Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of our discussion and analysis, including the following: (i) a description of our business strategy found in “Item 1. Business–Overview”; (ii) a description of recent developments, found in “Item 1. Business–Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.” Also, the Partnership files a separate Annual Report on Form 10-K with the SEC. 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.

Overview

Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. We own, operate, acquire and develop a diversified portfolio of complementary domestic midstream infrastructure assets.

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				0.50				57.04

(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

(3)	Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.

Volumes

In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration and production activity in the areas of our operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to our fractionators and our competitive and contractual position relative to other fractionators.

Contract Terms, Contract Mix and the Impact of Commodity Prices

With the potential for volatility of commodity prices, the contract mix of our Gathering and Processing segment (other than fee-based contracts in certain gathering and processing business units and gathering and processing services), can have a significant impact on our profitability, especially those percent-of-proceeds contracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from the commodities handled (“equity volumes”).

Contract terms in the Gathering and Processing segment are based upon a variety of factors, including natural gas and crude quality, geographic location, competitive dynamics and the pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common and other market factors.

The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. Transportation and fractionation services are supported by fee-based contracts whose rates and terms are driven by NGL supply and transportation and fractionation capacity. Export services are supported by fee-based contracts whose rates and terms are driven by global LPG supply and demand fundamentals. The Logistics and Transportation segment includes predominantly fee-based contracts.

The adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), in January of 2018 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. For more details, see “Revenue Recognition” included within Note 3 – Significant Accounting Policies.

Impact of Our Commodity Price Hedging Activities

We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue managing our exposure to commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Business product inventory and other working capital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk–Commodity Price Risk.”

Operating Expenses

Variable costs such as fuel, utilities, power, service and repairs can impact our results. The fuel and power costs are pass-through elements in many of our contracts, which mitigates their impact on our results. Continued expansion of existing assets will also give rise to additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and an indirect wholly-owned subsidiary of ours.

General and Administrative Expenses

We perform centralized corporate functions such as legal, accounting, treasury, insurance, risk management, health, safety, environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Other than our direct costs of being a separate public reporting company, these costs are reimbursed by the Partnership. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

General Trends and Outlook

We expect the midstream energy business environment to continue to be affected by the following key trends: demand for our products and services, commodity prices, volatile capital markets, competition and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Demand for Our Services

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels from our customers. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Producers generally focus their drilling activity on certain basins depending on commodity price fundamentals. As a result, our asset systems are predominantly located in some of the most economic basins in the United States. Accordingly, increased producer activity will drive demand for our midstream services and may result in incremental growth capital expenditures. Demand for our transportation, fractionation and other fee-based services is largely correlated with producer activity levels. Demand for our international export, storage and terminaling services has remained relatively constant, as demand for these services is based on a number of domestic and international factors.

During 2020, as a result of the COVID-19 pandemic and related travel restrictions, combined with uncertainty around global commodity supply and demand, commodity prices declined substantially, which led many exploration and production companies to reduce planned capital expenditures for drilling and production activities and also led to some companies shutting-in wells in the first half of 2020. Such activity declines negatively impacted our operations and demand for our services. While production from wells that were previously shut-in during the first half of 2020 across our operating areas has largely resumed, we are uncertain of what pricing and market demand, and the associated demand for our services, will be throughout 2021.

Commodity Prices

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. As a result of reduced economic activity due to the COVID-19 pandemic paired with uncertainty around global commodity supply and demand, global oil and natural gas commodity prices remain weak relative to historical levels and continue to remain volatile. The volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in supply, demand or these prices could adversely affect our results of operations and financial condition.”

Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, and where the spread between NGL prices and natural gas prices widens primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate. Pricing and supply are beyond our control and have been volatile. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines.

Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

Volatile Capital Markets and Competition

We continuously consider and enter into discussions regarding potential growth projects and acquisitions and identify appropriate private and public capital sources for funding potential growth projects and acquisitions. Any limitations on our access to capital may impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets may be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our growth and acquisition strategy.

Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our growth strategy. Due to increased volatility in commodity prices and the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. We believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures in 2021 and beyond. For additional information regarding our financing activities, see “Item 1. Business—Recent Developments—Financing Activities.”

Increased Regulation

Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers and increased GHG emission regulations may cause reductions in supplies of natural gas, NGLs and crude oil from producers. Please read “Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets” and “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” under Item 1A of this Annual Report. Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability in our results of operations.

How We Evaluate Our Operations

The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow.

Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

Our capital expenditures are classified as growth capital expenditures, business acquisitions, and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

Non-GAAP Measures

We utilize non-GAAP measures to analyze our performance. Gross margin, operating margin, Adjusted EBITDA, distributable cash flow, and free cash flow are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRC. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRC and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect net income, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.

