the courts have determined that certain pipelines that would otherwise be subject to the ICA are exempt from regulation by FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classification and regulation of some of our gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.

Various federal agencies within the U.S. Department of the Interior, particularly the BLM, Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, see “Item 1. Business—Regulation of Operations.”

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of the NGA or NGPA, respectively, up to approximately $1.29 million (adjusted annually for inflation) per day for each violation and disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission pipeline and Tarzan 311 residue line, have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA of up to approximately $13,500 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.”

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, because the U.S. Supreme Court has held that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years beginning in 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

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, in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020. Critical declarations made by one or more presidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions to oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as the rescission of the United States’ withdrawal from the Paris Agreement in November 2020. 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.

There are also increasing financial risks for fossil fuel producers as well as other companies handling fossil fuels, including owners of terminals, pipelines and refineries, as stockholders and bondholders currently invested in fossil fuel energy companies 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 also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development of production activities.

The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this

sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation, and financial risks may result in our oil and natural gas customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation. Finally, increasing concentrations of GHG in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events. If any such 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.

In 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) that extended PHMSA’s statutory mandate regarding pipeline safety until September 30, 2019 and required PHMSA to complete certain of its outstanding mandates under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). The 2011 Pipeline Safety Act had directed the promulgation of regulations relating to such matters as expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. The 2016 Pipeline Safety Act also empowered PHMSA to address unsafe conditions or practices constituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. On October 1, 2019, PHMSA published a final rule that replaced a 2016 interim rule, implementing the agency’s expanded authority relating to imminent hazards to life, property or the environment.

The imposition of new safety enhancement requirements pursuant to the 2016 Pipeline Safety Act and the 2011 Pipeline Safety Act or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could 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 our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

Additionally, PHMSA and one or more state regulators, including the RRC, have in recent years expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, we and other midstream operators of NGL fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA PSM and EPA RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to the authority under the NGPSA and HLPSA, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquids pipelines that, in the event of a pipeline leak or rupture could affect higher risk areas, known as HCAs and MCAs, which are areas where a release could have the most significant adverse consequences. The HCAs for natural gas ~~pipelines are predicated on high-population areas (which~~, ~~for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for~~ crude oil, NGL and condensate pipelines isimpose ~~based~~increasing ~~on high~~safety-~~population~~related ~~areas,~~requirements ~~certain~~as ~~drinking~~the ~~water~~population ~~sources~~density ~~and~~or ~~unusually sensitive~~ ecological ~~areas~~sensitivity increases. An MCA is ~~attributable~~defined in relation to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. Among other things, these regulations require operators of covered pipelines to:

•

perform ongoing assessments of pipeline integrity;

•

identify and characterize applicable threats to pipeline segments that could impact an HCA or MCA;

•

maintain processes for data collection, integration and analysis;

•

repair and remediate pipelines as necessary; and

•

implement preventive and mitigating actions.

42In 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 currently estimate an average annual cost of $4.9 million between 2021 and 2023 to implement pipeline integrity management program testing 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 or mitigative actions that may be determined to be necessary as a result of the discovery of anomaly conditions during the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

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 currently estimate an average annual cost of $3.8 million between 2020 and 2022 to implement pipeline integrity management program testing 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 or mitigative actions that may be determined to be necessary as a result of the discovery of anomaly conditions during the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.37

Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a ~~significant~~material adverse effect on us and similarly situated midstream operators. For instance, inseveral ~~2016,~~years ~~pursuant~~after topublishing ~~one of the requirements in the 2011 Pipeline Safety Act, PHMSA published~~ a proposed rulemaking, ~~that~~referred ~~would~~to ~~expand~~as ~~integrity~~the ~~management requirements and impose new pressure testing requirements on currently regulated natural~~ “gas ~~pipelines.~~Mega ~~The proposal would also significantly expand the regulation of gathering lines~~Rule,” ~~subjecting~~that ~~previously~~proposed ~~unregulated pipelines~~ to ~~requirements~~expand ~~regarding~~various ~~damage~~technical ~~prevention,~~and ~~corrosion control, public education programs, maximum allowable~~ operating ~~pressure~~aspects ~~limits~~of ~~and~~gas ~~other requirements. However~~pipelines, PHMSA ~~has~~elected ~~since decided~~ to split ~~its~~the ~~2016~~ proposed ~~rule,~~rulemaking ~~which has become known as the “gas Mega Rule,”~~ into three ~~separate rulemakings to facilitate completion~~rules. The first of these ~~three rulemakings~~rules, relating to onshore gas transmission pipelines, was published as a final rule onin October 1, 2019, ~~becomes~~and became effective onin July 1, 2020,. ~~and~~This ~~imposes~~final ~~numerous~~rule ~~requirements~~required, onamong ~~such~~other ~~pipelines~~things, ~~including~~reconfirmation of maximum allowable operating pressure (“MAOP”) ~~reconfirmation,~~and ~~the~~ assessment of additional pipeline mileage outside of HCAs (including all MCAs and those Class 3 and Class 4 areas found not to be in HCAs) within 14 years of the publication date and at least once every 10 years thereafter,. The remaining rulemakings comprising the ~~reporting~~gas ofMega ~~exceedances~~Rule ofhave ~~MAOP~~not yet been published, and ~~the~~we ~~consideration~~cannot ofpredict ~~seismicity~~when asthey awill ~~risk~~be ~~factor~~finalized; inhowever, ~~integrity~~they ~~management.~~are ~~The~~expected ~~remaining~~to ~~rulemakings~~include ~~comprising~~revised ~~the~~pipeline ~~gas~~repair ~~mega~~criteria ~~rule~~as ~~are~~well ~~expected~~as tomore bestringent ~~issued~~corrosion incontrol ~~2020~~requirements. Additionally, ~~on October 1, 2019,~~ PHMSA published a final rule in October 2019 for hazardous liquid transmission and gathering pipelines. ~~that~~This ~~becomes~~hazardous liquid final rule became effective in July 1, 2020 and significantly extends and expands the reach of certain PHMSA integrity management requirements, regardless of the pipeline’s proximity to an HCA ~~(for example, integrity assessments at least once every 10 years of onshore, piggable, hazardous liquid pipeline segments located outside of HCAs,~~ and ~~expanded use of leak detection systems beyond HCAs to all regulated hazardous liquid pipelines other than offshore gathering and regulated rural gathering pipelines). The final rule also~~ requires ~~all~~most hazardous liquid pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. ~~unless~~In ~~the~~April ~~basic~~2020 ~~construction~~and ofJune a2020, ~~pipeline~~PHMSA ~~cannot~~published beproposed ~~modified~~rules ~~to permit~~ that ~~accommodation.~~would Inseek ~~addition,~~to ~~the~~ease ~~final~~regulatory ~~rule~~burdens ~~extends~~on ~~annual, accident, and safety-related conditional reporting requirements to~~ hazardous liquid ~~gravity~~pipelines ~~lines~~ and ~~certain~~gas ~~gathering~~transmission, ~~lines~~distribution and ~~also~~gathering ~~imposes~~lines. ~~inspection~~No ~~requirements~~final onrules ~~hazardous~~have ~~liquid~~been ~~pipelines~~issued inwith ~~areas~~respect ~~affected~~to bythose ~~extreme~~proposed ~~weather~~rulemakings ~~events~~ and ~~natural~~it ~~disasters,~~is ~~such~~expected ~~as hurricanes, landslides, floods, earthquakes or other similar events~~ that ~~are~~President ~~likely~~Biden towill ~~damage~~reconsider ~~infrastructure~~those rules.

Congress subsequently enacted the 2016 Pipeline Safety Act, which reauthorized PHMSA’s hazardous liquid and gas pipeline programs through September 30, 2019, and thus it is expected that Congress will issue an updated pipeline safety law in 2019 or 2020 that will reauthorize those programs through 2023. The integrityIntegrity-related requirements and other provisions ofrequired ~~the~~under ~~2011~~applicable ~~Pipeline Safety Act, the 2016 Pipeline Safety Act, and any new Congressional~~ pipeline safety ~~legislation~~laws ~~that~~together iswith ~~expected to be introduced to reauthorize PHMSA pipeline safety programs, 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.

~~Portions~~We ofare ~~our~~subject ~~pipeline~~to ~~systems~~cyber ~~may~~security ~~require~~risks. ~~increased~~A ~~expenditures~~cyber ~~for~~incident ~~maintenance~~could occur and ~~repair~~result ~~owing~~in toinformation ~~the~~theft, ~~age~~data ~~of some of our systems~~corruption, ~~which~~operational ~~expenditures~~disruption and/or ~~resulting~~financial loss ~~of revenue due to pipeline age or condition could have a material adverse effect on our business and results of operations~~.

~~Some~~The ~~portions~~oil ofand ~~the~~natural ~~pipeline~~gas ~~systems~~industry ~~that~~has webecome ~~operate~~increasingly ~~have~~dependent ~~been~~on indigital ~~service~~technologies ~~for~~to ~~several~~conduct ~~decades~~business. ~~prior~~For example, we depend on digital technologies to operate our ~~purchase~~facilities, ofserve ~~them~~our customers and record financial data. ~~Consequently~~At the same time, ~~there~~cyber ~~may~~incidents, beincluding ~~historical~~deliberate ~~occurrences~~attacks, orhave ~~latent~~increased. ~~issues~~The ~~regarding~~U.S. ~~our~~government ~~pipeline~~has ~~systems~~issued public warnings that ~~our~~indicate ~~executive~~that ~~management~~energy ~~may~~assets might be ~~unaware~~specific targets of ~~and~~cyber ~~that~~security ~~may~~threats. ~~have~~Our atechnologies, ~~material~~systems ~~adverse~~and ~~effect~~networks, onand those of our ~~business~~vendors, suppliers, customers and ~~results~~other ofbusiness ~~operations.~~partners, ~~The~~may ~~age~~become ~~and~~the ~~condition~~target of ~~some~~cyberattacks ofor ~~our~~information ~~pipeline~~security ~~systems~~breaches that could ~~also~~ result in ~~increased~~the ~~maintenance~~unauthorized orrelease, ~~repair~~gathering, ~~expenditures~~monitoring, ~~and~~misuse, ~~any~~loss ~~downtime~~or ~~associated~~destruction ~~with~~of ~~increased~~proprietary ~~maintenance~~ and ~~repair~~other ~~activities~~information, or could ~~materially~~adversely ~~reduce~~disrupt our ~~revenue~~business operations. ~~Any~~In ~~significant~~addition, ~~increase~~certain incyber ~~maintenance~~incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to enhance our security posture and ~~repair~~cybersecurity ~~expenditures~~defenses or ~~loss~~to ofinvestigate ~~revenue~~and ~~due~~remediate toany ~~the~~vulnerability ~~age~~to or ~~condition~~consequences of ~~some~~cyber ~~portions~~incidents. ofOur ~~our~~insurance ~~pipeline~~coverages ~~systems~~for ~~could~~cyberattacks ~~adversely~~may ~~affect~~not ~~our~~be ~~business~~sufficient ~~and~~to ~~results~~cover all the losses we may experience as a result of ~~operations~~a cyber incident.

