# Targa Resources Corp.: Form 10-K for the period ended Dec 31, 2023

- Company: [Targa Resources Corp.](/companies/trgp.md) (CIK 1389170)
- Form: 10-K
- Filed: 2024-02-15
- Accepted by EDGAR: Feb 15, 2024, 16:01 ET
- Period: 2023-12-31
- Accession: 0000950170-24-015841
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1389170/000095017024015841/trgp-20231231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1389170/000095017024015841/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2023-01-01 to 2023-12-31 | $13.52bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Cost of revenue | 12 months, 2023-01-01 to 2023-12-31 | $10.68bn | us-gaap:CostOfGoodsAndServicesSold |
| Operating income | 12 months, 2023-01-01 to 2023-12-31 | $2.63bn | us-gaap:OperatingIncomeLoss |
| Income tax | 12 months, 2023-01-01 to 2023-12-31 | $363.2m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2023-01-01 to 2023-12-31 | $1.35bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2023-01-01 to 2023-12-31 | $3.66 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2023-01-01 to 2023-12-31 | $3.69 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2023-01-01 to 2023-12-31 | 226,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2023-01-01 to 2023-12-31 | $3.21bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2023-01-01 to 2023-12-31 | $2.39bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2023-12-31 | $141.7m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-12-31 | $2.19bn | us-gaap:AssetsCurrent |
| Total assets | at 2023-12-31 | $20.67bn | us-gaap:Assets |
| Current liabilities | at 2023-12-31 | $2.76bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2023-12-31 | $12.95bn | us-gaap:LongTermDebt |
| Shareholders' equity | at 2023-12-31 | $2.74bn | us-gaap:StockholdersEquity |

## Business

As filed, 181,030 characters.

### CONSOLIDATED BALANCE SHEETS

*(In millions)*

*ASSETS*

| Current assets: | December 31, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Cash and cash equivalents | $141.7 | $219.0 |
| Trade receivables, net of allowances of $2.5 million and $2.2 million at December 31, 2023 and December 31, 2022 | 1,471.0 | 1,408.4 |
| Inventories | 371.5 | 393.8 |
| Assets from risk management activities | 111.9 | 179.9 |
| Other current assets | 98.5 | 155.5 |
| Total current assets | 2,194.6 | 2,356.6 |
| Property, plant and equipment, net | 15,806.4 | 14,214.6 |
| Intangible assets, net | 2,350.6 | 2,734.6 |
| Long-term assets from risk management activities | 33.3 | 24.5 |
| Investments in unconsolidated affiliates | 146.3 | 131.3 |
| Other long-term assets | 140.6 | 98.4 |
| Total assets | $20,671.8 | $19,560.0 |
| **LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS’ EQUITY** |  |  |
| Current liabilities: |  |  |
| Accounts payable | $1,574.9 | $1,448.8 |
| Accrued liabilities | 281.7 | 289.5 |
| Interest payable | 229.6 | 174.0 |
| Liabilities from risk management activities | 54.0 | 320.1 |
| Current debt obligations | 620.7 | 834.3 |
| Total current liabilities | 2,760.9 | 3,066.7 |
| Long-term debt | 12,333.2 | 10,702.1 |
| Long-term liabilities from risk management activities | 16.8 | 140.1 |
| Deferred income taxes, net | 535.8 | 327.7 |
| Other long-term liabilities | 415.1 | 341.2 |
| Commitments and Contingencies (see Notes 17 and 18) |  |  |
| Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, zero shares issued and outstanding as of December 31, 2023 and December 31, 2022), net of discount | — | — |
| Owners’ equity: |  |  |
| Targa Resources Corp. stockholders’ equity: |  |  |
| Common stock ($0.001 par value, 450,000,000 shares authorized as of December 31, 2023 and December 31, 2022) | 0.2 | 0.2 |
| Issued Outstanding |  |  |
| December 31, 2023 240,095,699 222,611,259 |  |  |
| December 31, 2022 237,939,058 226,042,229 |  |  |
| Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, zero shares issued and outstanding) | — | — |
| Additional paid-in capital | 3,058.8 | 3,702.3 |
| Retained earnings (deficit) | 492.0 | (626.8) |
| Accumulated other comprehensive income (loss) | 85.6 | 54.7 |
| Treasury stock, at cost (17,484,440 shares as of December 31, 2023 and 11,896,829 shares as of December 31, 2022) | (896.9) | (464.7) |
| Total Targa Resources Corp. stockholders’ equity | 2,739.7 | 2,665.7 |
| Noncontrolling interests | 1,870.3 | 2,316.5 |
| Total owners’ equity | 4,610.0 | 4,982.2 |
| Total liabilities, Series A Preferred Stock and owners’ equity | $20,671.8 | $19,560.0 |

See notes to consolidated financial statements.