Gross Margin

We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing segment gross margin consists primarily of:

	•	service fees related to natural gas and crude oil gathering, treating and processing; and

	•	revenues from the sale of natural gas, condensate, crude oil and NGLs less producer payments, natural gas and crude oil purchases, and our equity volume hedge settlements.

Logistics and Transportation segment gross margin consists primarily of:

	•	service fees (including the pass-through of energy costs included in fee rates);

	•	system product gains and losses; and

	•	NGL and natural gas sales, less NGL and natural gas purchases, third-party transportation costs and the net inventory change.

The gross margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.

Operating Margin

We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess:

	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

	•	the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) attributable to TRC before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.

Distributable Cash Flow and Free Cash Flow

We define distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Preferred Units that were issued by the Partnership in October 2015 were redeemed in December 2020, and are no longer outstanding as of the end of the year. We define free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.

Our Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated.

		Year Ended December 31,
		2020					2019
		(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin
Net income (loss) attributable to TRC		$		(1,553.9	)	$		(209.2	)
Net income (loss) attributable to noncontrolling interests				228.9				250.4
Net income (loss)				(1,325.0	)			41.2
Depreciation and amortization expense				865.1				971.6
General and administrative expense				254.6				280.7
Impairment of long-lived assets				2,442.8				225.3
Interest (income) expense, net				391.3				337.8
Equity (earnings) loss				(72.6	)			(39.0	)
Income tax expense (benefit)				(248.1	)			(87.9	)
(Gain) loss on sale or disposition of business and assets				58.4				71.1
Write-down of assets				55.6				17.9
(Gain) loss from sale of equity-method investment				—				(69.3	)
(Gain) loss from financing activities				(45.6	)			1.4
Change in contingent considerations				(0.3	)			8.7
Other, net				(0.8	)			0.2
Operating margin		$		2,375.4		$		1,759.7
Operating expenses				779.8				792.9
Gross margin		$		3,155.2		$		2,552.6

		Year Ended December 31,
		2020					2019
		(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow
Net income (loss) attributable to TRC		$		(1,553.9	)	$		(209.2	)
Income attributable to TRP preferred limited partners				15.1				11.3
Interest (income) expense, net				391.3				337.8
Income tax expense (benefit)				(248.1	)			(87.9	)
Depreciation and amortization expense				865.1				971.6
Impairment of long-lived assets				2,442.8				225.3
(Gain) loss on sale or disposition of business and assets				58.4				71.1
Write-down of assets				55.6				17.9
(Gain) loss from sale of equity-method investment				—				(69.3	)
(Gain) loss from financing activities (1)				(45.6	)			1.4
Equity (earnings) loss				(72.6	)			(39.0	)
Distributions from unconsolidated affiliates and preferred partner interests, net				108.6				61.2
Change in contingent considerations				(0.3	)			8.7
Compensation on equity grants				66.2				60.3
Risk management activities				(228.2	)			112.8
Severance and related benefits (2)				6.5				—
Noncontrolling interests adjustments (3)				(224.3	)			(38.5	)
TRC Adjusted EBITDA		$		1,636.6		$		1,435.5
Distributions to TRP preferred limited partners				(15.1	)			(11.3	)
Interest expense on debt obligations (4)				(388.9	)			(342.1	)
Cash tax refund				44.4				—
Maintenance capital expenditures				(109.5	)			(141.7	)
Noncontrolling interests adjustments of maintenance capital expenditures				5.3				6.8
Distributable Cash Flow		$		1,172.8		$		947.2
Growth capital expenditures, net (5)				(597.9	)			(2,281.7	)
Free Cash Flow		$		574.9		$		(1,334.5	)

(1)	Gains or losses on debt repurchases or early debt extinguishments.

(2)	Represents one-time severance and related benefit expense related to our cost reduction measures.

(3)	Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests).

(4)	Excludes amortization of interest expense.

(5)	Represents growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates.

The Company has completed a number of announced growth capital projects since early 2019, and this has resulted in lower growth capital expenditures in 2020 and a transition to free cash flow. The following table details construction and project completion timing of our announced major growth capital projects:

		Three Months Ended
		March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019		March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020
Major Growth Capital Project (1):
Gathering & Processing:
Hopson Plant (2)		UC		C
Falcon Plant (3)		UC		UC		C
Pembrook Plant (2)		UC		UC		C
Little Missouri 4 Plant (4)		UC		UC		C
Peregrine Plant (3)		UC		UC		UC		UC		UC		C
Gateway Plant (2)						UC		UC		UC		UC		C
Heim Plant (5)																UC
Logistics & Transportation:
Train 6		UC		C
Grand Prix NGL Pipeline		UC		UC		C
Gulf Coast Express Pipeline		UC		UC		C
Train 7		UC		UC		UC		UC		C
Train 8		UC		UC		UC		UC		UC		UC		C
LPG Export Expansion		UC		UC		UC		UC		UC		UC		C
Grand Prix Central OK Extension		UC		UC		UC		UC		UC		UC		UC		C

(1)	"UC" and "C" indicates under construction and project completed as of the end of the period presented above.