4338

~~The~~Risks ~~implementation~~Related ofto ~~derivatives legislation could have an adverse effect on~~ our ~~ability~~Capital toProjects ~~use derivative instruments to reduce the effect of commodity price, interest rate~~ and ~~other~~Future ~~risks~~Growth ~~associated with our business.~~

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.

Our ability to grow depends, in part, on our ability to develop growth projects and/or make acquisitions that result in an increase in cash generated from operations. We will need to focus on organic growth and third-party acquisitions. If we are unable to develop accretive growth projects or make accretive acquisitions because we are (1) unable to develop growth projects economically or identify attractive acquisition candidates and negotiate acceptable acquisition agreements or, (2) unable to obtain financing for these projects or acquisitions on economically acceptable terms, or (3) unable to compete successfully for growth projects or acquisitions, then our future growth will be limited.

Any growth project or acquisition involves potential risks, including, among other things:

•

operating a significantly larger combined organization and adding new or expanded operations;

•

difficulties in the assimilation of the assets and operations of the growth projects or acquired businesses, especially if the assets developed or acquired are in a new business segment and/or geographic area;

•

the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

•

the failure to realize expected volumes, revenues, profitability or growth;

•

the failure to realize any expected synergies and cost savings;

•

coordinating geographically disparate organizations, systems and facilities;

•

the assumption of environmental and other unknown liabilities;

•

limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects;

•

the failure to attain or maintain compliance with environmental and other governmental regulations;

•

inaccurate assumptions about the overall costs of equity or debt;

•

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, or management who may have business interests, strategies or goals that are inconsistent with ours; and

•

customer or key employee losses at the acquired businesses or to a competitor.

If these risks materialize, any growth project or acquired assets may inhibit our growth, fail to deliver expected benefits and/or add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of a growth project or acquisition. If we consummate any future growth project or acquisition, our capitalization and results of operations may change significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future growth projects or acquisitions.

Our growth and acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants and new opportunities created by industry expansion. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit our opportunities for future growth projects or acquisitions and could adversely affect our operations and cash flows.

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.

Our growth and acquisition strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow through growth projects or acquisitions.

We continuously consider and enter into discussions regarding potential growth projects and acquisitions. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our growth and acquisition strategy.

In addition, we may experience increased competition for the types of assets we contemplate purchasing or developing. Current economic conditions, including those caused by the effects of the COVID-19 pandemic, and competition for asset purchases and development opportunities could limit our ability to fully execute our growth and acquisition strategy.

We may be unable to cause our majority-owned 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.

We participate in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities 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.

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

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 adversely affect our cash flow and results of operations.

Changes in future business conditions could have a negative impact on the demand for our services and could cause recorded long-lived assets to become further impaired, and our financial condition and results of operations could suffer if there is a negative impact on the demand for our services and an additional impairment of long-lived assets.

Should energy industry conditions deteriorate, there is a possibility that long-lived assets may be impaired in a future period. For example, in the first quarter of 2020, we recorded non-cash pre-tax impairments of $2,442.8 million primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. Any additional impairment charges that we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of long-lived assets. For a further discussion of our impairments of long-lived assets, see Note 5 — Property, Plant and Equipment and Intangible Assets of the “Consolidated Financial Statements” included in this Annual Report.

If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.

The implementation of derivatives legislation could have a material adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized most of these regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In January 2020, the CFTC proposed new rules that would 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. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.42

~~The~~In ~~CFTC~~October ~~has~~2020, ~~designated~~the ~~certain~~CFTC ~~interest~~adopted ~~rate~~new ~~swaps~~rules ~~and~~that ~~credit~~would ~~default~~place ~~swaps~~limits ~~for~~on ~~mandatory~~positions ~~clearing~~in ~~and~~certain ~~the~~core ~~associated~~futures ~~rules~~and ~~also~~equivalent ~~will~~swaps ~~require~~contracts ~~us,~~for inor ~~connection~~linked ~~with~~to ~~covered~~certain ~~derivative~~physical ~~activities~~commodities, tosubject ~~comply with clearing and trade-execution requirements or take steps~~ to ~~qualify~~exceptions for ancertain ~~exemption~~bona tofide ~~such~~hedging ~~requirements~~transactions. ~~Although~~The wenew ~~qualify~~rules ~~for~~became ~~the~~effective ~~end-user~~in ~~exception~~December ~~from~~2020 ~~the~~but ~~mandatory~~have ~~clearing~~a ~~requirements~~general ~~for~~compliance ~~swaps~~date ~~entered~~of toJanuary ~~hedge our commercial risks~~1, ~~the~~2022 ~~application of the mandatory clearing~~ and ~~trade~~later ~~execution~~compliance ~~requirements~~date toof ~~other~~January ~~market participants~~1, ~~such~~2023 aswith ~~swap~~respect ~~dealers,~~to ~~may change the cost and availability of the~~ swaps-related ~~that~~requirements ~~we use for hedging. The CFTC~~ and the ~~federal~~elimination ~~banking~~of ~~regulators~~previously ~~have~~granted ~~adopted~~risk ~~regulations~~management ~~requiring certain counterparties to swap to post initial and variation margin~~exemptions. ~~However,~~The ~~our~~impact ~~current~~of ~~hedging~~those ~~activities~~provisions ~~would~~on ~~qualify~~us ~~for~~is ~~the~~uncertain ~~non-financial~~at ~~end~~this ~~user exemption from the margin requirements~~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 full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until all of the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or increase our exposure to less creditworthy counterparties. 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.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.

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 become subject to or otherwise impacted by such regulations. As is the case with the Dodd-Frank Act and the regulations promulgated under it, the implementing regulations adopted by the EU and by other non-U.S. jurisdictions could have ana material adverse effect on us, our financial condition and our results of operations.

~~Terrorist~~Risks ~~attacks~~Related ~~and the threat of terrorist attacks have resulted in increased costs~~ to ~~our~~Our ~~business.~~Indebtedness ~~Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.~~

~~The~~Increases ~~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~~interest ~~and~~rates oncould usadversely inaffect ~~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~~business.

~~Increased~~We ~~security~~have ~~measures~~significant ~~taken~~exposure byto usincreases asin ainterest ~~precaution~~rates. ~~against~~As ~~possible~~of ~~terrorist~~December ~~attacks~~31, ~~have~~2020, ~~resulted~~our intotal ~~increased~~indebtedness ~~costs~~was to$7,246.0 ~~our~~million, ~~business~~excluding $0.2 ~~Uncertainty~~million ~~surrounding~~of ~~continued~~net ~~hostilities~~premiums inand ~~the~~$45.5 ~~Middle~~million ~~East~~of ornet ~~other~~debt ~~sustained~~issuance ~~military~~costs, ~~campaigns~~of ~~may~~which ~~affect~~$6,585.2 ~~our~~million ~~operations~~was inat ~~unpredictable~~fixed ~~ways~~interest rates, ~~including~~$630.0 ~~disruptions~~million ofwas ~~crude~~at ~~oil~~variable ~~supplies~~interest rates and ~~markets~~$30.8 ~~for~~million ~~our~~of ~~products,~~finance ~~and~~lease liabilities. A hypothetical change of 100 basis points in the ~~possibility~~rate ~~that~~of ~~infrastructure~~our ~~facilities~~variable ~~could~~interest berate ~~direct~~debt ~~targets,~~would orimpact ~~indirect~~our ~~casualties~~annual interest expense by $6.3 million based on our December 31, 2020 debt balances. As a result of anthis ~~act~~amount of ~~terror~~variable interest rate debt, our results of operations could be adversely affected by increases in interest rates.

~~Changes~~We inhave ~~the~~a ~~insurance~~substantial ~~markets~~amount ~~attributable~~of toindebtedness ~~terrorist~~which ~~attacks~~ may ~~make~~adversely ~~certain~~affect ~~types~~our offinancial ~~insurance~~position ~~more~~and ~~difficult~~we ~~for us to obtain. Moreover, the insurance that~~ may still be ~~available~~able to usincur ~~may~~substantially ~~be significantly~~ more ~~expensive~~debt, ~~than~~which ~~our~~could ~~existing~~collectively ~~insurance~~increase ~~coverage or coverage may be reduced or unavailable. Instability in~~ the ~~financial~~risks ~~markets~~associated aswith acompliance ~~result~~with ~~of terrorism or war could also affect~~ our ~~ability~~financial ~~to raise capital~~covenants.

We ~~face~~have ~~opposition~~a tosubstantial ~~operation~~amount of indebtedness. As of December 31, 2020, we had $6,530.6 million outstanding of our senior unsecured notes and ~~expansion~~$54.6 million of outstanding senior notes of TPL, excluding $0.2 million of unamortized net discounts and premiums. We also had $350.0 million outstanding under our ~~pipelines~~Securitization Facility. In addition, we had $44.4 million of letters of credit outstanding and ~~facilities~~$1,875.6 ~~from~~million ~~various~~of ~~individuals~~additional borrowing capacity available under the TRP Revolver. Our $2.2 billion TRP Revolver allows us to request increases in commitments up to an additional $500 million. For the years ended December 31, 2020, 2019 and ~~groups~~2018, our consolidated interest expense, net was $378.8 million, $320.8 million and $170.0 million.

WeIn ~~have~~August ~~experienced~~2020, ~~and~~ we ~~anticipate~~issued ~~that~~$1.0 webillion ~~will~~aggregate ~~encounter~~principal ~~from~~amount ~~time~~of to4⅞% ~~time~~Senior Notes due 2031, ~~opposition~~resulting in total net proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the ~~operation~~August Tender Offer and ~~expansion~~redeem ofany ~~our~~6¾% ~~pipelines~~Notes ~~and~~that ~~facilities~~remained ~~from~~outstanding ~~governmental~~after ~~officials,~~consummation ~~non-governmental~~of ~~environmental~~the ~~organizations~~August ~~and~~Tender ~~groups~~Offer, ~~landowners,~~with ~~tribal~~the remainder used for repayment of borrowings under the TRP Revolver.

