# Targa Resources Corp. (TRGP) FY 2023 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Targa Resources Corp.'s 10-K for fiscal year 2023.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1389170/000095017024015841/trgp-20231231.htm
Accession: 0000950170-24-015841
Filing date: 2024-02-15
Report date: 2023-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture.
Confidence: high

Company profile: /company/TRGP/
All MD&A years: /company/TRGP/mda/
Previous year: /company/TRGP/mda/fy2022/ (FY 2022)
Next year: /company/TRGP/mda/fy2024/ (FY 2024)

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 2021 items and year-to-year comparisons between 2022 and 2021 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, 2022.

General Trends and Outlook

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

Commodity Prices

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

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

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

[[GREPCENT_TABLE]]
[["","Natural Gas $/MMBtu (1)","","","Illustrative Targa NGL $/gal (2)","","","Crude Oil $/Bbl (3)"],["2023"],["4th Quarter","$","2.88","","","$","0.60","","","$","78.33"],["3rd Quarter","","2.54","","","","0.62","","","","82.18"],["2nd Quarter","","2.09","","","","0.56","","","","73.75"],["1st Quarter","","3.45","","","","0.70","","","","76.11"],["2023 Average","","2.74","","","","0.62","","","","77.59"],["2022"],["4th Quarter","$","6.27","","","$","0.72","","","$","82.63"],["3rd Quarter","","8.19","","","","0.94","","","","91.64"],["2nd Quarter","","7.17","","","","1.09","","","","108.42"],["1st Quarter","","4.92","","","","1.04","","","","94.38"],["2022 Average","","6.64","","","","0.95","","","","94.27"]]
[[/GREPCENT_TABLE]]

(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:

2023: 44% ethane, 32% propane, 11% normal butane, 4% isobutane and 9% natural gasoline

2022: 43% ethane, 32% propane, 12% normal butane, 4% isobutane and 9% natural gasoline

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

56

Volumes and Demand for our Services

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

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

Contract Terms, Contract Mix and the Impact of Commodity Prices

Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. Volatility in commodity prices can have a significant impact on our profitability, especially those percent-of-proceeds contracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from the commodities handled (“equity volumes”).

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

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

Impact of Our Commodity Price Hedging Activities

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

Operating Expenses

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

57

Volatile Capital Markets and Competition

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

Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our growth strategy. Due to increased volatility in commodity prices and the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. We believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures in 2023 and beyond. For additional information regarding our financing activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Liquidity and Capital Resources.”

Increased Regulation

Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers and increased GHG emission regulations may cause reductions in supplies of natural gas, NGLs and crude oil from producers. Please read “Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets”, “Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change (including legislation or regulation to address climate change) that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide,” and “Increasing stakeholder and market attention to sustainability matters and disclosure obligations 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: (i) throughput volumes, facility efficiencies and fuel consumption, (ii) operating expenses, (iii) capital expenditures and (iv) the following non-GAAP measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment).

58

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 inflation, and will fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

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

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

Non-GAAP Measures

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

59

Adjusted Operating Margin

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

Gathering and Processing adjusted operating margin consists primarily of:

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

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

Logistics and Transportation adjusted operating margin consists primarily of:

