# Targa Resources Corp. (TRGP) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Targa Resources Corp.'s 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1389170/000156459022006563/trgp-10k_20211231.htm
Accession: 0001564590-22-006563
Filing date: 2022-02-24
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/TRGP/
All MD&A years: /company/TRGP/mda/
Next year: /company/TRGP/mda/fy2022/ (FY 2022)

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of our discussion and analysis, including the following: (i) a description of our business strategy found in “Item 1. Business–Overview”; (ii) a description of recent developments, found in “Item 1. Business–Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.” Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report can be found in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2020.

General Trends and Outlook

We expect our results of operations to continue to be affected by the following key trends: commodity prices, volume throughput and demand for our products and services, contract terms and mix, the impact of our hedging activities, the cost to operate and support assets, volatile capital markets, competition and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Commodity Prices

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

Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices. Our processing profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate, both of which are beyond our control. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. The significant level of margin we derive from fee-based arrangements across our operations and particularly in our Downstream Business combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

The following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:

[[GREPCENT_TABLE]]
[["","Natural Gas $/MMBtu (1)","","","Illustrative Targa NGL $/gal (2)","","","Crude Oil $/Bbl (3)"],["2021"],["4th Quarter","$","5.84","","","$","0.94","","","$","77.17"],["3rd Quarter","","4.01","","","","0.86","","","","70.55"],["2nd Quarter","","2.83","","","","0.66","","","","66.06"],["1st Quarter","","2.70","","","","0.65","","","","57.80"],["2021 Average","","3.85","","","","0.78","","","","67.90"],["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"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(2)","\u201cIllustrative Targa NGL\u201d pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following composition for the periods noted:"]]
[[/GREPCENT_TABLE]]

2021: 45% ethane, 31% propane, 11% normal butane, 4% isobutane and 9% natural gasoline

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

[[GREPCENT_TABLE]]
[["(3)","Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX."]]
[[/GREPCENT_TABLE]]

54

Volumes and Demand for our Services

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels from our customers. In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration and production activity in the areas of our operations. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Producers generally focus their drilling activity on certain basins depending on commodity price fundamentals. Our asset systems are predominantly located in some of the most economic basins in the United States.

The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. Accordingly, increased producer activity will drive demand for our midstream services and may result in incremental growth capital expenditures. Demand for our transportation, fractionation and other fee-based services is largely correlated with producer activity levels. Demand for our international export, storage and terminaling services has remained relatively constant, as demand for these services is based on a number of domestic and international factors.

Contract Terms, Contract Mix and the Impact of Commodity Prices

Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements.

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

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

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

Impact of Our Commodity Price Hedging Activities

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

Operating Expenses

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

55

Volatile Capital Markets and Competition

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

Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our growth strategy. Due to increased volatility in commodity prices and the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. We believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures in 2022 and beyond. For additional information regarding our financing activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Liquidity and Capital Resources.”

Increased Regulation

Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers and increased GHG emission regulations may cause reductions in supplies of natural gas, NGLs and crude oil from producers. Please read “Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets”, “Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change (including legislation or regulation to address climate change) that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide,” and “Increasing attention to ESG matters may impact our business” under Item 1A of this Annual Report. Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability in our results of operations.

How We Evaluate Our Operations

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

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

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

56

Throughput Volumes, Facility Efficiencies and Fuel Consumption

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

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

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

Operating Expenses

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

Capital Expenditures

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

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

Non-GAAP Measures

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

57

Adjusted Operating Margin

We define adjusted operating margin for our segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing adjusted operating margin consists primarily of:

[[GREPCENT_TABLE]]
[["","\u2022","service fees related to natural gas and crude oil gathering, treating and processing; and"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u2022","revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and our equity volume hedge settlements."]]
[[/GREPCENT_TABLE]]

Logistics and Transportation adjusted operating margin consists primarily of:

[[GREPCENT_TABLE]]
[["","\u2022","service fees (including the pass-through of energy costs included in fee rates);"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u2022","system product gains and losses; and"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u2022","NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change."]]
[[/GREPCENT_TABLE]]

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

Adjusted operating margin for our segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of our financial statements, including investors and commercial banks, to assess:

[[GREPCENT_TABLE]]
[["","\u2022","the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u2022","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"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u2022","the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities."]]
[[/GREPCENT_TABLE]]

Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”

Adjusted EBITDA

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

Distributable Cash Flow and Adjusted Free Cash Flow

We define distributable cash flow as adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Preferred Units that were issued by the Partnership in October 2015 were redeemed in December 2020. We define adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.