Our substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

•

satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;

•

we will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;

•

our debt level may influence how counterparties view our creditworthiness, which could limit our ability to enter into commercial transactions at favorable rates or require us to post additional collateral in commercial transactions;

•

our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•

our debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.

Our long-term unsecured debt is currently rated by Standard & Poor’s Corporation (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”). As of December 31, 2020, Targa’s senior unsecured debt was rated “BB” by S&P. As of December 31, 2020, Targa’s senior unsecured debt was rated “Ba3” by Moody’s. Any future downgrades in our credit ratings could negatively impact our cost of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, investments or capital expenditures, acquisitions, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cash distributions. 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 TRP Revolver provides available commitments of $2.2 billion and allows us to request increases in commitments up to an additional $500 million. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If we incur additional debt, this could increase the risks associated with compliance with our financial covenants.

The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.

The agreements governing our outstanding indebtedness contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests. These agreements include covenants that, among other things, restrict our ability to:

•

incur or guarantee additional indebtedness or issue preferred units;

•

pay distributions 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;

~~groups,~~• ~~local~~enter ~~groups~~into sale and ~~other advocates. In some instances, we encounter opposition which disfavors hydrocarbon~~lease-~~based~~back ~~energy~~transactions ~~supplies regardless of practical implementation~~ or ~~financial considerations. Opposition to our operation and expansion can~~ take ~~many forms, including the delay, denial~~ -or-pay ~~termination~~contracts; of required governmental permits or approvals, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets or lawsuits or other actions designed to prevent, disrupt, delay or terminate the operation or expansion of our assets and business. In addition, destructive forms of protest or opposition by activists, including acts of sabotage or eco terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that restricts, delays or prevents the expansion of our business, interrupts the revenues generated by our operations or causes us to make significant expenditures not covered by insurance could adversely affect our business, results of operations, and financial condition.

We• ~~are~~change ~~subject~~business toactivities ~~cyber~~conducted ~~security~~by ~~risks~~us. ~~A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.~~

~~The~~In ~~oil~~addition, ~~and~~certain ~~natural~~of ~~gas~~our ~~industry~~debt ~~has~~agreements ~~become~~require ~~increasingly~~us ~~dependent on digital technologies~~ to ~~conduct~~satisfy ~~business.~~and ~~For~~maintain ~~example,~~specified wefinancial ~~depend~~ratios ~~on digital technologies to operate our facilities, serve our customers~~ and ~~record~~other financial ~~data.~~condition ~~At the same time, cyber incidents, including deliberate attacks, have increased~~tests. ~~The~~Our ~~U.S.~~ability ~~government~~to ~~has~~meet ~~issued~~those ~~public~~financial ~~warnings~~ratios ~~that~~and ~~indicate~~tests ~~that~~can ~~energy assets might~~ be ~~specific~~affected ~~targets~~by ofevents ~~cyber~~beyond ~~security threats. Our technologies, systems and networks, and those of~~ our ~~vendors~~control, ~~suppliers, customers~~ and ~~other~~we ~~business~~cannot ~~partners,~~assure ~~may~~you ~~become the target of cyberattacks or information security breaches~~ that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could adversely disrupt our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will ~~likely~~meet bethose ~~required~~ratios ~~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~~tests. ~~Our insurance coverages for cyberattacks may not be sufficient to cover all the losses we may experience as a result of a cyber incident.~~

WeA ~~are~~breach orof ~~may~~any ~~become~~of ~~subject~~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 ~~cybersecurity~~be immediately due and ~~data~~payable ~~privacy~~and ~~laws~~all applicable commitments to extend further credit could be terminated. For example, ~~regulations~~if we are unable to repay the accelerated debt under the TRP Revolver, ~~litigation~~the ~~and~~lenders ~~directives~~under ~~relating~~the TRP Revolver could proceed against the collateral granted to them to secure that indebtedness. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the assets and equity of certain of our ~~processing~~subsidiaries as collateral under the TRP Revolver and the accounts receivables of ~~personal~~Targa ~~information~~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.

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.

Risks Related to Our Structure

Targa owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa has conflicts of interest with us and may favor its own interests to your detriment.

All of our general partner’s directors and all of its executive officers are directors or officers of Targa. Therefore, conflicts of interest may arise between Targa, including our general partner, on the one hand, and us and our limited partners, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests over the interests of our limited partners. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires Targa to pursue a business strategy that favors us. Targa’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Targa, which may be contrary to our interests; and

• our general partner is allowed to take into account the interests of parties other than us, such as Targa or its owners, in resolving conflicts of interest.

Targa is not limited in its ability to compete with us and is under no obligation to offer assets it may acquire to us, which could limit our ability to acquire additional assets or businesses.

Our partnership agreement does not prohibit Targa from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Targa may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition from Targa could adversely impact our results of operations and cash available for distribution.

The credit and business risk profile of our general partner could adversely affect our credit ratings and profile.

The credit and business risk profiles of our general partner may be factors in credit evaluations of us. This is because our general partner can exercise significant influence over our business, including our cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness.

Targa, the owner of our general partner and all of our common units, is dependent on the cash distributions from its indirect general partner and limited partner equity interests in us to provide working capital. Any distributions by us to such entities will be made only after satisfying our then-current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.

~~Our~~Risks ~~partnership~~Related ~~agreement limits our general partner’s fiduciary duties~~ to ~~our~~Regulatory ~~limited partners and restricts the remedies available to limited partners for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.~~Matters

~~The~~Our ~~directors~~ and ~~officers~~our ofcustomers’ ~~our~~operations ~~general~~are ~~partner~~subject ~~have~~to a ~~fiduciary~~number ~~duty~~of torisks ~~manage~~arising ~~our~~out ~~general~~of ~~partner~~the inthreat aof ~~manner~~climate ~~beneficial~~change (including legislation or regulation to ~~its~~address ~~owner,~~climate ~~Targa.~~change) ~~Our~~that ~~partnership~~could ~~agreement~~result ~~contains~~in ~~provisions~~increased ~~that~~operating ~~reduce~~costs, limit the ~~standards~~areas toin which ~~our~~oil ~~general~~and ~~partner~~natural ~~would~~gas ~~otherwise~~production bemay ~~held~~occur, byand ~~state~~reduce ~~fiduciary~~demand ~~duty~~for ~~laws.~~the ~~For~~products ~~example,~~and ~~our~~services ~~partnership~~we ~~agreement:~~provide.

•The ~~permits~~threat ~~our~~of ~~general~~climate ~~partner~~change continues to ~~make~~attract aconsiderable ~~number~~attention ofin ~~decisions~~the United States and in ~~its~~foreign ~~individual~~countries. ~~capacity~~As a result, asnumerous ~~opposed~~proposals have been made and could continue to inbe ~~its~~made ~~capacity~~at asthe ~~our~~international, ~~general~~national, ~~partner.~~regional ~~This~~and ~~entitles~~state ~~our~~levels ~~general~~of ~~partner~~government to ~~consider~~monitor ~~only~~and ~~the~~limit ~~interests~~existing ~~and~~emissions ~~factors~~of ~~that~~GHGs itas ~~desires~~well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and itnatural ~~has~~gas noexploration ~~duty~~and orproduction ~~obligation~~customers are subject to ~~give~~a ~~any~~series ~~consideration~~of toexecutive, ~~any~~regulatory, ~~interest~~political, litigation, and financial risks associated with the production and processing of orfossil ~~factors~~fuels ~~affecting~~and ~~us;~~emission of GHGs.

• provides that our general partner does not have any liability to us or our limited partners for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;45

•In ~~generally~~the ~~provides~~United ~~that~~States, ~~affiliated~~no ~~transactions~~comprehensive climate change legislation has been implemented at the federal level, but President Biden has announced plans to take action with regards to climate change, has already signed several executive orders to this effect in January 2021 and, ~~resolutions~~with control of ~~conflicts~~Congress ofshifting ~~interest~~in ~~not~~January ~~approved~~2021, byis expected to pursue legislative as well as other executive and regulatory initiatives in the ~~conflicts~~future ~~committee~~to oflimit GHG emissions. Moreover, because the ~~board~~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 ~~directors~~GHG emissions from certain petroleum and natural gas system sources, implement New Source Performance Standards (“NSPS”) directing the reduction of ~~our~~methane ~~general~~from ~~partner~~certain ~~acting~~new, modified, or reconstructed facilities in ~~good~~the ~~faith~~oil and ~~not~~natural ~~involving~~gas asector, ~~vote~~and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. In recent years, there has been considerable uncertainty surrounding regulation of ~~limited~~the ~~partners~~emissions ~~must~~of methane, which may be onreleased ~~terms~~during nohydraulic ~~less~~fracturing, ~~favorable~~as tothe usEPA ~~than~~under ~~those~~the ~~generally~~Obama ~~being~~Administration ~~provided~~published final regulations under the CAA establishing performance standards in 2016, but since that time the EPA under the Trump Administration has undertaken several measures to ordelay ~~available~~implementation ~~from~~of ~~unrelated~~the ~~third~~methane ~~parties~~standards, orincluding ~~must~~publishing bein ~~“fair~~September 2020 final rule policy and ~~reasonable”~~technical amendments to usthe NSPS, asfor ~~determined~~stationary sources of air emissions. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and VOC requirements for the remaining sources that were established by ~~our~~former ~~general~~President ~~partner~~Obama's inAdministration, ~~good~~whereas ~~faith~~the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. Various industry and environmental groups are separately challenging both the 2016 standards and the EPA’s September 2020 final rules and on January 20, 2021, President Biden issued an executive order, that among other things, indirected ~~determining~~EPA ~~whether~~to reconsider the technical amendments and issue a ~~transaction~~proposed rule suspending, revising or ~~resolution~~rescinding those amendments by no later than September 2021. A reconsideration of the September 2020 policy amendments is ~~“fair~~expected ~~and~~to ~~reasonable~~follow. The January 20,” ~~our~~2021 ~~general~~executive ~~partner~~order ~~may~~also ~~consider~~directed the ~~totality~~establishment of ~~the~~new ~~relationships~~methane ~~between~~and ~~the~~volatile ~~parties~~organic ~~involved~~compound standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other ~~transactions~~regulatory initiatives that ~~may~~are befocused ~~particularly~~on ~~advantageous~~such orareas ~~beneficial~~as toGHG ~~us;~~cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.