### CONSOLIDATED STATEMENTS OF OPERATIONS

*(In millions, except per share amounts)*

| Revenues: | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Sales of commodities | $13,962.1 | $19,066.0 | $15,602.5 |
| Fees from midstream services | 2,098.2 | 1,863.8 | 1,347.3 |
| Total revenues | 16,060.3 | 20,929.8 | 16,949.8 |
| Costs and expenses: |  |  |  |
| Product purchases and fuel | 10,676.4 | 16,882.1 | 13,729.5 |
| Operating expenses | 1,077.9 | 912.8 | 747.0 |
| Depreciation and amortization expense | 1,329.6 | 1,096.0 | 870.6 |
| General and administrative expense | 348.7 | 309.7 | 273.2 |
| Impairment of long-lived assets | — | — | 452.3 |
| Other operating (income) expense | 1.5 | 0.2 | 12.4 |
| Income (loss) from operations | 2,626.2 | 1,729.0 | 864.8 |
| Other income (expense): |  |  |  |
| Interest expense, net | (687.8) | (446.1) | (387.9) |
| Equity earnings (loss) | 9.0 | 9.1 | (23.9) |
| Gain (loss) from financing activities | (2.1) | (49.6) | (16.6) |
| Gain (loss) from sale of equity method investment | — | 435.9 | — |
| Other, net | (2.8) | (15.1) | 0.5 |
| Income (loss) before income taxes | 1,942.5 | 1,663.2 | 436.9 |
| Income tax (expense) benefit | (363.2) | (131.8) | (14.8) |
| Net income (loss) | 1,579.3 | 1,531.4 | 422.1 |
| Less: Net income (loss) attributable to noncontrolling interests | 233.4 | 335.9 | 350.9 |
| Net income (loss) attributable to Targa Resources Corp. | 1,345.9 | 1,195.5 | 71.2 |
| Premium on repurchase of noncontrolling interests, net of tax | 510.1 | 53.2 | — |
| Dividends on Series A Preferred Stock | — | 30.0 | 87.3 |
| Deemed dividends on Series A Preferred Stock | — | 215.5 | — |
| Net income (loss) attributable to common shareholders | $835.8 | $896.8 | $(16.1) |
| Net income (loss) per common share - basic | $3.69 | $3.95 | $(0.07) |
| Net income (loss) per common share - diluted | $3.66 | $3.88 | $(0.07) |
| Weighted average shares outstanding - basic | 224.6 | 227.3 | 228.6 |
| Weighted average shares outstanding - diluted | 226.0 | 231.1 | 228.6 |

See notes to consolidated financial statements.

### CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

*(In millions)*

|  | Year Ended December 31, 2023 Pre-Tax | Related Income Tax | After Tax | 2022 Pre-Tax | Related Income Tax | After Tax | 2021 Pre-Tax | Related Income Tax | After Tax |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Net income (loss) |  |  | $1,579.3 |  |  | $1,531.4 |  |  | $422.1 |
| Other comprehensive income (loss): |  |  |  |  |  |  |  |  |  |
| Commodity hedging contracts: |  |  |  |  |  |  |  |  |  |
| Change in fair value | $193.4 | $(44.3) | 149.1 | $(5.6) | $1.3 | (4.3) | $(534.6) | $128.4 | (406.2) |
| Settlements reclassified to revenues | (153.4) | 35.2 | (118.2) | 373.0 | (83.1) | 289.9 | 417.3 | (100.2) | 317.1 |
| Other comprehensive income (loss) | 40.0 | (9.1) | 30.9 | 367.4 | (81.8) | 285.6 | (117.3) | 28.2 | (89.1) |
| Comprehensive income (loss) |  |  | 1,610.2 |  |  | 1,817.0 |  |  | 333.0 |
| Less: Comprehensive income (loss) attributable to noncontrolling interests |  |  | 233.4 |  |  | 335.9 |  |  | 350.9 |
| Comprehensive income (loss) attributable to Targa Resources Corp. |  |  | $1,376.8 |  |  | $1,481.1 |  |  | $(17.9) |

See notes to consolidated financial statements.

### CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY AND SERIES A PREFERRED STOCK

*(In millions, except shares in thousands)*

|  | Common Stock Shares | Amount | Additional Paid in Capital | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income (Loss) | Treasury Shares Shares | Amount | Noncontrolling Interests | Total Owners’ Equity | Series A Preferred Stock |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| **Balance, December 31, 2020** | **228,062** | **$0.2** | **$4,839.9** | **$(1,893.5)** | **$(141.8)** | **6,731** | **$(150.9)** | **$3,249.3** | **$5,903.2** | **$301.4** |
| Impact of accounting standard adoption | — | — | (448.3) | — | — | — | — | — | (448.3) | 448.3 |
| Compensation on equity grants | — | — | 59.2 | — | — | — | — | — | 59.2 | — |
| Dividend equivalent rights | — | — | (3.1) | — | — | — | — | — | (3.1) | — |
| Shares issued under compensation program | 1,312 | — | — | — | — | — | — | — | — | — |
| Shares tendered for tax withholding obligations | (397) | — | — | — | — | 397 | (13.2) | — | (13.2) | — |
| Repurchases of common stock | (756) | — | — | — | — | 756 | (40.0) | — | (40.0) | — |
| Series A Preferred Stock dividends |  |  |  |  |  |  |  |  |  |  |
| Dividends - $95.00 per share | — | — | — | (87.3) | — | — | — | — | (87.3) | — |
| Dividends in excess of retained earnings | — | — | (87.3) | 87.3 | — | — | — | — | — | — |
| Common stock dividends |  |  |  |  |  |  |  |  |  |  |
| Dividends - $0.40 per share | — | — | — | (91.5) | — | — | — | — | (91.5) | — |
| Dividends in excess of retained earnings | — | — | (91.5) | 91.5 | — | — | — | — | — | — |
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (449.1) | (449.1) | — |
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 15.8 | 15.8 | — |
| Other comprehensive income (loss) | — | — | — | — | (89.1) | — | — | — | (89.1) | — |
| Net income (loss) | — | — | — | 71.2 | — | — | — | 350.9 | 422.1 | — |
| **Balance, December 31, 2021** | **228,221** | **0.2** | **4,268.9** | **(1,822.3)** | **(230.9)** | **7,884** | **(204.1)** | **3,166.9** | **5,178.7** | **749.7** |
| Compensation on equity grants | **—** | **—** | 57.5 | **—** | **—** | **—** | **—** | — | 57.5 | **—** |
| Dividend equivalent rights | **—** | **—** | (7.1) | **—** | **—** | **—** | **—** | **—** | (7.1) | — |
| Shares issued under compensation program | 1,834 | **—** | **—** | **—** | **—** | **—** | **—** | **—** | — | — |
| Shares tendered for tax withholding obligations | (601) | **—** | **—** | **—** | **—** | 601 | (35.8) | **—** | (35.8) | — |
| Repurchases of common stock | (3,412) | **—** | **—** | **—** | **—** | 3,412 | (224.8) | — | (224.8) | — |
| Series A Preferred Stock dividends |  |  |  |  |  |  |  |  |  |  |
| Dividends - $47.50 per share | — | **—** | **—** | (30.0) | **—** | **—** | **—** | **—** | (30.0) | — |
| Dividends in excess of retained earnings | **—** | **—** | (30.0) | 30.0 | **—** | **—** | **—** | **—** | — | — |
| Deemed dividends - redemption of Series A Preferred Stock | **—** | **—** | (215.5) | — | **—** | **—** | **—** | **—** | (215.5) | — |
| Common stock dividends |  |  |  |  |  |  |  |  |  |  |
| Dividends - $1.40 per share | **—** | **—** | — | (318.3) | **—** | **—** | **—** | **—** | (318.3) | — |
| Dividends in excess of retained earnings | **—** | **—** | (318.3) | 318.3 | **—** | **—** | **—** | **—** | — | — |
| Redemption of Series A Preferred Stock | **—** | **—** | — | — | **—** | **—** | **—** | **—** | — | (749.7) |
| Distributions to noncontrolling interests | **—** | **—** | **—** | **—** | **—** | **—** | **—** | (354.5) | (354.5) | **—** |
| Contributions from noncontrolling interests | **—** | **—** | — | **—** | **—** | **—** | **—** | 26.1 | 26.1 | **—** |
| Repurchase of noncontrolling interests, net of tax | **—** | **—** | (53.2) | **—** | **—** | **—** | **—** | (857.9) | (911.1) | **—** |
| Other comprehensive income (loss) | **—** | **—** | **—** | **—** | 285.6 | **—** | **—** | — | 285.6 | **—** |
| Net income (loss) | **—** | **—** | — | 1,195.5 | **—** | **—** | **—** | 335.9 | 1,531.4 | **—** |
| **Balance, December 31, 2022** | **226,042** | **$0.2** | **$3,702.3** | **$(626.8)** | **$54.7** | **11,897** | **$(464.7)** | **$2,316.5** | **$4,982.2** | **$—** |

See notes to consolidated financial statements.

### CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY AND SERIES A PREFERRED STOCK

*(In millions, except shares in thousands)*

|  | Common Stock Shares | Amount | Additional Paid in Capital | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income (Loss) | Treasury Shares Shares | Amount | Noncontrolling Interests | Total Owners’ Equity | Series A Preferred Stock |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| **Balance, December 31, 2022** | **226,042** | **$0.2** | **$3,702.3** | **$(626.8)** | **$54.7** | **11,897** | **$(464.7)** | **$2,316.5** | **$4,982.2** | **$—** |
| Compensation on equity grants | — | — | 62.4 | — | — | — | — | — | 62.4 | — |
| Dividend equivalent rights | — | — | (2.3) | (1.6) | — | — | — | — | (3.9) | — |
| Shares issued under compensation program | 2,156 | — | — | — | — | — | — | — | — | — |
| Shares tendered for tax withholding obligations | (716) | — | — | — | — | 716 | (55.8) | — | (55.8) | — |
| Repurchases of common stock | (4,871) | — | — | — | — | 4,871 | (373.7) | — | (373.7) | — |
| Excise tax on repurchases of common stock | — | — | — | — | — | — | (2.7) | — | (2.7) | — |
| Common stock dividends |  |  |  |  |  |  |  |  |  |  |
| Dividends - $1.85 per share | — | — | — | (419.0) | — | — | — | — | (419.0) | — |
| Dividends in excess of retained earnings | — | — | (193.5) | 193.5 | — | — | — | — | — | — |
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (230.0) | (230.0) | — |
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 9.7 | 9.7 | — |
| Repurchase of noncontrolling interests, net of tax | — | — | (510.1) | — | — | — | — | (459.3) | (969.4) | — |
| Other comprehensive income (loss) | — | — | — | — | 30.9 | — | — | — | 30.9 | — |
| Net income (loss) | — | — | — | 1,345.9 | — | — | — | 233.4 | 1,579.3 | — |
| **Balance, December 31, 2023** | **222,611** | **$0.2** | **$3,058.8** | **$492.0** | **$85.6** | **17,484** | **$(896.9)** | **$1,870.3** | **$4,610.0** | **$—** |

See notes to consolidated financial statements.