58

Our Non-GAAP Financial Measures

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","2021","","","2020"],["","(In millions)"],["Reconciliation of Net income (loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow"],["Net income (loss) attributable to TRC","$","","71.2","","","$","","(1,553.9",")"],["Income attributable to TRP preferred limited partners","","","\u2014","","","","","15.1"],["Interest (income) expense, net","","","387.9","","","","","391.3"],["Income tax expense (benefit)","","","14.8","","","","","(248.1",")"],["Depreciation and amortization expense","","","870.6","","","","","865.1"],["Impairment of long-lived assets","","","452.3","","","","","2,442.8"],["(Gain) loss on sale or disposition of business and assets","","","2.0","","","","","58.4"],["Write-down of assets","","","10.3","","","","","55.6"],["(Gain) loss from financing activities (1)","","","16.6","","","","","(45.6",")"],["Equity (earnings) loss","","","23.9","","","","","(72.6",")"],["Distributions from unconsolidated affiliates and preferred partner interests, net","","","116.5","","","","","108.6"],["Change in contingent considerations","","","0.1","","","","","(0.3",")"],["Compensation on equity grants","","","59.2","","","","","66.2"],["Risk management activities","","","116.0","","","","","(228.2",")"],["Severance and related benefits (2)","","","\u2014","","","","","6.5"],["Noncontrolling interests adjustments (3)","","","(89.4",")","","","","(224.3",")"],["TRC Adjusted EBITDA","$","","2,052.0","","","$","","1,636.6"],["Distributions to TRP preferred limited partners","","","\u2014","","","","","(15.1",")"],["Interest expense on debt obligations (4)","","","(376.2",")","","","","(388.9",")"],["Maintenance capital expenditures, net (5)","","","(131.7",")","","","","(104.2",")"],["Cash taxes","","","(2.7",")","","","","44.4"],["Distributable Cash Flow","$","","1,541.4","","","$","","1,172.8"],["Growth capital expenditures, net (5)","","","(407.7",")","","","","(597.9",")"],["Adjusted Free Cash Flow","$","","1,133.7","","","$","","574.9"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Gains or losses on debt repurchases or early debt extinguishments."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(2)","Represents one-time severance and related benefit expense related to our cost reduction measures."]]
[[/GREPCENT_TABLE]]

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

[[GREPCENT_TABLE]]
[["(4)","Excludes amortization of interest expense."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(5)","Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates."]]
[[/GREPCENT_TABLE]]