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

•
system product gains and losses; and

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

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

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

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

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

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

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

Adjusted EBITDA

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

Distributable Cash Flow and Adjusted Free Cash Flow

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

60

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,"],["","2023","","","2022"],["","(In millions)"],["Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow"],["Net income (loss) attributable to Targa Resources Corp.","$","1,345.9","","","$","1,195.5"],["Interest (income) expense, net","","687.8","","","","446.1"],["Income tax expense (benefit)","","363.2","","","","131.8"],["Depreciation and amortization expense","","1,329.6","","","","1,096.0"],["(Gain) loss on sale or disposition of assets","","(5.3",")","","","(9.6",")"],["Write-down of assets","","6.9","","","","9.8"],["(Gain) loss from financing activities (1)","","2.1","","","","49.6"],["(Gain) loss from sale of equity method investment","","\u2014","","","","(435.9",")"],["Transaction costs related to business acquisition (2)","","\u2014","","","","23.9"],["Equity (earnings) loss","","(9.0",")","","","(9.1",")"],["Distributions (contributions) from unconsolidated affiliates, net","","18.6","","","","27.2"],["Compensation on equity grants","","62.4","","","","57.5"],["Risk management activities","","(275.4",")","","","302.5"],["Noncontrolling interests adjustments (3)","","(3.7",")","","","15.8"],["Litigation expense (4)","","6.9","","","","\u2014"],["Adjusted EBITDA","$","3,530.0","","","$","2,901.1"],["Interest expense on debt obligations (5)","","(675.8",")","","","(447.6",")"],["Maintenance capital expenditures, net (6)","","(223.4",")","","","(168.1",")"],["Cash taxes","","(13.6",")","","","(6.7",")"],["Distributable Cash Flow","$","2,617.2","","","$","2,278.7"],["Growth capital expenditures, net (6)","","(2,224.5",")","","","(1,177.2",")"],["Adjusted Free Cash Flow","$","392.7","","","$","1,101.5"]]
[[/GREPCENT_TABLE]]

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

(2)
Includes financial advisory, legal and other professional fees, and other one-time transaction costs.

(3)
Noncontrolling interest portion of depreciation and amortization expense.

(4)
Litigation expense includes charges related to litigation resulting from the major winter storm in February 2021 that we consider outside the ordinary course of our business and/or not reflective of our ongoing core operations. We may incur such charges from time to time, and we believe it is useful to exclude such charges because we do not consider them reflective of our ongoing core operations and because of the generally singular nature of the claims underlying such litigation.

(5)
Excludes amortization of debt issuance costs.

(6)
Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates.

61

Consolidated Results of Operations

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022","","","2023 vs. 2022"],["","(In millions)"],["Revenues:"],["Sales of commodities","$","13,962.1","","","$","19,066.0","","","$","(5,103.9",")","","(27","%)"],["Fees from midstream services","","2,098.2","","","","1,863.8","","","","234.4","","","13","%"],["Total revenues","","16,060.3","","","","20,929.8","","","","(4,869.5",")","","(23","%)"],["Product purchases and fuel","","10,676.4","","","","16,882.1","","","","(6,205.7",")","","(37","%)"],["Operating expenses","","1,077.9","","","","912.8","","","","165.1","","","18","%"],["Depreciation and amortization expense","","1,329.6","","","","1,096.0","","","","233.6","","","21","%"],["General and administrative expense","","348.7","","","","309.7","","","","39.0","","","13","%"],["Other operating (income) expense","","1.5","","","","0.2","","","","1.3","","NM"],["Income (loss) from operations","","2,626.2","","","","1,729.0","","","","897.2","","","52","%"],["Interest expense, net","","(687.8",")","","","(446.1",")","","","(241.7",")","","54","%"],["Equity earnings (loss)","","9.0","","","","9.1","","","","(0.1",")","","(1","%)"],["Gain (loss) from financing activities","","(2.1",")","","","(49.6",")","","","47.5","","","96","%"],["Gain (loss) from sale of equity method investment","","\u2014","","","","435.9","","","","(435.9",")","","(100","%)"],["Other, net","","(2.8",")","","","(15.1",")","","","12.3","","","81","%"],["Income tax (expense) benefit","","(363.2",")","","","(131.8",")","","","(231.4",")","","176","%"],["Net income (loss)","","1,579.3","","","","1,531.4","","","","47.9","","","3","%"],["Less: Net income (loss) attributable to noncontrolling interests","","233.4","","","","335.9","","","","(102.5",")","","(31","%)"],["Net income (loss) attributable to Targa Resources Corp.","","1,345.9","","","","1,195.5","","","","150.4","","","13","%"],["Premium on repurchase of noncontrolling interests, net of tax","","510.1","","","","53.2","","","","456.9","","NM"],["Dividends on Series A Preferred Stock","","\u2014","","","","30.0","","","","(30.0",")","","(100","%)"],["Deemed dividends on Series A Preferred Stock","","\u2014","","","","215.5","","","","(215.5",")","","(100","%)"],["Net income (loss) attributable to common shareholders","$","835.8","","","$","896.8","","","$","(61.0",")","","(7","%)"],["Financial data:"],["Adjusted EBITDA (1)","$","3,530.0","","","$","2,901.1","","","$","628.9","","","22","%"],["Distributable cash flow (1)","","2,617.2","","","","2,278.7","","","","338.5","","","15","%"],["Adjusted free cash flow (1)","","392.7","","","","1,101.5","","","","(708.8",")","","(64","%)"]]
[[/GREPCENT_TABLE]]