### CONSOLIDATED STATEMENTS OF CASH FLOWS

*(In millions)*

| Cash flows from operating activities | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Net income (loss) | $1,579.3 | $1,531.4 | $422.1 |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |
| Amortization in interest expense | 13.2 | 10.5 | 10.3 |
| Compensation on equity grants | 62.4 | 57.5 | 59.2 |
| Depreciation and amortization expense | 1,329.6 | 1,096.0 | 870.6 |
| Impairment of long-lived assets | — | — | 452.3 |
| (Gain) loss on sale or disposition of assets | (5.3) | (9.6) | 2.0 |
| Write-downs of assets | 6.9 | 9.8 | 10.3 |
| Accretion of asset retirement obligations | 5.9 | 4.8 | 4.0 |
| Deferred income tax expense (benefit) | 349.6 | 125.1 | 12.1 |
| Equity (earnings) loss of unconsolidated affiliates | (9.0) | (9.1) | 23.9 |
| Distributions of earnings received from unconsolidated affiliates | 13.1 | 12.2 | 84.0 |
| Risk management activities | (275.4) | 302.5 | 116.0 |
| (Gain) loss from financing activities | 2.1 | 49.6 | 16.6 |
| (Gain) loss from sale of equity method investment | — | (435.9) | — |
| Changes in operating assets and liabilities, net of acquisitions: |  |  |  |
| Receivables and other assets | (20.6) | 219.7 | (392.4) |
| Inventories | 36.0 | (236.2) | 40.6 |
| Accounts payable, accrued liabilities and other liabilities | 68.2 | (383.0) | 565.4 |
| Interest payable | 55.6 | 35.5 | 5.9 |
| Net cash provided by operating activities | 3,211.6 | 2,380.8 | 2,302.9 |
| **Cash flows from investing activities** |  |  |  |
| Outlays for property, plant and equipment | (2,385.4) | (1,334.3) | (505.1) |
| Outlays for business acquisition, net of cash acquired | — | (3,503.9) | — |
| Outlays for asset acquisition, net of cash acquired | — | (205.2) | — |
| Proceeds from sale of assets | 4.7 | 23.0 | 12.2 |
| Investments in unconsolidated affiliates | (24.6) | (1.5) | (0.6) |
| Proceeds from sale of equity method investment | — | 857.0 | — |
| Return of capital from unconsolidated affiliates | 5.5 | 16.8 | 20.2 |
| Other, net | (1.0) | (1.6) | 0.1 |
| Net cash provided by (used in) investing activities | (2,400.8) | (4,149.7) | (473.2) |
| **Cash flows from financing activities** |  |  |  |
| Debt obligations: |  |  |  |
| Proceeds from borrowings under credit facilities | — | 5,845.0 | 620.0 |
| Repayments of credit facilities | (290.0) | (5,555.0) | (1,455.0) |
| Proceeds from borrowings of commercial paper notes | 59,002.8 | 30,504.3 | — |
| Repayments of commercial paper notes | (59,836.5) | (29,495.6) | — |
| Proceeds from borrowings under term loan facility | — | 1,500.0 | — |
| Repayments of term loan facility | (1,000.0) | — | — |
| Proceeds from borrowings under accounts receivable securitization facility | 143.1 | 1,230.0 | 630.0 |
| Repayments of accounts receivable securitization facility | (368.1) | (580.0) | (830.0) |
| Proceeds from issuance of senior notes | 3,727.7 | 2,741.4 | 1,000.0 |
| Redemption of senior notes | — | (1,473.2) | (1,132.0) |
| Principal payments of finance leases | (42.9) | (19.7) | (12.5) |
| Costs incurred in connection with financing arrangements | (36.1) | (45.7) | (9.6) |
| Repurchase of shares | (429.5) | (260.6) | (53.2) |
| Contributions from noncontrolling interests | 9.7 | 26.1 | 15.8 |
| Distributions to noncontrolling interests | (222.1) | (316.4) | (500.0) |
| Repurchase of noncontrolling interests | (1,118.9) | (926.3) | — |
| Redemption of Series A Preferred Stock | — | (965.2) | — |
| Dividends paid to common and Series A Preferred shareholders | (427.3) | (379.7) | (187.5) |
| Net cash provided by (used in) financing activities | (888.1) | 1,829.4 | (1,914.0) |
| Net change in cash and cash equivalents | (77.3) | 60.5 | (84.3) |
| Cash and cash equivalents, beginning of period | 219.0 | 158.5 | 242.8 |
| Cash and cash equivalents, end of period | $141.7 | $219.0 | $158.5 |

See notes to consolidated financial statements.

### NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.*

### Note 1 — Organization and Operations

### Our Organization

Targa Resources Corp. (NYSE: TRGP) owns, operates, acquires, and develops a diversified portfolio of complementary domestic midstream infrastructure assets.