59

Consolidated Results of Operations

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2021","","","2020","","","2021 vs. 2020"],["","(In millions)"],["Revenues:"],["Sales of commodities","$","15,602.5","","","$","7,171.0","","","$","8,431.5","","","118","%"],["Fees from midstream services","","1,347.3","","","","1,089.3","","","","258.0","","","24","%"],["Total revenues","","16,949.8","","","","8,260.3","","","","8,689.5","","","105","%"],["Product purchases and fuel (1)","","13,729.5","","","","5,186.5","","","","8,543.0","","","165","%"],["Operating expenses (1)","","747.0","","","","698.4","","","","48.6","","","7","%"],["Depreciation and amortization expense","","870.6","","","","865.1","","","","5.5","","","1","%"],["General and administrative expense","","273.2","","","","254.6","","","","18.6","","","7","%"],["Impairment of long-lived assets","","452.3","","","","2,442.8","","","","(1,990.5",")","","(81","%)"],["Other operating (income) expense","","12.4","","","","116.6","","","","(104.2",")","","(89","%)"],["Income (loss) from operations","","864.8","","","","(1,303.7",")","","","2,168.5","","","166","%"],["Interest expense, net","","(387.9",")","","","(391.3",")","","","3.4","","","1","%"],["Equity earnings (loss)","","(23.9",")","","","72.6","","","","(96.5",")","","(133","%)"],["Gain (loss) from financing activities","","(16.6",")","","","45.6","","","","(62.2",")","","(136","%)"],["Change in contingent considerations","","(0.1",")","","","0.3","","","","(0.4",")","","(133","%)"],["Other, net","","0.6","","","","3.4","","","","(2.8",")","","(82","%)"],["Income tax (expense) benefit","","(14.8",")","","","248.1","","","","(262.9",")","","(106","%)"],["Net income (loss)","","422.1","","","","(1,325.0",")","","","1,747.1","","","132","%"],["Less: Net income (loss) attributable to noncontrolling interests","","350.9","","","","228.9","","","","122.0","","","53","%"],["Net income (loss) attributable to Targa Resources Corp.","","71.2","","","","(1,553.9",")","","","1,625.1","","","105","%"],["Dividends on Series A Preferred Stock","","87.3","","","","91.7","","","","(4.4",")","","(5","%)"],["Deemed dividends on Series A Preferred Stock","","\u2014","","","","39.2","","","","(39.2",")","","(100","%)"],["Net income (loss) attributable to common shareholders","$","(16.1",")","","$","(1,684.8",")","","$","1,668.7","","","99","%"],["Financial data:"],["Adjusted EBITDA (2)","$","2,052.0","","","$","1,636.6","","","$","415.4","","","25","%"],["Distributable cash flow (2)","","1,541.4","","","","1,172.8","","","","368.6","","","31","%"],["Adjusted free cash flow (2)","","1,133.7","","","","574.9","","","","558.8","","","97","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(2)","Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under \u201cManagement\u2019s Discussion and Analysis of Financial Condition and Results of Operations\u2013How We Evaluate Our Operations.\u201d"]]
[[/GREPCENT_TABLE]]

2021 Compared to 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($8,449.3 million) and higher NGL and natural gas volumes ($917.3 million), partially offset by lower petroleum products, crude marketing and condensate volumes ($147.6 million) and the unfavorable impact of hedges ($787.5 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees and fractionation volumes, partially offset by lower terminaling and storage fees.

The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes, partially offset by lower petroleum products, crude marketing and condensate volumes.

The increase in operating expenses was due to higher labor costs and repairs and maintenance primarily due to increased activity levels and system expansions, partially offset by the reduction in expense due to the idling of GCF in 2021.

See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.

The increase in general and administrative expense was primarily due to higher compensation and benefits and an increase in insurance costs.

In 2021, we recognized a non-cash pre-tax impairment loss of $452.3 million on assets in the South Texas region associated with our Central operations. In 2020, we recognized a non-cash pre-tax impairment loss of $2,442.8 million on assets in the Mid-Continent region associated with our Central operations and full impairment of our Coastal operations. See Note 5 - Property, Plant and Equipment and Intangible Assets for further discussion.

60

Other operating (income) expense in 2021 consisted primarily of the write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts.

The decrease in equity earnings is primarily due to non-cash pre-tax impairment losses of $77.2 on our investments in T2 Eagle Ford and T2 LaSalle located in the South Texas region and lower earnings from our investments in GCF, Cayenne and GCX DevCo JV. See Note 7 – Investments in Unconsolidated Affiliates for further discussion.

During 2021, the Partnership redeemed the 5⅛% Notes and the 4¼% Notes and Targa Pipeline Partners LP (“TPL”) redeemed the TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023, resulting in a $16.6 million net loss from financing activities. During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024 and the 5¼% Senior Notes due 2023, resulting in a $45.6 million net gain from financing activities.

The increase in income tax expense is primarily due to an increase in pre-tax book income.