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

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

2023 Compared to 2022

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($9,255.7 million), partially offset by higher NGL, natural gas and condensate volumes ($2,951.9 million) and the favorable impact of hedges ($1,195.8 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees including the impact of the acquisition of certain assets in the Delaware Basin and South Texas, and higher export volumes, partially offset by lower transportation and fractionation fees.

The decrease in product purchases and fuel reflects lower NGL, natural gas and condensate prices, partially offset by higher NGL, natural gas and condensate volumes.

The increase in operating expenses is primarily due to higher labor, maintenance and rental costs due to increased activity and system expansions, the acquisition of certain assets in the Delaware Basin and South Texas, and inflation.

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

The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and the impact of system expansions on our asset base, partially offset by the shortening of depreciable lives of certain assets that were idled in 2022.

The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs, computer systems and professional fees.

62

The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates, partially offset by higher capitalized interest resulting from higher growth capital investments.

During 2022, we terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership’s senior secured revolving credit facility. In addition, the Partnership redeemed its 5.375% Senior Notes due 2027 and its 5.875% Senior Notes due 2026. These transactions resulted in a net loss from financing activities.

During 2022, we completed the sale of Targa GCX Pipeline LLC, which held a 25% equity interest in Gulf Coast Express Pipeline to a third party for $857 million (the “GCX Sale”) resulting in a gain from sale of an equity method investment. See Note 4 - Acquisitions and Divestitures for further discussion.

The increase in income tax expense is primarily due to an increase in pre-tax book income and a smaller release of the valuation allowance in 2023 compared to 2022.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to our joint venture partner in WestTX.

The premium on repurchase of noncontrolling interests, net of tax is primarily due to the Grand Prix Transaction in 2023 and the purchase of all of Stonepeak Infrastructure Partners’ interests in our development company joint ventures in 2022.

The decrease in dividends on Series A Preferred is due to the full redemption of all of our issued and outstanding shares of Series A Preferred in May 2022. See Note 11 – Preferred Stock for further discussion.

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, 2023","","$","2,082.2","","","$","1,948.7","","","$","275.5"],["December 31, 2022","","","1,981.0","","","","1,456.3","","","","(302.4",")"]]
[[/GREPCENT_TABLE]]