•At ~~provides~~the ~~that~~international ~~our~~level, ~~general~~the ~~partner~~non-binding ~~and~~“Paris ~~its~~Agreement” ~~officers~~calls ~~and~~for ~~directors~~parties ~~are~~to ~~not~~undertake ~~liable~~efforts ~~for~~to ~~monetary~~limit ~~damages~~their toGHG ~~us,~~emissions ~~our~~through ~~limited~~individually-determined ~~partners~~reduction orgoals ~~assignees~~every ~~for~~five ~~any~~years ~~acts~~beginning orin ~~omissions~~2020. ~~unless~~Although ~~there~~the United States under the Trump Administration withdrew from the agreement, President Biden has ~~been~~issued aexecutive ~~final~~orders in January 2021 recommitting the United States to the Paris Agreement and ~~non-appealable~~calling ~~judgment~~for ~~entered~~the byfederal agovernment ~~court~~to ofbegin ~~competent~~formulating ~~jurisdiction~~the ~~determining~~United ~~that~~States’ ~~our~~nationally ~~general~~determined ~~partner~~emissions orreduction ~~those~~goal ~~other~~under ~~persons~~the ~~acted~~agreement. inWith ~~bad~~the ~~faith~~United orStates ~~engaged~~recommitting into ~~fraud~~the Paris Agreement, executive orders may be issued or ~~willful~~federal ~~misconduct~~legislation or, inregulatory initiatives may be adopted to achieve the ~~case~~agreement’s ofgoals, awhich ~~criminal~~could ~~matter~~require us or our customers to incur increased, ~~acted~~potentially ~~with~~significant, ~~knowledge~~costs ~~that~~to ~~the~~comply ~~conduct~~with ~~was~~such ~~criminal;~~requirements. ~~and~~

•Governmental, ~~provides~~scientific, ~~that~~and inpublic ~~resolving~~concern ~~conflicts~~over the threat of ~~interest,~~climate itchange isarising ~~presumed~~from ~~that~~GHG emissions has resulted in ~~making~~increasing ~~its~~political ~~decision~~risks ~~our~~in ~~general~~the ~~partner~~United ~~acted~~States. inBeyond ~~good~~the ~~faith~~Biden Administration’s recommitting the United States to the Paris Agreement and proposing to issue more stringent methane standards, on January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new oil and ingas ~~any~~leases ~~proceeding~~and ~~brought~~drilling bypermits oron non-Indian federal lands and waters for a period of 60 days. Building on ~~behalf~~this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of ~~any~~a ~~limited~~comprehensive ~~partner~~review orand usreconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. The January 20, 2021 and January 27, 2021 orders do not apply to existing leases and the ~~person~~January ~~bringing~~27, or2021 ~~prosecuting~~order ~~such~~further ~~proceeding~~directs ~~will~~applicable agencies to eliminate fossil fuel subsidies. Legal challenges to these suspensions are expected, with at least one industry group filing a lawsuit on January 27, 2021, in Wyoming federal district court and seeking to have the ~~burden~~moratorium ofon ~~overcoming~~leasing ~~such~~declared ~~presumption~~invalid.

~~Your~~Litigation ~~liability~~risks ~~may~~are ~~not~~also beincreasing, ~~limited~~as if a number of states, municipalities and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, ~~finds~~alleging, among other things, that ~~limited~~such ~~partner~~companies ~~action~~created ~~constitutes~~public ~~control~~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 ~~our~~the ~~business~~adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Our partnership is organized under Delaware law and we conduct business in Louisiana, Texas, Oklahoma and North Dakota as well as other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or that your right to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

~~Limited~~There ~~partners~~are also increasing financial risks for fossil fuel producers as well as other companies handling fossil fuels, including owners of terminals, pipelines and refineries, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may ~~have~~elect ~~liability~~in the future to ~~repay~~shift ~~distributions~~some ~~that~~or ~~were~~all ~~wrongfully~~of ~~distributed~~their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development of production activities.

~~Under~~The ~~certain~~adoption ~~circumstances,~~and ~~limited~~implementation ~~partners~~of ~~may~~any ~~have~~international, tofederal ~~repay~~or ~~amounts~~state ~~wrongfully~~executive ~~returned~~actions, legislation, or ~~distributed~~regulatory toinitiatives ~~them.~~that ~~Under~~impose ~~Section 17-607~~more ofstringent standards for GHG emissions from the ~~Delaware~~oil ~~Revised~~and ~~Uniform~~natural ~~Limited~~gas ~~Partnership Act,~~sector weor ~~may~~otherwise ~~not~~restrict ~~make~~the aareas ~~distribution~~in towhich ~~limited~~this ~~partners~~sector ifmay ~~the~~produce ~~distribution~~oil ~~would~~and ~~cause~~natural ~~our~~gas ~~liabilities~~or togenerate ~~exceed~~GHG ~~the~~emissions ~~fair~~could ~~value~~result in increased costs of ~~our~~compliance ~~assets.~~or ~~Delaware~~costs ~~law~~of ~~provides~~consuming, ~~that~~and thereby reduce demand for aoil ~~period~~and ofnatural ~~three~~gas, ~~years~~which ~~from~~could ~~the~~reduce ~~date~~demand offor ~~the~~our ~~impermissible~~services ~~distribution~~and products. Additionally, ~~limited~~political, ~~partners~~litigation, ~~who~~and ~~received~~financial ~~the~~risks ~~distribution~~may result in our oil and ~~who~~natural ~~knew~~gas atcustomers ~~the~~restricting ~~time~~or ofcancelling ~~the~~production ~~distribution~~activities, ~~that~~incurring itliability ~~violated~~for ~~Delaware~~infrastructure ~~law~~damages ~~will~~as bea ~~liable~~result of climatic changes, or impairing their ability to ~~the~~continue ~~limited~~to ~~partnership~~operate ~~for~~in ~~the~~an ~~distribution~~economic ~~amount.~~manner, ~~Substituted~~which ~~limited~~also ~~partners~~could ~~are~~reduce ~~liable~~demand for ~~the~~our ~~obligations~~services and products. One or more of ~~the~~these ~~assignor~~developments tocould ~~make~~have ~~contributions~~a tomaterial ~~the~~adverse ~~partnership~~effect ~~that~~on ~~are~~our ~~known~~business, tofinancial ~~the~~condition ~~substituted~~and ~~limited~~results ~~partner~~of atoperation. Moreover, the ~~time~~increased itcompetitiveness ~~became~~of aalternative ~~limited~~energy ~~partner~~sources (such as wind, solar geothermal, tidal and biofuels) could reduce demand for ~~unknown~~hydrocarbons, ~~obligations~~and iftherefore ~~the~~for ~~liabilities~~our ~~could~~services, bewhich ~~determined~~would ~~from~~lead ~~the~~to ~~partnership~~a ~~agreement~~reduction in our revenues. ~~Liabilities~~Finally, toincreasing ~~partners~~concentrations onof ~~account~~GHG in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of ~~their~~storms, ~~partnership~~droughts, ~~interest~~floods, rising sea levels and ~~liabilities~~other ~~that~~climatic ~~are~~events. ~~non-recourse~~If any such climate changes were to ~~the~~occur, ~~partnership~~they ~~are~~could ~~not~~have ~~counted~~a ~~for~~material ~~purposes~~adverse effect on our financial condition and results of ~~determining~~operations ~~whether~~and athe ~~distribution~~financial iscondition ~~permitted~~and operations of our customers.

~~Risks~~Increasing ~~Related~~attention to ~~the~~environmental, ~~Preferred~~social ~~Units~~and governance (ESG) matters may impact our business.

WeIncreasing ~~cannot~~attention ~~assure~~to ~~you~~climate ~~that~~change, weincreasing ~~will~~societal beexpectations ~~able~~on companies to ~~pay~~address ~~distributions~~climate onchange, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our ~~Preferred~~customers’ ~~Units~~products ~~regularly~~and our services, reduced profits, increased investigations and ~~the~~litigation, ~~agreements~~and ~~governing~~negative impacts on our ~~indebtedness~~access ~~may~~to ~~limit~~capital ~~the~~markets. ~~cash~~Increasing ~~available~~attention to ~~make~~climate ~~distributions~~change, onfor ~~the~~example, ~~Preferred~~may ~~Units~~result in demand shifts for our customers’ hydrocarbon products and additional governmental investigations and private litigation against those customers.

~~Subject~~In toaddition, ~~the~~organizations ~~limitations~~that onprovide ~~restricted~~information ~~payments~~to ~~contained~~investors inon ~~our~~corporate ~~indentures~~governance and inrelated ~~our~~matters ~~senior~~have ~~secured~~developed ~~credit~~ratings ~~agreement,~~processes wefor ~~distribute~~evaluating ~~all~~companies ofon ~~our~~their ~~“available~~approach ~~cash” each quarter~~ to ~~our~~ESG ~~limited partners and our general partner~~matters. ~~“Available~~Additionally, ~~cash”~~we isand ~~defined~~other companies in our ~~partnership~~industry ~~agreement~~publish ~~and~~sustainability ~~described~~reports ~~below~~that ~~under~~are ~~“Item~~made 5.available ~~Market~~to ~~for~~investors. ~~Registrant’s~~Such ~~Common~~ratings ~~Equity,~~and ~~Related~~reports ~~Unitholder~~are ~~Matters~~used ~~and~~by ~~Issuer~~some ~~Purchases~~investors ofto ~~Equity~~inform ~~Securities—Distributions~~their ofinvestment ~~Available~~and ~~Cash—Definition~~voting ~~of Available Cash~~decisions.” AsUnfavorable aESG ~~result,~~ratings wemay dolead ~~not expect~~ to ~~accumulate~~increased ~~significant~~negative ~~amounts~~investor ofsentiment ~~cash.~~toward ~~Depending~~us onor ~~the~~our ~~timing~~customers and ~~amount~~to the diversion of ~~our~~investment ~~cash~~to ~~distributions,~~other ~~these~~industries ~~distributions~~which could ~~significantly~~have ~~reduce~~a ~~the~~negative ~~cash~~impact ~~available~~on toour usstock inprice ~~subsequent~~and/or ~~periods~~our access to ~~make~~and ~~payments~~costs onof ~~the Preferred Units~~capital.

~~The~~We ~~Preferred Units are subordinated to our existing and future debt obligations, and~~ could beincur ~~diluted~~significant bycosts ~~the~~in ~~issuance~~complying ofwith ~~additional~~more ~~units,~~stringent ~~including~~occupational ~~additional~~safety ~~Preferred Units,~~ and byhealth ~~other transactions~~requirements.