The increase in net income attributable to noncontrolling interests is primarily due to impairment losses allocated to noncontrolling interest holders in the first quarter of 2020 and higher income allocated to noncontrolling interest holders in Grand Prix Joint Venture. The increase in net income attributable to noncontrolling interests was partially offset by impairment losses allocated to noncontrolling interest holders in the fourth quarter of 2021 and the impact of the redemption of the Partnership’s preferred units in December 2020.

The decrease in dividends on Series A Preferred is due to the partial repurchase of our Series A Preferred in December 2020.

The decrease in deemed dividends on Series A Preferred is due to the adoption of Accounting Standards Update 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend.

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

[[GREPCENT_TABLE]]
[["","Gathering and Processing","","","Logistics and Transportation","","","Other"],["","(In millions)"],["Year Ended:"],["December 31, 2021","$","","1,325.3","","","$","","1,264.3","","","$","","(115.9",")"],["December 31, 2020","","","1,017.7","","","","","1,128.0","","","","","229.7"]]
[[/GREPCENT_TABLE]]

61

Gathering and Processing Segment

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2021","","","2020","","","2021 vs. 2020"],["","(In millions, except operating statistics and price amounts)"],["Operating margin","$","","1,325.3","","","$","","1,017.7","","","$","","307.6","","","","30","%"],["Operating expenses (1)","","","476.2","","","","","429.9","","","","","46.3","","","","11","%"],["Adjusted operating margin (1)","$","","1,801.5","","","$","","1,447.6","","","$","","353.9","","","","24","%"],["Operating statistics (2):"],["Plant natural gas inlet, MMcf/d (3),(4)"],["Permian Midland (5)","","","1,928.4","","","","","1,745.6","","","","","182.8","","","","10","%"],["Permian Delaware","","","839.8","","","","","729.4","","","","","110.4","","","","15","%"],["Total Permian","","","2,768.2","","","","","2,475.0","","","","","293.2"],["SouthTX (6)","","","177.7","","","","","248.1","","","","","(70.4",")","","","(28","%)"],["North Texas","","","178.9","","","","","201.6","","","","","(22.7",")","","","(11","%)"],["SouthOK (6)","","","405.9","","","","","443.0","","","","","(37.1",")","","","(8","%)"],["WestOK","","","212.6","","","","","249.5","","","","","(36.9",")","","","(15","%)"],["Total Central","","","975.1","","","","","1,142.2","","","","","(167.1",")"],["Badlands (6) (7)","","","139.8","","","","","137.8","","","","","2.0","","","","1","%"],["Total Field","","","3,883.1","","","","","3,755.0","","","","","128.1"],["Coastal","","","587.2","","","","","643.3","","","","","(56.1",")","","","(9","%)"],["Total","","","4,470.3","","","","","4,398.3","","","","","72.0","","","","2","%"],["NGL production, MBbl/d (4)"],["Permian Midland (5)","","","277.9","","","","","250.8","","","","","27.1","","","","11","%"],["Permian Delaware","","","114.1","","","","","99.1","","","","","15.0","","","","15","%"],["Total Permian","","","392.0","","","","","349.9","","","","","42.1"],["SouthTX (6)","","","22.2","","","","","26.1","","","","","(3.9",")","","","(15","%)"],["North Texas","","","20.1","","","","","23.9","","","","","(3.8",")","","","(16","%)"],["SouthOK (6)","","","49.5","","","","","52.4","","","","","(2.9",")","","","(6","%)"],["WestOK","","","16.5","","","","","20.3","","","","","(3.8",")","","","(19","%)"],["Total Central","","","108.3","","","","","122.7","","","","","(14.4",")"],["Badlands (6)","","","16.2","","","","","16.3","","","","","(0.1",")","","","(1","%)"],["Total Field","","","516.5","","","","","488.9","","","","","27.6"],["Coastal","","","33.9","","","","","40.0","","","","","(6.1",")","","","(15","%)"],["Total","","","550.4","","","","","528.9","","","","","21.5","","","","4","%"],["Crude oil, Badlands, MBbl/d","","","140.9","","","","","156.5","","","","","(15.6",")","","","(10","%)"],["Crude oil, Permian, MBbl/d","","","35.0","","","","","43.3","","","","","(8.3",")","","","(19","%)"],["Natural gas sales, BBtu/d (4)","","","2,207.7","","","","","2,094.8","","","","","112.9","","","","5","%"],["NGL sales, MBbl/d (4)","","","394.6","","","","","399.5","","","","","(4.9",")","","","(1","%)"],["Condensate sales, MBbl/d","","","14.9","","","","","15.5","","","","","(0.6",")","","","(4","%)"],["Average realized prices - inclusive of hedges (8):"],["Natural gas, $/MMBtu","","","3.27","","","","","1.27","","","","","2.00","","","","157","%"],["NGL, $/gal","","","0.61","","","","","0.26","","","","","0.35","","","","135","%"],["Condensate, $/Bbl","","","60.02","","","","","39.40","","","","","20.62","","","","52","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business."]]
[[/GREPCENT_TABLE]]