63

Gathering and Processing Segment

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022","","","2023 vs. 2022"],["","(In millions, except operating statistics and price amounts)"],["Operating margin","$","","2,082.2","","","$","","1,981.0","","","$","","101.2","","","","5","%"],["Operating expenses","","","746.6","","","","","611.8","","","","","134.8","","","","22","%"],["Adjusted operating margin","$","","2,828.8","","","$","","2,592.8","","","$","","236.0","","","","9","%"],["Operating statistics (1):"],["Plant natural gas inlet, MMcf/d (2) (3)"],["Permian Midland (4)","","","2,535.2","","","","","2,223.6","","","","","311.6","","","","14","%"],["Permian Delaware (5)","","","2,526.5","","","","","1,536.1","","","","","990.4","","","","64","%"],["Total Permian","","","5,061.7","","","","","3,759.7","","","","","1,302.0","","","","35","%"],["SouthTX (6)","","","367.4","","","","","276.5","","","","","90.9","","","","33","%"],["North Texas","","","205.9","","","","","187.0","","","","","18.9","","","","10","%"],["SouthOK (6)","","","385.0","","","","","406.8","","","","","(21.8",")","","","(5","%)"],["WestOK","","","207.1","","","","","208.7","","","","","(1.6",")","","","(1","%)"],["Total Central","","","1,165.4","","","","","1,079.0","","","","","86.4","","","","8","%"],["Badlands (6) (7)","","","130.0","","","","","134.9","","","","","(4.9",")","","","(4","%)"],["Total Field","","","6,357.1","","","","","4,973.6","","","","","1,383.5","","","","28","%"],["Coastal","","","541.1","","","","","537.6","","","","","3.5","","","","1","%"],["Total","","","6,898.2","","","","","5,511.2","","","","","1,387.0","","","","25","%"],["NGL production, MBbl/d (3)"],["Permian Midland (4)","","","367.7","","","","","321.7","","","","","46.0","","","","14","%"],["Permian Delaware (5)","","","321.6","","","","","188.6","","","","","133.0","","","","71","%"],["Total Permian","","","689.3","","","","","510.3","","","","","179.0","","","","35","%"],["SouthTX (6)","","","40.9","","","","","31.2","","","","","9.7","","","","31","%"],["North Texas","","","24.0","","","","","21.2","","","","","2.8","","","","13","%"],["SouthOK (6)","","","43.1","","","","","47.6","","","","","(4.5",")","","","(9","%)"],["WestOK","","","12.5","","","","","14.6","","","","","(2.1",")","","","(14","%)"],["Total Central","","","120.5","","","","","114.6","","","","","5.9","","","","5","%"],["Badlands (6)","","","15.5","","","","","16.1","","","","","(0.6",")","","","(4","%)"],["Total Field","","","825.3","","","","","641.0","","","","","184.3","","","","29","%"],["Coastal","","","39.2","","","","","32.0","","","","","7.2","","","","23","%"],["Total","","","864.5","","","","","673.0","","","","","191.5","","","","28","%"],["Crude oil, Badlands, MBbl/d","","","105.5","","","","","117.6","","","","","(12.1",")","","","(10","%)"],["Crude oil, Permian, MBbl/d","","","27.4","","","","","29.5","","","","","(2.1",")","","","(7","%)"],["Natural gas sales, BBtu/d (3)","","","2,685.8","","","","","2,383.4","","","","","302.4","","","","13","%"],["NGL sales, MBbl/d (3)","","","495.8","","","","","439.8","","","","","56.0","","","","13","%"],["Condensate sales, MBbl/d","","","18.5","","","","","15.5","","","","","3.0","","","","19","%"],["Average realized prices (8):"],["Natural gas, $/MMBtu","","","1.94","","","","","5.21","","","","","(3.27",")","","","(63","%)"],["NGL, $/gal","","","0.46","","","","","0.75","","","","","(0.29",")","","","(39","%)"],["Condensate, $/Bbl","","","74.35","","","","","88.26","","","","","(13.91",")","","","(16","%)"]]
[[/GREPCENT_TABLE]]

(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 period and the denominator is the number of calendar days during the period.

(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 a 72.8% undivided interest, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(5)
Includes operations from the acquisition of certain assets in the Delaware Basin for the period effective August 1, 2022.

(6)
Operations include facilities that are not wholly owned by us. SouthTX operating statistics include the impact of the South Texas Acquisition for the period effective April 21, 2022. For more information regarding our joint ventures and jointly owned facilities, see “Item 1. Business—Our Business Operations.”

(7)
Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.

(8)
Average realized prices, net of fees, 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, net of fees.

64

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, 2023","","","Year Ended December 31, 2022"],["","","(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)","","","63.2","","","$","1.22","","","$","77.4","","","","74.8","","","$","(2.13",")","","$","(159.2",")"],["NGL (MMgal)","","","680.3","","","","0.07","","","","49.9","","","","717.6","","","","(0.30",")","","","(213.0",")"],["Crude oil (MBbl)","","","2.4","","","","(6.92",")","","","(16.6",")","","","2.2","","","","(31.73",")","","","(69.8",")"],["","","","","","","","","$","110.7","","","","","","","","","$","(442.0",")"]]
[[/GREPCENT_TABLE]]

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

2023 Compared to 2022

The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets in the Delaware Basin during the third quarter of 2022, the addition of the Legacy I and Red Hills VI plants during the third quarter of 2022, the Legacy II plant during the first quarter of 2023, the Greenwood plant during the fourth quarter of 2023, and continued strong producer activity. Natural gas inlet volumes in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in the Delaware Basin and South Texas. Additionally, higher volumes in the Permian, the addition of the Legacy I, Red Hills VI, Legacy II, Midway, Greenwood and Wildcat II plants, and inflation impacts resulted in increased costs.