In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” “Targa” or “TRGP” are intended to mean our consolidated business and operations. TRGP controls the general partner of and owns all of the outstanding common units representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership”. Targa consolidates the Partnership and its subsidiaries under GAAP, and the accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. Targa’s consolidated financial statements include differences from the consolidated financial statements of the Partnership. The most noteworthy differences are:

- the inclusion of the TRGP senior revolving credit facility and term loan facility;
- the inclusion of the TRGP senior notes;
- the inclusion of the TRGP commercial paper notes;
- the inclusion of Series A Preferred Stock (“Series A Preferred”) prior to full redemption in May 2022; and
- the impacts of TRGP’s treatment as a corporation for U.S. federal income tax purposes.

### Our Operations

The Company is primarily engaged in the business of:

- gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;
- transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and
- gathering, storing, terminaling, and purchasing and selling crude oil.

See Note 23 – Segment Information for certain financial information regarding our business segments.

### Note 2 — Basis of Presentation

These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2023 and 2022, and the results of operations, comprehensive income (loss), cash flows, and changes in owners’ equity for the years ended December 31, 2023, 2022 and 2021. We have prepared these consolidated financial statements in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods have been reclassified to conform to the current year presentation.

### Note 3 — Significant Accounting Policies

### Consolidation Policy

Our consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain gas gathering and processing facilities in which we own an undivided interest and are responsible for our proportionate share of the costs and expenses of the facilities. Third party ownership interests in our controlled subsidiaries are presented as noncontrolling interests within the equity section of our Consolidated Balance Sheets, except in the case of undivided interest ownership. In our Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income (Loss), noncontrolling interests reflect the attribution of results to third-party investors. All intercompany balances and transactions have been eliminated in consolidation.

As of December 31, 2023, our consolidated joint ventures include the following:

#### Gathering and Processing Segment

- 60% ownership interest in Centrahoma Processing LLC;
- 55% ownership interest in Targa Badlands LLC;
- 72.8% undivided interest in the assets of Targa Pipeline Mid-Continent WestTex LLC; and
- 76.8% ownership interest in Venice Energy Services Company, LLC.

#### Logistics and Transportation Segment

- 88% ownership interest in Cedar Bayou Fractionators, L.P.; and
- 80% ownership interest in Targa Train 7 LLC.

We apply the equity method of accounting to investments over which we exercise significant influence over the operating and financial policies of our investee, but do not exercise control. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as a non-cash pre-tax impairment loss within Equity earnings (loss) in our Consolidated Statements of Operations.

As of December 31, 2023, our investments in unconsolidated affiliates include the following:

#### Gathering and Processing Segment

- 50% ownership interest in Little Missouri 4 LLC (“Little Missouri 4”).

#### Logistics and Transportation Segment

- 50% ownership interest in Cayenne Pipeline, LLC (“Cayenne”); and
- 38.8% ownership interest in Gulf Coast Fractionators (“GCF”).

### Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Changes in facts and circumstances may result in revised estimates and actual results could differ materially from those estimates. Estimates and judgments are used in, among other things, (i) estimating unbilled revenues, product purchases and operating and general and administrative cost accruals, (ii) developing fair value assumptions, including estimates of future cash flows and discount rates, (iii) analyzing long-lived assets for possible impairment, (iv) estimating the useful lives of assets and (v) estimating contingencies, guarantees and indemnifications.

### Cash and Cash Equivalents

Cash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily convertible into cash, and have original maturities of three months or less.

### Allowance for Credit Losses

Estimated losses on accounts receivable are provided through an allowance for credit losses. We estimate the allowance for credit losses through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts.

We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. Our evaluation procedures also include performing account reconciliations, dispute resolution and payment confirmation.

As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to our allowance may be required.

### Inventories

Our inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the average cost method. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are included in Property, plant and equipment.

### Product Exchanges

Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities.

### Gas Processing Imbalances

Quantities of natural gas and/or NGLs over-delivered or under-delivered, related to certain gas plant operational balancing agreements, are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or net realizable value using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.

### Derivative Instruments

We utilize derivative instruments to manage the volatility of our cash flows due to fluctuating energy commodity prices. For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis. Cash flows from derivative instruments designated as hedges are recognized in the same financial statement line item as the cash flows from the respective item being hedged.

We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in achieving the offset of changes in cash flows attributable to the hedged risk.

We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales election.

The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements:

*Recognition and Measurement*

|  |  |  |
| --- | --- | --- |
| **Derivative Treatment** | **Balance Sheet** | **Income Statement** |
| Normal Purchases and Normal Sales | Fair value not recorded | Earnings recognized when volumes are physically delivered or received |
| Mark-to-Market | Recorded at fair value | Change in fair value recognized currently in earnings |
| Cash Flow Hedge | Recorded at fair value with changes in fair value deferred in Accumulated Other Comprehensive Income (“AOCI”) | The gain/loss on the derivative instrument is reclassified out of AOCI into earnings when the forecasted transaction occurs |

We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or the forecasted transaction is no longer probable to occur. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.

### Property, Plant and Equipment

Property, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of, and demand for, hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.

Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its existing service potential or prevents environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. Certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs, are capitalized.

### Impairment of Long-Lived Assets

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

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

### Goodwill

Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not subject to amortization but is tested for impairment at least annually. This test requires us to attribute goodwill to an appropriate reporting unit, which is an operating segment or one level below an operating segment (also known as a component). We evaluate goodwill for impairment on November 30 of each year, or whenever impairment indicators are present. Prior to us conducting the goodwill impairment test, we complete a review of the carrying values of our long-lived assets, including property, plant and equipment and other intangible assets. If it is determined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment.