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

[[GREPCENT_TABLE]]
[["(3)","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."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(4)","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."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(5)","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."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(6)","Operations include facilities that are not wholly owned by us. For more information regarding our joint ventures and jointly owned facilities, see \u201cItem 1. Business\u2014Our Business Operations.\u201d"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(7)","Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(8)","Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator."]]
[[/GREPCENT_TABLE]]

62

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

[[GREPCENT_TABLE]]
[["","","Year Ended December 31, 2021","","","Year Ended December 31, 2020"],["","","(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)","","","76.8","","","$","(1.41",")","","$","(108.0",")","","","68.1","","","$","0.37","","","$","25.1"],["NGL (MMgal)","","","581.5","","","","(0.26",")","","","(153.1",")","","","451.4","","","","0.12","","","","53.3"],["Crude oil (MBbl)","","","2.1","","","","(14.33",")","","","(30.1",")","","","1.9","","","","18.54","","","","34.9"],["","","","","","","","","","","$","(291.2",")","","","","","","","","","","$","113.3"]]
[[/GREPCENT_TABLE]]

________________

[[GREPCENT_TABLE]]
[["(1)","The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction."]]
[[/GREPCENT_TABLE]]

2021 Compared to 2020

The increase in adjusted operating margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting in increased margin predominantly in the Permian, partially offset by the short-term operational disruption and impacts associated with a major winter storm during the first quarter of 2021. The increase in natural gas inlet volumes in the Permian was attributable to higher production, higher producer activity, the addition of the Peregrine and Gateway plants during 2020 and the Heim plant during the third quarter of 2021. In the Badlands, natural gas inlet volumes were relatively flat, while the decrease in the Central and Coastal regions was due to lower production and continued low producer activity. Total crude oil volumes decreased in the Badlands and the Permian due to lower production.

Operating expenses were higher due to increased activity levels in the Permian, the additions of the Peregrine and Gateway plants in 2020 and the Heim plant in the third quarter of 2021, which resulted in increased labor costs, materials and chemicals, partially offset by a reduction in taxes.

Logistics and Transportation Segment

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2021","","","2020","","","2021 vs. 2020"],["","(In millions, except operating statistics)"],["Operating margin","$","","1,264.3","","","$","","1,128.0","","","$","","136.3","","","12%"],["Operating expenses (1)","","","273.0","","","","","274.0","","","","","(1.0",")","","\u2014"],["Adjusted operating margin (1)","$","","1,537.3","","","$","","1,402.0","","","$","","135.3","","","10%"],["Operating statistics MBbl/d (2):"],["NGL pipeline transportation volumes (3)","","","396.2","","","","","293.7","","","","","102.5","","","35%"],["Fractionation volumes","","","616.0","","","","","602.9","","","","","13.1","","","2%"],["Export volumes (4)","","","316.9","","","","","300.4","","","","","16.5","","","5%"],["NGL sales","","","899.7","","","","","752.5","","","","","147.2","","","20%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(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 period and the denominator is the number of calendar days during the period."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(3)","Represents the total quantity of mixed NGLs that earn a transportation margin."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(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."]]
[[/GREPCENT_TABLE]]

2021 Compared to 2020

The increase in adjusted operating margin was primarily due to higher pipeline transportation and fractionation volumes that benefited from higher supply volumes from our Permian Gathering and Processing systems, partially offset by short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021. Additionally, fractionation volumes for the full year were partially offset by an unplanned outage and associated repairs and maintenance in the fourth quarter of 2021. Other drivers included higher marketing margin due to greater optimization opportunities, partially offset by lower LPG export margin primarily attributable to lower fees.