Logistics and Transportation Segment

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022","","","2023 vs. 2022"],["","(In millions, except operating statistics)"],["Operating margin","$","","1,948.7","","","$","","1,456.3","","","$","","492.4","","","34%"],["Operating expenses","","","332.0","","","","","300.2","","","","","31.8","","","11%"],["Adjusted operating margin","$","","2,280.7","","","$","","1,756.5","","","$","","524.2","","","30%"],["Operating statistics MBbl/d (1):"],["NGL pipeline transportation volumes (2)","","","635.5","","","","","488.6","","","","","146.9","","","30%"],["Fractionation volumes","","","798.1","","","","","731.7","","","","","66.4","","","9%"],["Export volumes (3)","","","365.2","","","","","314.5","","","","","50.7","","","16%"],["NGL sales","","","1,019.8","","","","","866.3","","","","","153.5","","","18%"]]
[[/GREPCENT_TABLE]]

(1)
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.

(2)
Represents the total quantity of mixed NGLs that earn a transportation margin.

(3)
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.

2023 Compared to 2022

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, higher marketing margin, and higher LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems and higher fees. Marketing margin increased due to greater optimization opportunities. LPG Export margin increased due to the completion of the expansion during the third quarter of 2023 resulting in higher volumes and fees.

The increase in operating expenses was due to higher system volumes, higher compensation and benefits, higher repairs and maintenance and higher taxes.

Other

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022","","","2023 vs. 2022"],["","(In millions)"],["Operating margin","$","275.5","","","$","(302.4",")","","$","577.9"],["Adjusted operating margin","$","275.5","","","$","(302.4",")","","$","577.9"]]
[[/GREPCENT_TABLE]]

65

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, 2023, inclusive of our consolidated joint venture accounts, we had $141.7 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, Commercial Paper Program, Securitization Facility, and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

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

Short-term Liquidity

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

Our short-term liquidity on a consolidated basis as of December 31, 2023, was:

[[GREPCENT_TABLE]]
[["","","Consolidated Total"],["","","(In millions)"],["Cash on hand (1)","","$","141.7"],["Total availability under the Securitization Facility","","","600.0"],["Total availability under the TRGP Revolver and Commercial Paper Program","","","2,750.0"],["","","","3,491.7"],["Less: Outstanding borrowings under the Securitization Facility","","","(575.0",")"],["Outstanding borrowings under the TRGP Revolver and Commercial Paper Program","","","(175.0",")"],["Outstanding letters of credit under the TRGP Revolver","","","(22.3",")"],["Total liquidity","","$","2,719.4"]]
[[/GREPCENT_TABLE]]

(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 $500.0 million in commitment increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 17, 2027.

In August 2023, the Partnership amended the Securitization Facility to decrease the size of the Securitization Facility from $800.0 million to $600.0 million and to extend the termination date of the Securitization Facility to August 29, 2024.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of December 31, 2023, we had $22.3 million in letters of credit outstanding under the TRGP Revolver. The letters of credit also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels, which we closely manage, and valuation; (iii) changes in payables and accruals

66

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, 2023 increased $143.8 million compared to December 31, 2022. The increase was primarily due to lower net borrowing on the Securitization Facility and lower net liabilities for hedging activities, partially offset by higher accounts payable related to capital spending on growth projects.

Long-term Financing

Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements. The majority of our debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRGP Revolver, Term Loan Facility, the Securitization Facility, and the Commercial Paper Program. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2023, 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 January 2023, we completed the underwritten public offering of the 6.125% Notes and the January 2023 6.500% Notes, resulting in net proceeds of approximately $1.7 billion. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining net proceeds for general corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.

In November 2023, we completed the underwritten public offering of the 2023 6.150% Notes and the November 2023 6.500% Notes, resulting in net proceeds of approximately $2.0 billion. We used a portion of the net proceeds to repay $1.0 billion in borrowings under the Term Loan Facility and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program. As a result of the repayment of borrowings under the Term Loan Facility, we recorded a loss of $2.1 million due to a write-off of debt issuance costs.