As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when measuring goodwill, we consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit, if applicable.

### Intangible Assets

Our intangible assets include producer dedications under long-term contracts and customer relationships associated with business and asset acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. We amortize the costs of our assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers.

### Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. We record a liability and increase the basis in the underlying asset for the present value of each expected ARO when there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction.

Our obligations are estimated based on discounted cash flow (“DCF”) estimates. Over time, the ARO liability is accreted to its present value as a period cost and the capitalized amount is depreciated over the asset’s respective useful life. At least annually, we review the projected timing and amount of AROs and reflect revisions as an increase or decrease in the carrying amount of the liability and the basis in the underlying asset. Upon settlement, we will recognize any difference between the recorded amount and the actual settlement cost as a gain or loss.

### Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities and the term loan facility are amortized on a straight-line basis and those related to long-term debt are amortized using the effective-interest method. Debt issuance costs related to revolving credit facilities are presented as other long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs.

### Accounts Receivable Securitization Facility

Proceeds from the sale or contribution of certain receivables under the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities in our Consolidated Statements of Cash Flows.

### Commercial Paper Program

Under the terms of the unsecured commercial paper note program (the “Commercial Paper Program”), we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid, and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. We maintain a minimum available borrowing capacity under the $2.75 billion TRGP senior revolving credit facility (the “TRGP Revolver”) equal to the aggregate amount outstanding under the Commercial Paper Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver.

The outstanding borrowings of the commercial paper program are classified as noncurrent because we intend to refinance the borrowings on a long-term basis through the TRGP Revolver. We confirm, on a quarterly basis, that there is sufficient liquidity under the TRGP Revolver to refinance outstanding borrowings of the Commercial Paper Program and such liquidity is not overcommitted for other anticipated uses.

As the outstanding borrowings of the Commercial Paper Program are included as part of long-term debt (i.e., classified as noncurrent), we report Commercial Paper Program borrowings and repayments gross on the statement of cash flows (consistent with the presentation of cash flows associated with the TRGP Revolver).

### Debt Modification and Extinguishment

When similar debt instruments are issued and redeemed in the same period, we evaluate whether the issuance of the new instrument should be accounted for as a modification of the existing debt or as an extinguishment of the existing debt and issuance of new debt. We account for these debt transactions as modifications unless they are considered substantially different debt instruments, in which case we account for them as debt extinguishments and new issuances. Transactions involving the issuance of a new debt instrument to one lender and the concurrent satisfaction of an existing debt instrument with another unrelated lender are always accounted for as an extinguishment of the existing debt and issuance of new debt.

Debt instruments are considered substantially different if the present value of the cash flows under the terms of the new debt instrument is at least 10 percent different from the present value of the remaining cash flows under the terms of the existing debt instrument. We consider changes in principal amounts, interest rates, and maturity dates of the existing and new instruments when evaluating the change in cash flows between the instruments.

Transactions accounted for as modifications do not result in a gain or loss. We calculate a new effective interest rate based on the revised cash flows. Fees paid to existing lenders are capitalized and amortized while expenses paid to third parties are expensed. Transactions accounted for as extinguishments result in derecognition of the extinguished debt and recording the new debt at fair value. A gain or loss is recognized for the difference between the carrying value of the extinguished debt and the fair value of the new debt. New fees paid to existing lenders are expensed while fees paid to third parties are capitalized and amortized as debt issuance costs.

### Environmental Liabilities and Other Loss Contingencies

We accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources, when the loss is probable and reasonably estimable.

### Income Taxes

We file many income tax returns with the U.S. Department of the Treasury, as well as numerous states. We are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense, together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are reported on a net basis by jurisdiction within our Consolidated Balance Sheets. We report these timing differences based on statutory tax rates applicable to the scheduled timing difference reversal periods.

We assess the likelihood that we will recover our deferred tax assets from future taxable income. We establish a valuation allowance if we believe that it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence to determine whether, based on the weight of the evidence, we need a valuation allowance. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

### Dividends

Preferred and common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.

### Comprehensive Income

Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges.

### Revenue Recognition

Our operating revenues are primarily derived from the following activities:

- sales of natural gas, NGLs, condensate and crude oil;
- services related to compressing, gathering, treating, and processing of natural gas; and
- services related to NGL fractionation, terminaling and storage, transportation and treating.

We have multiple types of contracts with commercial counterparties and many of these contracts contain embedded fees with settlement provisions that deduct these fees from the sales price paid by Targa in exchange for commodities. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606, *Revenue from Contracts with Customers*. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases and fuel.

Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues.

We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis.

Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price.

Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract.

The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight-line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation.

Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue.

We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.

We have certain contracts that contain provisions in which customers provide contributions in aid of construction in exchange for Targa constructing assets to fulfill the services in the contract. In general, these arrangements result in deferred revenue, which will be recognized over the contract term.

#### Contract Assets

We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of the reporting period.

We enter into various contractual arrangements that result in the transfer of assets for no upfront compensation or cash payments, resulting in more favorable long-term contractual terms. The fair value of the assets transferred is reflected as long-term contract assets. These deferred amounts are amortized over the term of the related contract into the appropriate revenue or cost of sales accounts.