Operating expenses were flat. The sale of assets in Channelview, Texas in 2020 and the absence of one-time maintenance expenses, including hurricane damage repairs in the fourth quarter of 2020, were offset by higher taxes due to system expansions and higher compensation and benefits.

63

Other

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2021","","","2020","","","2021 vs. 2020"],["","(In millions)"],["Operating margin","$","(115.9",")","","$","229.7","","","$","(345.6",")"],["Adjusted operating margin","$","(115.9",")","","$","229.7","","","$","(345.6",")"]]
[[/GREPCENT_TABLE]]

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

Our Liquidity and Capital Resources

As of December 31, 2021, inclusive of our consolidated joint venture accounts, we had $158.5 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the New TRC Revolver and the Securitization Facility and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

We believe our sources of liquidity and capital resources are sufficient to meet our anticipated cash requirements for at least the next twelve months to satisfy our obligations. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments.”

Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity, subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements, as well as the ability to contribute capital to the Partnership, subject to any restrictions contained in the covenants of our debt agreements. We are entitled to the entirety of distributions made by the Partnership on its equity interests. The actual amount we declare as distributions depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.

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

Short-term Liquidity

Our principal sources of short-term liquidity consist of internally generated cash flow, borrowings available under the New TRC Revolver, as well as our right to request additional commitment increases under the New TRC Revolver, the Securitization Facility, proceeds from debt and equity offerings and joint ventures and/or asset sales. Based on anticipated levels of operations and absent any disruptive events, we believe our liquidity is sufficient to finance our operations, capital expenditures, quarterly cash dividends and obligations, as discussed further below, for at least the next twelve months.

64

Our short-term liquidity on a consolidated basis as of February 18, 2022, was:

[[GREPCENT_TABLE]]
[["","","Consolidated Total"],["","","(In millions)"],["Cash on hand (1)","","$","382.1"],["Total availability under the New TRC Revolver","","","2,750.0"],["Total availability under the Securitization Facility","","","400.0"],["","","","3,532.1"],["Less: Outstanding borrowings under the New TRC Revolver","","","(825.0",")"],["Outstanding borrowings under the Securitization Facility","","","(400.0",")"],["Outstanding letters of credit under the New TRC Revolver","","","(105.2",")"],["Total liquidity","","$","2,201.9"]]
[[/GREPCENT_TABLE]]

_________________________________

[[GREPCENT_TABLE]]
[["(1)","Includes cash held in our consolidated joint venture accounts."]]
[[/GREPCENT_TABLE]]

Other potential capital resources associated with our existing arrangements includes our right to request an additional $500.0 million in commitment increases under the New TRC Revolver, subject to the terms therein. The New TRC Revolver matures on February 17, 2027.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P as of February 18, 2022. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

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

Working capital as of December 31, 2021 decreased $209.6 million compared to December 31, 2020. The decrease was primarily due to higher product purchases and fuel payable as a result of higher commodity prices and an increase in the current liability position of our derivative contracts, partially offset by higher receivables resulting from higher commodity prices and lower borrowings on the Securitization Facility.

Long-term Financing

Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements. The majority of our debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the New TRC Revolver and the Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2021, we did not have any interest rate hedges.

To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 8 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

In February 2021, the Partnership issued $1.0 billion aggregate principal amount of 4% Senior Notes due 2032, resulting in net proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the February Tender Offer and subsequent redemption payment for the 5⅛% Notes, with the remainder used for repayment of borrowings under the Existing TRP Revolver and Existing TRC Revolver. As a result of the February Tender Offer and the subsequent redemption of the 5⅛% Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

65

Additionally, TPL redeemed all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023 (collectively, the “TPL Notes”) in February 2021 with available liquidity under the Existing TRP Revolver. As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.