(2)	Part of our Permian Midland operating area.

(3)	Part of our Permian Delaware operating area.

(4)	Part of our Badlands operating area.

(5)	In November 2020, we announced the relocation of the former Longhorn Plant from our North Texas system to our Permian Midland system as the Heim Plant. The Heim Plant is expected to begin operations in the fourth quarter of 2021.

Consolidated Results of Operations

The following table and discussion is a summary of our consolidated results of operations:

	Year Ended December 31,
	2020				2019				2020 vs. 2019
	(In millions)
Revenues:
Sales of commodities	$	7,171.0			$	7,393.8			$	(222.8	)			(3	%)
Fees from midstream services		1,089.3				1,277.3				(188.0	)			(15	%)
Total revenues		8,260.3				8,671.1				(410.8	)			(5	%)
Product purchases		5,105.1				6,118.5				(1,013.4	)			(17	%)
Gross margin (1)		3,155.2				2,552.6				602.6				24	%
Operating expenses		779.8				792.9				(13.1	)			(2	%)
Operating margin (1)		2,375.4				1,759.7				615.7				35	%
Depreciation and amortization expense		865.1				971.6				(106.5	)			(11	%)
General and administrative expense		254.6				280.7				(26.1	)			(9	%)
Impairment of long-lived assets		2,442.8				225.3				2,217.5			NM
Other operating (income) expense		116.6				89.2				27.4				31	%
Income (loss) from operations		(1,303.7	)			192.9				(1,496.6	)		NM
Interest expense, net		(391.3	)			(337.8	)			(53.5	)			(16	%)
Equity earnings (loss)		72.6				39.0				33.6				86	%
Gain (loss) from financing activities		45.6				(1.4	)			47.0			NM
Gain (loss) from sale of equity-method investment		—				69.3				(69.3	)			(100	%)
Change in contingent considerations		0.3				(8.7	)			9.0				103	%
Other, net		3.4				—				3.4				—
Income tax (expense) benefit		248.1				87.9				160.2				182	%
Net income (loss)		(1,325.0	)			41.2				(1,366.2	)		NM
Less: Net income (loss) attributable to noncontrolling interests		228.9				250.4				(21.5	)			(9	%)
Net income (loss) attributable to Targa Resources Corp.		(1,553.9	)			(209.2	)			(1,344.7	)		NM
Dividends on Series A Preferred Stock		91.7				91.7				—				—
Deemed dividends on Series A Preferred Stock		39.2				33.1				6.1				18	%
Net income (loss) attributable to common shareholders	$	(1,684.8	)		$	(334.0	)		$	(1,350.8	)		NM
Financial data:
Adjusted EBITDA (1)	$	1,636.6			$	1,435.5			$	201.1				14	%
Distributable cash flow (1)		1,172.8				947.2				225.6				24	%
Free cash flow (1)		574.9				(1,334.5	)			1,909.4			NM

(1)	Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations–How We Evaluate Our Operations.”

NM	Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

2020 Compared to 2019

The decrease in sales of commodities reflects lower NGL, condensate, petroleum product and natural gas prices ($945.1 million) and lower crude marketing and petroleum product volumes ($397.1 million), partially offset by higher NGL, natural gas, and condensate volumes ($816.3 million) and the favorable impact of hedges ($301.1 million).

The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, partially offset by increased export and terminaling and storage volumes.

The decrease in product purchases reflects lower NGL, condensate, petroleum product and natural gas prices, lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower petroleum products volumes, partially offset by higher NGL, natural gas and condensate volumes.

Higher operating margin and gross margin in 2020 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense decreased primarily due to a lower depreciable base associated with assets that were impaired during 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by depreciation related to major growth capital projects placed in service, including Train 7 in the first quarter of 2020, the additional processing plants and associated infrastructure in the Permian Basin and a full year of depreciation related to Grand Prix, which was placed in service in the third quarter of 2019.

General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.

We recognized non-cash pre-tax impairment charges of $2,442.8 million and $225.3 million during 2020 and 2019. The non-cash pre-tax impairment charge in 2020 is primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations and full impairment of our Coastal operations. The non-cash pre-tax impairment charge in 2019 is primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central and Coastal operations.

Other operating (income) expense in 2020 consisted primarily of a loss associated with the sale of our assets in Channelview, Texas and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of our Delaware crude system, which was effective December 1, 2019, and write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4, partially offset by lower earnings from GCF.