### Share-Based Compensation

We award share-based compensation to employees and non-employee directors in the form of restricted stock, restricted stock units and performance share units. Compensation expense on our equity-classified awards is recorded at grant-date fair value. Compensation expense is recognized in general and administrative expense over the requisite service period of each award, and forfeitures are recognized as they occur. We may purchase a portion of the shares issued to satisfy employees’ tax withholding obligations on vested awards. These shares are recorded in treasury stock, at cost, and cash paid is classified as a financing activity in our Consolidated Statements of Cash Flows. All excess tax benefits and tax deficiencies related to share-based compensation are recognized as income tax benefit or expense in our Consolidated Statements of Operations, with the tax effects of exercised or vested awards treated as discrete items in the reporting period which they occur. Excess tax benefits are classified as an operating activity.

### Earnings per Share

We calculate basic earnings (loss) per common share (“EPS”) using the two-class method, which is an earnings allocation formula that determines net income (loss) per share for each class of common stock and participating security according to dividends declared and participation rights in undistributed earnings. Our participating securities consist of unvested restricted stock units that vest no later than three years following grant date as well as certain four-year retention awards that participate in nonforfeitable dividends with the common equity owners.

EPS is net income (loss) attributable to common shareholders less earnings allocated to participating securities divided by the sum of the weighted-average number of common shares outstanding. Earnings are allocated to common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings to the extent that each security participates in earnings. Diluted EPS includes any dilutive effect of preferred stock, unvested restricted stock, restricted stock units and performance share units. The dilutive effect is calculated through the application of (i) the if-converted method for convertible preferred stock, (ii) the treasury stock method for unvested stock awards and (iii) two-class method. During a period of net loss or negative undistributed earnings, the two-class method is not applicable.

### Leases

We recognize the following for all leases (with the exception of short-term leases) at the commencement date:

- A lease liability, which is a lessee’s obligation to make lease payments arising from a lease.
- A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Company’s leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases.

Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option.

### Recent Accounting Pronouncements

### Recently Adopted Accounting Pronouncements

#### Supplier Finance Programs

In September 2022, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2022-04, Liabilities—Supplier Finance Programs (Subtopic 405-50). Amendments in this update require annual and interim disclosure of the key terms of outstanding supplier finance programs and a rollforward of the related obligations. These amendments do not affect the recognition, measurement or financial statement presentation of the supplier finance program obligations. These amendments are effective for fiscal years beginning after December 15, 2022, except for the rollforward requirements, which are effective for fiscal years beginning after December 15, 2023. We maintain a supply chain finance program that allows participating suppliers to request early payment from a third-party financial institution of invoices that we confirm as valid. Under this program, we make payments in full to the third-party financial institution for the prior month’s outstanding balance within 15 days. The outstanding balance at the end of each reporting period is included in Accounts payable on our Consolidated Balance Sheets. We adopted the amendments on January 1, 2023, with no material impact on our consolidated financial statements.

### Recently issued accounting pronouncements not yet adopted

#### Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments in this update require, among other items, that public entities disclose, on an annual and interim basis, significant segment expenses that are regularly provided to the chief operating decision maker (“CODM”) and included within each reported measure of segment profit or loss. Additionally, the amendments require annual disclosure of the title and position of the CODM and how that individual uses the reported measure(s) of segment profit or loss in assessing segment performance and how to allocate resources.

These amendments are effective for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The disclosures required in the amendments apply retrospectively to all prior periods presented in the financial statements. We are evaluating the effect of the amendments on our consolidated financial statements and expect to disclose the required information for fiscal years beginning in the Annual Report on Form 10-K for the year ended December 31, 2024 and for interim periods beginning in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2025.

#### Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in this update require, among other items, that public entities disclose, on an annual and interim basis, (i) specific categories of income taxes in the rate reconciliation, and (ii) a disaggregation of income taxes paid by federal, state, and foreign taxes.

These amendments are effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The amendments are required to be applied prospectively with retrospective application permitted. We are evaluating the effect of the amendments on our consolidated financial statements and expect to disclose the required information beginning in the Annual Report on Form 10-K for the year ended December 31, 2025.

### Note 4 – Acquisitions and Divestitures

### Delaware Basin Acquisition

In July 2022, we completed the acquisition of all of the interests in Lucid Energy Delaware, LLC (“Lucid”) from Riverstone Holdings LLC and Goldman Sachs Asset Management for approximately $3.5 billion in cash (the “Delaware Basin Acquisition”), subject to customary closing adjustments. We received a final net working capital adjustment payment of approximately $11.4 million in the fourth quarter of 2022. We funded the acquisition with (i) $1.5 billion in proceeds drawn under our Term Loan Agreement with Mizuho Bank, Ltd. (“Mizuho”) as the Administrative Agent and a lender, and other lenders party thereto (the “Term Loan Facility”), (ii) $750.0 million in aggregate principal amount of our 5.200% Senior Notes due 2027 (the “5.200% Notes”) and $500.0 million in aggregate principal amount of our 6.250% Senior Notes due 2052 (the “6.250% Notes”) pursuant to an underwritten public offering that closed in July 2022 and (iii) $800.0 million drawn on our $2.75 billion TRGP revolving credit facility (the “TRGP Revolver”). We recorded $16.9 million of debt issuance costs related to the Term Loan Facility, the 5.200% Notes and the 6.250% Notes in our Consolidated Balance Sheets. See Note 8 – Debt Obligations for further details on our financing activities.