The Partnership redeemed all of the outstanding 4¼% Senior Notes due 2023 (the “4¼% Senior Notes”) in May 2021 with available liquidity under the Existing TRP Revolver. As a result of the redemption of the 4¼% Senior Notes, we recorded a loss due to debt extinguishment of $1.9 million.

In April 2021, we amended the Securitization Facility to increase the facility size from $350.0 million to $400.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2022.

In February 2022, we entered into the New TRC Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto. The New TRC Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $2.75 billion, with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the New TRC Revolver, and a swing line sub-facility of up to $100.0 million. The New TRC Revolver matures on February 17, 2027. In connection with our entry into the New TRC Revolver, we terminated the Existing TRC Revolver and Existing TRP Revolver.

On February 18, 2022, we and certain of our subsidiaries entered into a Parent Guarantee to guarantee all of the obligations of the Partnership and Targa Resources Partners Finance Corp. (together with the Partnership, the “Issuers”) under the respective indentures governing the Issuers’ $6.5 billion of outstanding senior unsecured notes. For a full discussion of the senior unsecured notes and related terms, see Note 8 – Debt Obligations in our Consolidated Financial Statements beginning on page F-1 in this Form 10-K.

We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Additionally, we may redeem all or a portion of the Series A Preferred in the future pursuant to its terms or repurchase Series A Preferred shares in privately negotiated transactions. Such repurchases, exchanges or transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 8 - Debt Obligations to our consolidated financial statements.

Compliance with Debt Covenants

As of December 31, 2021, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flow Analysis

Cash Flows from Operating Activities

[[GREPCENT_TABLE]]
[["Year Ended December 31,"],["2021","","","2020","","","2021 vs. 2020"],["(In millions)"],["$","2,302.9","","","$","1,744.5","","","$","558.4"]]
[[/GREPCENT_TABLE]]

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

The increase in net cash provided by operations was primarily due to higher commodity prices, resulting in higher collections from customers, partially offset by an increase in payments for product purchases and fuel and hedge transactions.

66

Cash Flows from Investing Activities

[[GREPCENT_TABLE]]
[["Year Ended December 31,"],["2021","","","2020","","","2021 vs. 2020"],["(In millions)"],["$","(473.2",")","","$","(738.1",")","","$","264.9"]]
[[/GREPCENT_TABLE]]

The decrease in net cash used in investing activities was primarily due to lower outlays for property, plant and equipment of $446.5 million, resulting from the completion of Trains 7 and 8, the LPG export expansion, the Grand Prix Central Oklahoma extension, and the Gateway and Peregrine plants and associated infrastructure in the Permian Basin in 2020, partially offset by higher proceeds from the sale of business and assets of $186.5 million, including from the sale of our Delaware crude system in 2020.

Cash Flows from Financing Activities

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2021","","","2020"],["","(In millions)"],["Source of Financing Activities, net"],["Debt, including financing costs","$","(1,189.1",")","","$","(32.9",")"],["Contributions from (distributions to) noncontrolling interests","","(484.2",")","","","(397.7",")"],["Dividends and distributions","","(187.5",")","","","(395.9",")"],["Redemption of Preferred Units","","\u2014","","","","(125.0",")"],["Partial repurchase of Series A Preferred Stock","","\u2014","","","","(45.8",")"],["Other","","(53.2",")","","","(97.4",")"],["Net cash provided by (used in) financing activities","$","(1,914.0",")","","$","(1,094.7",")"]]
[[/GREPCENT_TABLE]]

The increase in net cash used in financing activities was primarily due to higher repayments of debt and higher distributions to noncontrolling interests in 2021, partially offset by lower dividends and distributions paid in 2021 and redemption of Preferred Units and partial repurchase of Preferred Stock in 2020.