During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024 and the 5¼% Senior Notes due 2023, resulting in a $45.6 million net gain from financing activities. During 2019, the Partnership redeemed the 4⅛% Senior Notes due 2019, resulting in $1.4 million loss from financing activities.

During 2019, the Partnership closed on the sale of an equity-method investment that resulted in a gain of $69.3 million.

The increase in income tax benefit is primarily due to a higher pre-tax book loss and benefit of a net operating loss carryback from the CARES Act, partially offset by a valuation allowance in 2020.

Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of non-cash pre-tax impairment losses recognized during the first quarter of 2020, partially offset by increased earnings allocated to interests holders in the DevCo Joint Ventures, Targa Badlands and Grand Prix.

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

	Gathering and Processing					Logistics and Transportation					Other					Consolidated Operating Margin
	(In millions)
December 31, 2020	$		1,017.7			$		1,128.0			$		229.7			$		2,375.4
December 31, 2019			1,006.4					867.2					(113.9	)				1,759.7

Gathering and Processing Segment

	Year Ended December 31,
	2020					2019					2020 vs. 2019
	(In millions, except operating statistics and price amounts)
Gross margin	$		1,450.3			$		1,496.0			$		(45.7	)			(3	%)
Operating expenses			432.6					489.6					(57.0	)			(12	%)
Operating margin	$		1,017.7			$		1,006.4			$		11.3				1	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)			1,745.6					1,471.6					274.0				19	%
Permian Delaware			729.4					599.7					129.7				22	%
Total Permian			2,475.0					2,071.3					403.7
SouthTX (5)			248.1					321.2					(73.1	)			(23	%)
North Texas			201.6					226.9					(25.3	)			(11	%)
SouthOK (6)			443.0					606.1					(163.1	)			(27	%)
WestOK			249.5					330.2					(80.7	)			(24	%)
Total Central			1,142.2					1,484.4					(342.2	)
Badlands (7),(8)			137.8					116.7					21.1				18	%
Total Field			3,755.0					3,672.4					82.6
Coastal			643.3					774.2					(130.9	)			(17	%)
Total			4,398.3					4,446.6					(48.3	)			(1	%)
NGL production, MBbl/d (3)
Permian Midland (4)			250.8					209.1					41.7				20	%
Permian Delaware			99.1					78.6					20.5				26	%
Total Permian			349.9					287.7					62.2
SouthTX (5)			26.1					41.6					(15.5	)			(37	%)
North Texas			23.9					26.8					(2.9	)			(11	%)
SouthOK (6)			52.4					67.1					(14.7	)			(22	%)
WestOK			20.3					21.6					(1.3	)			(6	%)
Total Central			122.7					157.1					(34.4	)
Badlands (8)			16.3					13.8					2.5				18	%
Total Field			488.9					458.6					30.3
Coastal			40.0					46.8					(6.8	)			(15	%)
Total			528.9					505.4					23.5				5	%
Crude oil, Badlands, MBbl/d			156.5					172.6					(16.1	)			(9	%)
Crude oil, Permian, MBbl/d (9)			43.3					83.3					(40.0	)			(48	%)
Natural gas sales, BBtu/d (3),(10)			2,094.8					2,020.6					74.2				4	%
NGL sales, MBbl/d (3),(10)			399.5					391.9					7.6				2	%
Condensate sales, MBbl/d			15.5					12.3					3.2				26	%
Average realized prices - inclusive of hedges (11):
Natural gas, $/MMBtu			1.27					1.35					(0.08	)			(6	%)
NGL, $/gal			0.26					0.34					(0.08	)			(24	%)
Condensate, $/Bbl			39.40					49.99					(10.59	)			(21	%)

(1)	Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.

(2)	Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands.

(3)	Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.

(4)	Permian Midland includes operations in WestTX, of which we own 72.8%, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(5)	SouthTX includes the Raptor Plant, of which we own a 50% interest through the Carnero Joint Venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(6)	SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants that are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(7)	Badlands natural gas inlet represents the total wellhead volume, and includes the Targa volumes processed at the LM4 Plant.

(8)	As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which we owned a 100% interest. Targa Badlands is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(9)	Permian crude oil volumes reflect the sale of the Delaware crude system, which was effective December 1, 2019.

(10)	Natural gas and NGL sales statistics in 2020 include statistics related to new commercial arrangements effective in January 2020, which resulted in a change from net presentation as “Fees from midstream services” to gross presentation as “Sales of commodities” and “Product purchases”. This change in presentation did not result in an impact to our operating or gross margin.

(11)	Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes, previously shown in Other. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator.