~~The~~We ~~Preferred Units~~ are ~~subordinated~~subject to ~~all~~stringent offederal ~~our~~and ~~existing~~state laws and ~~future~~regulations, ~~indebtedness (~~including ~~indebtedness~~the ~~outstanding~~federal ~~under~~Occupational ~~our~~Safety ~~senior~~and ~~secured~~Health ~~credit~~Act ~~facility~~and comparable state statutes, ~~our~~whose ~~existing~~purpose ~~senior~~is ~~notes~~to protect the health and ~~indebtedness~~safety ~~outstanding~~of ~~under~~workers, ~~our~~both ~~Securitization~~generally ~~Facility)~~and within the pipeline industry. ~~The~~In ~~payment~~addition, ofthe ~~principal~~federal Occupational Safety and ~~interest~~Health onAdministration’s ~~our~~(“OSHA”) ~~debt~~hazard ~~reduces~~communication ~~cash~~standard, ~~available~~the ~~for~~EPA ~~distribution~~community right-to-know usregulations under Title III of the Federal Superfund Amendment and onReauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our ~~units~~operations and that this information be provided to employees, ~~including~~state ~~the~~and ~~Preferred~~local ~~Units~~government authorities and citizens. ~~The~~We ~~issuance~~and ofthe ~~additional~~entities ~~units~~in ~~pari~~which ~~passu~~we ~~with~~own oran ~~senior~~interest are subject to ~~the~~OSHA ~~Preferred~~Process ~~Units~~Safety ~~would~~Management ~~dilute~~regulations, ~~the~~which ~~interests~~are ofdesigned to prevent or minimize the ~~holders~~consequences of ~~the~~catastrophic ~~Preferred~~releases ~~Units~~of toxic, ~~and~~reactive, flammable or explosive chemicals. The regulations apply to any ~~issuance~~process ofthat ~~Senior~~(1) ~~Securities~~involves a listed chemical in a quantity at or ~~Parity~~above ~~Securities~~the ~~(each~~threshold asquantity ~~defined~~specified in ~~our~~the ~~partnership~~regulation ~~agreement)~~for that chemical, or ~~additional~~(2) ~~indebtedness~~involves ~~could~~certain ~~affect~~flammable ~~our~~gases ~~ability~~or toflammable ~~pay~~liquids ~~distributions~~present on site in one location in a quantity of 10,000 ~~redeem~~pounds or ~~pay~~more. Flammable liquids stored in atmospheric tanks below their normal boiling point without the ~~liquidation~~benefit ~~preference~~of onchilling or refrigeration are exempt. 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 ~~Preferred~~imposition ~~Units~~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.

Our ability to issue parity securities in the future could adversely affect the rights of holders of our Preferred Units.

We are allowed to issue additional Preferred Units and parity securities without any vote of the holders of the Preferred Units, except where the cumulative distributions on the Preferred Units or any parity securities are in arrears. The issuance of additional Preferred Units or any parity securities would have the effect of reducing the amounts available to the holders of the outstanding Preferred Units upon our liquidation, dissolution or winding up if we do not have sufficient funds to pay all liquidation preferences of the Preferred Units and parity securities in full. It also would reduce amounts available to make distributions on the outstanding Preferred Units if we do not have sufficient funds to pay distributions on all outstanding Preferred Units and parity securities.

In addition, although holders of Preferred Units are entitled to limited voting rights, with respect to certain matters the Preferred Units will generally vote separately as a class along with all other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Preferred Units may be significantly diluted, and the holders of such other series of Parity Securities that we may issue may be able to control or significantly influence the outcome of any vote. Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Preferred Units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Tax Risks to Holders of Preferred Units

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you may be substantially reduced.

A publicly traded partnership such as us may be treated as a corporation for U.S. federal income tax purposes unless it satisfies the “qualifying income” requirement within Section 7704(d)(1)(E) of the Internal Revenue Code. Based on our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S.

~~federal~~Laws ~~income~~and ~~tax~~regulations ~~purposes~~regarding orhydraulic ~~otherwise~~fracturing ~~subject~~could usresult toin ~~taxation~~restrictions, asdelays anor ~~entity.~~cancellations Wein ~~have~~drilling ~~not~~and ~~requested,~~completing new oil and donatural ~~not~~gas ~~plan~~wells toby ~~request~~our customers, awhich ~~ruling~~could ~~from~~adversely impact our revenues by decreasing the ~~IRS~~volumes ~~with~~of ~~respect~~natural togas, ~~our~~NGLs ~~treatment~~or ascrude aoil ~~partnership~~through ~~for~~our ~~U.S.~~facilities ~~federal~~and ~~income~~reducing ~~tax~~the ~~purposes.~~utilization of our assets.

IfWhile we ~~were~~do ~~treated~~not asconduct ahydraulic ~~corporation~~fracturing, ~~for~~many ~~U.S.~~of ~~federal~~our ~~income~~oil ~~tax~~and ~~purposes,~~gas weexploration ~~would~~and ~~pay~~production ~~U.S.~~customers ~~federal~~do ~~income~~perform ~~tax~~such onactivities. ~~our~~The ~~taxable~~process ~~income~~is attypically ~~the~~regulated ~~corporate~~by ~~tax~~state ~~rate,~~oil ~~which~~and isgas ~~21%~~commissions, ~~for~~but ~~tax~~several ~~years~~federal ~~beginning~~agencies ~~after~~have ~~December~~asserted 31regulatory authority over, ~~2017~~proposed or promulgated regulations governing, and ~~would~~conducted ~~likely~~investigations ~~pay~~relating ~~state~~to ~~income~~certain ~~tax~~aspects atof ~~varying~~the ~~rates~~process, including the EPA and BLM. ~~Distributions~~The toBLM ~~you~~under ~~would~~the ~~generally~~Obama beAdministration ~~taxed~~issued ~~again~~a asrule ~~corporate~~in ~~distributions~~2015 ~~instead~~regulating ofhydraulic asfracturing ~~guaranteed~~activities ~~payments~~on federal lands including requirements for ~~the~~disclosure, ~~use~~wellbore integrity and handling of ~~capital~~flowback water; however, asin ~~described~~late ~~further~~2017, ~~below.~~the ~~Because~~BLM under the Trump Administration issued a ~~tax~~rescission ~~would~~of bethe ~~imposed~~2015 ~~upon~~rule uson ashydraulic afracturing ~~corporation,~~but ~~our~~a ~~cash~~federal ~~available~~district ~~for~~court ~~distribution~~vacated tothe ~~you~~2017 ~~may~~rescission bein ~~substantially~~July ~~reduced~~2020. ~~Therefore~~In another example, in late 2016, the ~~treatment~~EPA released its final report on the potential impacts of ushydraulic asfracturing aon ~~corporation~~drinking ~~may~~water ~~result~~resources, inconcluding athat ~~material~~“water ~~reduction~~cycle” inactivities ~~the~~associated ~~anticipated~~with ~~cash~~hydraulic ~~flow~~fracturing may impact drinking water resources under certain circumstances.

AtIn ~~the~~addition, ~~state~~although ~~level,~~Congress ~~because~~has from time to time considered but refused to adopt legislation to provide for federal regulation of ~~widespread~~hydraulic ~~state~~fracturing, ~~budget~~there ~~deficits~~is a possibility that a Biden Administration will consider such legislation and, ~~other~~in ~~reasons~~any event has already issued executive orders, ~~several~~and ~~states~~may ~~are~~issue ~~evaluating~~additional ~~ways~~orders, tosuspending ~~subject~~leasing ~~partnerships~~and topermitting ~~entity-level~~of ~~taxation~~oil ~~through~~and gas activities on federal lands and waters that have the ~~imposition~~effect of ~~state~~limiting ~~income~~hydraulic fracturing. Moreover, many states, including Texas, Louisiana and ~~franchise~~Oklahoma, ~~taxes~~have already adopted, and ~~other~~others ~~forms~~may consider adopting, legal requirements that impose stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, assess more taxes, fees or royalties on natural gas production, or otherwise limit the use of ~~taxation~~the technique. ~~For~~States ~~example~~could elect to prohibit hydraulic fracturing or high volume hydraulic fracturing altogether, weas ~~are~~several ~~subject~~states have already done. Local governments may also seek to ~~the~~adopt ~~Texas~~ordinances ~~franchise~~within ~~tax~~their atjurisdictions aregulating ~~maximum~~the ~~effective~~time, ~~rate~~place and manner of 0drilling activities in general or hydraulic fracturing activities in particular.~~75%~~ ofAdditionally, non-governmental organizations may seek to restrict hydraulic fracturing through litigation, state ballot initiatives, or protests. New or more stringent executive orders, laws, regulations or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to our ~~gross~~customers ~~income~~reducing ~~apportioned~~crude oil and natural gas drilling activities using hydraulic fracturing techniques, while increased litigation against, or public opposition with respect to ~~Texas~~activities using such techniques may result in ~~the~~operational ~~prior~~delays, ~~year~~restrictions or cessations or bans. 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.

~~Holders~~Our ofoperations ~~Preferred~~are ~~Units~~subject ~~should~~to ~~consult~~environmental ~~their~~laws ~~tax~~and ~~advisor~~regulations ~~with~~and ~~respect~~a failure to comply or an accidental release into the ~~consequences~~environment ofmay ~~owning~~cause ~~our~~us ~~Preferred~~to ~~Units~~incur significant costs and liabilities.