Common Stock Dividends

The following table details the dividends declared and/or paid by us to common shareholders for 2021:

[[GREPCENT_TABLE]]
[["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, 2021","","February 15, 2022","$","","81.4","","$","","80.1","","$","","1.3","","$","","0.35000"],["September 30, 2021","","November 15, 2021","","","23.3","","","","22.9","","","","0.4","","","","0.10000"],["June 30, 2021","","August 16, 2021","","","23.3","","","","22.9","","","","0.4","","","","0.10000"],["March 31, 2021","","May 14, 2021","","","23.3","","","","22.9","","","","0.4","","","","0.10000"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting."]]
[[/GREPCENT_TABLE]]

Preferred Dividends

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

Cash dividends of $87.3 million were paid to holders of the Series A Preferred during the year ended December 31, 2021. As of December 31, 2021, cash dividends accrued for our Series A Preferred were $21.8 million, which were paid on February 14, 2022.

67

Capital Expenditures

The following table details cash outlays for capital projects for the years ended December 31, 2021 and 2020:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020"],["","","(In millions)"],["Capital expenditures:"],["Growth (1)","","$","421.9","","","$","617.3"],["Maintenance (2)","","","138.6","","","","109.5"],["Gross capital expenditures","","","560.5","","","","726.8"],["Transfers from materials and supplies inventory to property, plant and equipment","","","(2.4",")","","","(2.1",")"],["Change in capital project payables and accruals, net","","","(53.0",")","","","226.9"],["Cash outlays for capital projects","","$","505.1","","","$","951.6"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $407.7 million and $597.9 million for the years ended December 31, 2021 and 2020."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(2)","Maintenance capital expenditures, net of contributions from noncontrolling interests, were $131.7 million and $104.2 million for the years ended December 31, 2021 and 2020."]]
[[/GREPCENT_TABLE]]

The decrease in total growth capital expenditures was primarily due to lower spending on growth capital investments in 2021, as a significant portion of our major projects began full service in 2020, including Trains 7 and 8, the LPG export expansion, the Grand Prix Central Oklahoma extension, and the Gateway and Peregrine plants and associated infrastructure in the Permian Basin. The increase in total maintenance capital expenditures was primarily due to system expansions.

We currently estimate that in 2022 we will invest between $700 to $800 million in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investment opportunities. We expect that 2022 maintenance capital expenditures, net of noncontrolling interests, will be approximately $150 million.

Off-Balance Sheet Arrangements

As of December 31, 2021, there were $65.2 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

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

Contractual Obligations

We believe we have sufficient liquidity to fund our operations and meet our short-term and long-term obligations. The following is a summary of our material future contractual obligations:

[[GREPCENT_TABLE]]
[["Contractual Obligations:","","Total","","","Within 12 Months"],["","(in millions)"],["Long-term debt obligations (1)","","$","","6,465.7","","","$","","\u2014"],["Interest on debt obligations (2)","","","","2,457.4","","","","","359.3"],["Operating leases (3)","","","","51.6","","","","","13.3"],["Finance leases (4)","","","","27.9","","","","","13.1"],["Land site lease and rights of way (5)","","","","237.3","","","","","4.5"],["Purchase obligations (6)","","","","1,477.0","","","","","645.0"],["Other long-term liabilities (7)","","","","112.2","","","","","11.8"],["Total","","$","","10,829.1","","","$","","1,047.0"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Represents scheduled future maturities of long-term debt obligation. See Note 8 - Debt Obligations for more information."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(2)","Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2021 rates for floating debt. See Note 8 - Debt Obligations for more information."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(3)","Includes minimum payments on operating lease obligations for office space and railcars. See Note 10 - Leases for more information."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(4)","Includes minimum payments on finance lease obligations for vehicles and tractors. See Note 10 - Leases for more information."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(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."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(6)","Includes commitments for pipeline capacity payments for firm transportation and throughput and deficiency agreements, purchase of natural gas and NGLs, capital expenditures, operating expenses and service contracts. Contracts that will be settled at future spot prices are valued using prices as of December 31, 2021."]]
[[/GREPCENT_TABLE]]

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

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.

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