The following table presents the realized commodity hedge gain/loss attributable to our equity volumes that are included in the gross margin of Gathering and Processing segment:

		Year Ended December 31, 2020												Year Ended December 31, 2019
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)
Natural gas (BBtu)			68.1			$	0.37			$	25.1				62.9			$	1.17			$	73.7
NGL (MMgal)			451.4				0.12				53.3				369.7				0.10				38.0
Crude oil (MBbl)			1.9				18.54				34.9				1.5				(2.29	)			(3.5	)
										$	113.3											$	108.2

---

(1)	The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

2020 Compared to 2019

During the year ended December 31, 2020, the COVID-19 pandemic reduced economic activity and the related demand for energy commodities, which contributed to weak commodity prices compared to historical levels and price volatility. The drop in commodity prices also resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production, particularly during the second quarter.

The resulting decrease in Gathering and Processing segment gross margin was primarily due to lower Central region volumes and lower commodity prices, partially offset by higher inlet volumes and fee-based margin in the Permian region and the Badlands and higher realized hedge gains. Lower volumes in the Central region were attributable to reduced producer activity and temporary shut-ins. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third and fourth quarters of 2020, which necessitated temporary shut downs of certain facilities. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures implemented in response to the impact of the COVID-19 pandemic on our business, which resulted in decreases in contract labor, chemicals and compressor rentals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Logistics and Transportation Segment

		Year Ended December 31,
		2020					2019					2020 vs. 2019
	(In millions, except operating statistics and price amounts)
Gross margin		$		1,480.7			$		1,173.9			$		306.8			26%
Operating expenses (1)				352.7					306.7					46.0			15%
Operating margin		$		1,128.0			$		867.2			$		260.8			30%
Operating statistics MBbl/d (2):
Fractionation volumes (3)				602.9					519.0					83.9			16%
Export volumes (4)				300.4					237.9					62.5			26%
Pipeline throughput (5)				293.7					100.4					193.3			NM
NGL sales				752.5					651.0					101.5			16%

(1)	Effective January 1, 2020, pursuant to amendments to contractual arrangements with our partners, our share of operating expenses associated with GCF, an investment in an unconsolidated affiliate, are included in operating expenses.

(2)	Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.

(3)	Fractionation contracts include pricing terms composed of base fees and fuel and power components that vary with the cost of energy. As such, the Logistics and Transportation segment results include effects of variable energy costs that impact both gross margin and operating expenses.

(4)	Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

(5)	Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu.

NM	Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

2020 Compared to 2019

The increase in Logistics and Transportation segment gross margin was driven by higher pipeline transportation, fractionation and LPG export system volumes from higher supply volumes from our Permian Gathering and Processing systems and associated downstream system expansions, partially offset by fewer optimization opportunities in our marketing businesses. NGL transportation and fractionation volumes increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and the commencement of operations of Train 6 in the second quarter of 2019, Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020.

Operating expenses were higher due to system expansions, including Grand Prix, fractionation capacity and expansion of our LPG export capabilities and our share of operating expenses associated with GCF and certain one-time maintenance expenses including hurricane damage repairs, partially offset by lower fuel and power costs and cost reduction measures.

Other

		Year Ended December 31,
		2020				2019				2020 vs. 2019
		(In millions)
Gross margin		$	229.7			$	(113.9	)		$	343.6
Operating margin		$	229.7			$	(113.9	)		$	343.6

Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 7A. – Quantitative and Qualitative Disclosures About Market Risk.”

Our Liquidity and Capital Resources

As of December 31, 2020, inclusive of our consolidated joint venture accounts, we had $242.8 million of “Cash and cash equivalents” on our Consolidated Balance Sheets. We believe our cash positions, our cash flows from operating activities, our free cash flow after dividends and remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”) are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity, subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements, as well as the ability to contribute capital to the Partnership, subject to any restrictions contained in the covenants of our debt agreements.

On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, meeting our collateral requirements, and to pay dividends declared by our board of directors will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments – Response to Current Market Conditions”.

We are entitled to the entirety of distributions made by the Partnership on its equity interests. The actual amount we declare as distributions depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.

The Partnership’s debt agreements may restrict or prohibit the payment of distributions if the Partnership is in default or threat of default. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our common stock or Preferred Shares. In addition, so long as any of our Preferred Shares are outstanding, certain common stock distribution limitations exist.

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRC Revolver, the TRP Revolver, and the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

Short-term Liquidity

Our short-term liquidity on a consolidated basis as of February 12, 2021, was:

		February 12, 2021
		TRC				TRP				Consolidated Total
		(In millions)
Cash on hand (1)		$	11.0			$	295.1			$	306.1
Total availability under the TRC Revolver			670.0				—				670.0
Total availability under the TRP Revolver			—				2,200.0				2,200.0
Total availability under the Partnership's Securitization Facility			—				350.0				350.0
			681.0				2,845.1				3,526.1
Less: Outstanding borrowings under the TRC Revolver			(270.0	)			—				(270.0	)
Outstanding borrowings under the TRP Revolver			—				—				—
Outstanding borrowings under the Partnership's Securitization Facility			—				—				—
Outstanding letters of credit under the TRP Revolver			—				(89.2	)			(89.2	)
Total liquidity		$	411.0			$	2,755.9			$	3,166.9

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(1)	Includes cash held in our consolidated joint venture accounts.