~~The~~Our ~~tax~~operations ~~treatment~~are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational health and safety, the discharge of ~~publicly~~pollutants ~~traded~~into ~~partnerships~~the environment or anotherwise ~~investment~~relating into environmental protection. These laws and regulations may impose numerous obligations that are applicable to our ~~Preferred~~operations ~~Units~~including ~~could~~acquisition of a permit or other approval before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be ~~subject~~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 ~~potential~~comply ~~legislative~~with pollution control requirements, ~~judicial~~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, ~~changes~~civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or ~~differing~~the ~~interpretations~~incurrence of capital expenditures; the occurrence of restrictions, ~~possibly~~delays ~~applied~~or oncancellations 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 ~~retroactive~~particular ~~basis~~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 ~~present~~risk ~~U.S. federal income tax treatment~~ of ~~publicly~~incurring ~~traded~~environmental ~~partnerships,~~costs ~~including~~and ~~us,~~liabilities ~~or an investment~~ in ~~us,~~connection ~~may~~with beour ~~modified~~operations byis ~~administrative,~~significant ~~legislative~~due orto ~~judicial~~our ~~changes~~handling orof ~~differing~~natural ~~interpretations~~gas, atNGLs, ~~any~~crude ~~time.~~oil ~~From~~and ~~time~~other topetroleum ~~time~~products, ~~members~~because of ~~Congress~~air ~~propose~~emissions and ~~consider~~product-related ~~such~~discharges ~~substantive~~arising ~~changes~~out toof ~~the~~our ~~existing~~operations, ~~U.S.~~and ~~federal~~as ~~income~~a ~~tax~~result ~~laws that would affect publicly traded partnerships, including elimination~~ of ~~partnership~~historical ~~tax~~industry ~~treatment~~operations ~~for~~and ~~certain~~waste ~~publicly~~disposal ~~traded partnerships~~practices. For example, ~~the~~an ~~“Clean~~accidental ~~Energy~~release ~~for~~from ~~America~~one ~~Act,”~~of ~~which~~our isfacilities ~~similar~~could tosubject ~~legislation~~us ~~that~~to ~~was~~substantial ~~commonly~~liabilities ~~proposed~~arising ~~during~~from ~~the~~environmental ~~Obama~~cleanup ~~Administration,~~and ~~was~~restoration ~~introduced in the U.S. Senate on May 2~~costs, ~~2019.~~claims Ifmade ~~enacted,~~by ~~this~~neighboring ~~proposal~~landowners ~~would,~~and ~~among~~ other ~~things,~~third ~~repeal~~parties ~~the qualifying income exception within Section 7704(d)(1)(E) of the Internal Revenue Code upon which we rely~~ for ~~our~~personal ~~treatment as a partnership for U.S. federal income tax purposes. In addition~~injury, ~~the~~natural ~~Treasury~~resource ~~Department~~and ~~has~~property ~~issued,~~damages and infines ~~the~~or ~~future~~penalties ~~may~~for ~~issue,~~related ~~regulations~~violations ~~interpreting~~of ~~those~~environmental laws ~~that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws~~ or ~~the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership for U~~regulations.S. ~~federal income tax purposes in the future.~~

Any modification to the U.S. federal income tax laws or interpretations thereof may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such future changes could negatively impact the value of an investment in us. You are urged to consult with your own tax advisor with respect to the status of regulatory, legislative or administrative developments and proposals and their potential effect on your investment in our Preferred Units.

The tax treatment of income attributable to distributions on our Preferred Units as guaranteed payments for the use of capital is uncertain and such distributions will not be eligible for the 20% deduction.

The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of Preferred Units as partners for tax purposes and will treat income attributable to distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Preferred Units as ordinary income. We anticipate accruing and making guaranteed payment distributions on a monthly basis. However, the accrual of such a guaranteed payment is not contingent upon a cash distribution, and holders of Preferred Units will recognize taxable income from such accrual even in the absence of a contemporaneous cash distribution. Otherwise, the holders of Preferred Units are generally neither anticipated to share in our items of income, gain, loss or deduction, nor be allocated any share of our nonrecourse liabilities. If the Preferred Units were treated as payments on indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Preferred Units.

Recently issued final Treasury Regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction. As a result income attributable to a guaranteed payment for use of capital recognized by holders of our Preferred Units is not eligible for the 20% deduction.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Preferred Units that may result in adverse tax consequences to them.

Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of the Preferred Units as “effectively connected income” (which will subject holders to U.S. net income taxation and

~~possibly~~Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the ~~branch~~cost ~~profits~~of ~~tax)~~any remediation that ~~are~~may ~~subject~~become tonecessary. ~~withholding~~For ~~taxes~~example, ~~imposed~~in at2015, the ~~highest~~EPA ~~effective~~under ~~tax~~the ~~rate~~Obama ~~applicable~~Administration toissued ~~such~~a ~~non~~final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-~~U.S.~~level ~~holders~~ozone. IfSince that time, the ~~amount~~EPA under the Trump Administration has designated attainment and non-attainment regions and, more recently, on December 31, 2020, published notice of ~~withholding~~a ~~exceeds~~final ~~the~~action ~~amount~~that, upon conducting a periodic review of ~~U.S.~~the ~~federal~~ozone ~~income~~standard ~~tax~~in ~~actually~~accord ~~due~~with CAA requirements, ~~non~~elected to retain the 2015 ozone NAAQS without revision on a going-Uforward basis.S. ~~holders~~However, ~~may~~this beDecember ~~required~~2020 final action is subject to ~~file~~legal ~~U.S.~~challenge, ~~federal~~and ~~income~~the ~~tax~~NAAQS ~~returns~~may inbe ~~order~~subject to ~~seek~~further arevision ~~refund~~under the Biden Administration. State implementation of ~~such~~the ~~excess~~revised ozone NAAQS could increase our compliance costs. ~~Non-~~Also in 2015, the EPA and U.S. ~~holders~~Army Corps of ~~Preferred~~Engineers ~~Units~~(“Corps”) ~~who~~under ~~sell~~the orObama ~~otherwise~~administration ~~dispose~~published of a ~~Preferred~~final ~~Unit~~rule ~~will~~outlining ~~also~~federal bejurisdictional ~~subject~~reach tounder ~~U.S.~~the ~~federal~~Clean ~~income~~Water ~~tax~~Act onover waters of the ~~gain~~United ~~realized~~States, ~~from~~including wetlands; however, the ~~sale~~2015 orrule ~~disposition~~was ofrepealed ~~that~~by ~~Preferred~~the ~~Unit.~~EPA ~~The~~and ~~transferee~~the ofCorps anunder ~~interest~~the Trump Administration in a ~~partnership~~final rule that isbecame ~~engaged~~effective in aDecember U2019.S. ~~trade~~The orTrump ~~business~~Administration issubsequently ~~generally~~published ~~required~~a tofinal ~~withhold~~rule ~~10%~~in April 2020 re-defining the term “waters of the ~~amount~~United ~~realized~~States” byas applied under the ~~transferor~~Clean ~~unless~~Water Act and narrowing the ~~transferor~~scope ~~certifies~~of ~~that~~waters subject to federal regulation. The April 2020 final rule is subject to various pending legal challenges and it is ~~not~~expected that a ~~foreign~~Biden ~~person,~~Administration ~~and~~may wereconsider ~~are~~this ~~required~~final torule. ~~deduct~~If the EPA and ~~withhold~~the ~~from~~Corps under the ~~transferee~~Biden ~~amounts~~Administration ~~that~~revises ~~should~~the ~~have~~June ~~been~~2020 ~~withheld~~final byrule ~~the~~in ~~transferees~~a ~~but~~manner ~~were~~similar ~~not~~to ~~withheld.~~or ~~However,~~more ~~pending~~stringent than the ~~issuance~~original of2015 final ~~regulations~~rule, ~~the~~or ~~IRS~~if ~~has~~any ~~suspended~~challenge to the ~~application~~June of2020 ~~this~~final ~~withholding~~ rule tois ~~transfers~~successful, the scope of ~~publicly~~the ~~traded~~Clean ~~interests~~Water Act’s jurisdiction in ~~publicly~~areas ~~traded~~where ~~partnerships.~~we Ifor ~~recently~~our ~~promulgated~~customers ~~regulations~~conduct ~~are~~operations ~~finalized~~could asagain ~~proposed,~~be expanded. Any such ~~regulations~~developments ~~would~~could ~~provide~~delay, ~~with~~restrict ~~respect~~or tohalt ~~transfers~~permitting ofor ~~publicly~~development ~~traded~~of ~~interests~~projects, result in ~~publicly~~longer ~~traded~~permitting ~~partnerships~~timelines, ~~effected~~or ~~through~~increased acompliance ~~broker,~~expenditures ~~that~~or ~~the~~mitigation ~~obligation~~costs tofor ~~withhold~~our isand ~~imposed~~our onoil ~~the~~and ~~transferor~~natural gas customers’s ~~broker~~operations. ~~However,~~These itresults ismay ~~not~~consequently ~~clear~~reduce ~~when~~the ~~such~~rate ~~regulations~~of ~~will~~production beof ~~finalized~~natural ~~and~~gas ifor ~~they~~crude ~~will~~oil befrom ~~finalized~~operators with whom we have a business relationship and, in ~~their~~turn, ~~current~~have ~~form.~~a material adverse effect on our business, results of operations and cash flows.

~~Furthermore,~~A ~~the~~change ~~treatment~~in ofthe ~~guaranteed~~jurisdictional ~~payments~~characterization ~~for~~of ~~the~~some ~~use~~ of ~~capital~~our toassets ~~tax-exempt~~by ~~investors is not certain and such payments may be treated as unrelated business taxable income, or UBTI, for~~ federal ~~income tax purposes. With respect to taxable years beginning after December 31~~, ~~2017~~state, ~~subject~~tribal toor ~~the~~local ~~proposed~~regulatory ~~aggregation~~agencies ~~rules for certain similarly situated businesses~~ or ~~activities issued by the Treasury Department,~~ a ~~tax-exempt~~change ~~entity~~in ~~with~~policy ~~more than one unrelated trade or business (including~~ by ~~attribution~~those ~~from~~agencies ~~investment~~may result in aincreased ~~partnership~~regulation ~~such as ours) is required to compute the unrelated business taxable income~~ of ~~such~~our ~~tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result~~assets, ~~for~~which ~~years beginning after December 31, 2017, it~~ may ~~not~~cause beour ~~possible~~revenues ~~for tax-exempt entities~~ to ~~utilize~~decline ~~losses~~and ~~from~~operating anexpenses ~~investment in our partnership~~ to ~~offset~~increase ~~unrelated~~or ~~business~~delay ~~taxable~~or ~~income~~increase ~~from~~the ~~another~~cost ~~unrelated~~of ~~trade~~expansion ~~or business and vice versa~~projects.

IfWith ~~you~~the exception of the Driver Residue Pipeline, TPL SouthTex Transmission pipeline and Tarzan 311 residue line, which are aeach ~~tax-exempt~~subject ~~entity~~to limited FERC regulation under either the NGA or aNGPA, our natural gas pipeline operations are generally exempt from FERC regulation, but FERC regulation still affects our non-UFERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in a given year.S 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. ~~person~~However, ~~you~~the ~~should~~distinction ~~consult~~between ~~your~~FERC-regulated ~~tax~~transmission ~~advisor~~services ~~with~~and ~~respect~~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 ~~consequences~~courts or Congress. We also operate natural gas pipelines that extend from some of ~~owning~~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 ~~Preferred~~plant ~~Units~~tailgate pipelines are relatively short, we treat them as “stub” lines, which are exempt from FERC’s jurisdiction under the Natural Gas Act.