In the future, we or the Partnership may redeem, purchase or exchange certain of our and/or the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness.

Compliance with Debt Covenants

As of December 31, 2023, 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,"],["2023","","","2022","","","2023 vs. 2022"],["(In millions)"],["$","3,211.6","","","$","2,380.8","","","$","830.8"]]
[[/GREPCENT_TABLE]]

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

67

The increase in net cash provided by operations was primarily due to higher settlements for hedge transactions and a decrease in payments for product purchases and fuel, partially offset by lower collections from customers.

Cash Flows from Investing Activities

[[GREPCENT_TABLE]]
[["Year Ended December 31,"],["2023","","","2022","","","2023 vs. 2022"],["(In millions)"],["$","(2,400.8",")","","$","(4,149.7",")","","$","1,748.9"]]
[[/GREPCENT_TABLE]]

The decrease in net cash used in investing activities was primarily due to higher outlays for the acquisition of certain assets in the Delaware Basin and South Texas in 2022, partially offset by proceeds from the GCX Sale in 2022 and higher outlays for property, plant and equipment in 2023 primarily related to construction activities in the Permian region and Mont Belvieu, Texas.

Cash Flows from Financing Activities

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022"],["","(In millions)"],["Source of Financing Activities, net"],["Debt, including financing costs","$","1,300.0","","","$","4,651.5"],["Redemption of Series A Preferred Stock","","\u2014","","","","(965.2",")"],["Repurchase of noncontrolling interests","","(1,118.9",")","","","(926.3",")"],["Dividends","","(427.3",")","","","(379.7",")"],["Contributions from (distributions to) noncontrolling interests","","(212.4",")","","","(290.3",")"],["Repurchase of shares","","(429.5",")","","","(260.6",")"],["Net cash provided by (used in) financing activities","$","(888.1",")","","$","1,829.4"]]
[[/GREPCENT_TABLE]]

The change in net cash provided by (used in) financing activities was primarily due to lower borrowings of debt, higher repurchases of noncontrolling interests and higher repurchases of common stock, partially offset by the redemption of all of our Series A Preferred in 2022 and higher distributions to noncontrolling interests prior to the Grand Prix Transaction.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

Our subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and severally, the payment of TRGP’s senior notes, subject to certain limited exceptions.

In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.

All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information.

68

Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group as of the end of the most recent period presented follows:

[[GREPCENT_TABLE]]
[["Summarized Combined Balance Sheet Information"],["","","December 31, 2023","","","December 31, 2022"],["","","(In millions)"],["ASSETS"],["Current assets","","$","966.3","","","$","1,425.4"],["Current assets - affiliates","","","11.2","","","","6.0"],["Long-term assets","","","15,267.6","","","","14,398.8"],["Long-term assets - affiliates","","","\u2014","","","","10.5"],["Total assets","","$","16,245.1","","","$","15,840.7"],["LIABILITIES AND OWNERS\u2019 EQUITY"],["Current liabilities","","$","2,107.9","","","$","2,169.6"],["Current liabilities - affiliates","","","26.2","","","","28.0"],["Long-term liabilities","","","13,278.8","","","","11,503.4"],["Targa Resources Corp. stockholders\u2019 equity","","","832.2","","","","2,139.7"],["Total liabilities and owners\u2019 equity","","$","16,245.1","","","$","15,840.7"],["Summarized Combined Statement of Operations Information"],["","","Year Ended","","","Year Ended"],["","","December 31, 2023","","","December 31, 2022"],["","","(In millions)"],["Revenues","","$","15,737.0","","","$","20,477.0"],["Operating income (loss)","","","2,134.2","","","","1,108.3"],["Net income (loss)","","","1,100.1","","","","909.0"],["Dividends on Series A Preferred","","","\u2014","","","","30.0"]]
[[/GREPCENT_TABLE]]

Common Stock Dividends

The following table details the dividends declared and/or paid by us to common shareholders for 2023:

[[GREPCENT_TABLE]]
[["Three Months Ended","","Date Paid or To Be Paid","","Total Common Dividends Declared","","","Amount of Common Dividends Paid or To Be Paid","","","Dividends on Share-Based Awards","","","Dividends Declared per Share of Common Stock"],["(In millions, except per share amounts)"],["December 31, 2023","","February 15, 2024","$","","112.8","","$","","111.6","","$","","1.2","","$","","0.50000"],["September 30, 2023","","November 15, 2023","","","113.0","","","","111.5","","","","1.5","","","","0.50000"],["June 30, 2023","","August 15, 2023","","","113.6","","","","111.8","","","","1.8","","","","0.50000"],["March 31, 2023","","May 15, 2023","","","114.7","","","","113.0","","","","1.7","","","","0.50000"]]
[[/GREPCENT_TABLE]]

Preferred Dividends

Series A Preferred Redemption

In May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, of which $215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. See Note 11 - Preferred Stock to our Consolidated Financial Statements.

Prior to the redemption of our Series A Preferred in May 2022, our Series A Preferred bore a cumulative 9.5% fixed dividend payable at the end of each fiscal quarter. During the year ended December 31, 2022, we paid $51.8 million of dividends to preferred shareholders.

69

Capital Expenditures

The following table details cash outlays for capital projects for the years ended December 31, 2023 and 2022:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","","2022"],["","","(In millions)"],["Capital expenditures:"],["Growth (1)","","$","2,211.0","","","$","1,219.0"],["Maintenance (2)","","","232.6","","","","175.4"],["Gross capital expenditures","","","2,443.6","","","","1,394.4"],["Change in capital project payables and accruals, net","","","(58.2",")","","","(60.1",")"],["Cash outlays for capital projects","","$","2,385.4","","","$","1,334.3"]]
[[/GREPCENT_TABLE]]

(1)
Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $2,224.5 million and $1,177.2 million for the years ended December 31, 2023 and 2022.

(2)
Maintenance capital expenditures, net of contributions from noncontrolling interests, were $223.4 million and $168.1 million for the years ended December 31, 2023 and 2022.

The increase in total growth capital expenditures was primarily due to system expansions in the Permian region in response to forecasted production growth and higher activity levels, and expansions in our downstream business. The increase in total maintenance capital expenditures was primarily due to our growing infrastructure footprint.

With our announced natural gas processing additions currently under construction in the Permian region, coupled with the construction of our Daytona NGL Pipeline and Train 9 and 10 fractionators in Mont Belvieu, we currently estimate that in 2024 we will invest between $2.3 billion to $2.5 billion in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investment opportunities. We expect that 2024 maintenance capital expenditures, net of noncontrolling interests, will be approximately $225 million.

Off-Balance Sheet Arrangements

As of December 31, 2023, there were $248.1 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)","","$","","12,209.4","","","$","","\u2014"],["Interest on debt obligations (2)","","","","7,109.8","","","","","695.7"],["Operating leases (3)","","","","88.3","","","","","25.5"],["Finance leases (4)","","","","332.1","","","","","57.5"],["Land site lease and rights of way (5)","","","","297.4","","","","","8.5"],["Purchase obligations (6)","","","","3,014.8","","","","","1,800.7"],["Other long-term liabilities (7)","","","","122.6","","","","","17.0"],["Total","","$","","23,174.4","","","$","","2,604.9"]]
[[/GREPCENT_TABLE]]

(1)
Represents scheduled future maturities of long-term debt obligation. See Note 8 - Debt Obligations for more information.

(2)
Represents interest expense on long-term debt obligations based on both fixed debt interest rates and prevailing December 31, 2023 rates for floating debt. See Note 8 - Debt Obligations for more information.

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

(4)
Includes minimum payments on finance lease obligations for compressors, substations, vehicles and tractors. See Note 10 - Leases for more information.

(5)
Land site lease and rights of way provide for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates with varying terms, some of which are perpetual. See Note 17 - Commitments for more information.

(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, 2023.

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

Critical Accounting Policies and Estimates

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

Business Acquisitions

For business acquisitions, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Goodwill results when the cost of a business acquisition exceeds the fair value of the net identifiable assets of the acquired business. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectations regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest in the investee, the duration of each liability, and any resulting goodwill can materially impact the financial statements in periods after acquisition. See Note 4 – Acquisitions and Divestitures in our Consolidated Financial Statements.

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

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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.