Other potential capital resources associated with our existing arrangements include:

	•	Our right to request an additional $200 million in commitment increases under the TRC Revolver, subject to the terms therein. The TRC Revolver matures on June 29, 2023.

	•	Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRP Revolver matures on June 29, 2023.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels and valuation, which we closely manage; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Partnership’s Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.

Working capital as of December 31, 2020 decreased $104.8 million compared to December 31, 2019. The decrease was primarily attributable to the reduction in held for sale assets as a result of the closing of the Delaware crude system sale, which was effective December 1, 2019, and an increase in the current liability position of our derivative contracts, partially offset by lower payables for capital expenditures.

Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the TRC Revolver, the TRP Revolver and the Partnership’s Securitization Facility and proceeds from debt and equity offerings, as well as joint ventures and/or asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash dividends for at least the next twelve months.

Long-term Financing

Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements.

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”), which committed a maximum of approximately $960 million of capital to the DevCo JVs. As of December 31, 2020, total contributions from Stonepeak to the DevCo JVs were $911.6 million and are included in noncontrolling interests.

Additionally, we serve as operator of our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), in which Blackstone Energy Partners (“Blackstone”) owns a 25% interest. As of December 31, 2020, total contributions from funds managed by Blackstone to the Grand Prix Joint Venture were $347.4 million and are included in noncontrolling interests.

In April 2019, we closed on the sale of a 45% interest in Targa Badlands to GSO for $1.6 billion in cash. Growth capital of Targa Badlands after the sale is funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to GSO and Targa, with GSO having a priority right on such MQDs. Additionally, GSO’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. As of December 31, 2020, the contributions from GSO were $75.7 million for growth capital expenditures.

In the second quarter of 2019, Williams exercised its initial option to acquire a 20% equity interest in Train 7 and subsequently executed a joint venture agreement with us. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, was funded and is owned 100% by Targa. As of December 31, 2020, the contributions from Williams were $29.9 million.

From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums.

We consolidate the debt of the Partnership with that of our own; however, we do not have the contractual obligation to make interest or principal payments with respect to the debt of the Partnership. Our debt obligations do not restrict the ability of the Partnership to make distributions to us. Our Credit Agreement has restrictions and covenants that may limit our ability to pay dividends to our stockholders. See Note 8 – Debt Obligations for more information regarding our debt obligations.

The majority of our debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRC Revolver, the TRP Revolver and the Partnership’s Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2020, we did not have any interest rate hedges.

We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. 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 January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,486.6 million. The net proceeds from the issuance were used to redeem in full the Partnership’s outstanding 4⅛% Senior Notes due 2019, at par value plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repayment of borrowings under the TRP Revolver.

In November 2019, the Partnership issued $1.0 billion aggregate principal amount of 5½% Senior Notes due March 2030, resulting in net proceeds of $990.8 million. The net proceeds from the issuance were used to repay borrowings under the TRP Revolver and for general partnership purposes.

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

In August 2020, the Partnership 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 August Tender Offer and redemption payments for the 6¾% Notes, with the remainder used for repayment of borrowings under the TRP Revolver.

We accepted for purchase all the 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, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023 with available liquidity under the TRP Revolver. As a result, we recorded a loss due to debt extinguishment of $1.8 million related to a write-off of debt issuance costs.

In February 2021, the Partnership issued $1.0 billion of 4% Senior Notes due 2032, resulting in net proceeds of approximately $992 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “January Tender Offer”) and subsequent redemption payment for the Partnership’s 5⅛% Senior Notes due 2025 (the “5⅛% Notes”), with the remainder used for repayment of borrowings under the TRP Revolver and the TRC Revolver.

Additionally, TPL issued notices of redemption for all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023. These notes will be redeemed on February 22, 2021 with available liquidity under the TRP Revolver.

As of December 31, 2020 and December 31, 2019, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations, including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was $7,387.1 million and $7,440.2 million. To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 8 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

On September 20, 2018, we entered into an equity distribution agreement (the “September 2018 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock (the “2018 ATM Program”). Such shares of common stock were registered for sale under our May 2016 Shelf and the related prospectus supplement filed in September 2018.

The May 2016 Shelf expired in May 2019. Accordingly, in May 2019, we filed (i) the May 2019 Shelf, (ii) a new prospectus supplement to continue the 2017 ATM Program and (iii) a new prospectus supplement to continue the 2018 ATM Program.