IfTarga ~~the~~NGL, ~~IRS~~Targa ~~contests~~Gulf ~~the~~Coast, Uand Grand Prix Joint Venture have pipelines that are considered common carrier pipelines subject to regulation by FERC under ICA.S. ~~federal~~The ~~income~~ICA ~~tax~~requires ~~positions~~that we ~~take~~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 ~~market~~rates we charge for ~~our~~providing ~~Preferred~~transportation ~~Units~~services ~~may~~as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be ~~adversely~~“just ~~affected~~and reasonable” and non-discriminatory. With respect to pipelines that have been granted a waiver of the ~~cost~~ICA and related regulations by FERC, should a particular pipeline’s circumstances change, FERC could, either at the request of ~~any~~other ~~contest~~entities ~~will~~or ~~reduce~~on ~~our~~its ~~cash~~own ~~available~~initiative, assert that such pipeline no longer qualifies for ~~distribution~~a waiver. In the event that FERC were to ~~you.~~determine ~~The~~that ~~Bipartisan~~one ~~Budget~~or ~~Act~~more of ~~2015~~these ~~alters~~pipelines ~~the~~no ~~procedures~~longer qualified for ~~assessing~~a ~~and~~waiver, ~~collecting~~we ~~taxes~~would ~~due~~likely ~~for~~be ~~taxable~~required ~~years~~to ~~beginning~~file ~~after~~a ~~December~~tariff ~~31,~~with ~~2017~~FERC for the applicable pipeline(s), inprovide a ~~manner~~cost ~~that~~justification ~~could~~for ~~substantially~~the ~~reduce~~transportation ~~cash~~charge, ~~available~~and ~~for~~provide ~~distribution~~service to ~~you~~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.

WeThe ~~have~~classification ~~not~~of ~~requested,~~some ~~and~~of doour ~~not~~gathering ~~plan~~facilities, totransportation ~~request~~pipelines, aand ~~ruling~~purchase ~~from~~and ~~the~~sale ~~IRS~~transactions ~~with respect to our treatment~~ as aFERC-jurisdictional ~~partnership for U.S. federal income tax purposes~~ or ~~any~~non-jurisdictional ~~other matter affecting us. The IRS~~ may ~~adopt positions that differ from the positions we take. It may~~ be ~~necessary~~subject to ~~resort~~change tobased ~~administrative~~on orfuture ~~court~~determinations ~~proceedings~~by toFERC, ~~sustain some or all of~~ the ~~positions~~courts ~~we take. A court may not agree with some~~ or ~~all~~Congress, ofin ~~the positions we take. Any contest with the IRS may materially and adversely impact the market for our Preferred Units and the price at~~ which ~~they trade. In addition~~case, our operating costs ofcould ~~any~~increase ~~contest~~and ~~with~~we ~~the~~could ~~IRS will~~ be ~~borne~~subject ~~indirectly~~to byenforcement ~~our~~actions ~~partners~~under ~~because~~ the ~~costs~~EP ~~will~~Act ~~reduce~~of ~~our cash available for distribution~~2005.

The Bipartisan Budget Act of 2015, which is applicable to us for taxable years beginning after December 31, 2017, alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised information statements to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our partners may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, partners during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

AVarious ~~holder~~federal ofagencies ~~Preferred~~within ~~Units~~the ~~whose~~U.S. ~~units~~Department ~~are~~of the ~~subject~~Interior, particularly the BLM, Office of aNatural ~~securities~~Resources ~~loan~~Revenue (~~e.g.~~formerly the Minerals Management Service) and the Bureau of Indian Affairs, aalong ~~loan~~with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to ~~cover~~operations on the Fort Berthold Indian Reservation, on which we operate a ~~short~~significant ~~sale~~portion of ~~units)~~our ~~may~~Badlands begathering ~~considered~~and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to ~~have~~enforce ~~disposed~~certain oflaws ~~those~~and ~~units.~~regulations Ifindependent sofrom federal, ~~such~~state ~~holder~~and oflocal ~~Preferred~~statutes ~~Units~~and ~~may~~regulations. noThese ~~longer~~tribal belaws ~~treated~~and ~~for~~regulations ~~tax~~include ~~purposes~~various astaxes, afees ~~partner~~and ~~with~~other ~~respect~~conditions that apply to ~~those~~lessees, ~~units~~operators ~~during~~and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can generally be subject to the ~~period~~Native American tribal court system. One or more of these factors may increase our costs of doing business on the ~~loan~~Fort Berthold Indian Reservation and ~~could~~may ~~recognize~~have ~~gain~~an oradverse ~~loss~~impact ~~from~~on our ability to effectively transport products within the ~~disposition~~Fort Berthold Indian Reservation or to conduct our operations on such lands.

~~Because~~Other ~~there~~FERC ~~are~~regulations nomay ~~specific~~indirectly ~~rules~~impact ~~governing~~our ~~the~~businesses ~~federal~~and ~~tax~~the ~~consequences~~markets offor ~~loaning~~products aderived ~~partnership~~from ~~interest,~~these abusinesses. ~~holder~~FERC’s ofpolicies ~~Preferred~~and ~~Units~~practices ~~whose~~across ~~units are~~ the ~~subject~~range of aits ~~securities~~natural ~~loan~~gas ~~may~~regulatory beactivities, ~~considered~~including, tofor ~~have~~example, ~~disposed~~its ofpolicies ~~the~~on ~~loaned~~open ~~units.~~access Intransportation, ~~that~~gas ~~case~~quality, ~~the~~ratemaking, ~~holder~~capacity ~~may~~release noand ~~longer~~market becenter ~~treated~~promotion, ~~for~~may ~~tax~~indirectly ~~purposes~~affect asthe anatural ~~partner~~gas ~~with~~market. ~~respect~~In torecent ~~those~~years, ~~units~~FERC ~~during~~has ~~the~~pursued ~~period~~pro-competitive ofpolicies ~~the~~in ~~loan,~~its ~~and~~regulation ~~the~~of ~~holder~~interstate ~~may~~natural ~~recognize~~gas ~~gain or loss from such disposition~~pipelines. ~~Unitholders~~However, ~~desiring~~we tocannot assure ~~their~~you ~~status~~that asFERC ~~partners~~will ~~and~~continue ~~avoid~~this ~~the~~approach ~~risk~~as ofit ~~gain~~considers ~~recognition~~matters ~~from~~such aas ~~loan~~pipeline ofrates ~~their~~and ~~units~~rules ~~are~~and ~~urged~~policies tothat ~~consult~~may aaffect ~~tax~~rights ~~advisor~~of access to ~~determine~~transportation ~~whether~~capacity. itFor ismore ~~advisable~~information toregarding ~~modify~~the ~~any~~regulation ~~applicable~~of ~~brokerage~~our ~~account~~operations, ~~agreements~~see to“Item ~~prohibit~~1. ~~their~~Business—Regulation ~~brokers~~of ~~from borrowing their units~~Operations.”

~~You~~Federal ~~may~~and bestate ~~subject~~legislative toand ~~state~~regulatory ~~and~~initiatives ~~local~~relating ~~taxes~~to ~~and~~pipeline ~~return~~safety ~~filing~~that ~~requirements~~require inthe ~~jurisdictions~~use ~~where~~of ~~you~~new door ~~not~~more ~~live~~stringent assafety acontrols or result in more rigorous enforcement of ~~investing~~applicable inlegal ~~our~~requirements ~~Preferred~~could ~~Units~~subject us to increased capital costs, operational delays and costs of operation.

InLegislation ~~addition~~in tothe ~~federal~~past ~~income~~decade ~~taxes~~has resulted in more stringent mandates for pipeline safety. In 2016, ~~holders~~President Obama signed the Protecting our Infrastructure of ~~Preferred~~Pipelines ~~Units~~and ~~may~~Enhancing beSafety ~~subject~~Act of 2016 (“2016 Pipeline Safety Act”) required PHMSA to ~~return~~complete ~~filing~~certain ~~requirements~~of ~~and~~its ~~other~~outstanding ~~taxes,~~mandates ~~including~~under ~~state~~the Pipeline Safety, ~~local~~Regulatory Certainty, and ~~non-U~~Job Creation Act of 2011 (“2011 Pipeline Safety Act”).S. ~~income~~The ~~taxes~~2011 Pipeline Safety Act had directed the promulgation of regulations relating to such matters as expanded integrity management requirements, ~~unincorporated~~automatic ~~business~~or ~~taxes~~remote-controlled valve use, ~~and~~excess ~~estate~~flow valve use, ~~inheritance~~leak ordetection ~~intangible~~system ~~taxes~~installation, ~~that~~testing ~~may~~to beconfirm ~~imposed~~the bymaterial strength of certain pipelines and operator verification of records confirming the ~~various~~maximum ~~jurisdictions~~allowable inpressure ~~which~~of wecertain ~~conduct~~intrastate ~~business~~gas ortransmission ~~own~~pipelines. ~~property~~The ~~now~~2016 Pipeline Safety Act also empowered PHMSA to address unsafe conditions or inpractices ~~the~~constituting ~~future~~imminent hazards by imposing emergency restrictions, ~~even~~prohibitions ifand ~~they~~safety domeasures ~~not~~on ~~live~~owners inand ~~any~~operators of ~~those~~gas ~~jurisdictions.~~or ~~Moreover,~~hazardous weliquid ~~may~~pipeline ~~also~~facilities ~~own~~without ~~property~~prior notice or doan ~~business~~opportunity infor ~~other~~a ~~states~~hearing. Most recently, in December 2020, Congress passed the ~~future~~Fiscal ~~that~~Year ~~impose~~2021 ~~income~~Omnibus orAppropriations ~~similar~~Bill, ~~taxes~~made effective on ~~nonresident~~December ~~individuals.~~27, ~~You~~2020, ~~may~~pursuant beto ~~subject~~which toCongress ~~penalties~~adopted ~~for~~the ~~failure~~“Protecting toOur ~~comply~~Infrastructure ~~with~~of ~~return~~Pipelines ~~filing~~and ~~requirements~~Enhancing Safety (“PIPES”) Act of 2020.” ItThe isPIPES ~~your~~Act ~~responsibility~~of to2020 ~~file~~reauthorized ~~all~~PHMSA ~~U.S.~~through federal, ~~foreign,~~Fiscal ~~state~~Year 2023 and ~~local~~directed ~~tax~~the ~~returns~~agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and ~~pay~~the ~~any~~“Pipeline ~~taxes~~Safety: ~~due~~Safety inof ~~these~~Gas ~~jurisdictions~~Transmission and Gathering Pipelines” proposed rulemakings. ~~You~~Congress ~~should~~has ~~consult~~also ~~with~~instructed ~~your~~PHMSA ~~own~~to ~~tax~~issue ~~advisors~~final ~~regarding~~regulations ~~the~~that ~~filing~~will require operators of ~~such~~non-rural ~~tax~~gas ~~returns,~~gathering ~~the~~lines ~~payment~~and ofnew ~~such~~and ~~taxes,~~existing transmission and ~~the~~distribution ~~deductibility~~pipeline offacilities ~~any~~to ~~taxes~~conduct ~~paid~~certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.