During 2020, no shares of common stock were issued under either the May 2017 EDA or the September 2018 EDA. As a result, we have $382.1 million and $750.0 million remaining under the May 2017 EDA and September 2018 EDA as of December 31, 2020.

Compliance with Debt Covenants

As of December 31, 2020, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flow

Cash Flows from Operating Activities

2020				2019				2020 vs. 2019
(In millions)
$	1,744.5			$	1,389.8			$	354.7

The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil (iii) changes in payables and accruals related to major growth capital projects; and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

Net cash provided by operations increased in 2020 compared to 2019 primarily due to higher operating margin, partially offset by an increase in interest payments as a result of higher average borrowings and lower cash received from settlement of hedging transactions.

Cash Flows from Investing Activities

2020				2019				2020 vs. 2019
(In millions)
$	(738.1	)		$	(3,071.9	)		$	2,333.8

Cash used in investing activities decreased in 2020 compared to 2019, primarily due to lower cash outlays for major growth capital projects of $1,926.2 million, resulting from the completion of construction of Grand Prix, Train 6, Train 7, and additional processing plants and associated infrastructure in the Permian Basin in 2019 and early 2020. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system in 2020 and a $264.1 million decrease in our contributions to unconsolidated affiliates primarily due to the completion of GCX Pipeline in 2019.

Cash Flows from Financing Activities

	2020				2019
	(In millions)
Source of Financing Activities, net
Contributions from (distributions to) noncontrolling interests	$	(397.7	)		$	363.6
Dividends and distributions		(395.9	)			(964.8	)
Redemption of Preferred Units		(125.0	)			—
Partial repurchase of Series A Preferred Stock		(45.8	)			—
Debt, including financing costs		(32.9	)			1,104.4
Sale of ownership interests in subsidiaries		—				1,619.7
Payment of contingent consideration		—				(317.1	)
Other		(97.4	)			(24.7	)
Net cash provided by (used in) financing activities	$	(1,094.7	)		$	1,781.1

In 2020, net cash used in financing activities was primarily due to net distributions to noncontrolling interests and payments of dividends to our common and Series A preferred shareholders, redemption of the Preferred Units and partial repurchase of our Series A Preferred Stock. Our distributions to noncontrolling interests are higher than our contributions from noncontrolling interests in 2020, primarily due to completion of major growth capital projects in 2019.

In 2019, we realized a net source of cash from financing activities primarily due to the sale of ownership interests in Targa Badlands and Train 7, net increase of debt outstanding and net contributions from noncontrolling interests. The result was partially offset by payments of dividends and distributions, as well as the final contingent consideration payment associated with our purchase of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC and Outrigger Midland Operating, LLC (together, the “Permian Acquisition”). As part of the Permian Acquisition, which closed in March 2017, we were required to make potential earn-out payments, subject to certain performance-linked measures and other conditions. In May 2019, we made the final earn-out payment of $317.1 million. Additionally, during 2019, we issued 6½% Senior Notes due 2027, 6⅞% Senior Notes due January 2029 and 5½% Senior Notes due March 2030, with the use of proceeds primarily to repay the Partnership’s revolving credit facility and to redeem 4⅛% Senior Notes due November 2019, resulting in net increases in debt outstanding. We received net contributions from noncontrolling interests primarily from Stonepeak and Blackstone to fund growth projects.

Common Stock Dividends

The following table details the dividends declared and/or paid by us to common shareholders for 2020:

Three Months Ended		Date Paid or To Be Paid		Total Common Dividends Declared				Amount of Common Dividends Paid or To Be Paid				Accrued Dividends (1)				Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
December 31, 2020		February 16, 2021	$		23.3		$		22.9		$		0.4		$		0.10000
September 30, 2020		November 16, 2020			23.8				23.3				0.5				0.10000
June 30, 2020		August 17, 2020			23.7				23.3				0.4				0.10000
March 31, 2020		May 15, 2020			23.7				23.3				0.4				0.10000

(1)	Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Preferred Dividends

Our Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter.

Cash dividends of $92.7 million were paid to holders of the Series A Preferred during the year ended December 31, 2020. As of December 31, 2020, cash dividends accrued for our Series A Preferred were $22.9 million, which were paid on February 12, 2021.

Capital Expenditures

The following table details cash outlays for capital projects for the years ended December 31, 2020 and 2019:

		Year Ended December 31,
		2020				2019
		(In millions)
Capital expenditures:
Growth (1)		$	617.3			$	2,566.8
Maintenance (2)			109.5				141.7
Gross capital expenditures			726.8				2,708.5
Transfers from materials and supplies inventory to property, plant and equipment			(2.1	)			(25.1	)
Change in capital project payables and accruals, net			226.9				194.4
Cash outlays for capital projects		$	951.6			$	2,877.8

(1)	Growth capital expenditures, net of contributions from noncontrolling interests, were $597.1 million and $2,201.7 million for the years ended December 31, 2020 and 2019. Net contributions to investments in unconsolidated affiliates were $0.8 million and $80.0 million for the years ended December 31, 2020 and 2019.

(2)	Maintenance capital expenditures, net of contributions from noncontrolling interests, were $104.2 million and $134.9 million for the years ended December 31, 2020 and 2019.

During 2020, we invested $597.9 million in growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates. We currently estimate that in 2021 we will invest approximately $350 to $450 million in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investment opportunities. We expect that 2021 maintenance capital expenditures, net of noncontrolling interests, will be approximately $130 million.

Total growth capital expenditures were lower for the year ended December 31, 2020 as compared to the year ended December 31, 2019, primarily due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2019, including Grand Prix, Train 6 and additional processing plants and associated infrastructure in the Permian, partially offset by spending related to Train 7 and Train 8. Total maintenance capital expenditures were lower for 2020 as compared to 2019, primarily due to timing of maintenance projects.

Off-Balance Sheet Arrangements

As of December 31, 2020, there were $69.8 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 7 – Investments in Unconsolidated Affiliates and Note 8 – Debt Obligations.

Contractual Obligations

In addition to disclosures related to debt and lease obligations, contained in our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report, the following is a summary of certain contractual obligations over the next several years:

		Payments Due By Period
							Less Than															More Than
Contractual Obligations		Total					1 Year					1-3 Years					3-5 Years					5 Years
		(in millions)
Long-term debt obligations (1)		$		7,420.2			$		6.5			$		1,467.0			$		481.0			$		5,465.7
Interest on debt obligations (2)				2,592.1					386.5					757.2					647.3					801.1
Finance leases (3)				32.4					13.0					17.6					1.8					—
Operating leases (4)				65.7					14.1					24.8					11.3					15.5
Land site lease and rights of way (5)				187.2					4.0					8.6					10.7					163.9
Purchase Obligations (6):
Pipeline capacity and throughput agreements (7)				1,131.1					184.9					324.0					217.1					405.1
Commodities (8)				24.2					24.2					—					—					—
Purchase commitments and service contracts (9)				210.7					195.9					5.2					2.5					7.1
Other long-term liabilities (10)				119.2					14.6					71.5					8.2					24.9
		$		11,782.8			$		843.7			$		2,675.9			$		1,379.9			$		6,883.3
Commodity Volumetric Commitments
Natural gas (MMBtu)				0.9					0.9					—					—					—
NGLs (MMgal)				87.8					87.8					—					—					—

(1)	Represents scheduled future maturities of long-term debt obligations for the periods indicated. See Note 8 - Debt Obligations for more information regarding our debt obligations.

(2)	Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2020 rates for floating debt. See Note 8 - Debt Obligations for more information regarding our debt obligations.

(3)	Includes minimum payments on finance lease obligations for vehicles and tractors. See Note 10 - Leases for more information regarding our finance leases.

(4)	Includes minimum payments on operating lease obligations for office space and railcars. See Note 10 - Leases for more information regarding our operating leases.

(5)	Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates with varying terms, some of which are perpetual. See Note 18 - Commitments for more information regarding our land site lease and rights of way.

(6)	A purchase obligation represents an agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms, including: fixed minimum or variable price provisions; and the approximate timing of the transaction.

(7)	Consists of pipeline capacity payments for firm transportation and throughput and deficiency agreements.

(8)	Includes natural gas and NGL purchase commitments. Contracts that will be settled at future spot prices are valued using prices as of December 31, 2020.

(9)	Includes commitments for capital expenditures, operating expenses and service contracts.

(10)	Includes long-term liabilities of which we are certain of the amount and timing, including certain arrangements that resulted in deferred revenue and other liabilities pertaining to accrued dividends. See Note 9 - Other Long-term Liabilities for more information regarding our other long-term liabilities.

Critical Accounting Policies and Estimates

The accounting policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Depreciation of Property, Plant and Equipment and Amortization of Intangible Assets

Depreciation of our property, plant and equipment is computed using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. The determination of useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of and demand for hydrocarbons in the markets served, normal wear and tear of facilities, and the extent and frequency of maintenance programs.

We amortize the costs of our intangible assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers. At the time assets are placed in service or acquired, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation/amortization amounts prospectively.

Impairment of Long-Lived Assets, including Intangible Assets

We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other factors.

If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment charge equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments.

Price Risk Management (Hedging)

Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. In an effort to reduce the volatility of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL, and condensate equity volumes, future commodity purchases and sales, and transportation basis risk.

One of the factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, which are reflected at their fair values on the balance sheet. We determine the fair value of our derivative instruments using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. Changes in the methods or assumptions we use to calculate the fair value of our derivative instruments could have a material effect on our consolidated financial statements.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.