The imposition of new safety enhancement requirements pursuant to the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act and the PIPES Act of 2020, or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could 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 our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. Additionally, PHMSA and one or more state regulators, including the RRC, have in recent years expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, we and other midstream operators of NGL fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA PSM and EPA RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

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 approximately $1.3 million (adjusted annually for inflation) per day for each violation and disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission pipeline and Tarzan 311 residue line, have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA of up to approximately $13,685 per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability. For more information regarding regulation of our operations, see “Item 1. Business—Regulation of Operations.”

We are or may become subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing of personal information.

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.

~~The~~On ~~information~~December ~~required~~26, ~~for~~2018, ~~this~~Vitol ~~item~~Americas isCorp. ~~provided~~(“Vitol”) filed a lawsuit in ~~Note~~the 1880th –District ~~Contingencies~~Court of Harris County, ~~under~~Texas against Targa Channelview LLC, then a subsidiary of the ~~heading~~Company (“~~Legal~~Targa ~~Proceedings~~Channelview”), ~~included~~seeking recovery of $129.0 million in ~~the~~payments ~~Notes~~made to ~~Consolidated~~Targa ~~Financial~~Channelview, ~~Statements~~additional ~~included~~monetary ~~under~~damages, ~~Part~~attorneys’ IIfees and costs. Vitol alleges that Targa Channelview breached an agreement, ~~Item~~dated 8December of27, ~~this~~2015, ~~Annual~~for ~~Report~~crude oil and condensate between Targa Channelview and Noble Americas Corp. (the “Splitter Agreement”), which isprovided ~~incorporated~~for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by ~~reference~~Targa ~~into~~Channelview ~~this~~to ~~item~~provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

On October 15, 2020, the District Court awarded Vitol $129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company has filed an appeal challenging the award, and the appeal is currently pending in the Fourteenth Court of Appeals in Houston, Texas.

In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings.

Additional information required for this item is provided in Note 16 – 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.

5052

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

On February 17, 2016, TRC completed the TRC/TRP Merger, pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Pursuant to the TRC/TRP Merger Agreement, TRC agreed to cause our common units under the symbol “NGLS” to be delisted from the NYSE and deregistered under the Exchange Act. As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. ~~The Preferred Units remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS/PA.”~~

There is no established trading market for the 5,629,136 general partner units held only by our general partner.

Our Preferred Units that were issued in October 2015 were redeemed in December 2020 and are no longer outstanding as of the end of the year. Prior to the redemption, the Preferred Units were limited partner interests in us and were traded on the NYSE under the symbol “NGL/PA.”

Distributions of Available Cash

General

As a result of the TRC/TRP Merger, Targa owns all of our outstanding common units. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 108 – Debt Obligations and Note 1311 – Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Annual Report.

Definition of Available Cash

Under the partnership agreement, the term “available cash,” is defined, for any quarter or month, as applicable, as the sum of all cash and cash equivalents on hand at the end of that quarter or month, as applicable, and all additional cash and cash equivalents on hand immediately prior to the date of the distribution of available cash resulting from borrowings for working capital purposes subsequent to the end of that quarter or month, as applicable, less the amount of any cash reserves established by our general partner to:

•

provide for the proper conduct of our business (including reserves for future capital expenditures and for anticipated future credit needs);

•

comply with applicable law or any loan agreements, security agreements, mortgages, debt instruments or other agreements;

•

provide funds for distributions on and redemptions with respect to the Preferred Units; or

•

provide funds for further distributions.

The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. The board of directors of our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business~~, including reserves to provide funds for distributions on and redemptions with respect to the Preferred Units~~. These can also include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to our unitholders, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations. We will be prohibited from making any distributions to unitholders if it would cause an event of default or if an event of default exists under our credit agreement or indentures.

Preferred Units

~~Distributions~~Prior onto the redemption of our Preferred Units, ~~are~~distributions were cumulative from the date of original issue in October 2015 and ~~are~~were payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on ~~the~~our Preferred Units ~~will~~were bepayable ~~paid~~ out of amounts legally available ~~therefor to, but not including, November 1, 2020,~~ at a rate equal to 9.0% per annum., Onuntil ~~and after~~ November 1, 2020, when distributions on ~~the~~our Preferred Units ~~will~~started to accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. ~~For~~We ~~the~~paid ~~year~~total ~~ended~~distributions ~~December 31,~~of ~~2019,~~$15.1 wemillion ~~have~~in ~~paid~~2020 and $11.3 million each year in ~~distributions~~2019 and 2018 to the ~~holders~~Preferred Unitholders. All cumulative distributions were made at the time of ~~our~~redemption, ~~Preferred~~and ~~Units~~no additional distributions will be required. See Note 1311 - Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Annual Report.

Recent Sales of Unregistered Equity Securities

There were no sales of unregistered equity securities for the year ended December 31, ~~2019~~2020.

Repurchase of Equity by Targa Resources Partners LP or Affiliated Purchasers

None.

Item 6. Selected Financial Data.

The following table presents selected historical consolidated financial and operating data of Targa Resources Partners LP for the periods ended, and as of, the dates indicated. We derived this information from our historical “Consolidated Financial Statements” and accompanying notes. The information in the table below should be read together with, and is qualified in its entirety by reference to, those financial statements and notes in this Annual Report.

	2019			2018			2017			2016			2015
	2020			2019			2018			2017			2016
	(In millions, except per unit amounts)
Statement of operations data:
Revenues (1)	$	8,~~671~~260.13		$	108,~~484~~671.01		$	810,~~814~~484.90		$	68,~~690~~814.9		$	6,~~658~~690.69
Income (loss) from operations		206.1			253.6			(109.4	)		66.0			167.4
Income (loss) from operations (3)		(1,291.3	)		206.1			253.6			(109.4	)		66.0
Net income (loss)		(151,545.61	)		98(15.6	)		~~(250~~98.6	)		(~~228~~250.76	)		(59228.37	)
Balance sheet data (at end of period):
Total assets (2)	$	1815,~~744~~828.5		$	1618,~~890~~744.15		$	1416,~~359~~890.01		$	1214,~~744~~359.90		$	1312,~~126~~744.89
Long-term debt (2)		76,~~005~~832.21			57,~~197~~005.42			45,~~268~~197.04			4,~~177~~268.0			54,~~125~~177.70
Other:
Distributions declared per unit	(3)			(3)			(3)			(3)			$	3.3000

_________________________________

(1) Revenues for 2020, 2019 and 2018 include the impact of the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). See “~~Item~~Revenue ~~7. Management’s Discussion and Analysis of Financial Condition of Results of Operations~~Recognition” ~~for~~included awithin ~~discussion~~Note of3 ~~the~~– ~~impact~~Significant ofAccounting ~~adoption of the revenue standard on our financial statements and results of operations~~Policies.

(2) Total assets and long-term debt include the impact of the adoption of ASU 2016-02, Leases (Topic 842). See Note 1210 – Leases.

(3) ~~Distributions~~Includes ~~declared~~the ~~per~~impact ~~unit~~of ~~are~~pre-tax nonon-cash ~~longer~~impairments ~~relevant~~of ~~after~~long-lived ~~the~~assets. ~~TRC/TRP~~For ~~Merger~~a further discussion, see Note 5 — Property, Plant and Equipment and Intangible Assets.

5254

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, ~~and~~including ~~include~~ 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 2018 items and year-to-year comparisons between 2019 and 2018 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, 2019.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The amendments in this update supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. We adopted Topic 606 on January 1, 2018 by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result in an impact to our operating or gross margin. However, the adoption did have an impact on the classification between components of operating margin and gross margin, “Fees from midstream services” and “Product purchases,” as well as the reporting of gross versus net revenues.

Overview

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by TRC. Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all our outstanding common units that it and its subsidiaries did not already own. Our ~~9.00%~~Preferred ~~Series~~Units Athat ~~Fixed-to-Floating~~were ~~Rate~~issued ~~Cumulative~~in ~~Redeemable~~October ~~Perpetual~~2015 ~~Preferred~~were ~~Units~~redeemed ~~(the~~in ~~“Preferred~~December ~~Units”)~~2020 ~~remain~~and are no longer outstanding as of the end of the year. Prior to the Redemption Date, the preferred units were limited partner interests in us and ~~continue~~were totraded ~~trade~~ on the NYSE under the symbol “NGLS/PA.”

We are engaged primarily in the business of:

• gathering, compressing, treating, processing, transporting and purchasing and selling natural gas;

• transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and

• gathering, storing, terminaling and purchasing and selling crude oil.

Factors That Significantly Affect Our Results

Our results of operations are impacted by a number of factors, including the volumes that move through our gathering, processing and logistics assets, contract terms, changes in commodity prices, the impact of hedging activities and the cost to operate and support assets.

Commodity Prices

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)
2020
4th Quarter	$	2.66	$	0.47	$	42.67
3rd Quarter		1.97		0.42		40.94
2nd Quarter		1.70		0.32		27.55
1st Quarter		1.98		0.36		46.59
2020 Average		2.08		0.39		39.44
2019
4th Quarter	$	2.50	$	0.49	$	56.96
3rd Quarter		2.23		0.42		56.45
2nd Quarter		2.64		0.50		59.83
1st Quarter		3.16		0.60		54.90
2019 Average		2.63		0.5150		57.0304
2018
4th Quarter	$	3.66	$	0.69	$	58.83
3rd Quarter		2.91		0.88		69.50
2nd Quarter		2.80		0.75		67.90
1st Quarter		2.99		0.71		62.89
2018 Average		3.09		0.76		64.78
2017
4th Quarter	$	2.93	$	0.74	$	55.39
3rd Quarter		2.99		0.63		48.19
2nd Quarter		3.19		0.55		48.29
1st Quarter		3.31		0.61		51.86
2017 Average		3.11		0.63		50.93

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(1)	Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.

(2)	“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:

2020: 43% ethane, 32% propane, 12% normal butane, 4% isobutane and 9% natural gasoline

2019: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline

2018: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline

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