The assets acquired in the Delaware Basin Acquisition provide natural gas gathering, treating, and processing services in the Delaware Basin, through owning and operating approximately 1,050 miles of natural gas pipelines and approximately 1.4 billion cubic feet per day (“Bcf/d”) of cryogenic natural gas processing capacity primarily in Eddy and Lea counties of New Mexico. The Delaware Basin Acquisition assets increased our footprint in the Delaware Basin and are integrated into our Permian Delaware operations.

The Delaware Basin Acquisition was accounted for under the acquisition method in accordance with ASC 805, *Business Combinations*, which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions, including projections of future production volumes, commodity prices, and other cash flows, market-participant assumptions (e.g., discount rate and exit multiple), expectations regarding customer contracts and relationships, tangible asset replacement costs, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 15 – Fair Value Measurements. These inputs require judgments and estimates at the time of valuation.

The following table summarizes the purchase price allocation based on the final fair values assigned to assets acquired and liabilities assumed (in millions):

|  |  |
| --- | ---: |
| Cash and cash equivalents | $9.9 |
| Trade receivables, net of allowances (1) | 211.0 |
| Other current assets | 3.5 |
| Property, plant and equipment, net | 1,669.0 |
| Intangible assets, net | 1,882.0 |
| Other long-term assets | 57.3 |
| Current liabilities | (236.7) |
| Other long-term liabilities | (100.7) |
| Purchase price | $3,495.3 |

(1) The fair value of the assets acquired included trade receivables of $211.0 million. The gross amount due under contract was $213.4 million, of which $2.4 million was expected to be uncollectible. Trade receivables, net of allowances, excluded $18.5 million that was due from Targa. We reflected this settlement of a preexisting relationship as a reduction of the purchase price in accordance with ASC 805.

The value of property, plant and equipment is determined using the cost approach and is primarily comprised of Gathering and Processing assets that will be depreciated on a straight-line basis over an estimated weighted-average useful life of 20 years. The associated useful lives of property, plant and equipment were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

The value of intangible assets is comprised of customer relationships, which represent estimated value of long-term contracts with customers that will be amortized in a manner that closely resembles the expected benefit pattern of the intangible assets over an estimated useful life of 14 years. The associated useful lives of intangible assets were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows. The fair value of customer relationships was determined at the date of acquisition based on the present value of estimated future cash flows using the multi-period excess earnings method. The significant assumptions used by management in determining the fair value of customer relationships intangible assets include future revenues, discount rate, and customer attrition rates.

The fair values of the tangible and intangible assets are Level 3 measurements in the fair value hierarchy. The fair value of the intangible assets was determined by applying a discounted cash flow approach, which utilized a discount rate of approximately 19% based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets, and customer attrition rates of approximately 5%.

The results of operations attributable to the assets and liabilities acquired in the Delaware Basin Acquisition have been included in our consolidated financial statements as part of our Permian Delaware operations in the Gathering and Processing segment since the date of the acquisition. Revenue and Net Income attributable to the assets acquired for the period August 1, 2022 through December 31, 2022 were $374.1 million and $7.9 million, respectively. As of December 31, 2022, we had incurred $14.4 million of acquisition-related costs.

### Unaudited Pro Forma Financial Information

The following unaudited pro forma summary presents the consolidated results of operations for the years ended December 31, 2022 and 2021 as if the Delaware Basin Acquisition had occurred on January 1, 2021. The unaudited pro forma financial information is presented for informational purposes only and is not necessarily indicative of our results of operations that would have occurred had the transaction been consummated at the beginning of the period presented, nor is it necessarily indicative of future results.

|  | Year Ended December 31, 2022 | 2021 |
| --- | ---: | ---: |
| Revenues | $21,268.9 | $17,464.7 |
| Net income (loss) | 1,477.4 | 215.7 |

The summarized unaudited pro forma information has been calculated after applying our accounting policies and reflects adjustments for the following:

- Reflects depreciation and amortization based on the fair values of property, plant and equipment and intangible assets, respectively. Property, plant and equipment are depreciated utilizing a straight-line approach. Intangible assets are amortized in a manner that closely resembles their expected benefit pattern;
- Excludes $14.4 million of acquisition-related costs incurred as of December 31, 2022 from pro forma net income for the year ended December 31, 2022. Pro forma net income for the year ended December 31, 2021 was adjusted to include those costs;
- Excludes the impact of operations previously sold by Lucid, prior to Targa’s acquisition of Lucid;
- Excludes the impact of historical activity between Targa and Lucid, prior to Targa’s acquisition of Lucid;
- Excludes general and administrative expense related to Lucid’s former parent company, which Targa did not acquire;
- Excludes amortization of interest expense and debt issuance costs associated with Lucid’s debt, which was not assumed by Targa;
- Includes interest expense and debt issuance cost amortization associated with Targa’s borrowings to finance the Delaware Basin Acquisition; and
- Reflects the income tax effects of the above pro forma adjustments.

### South Texas Acquisition

In April 2022, we completed the acquisition of Southcross Energy Operating LLC and its subsidiaries (“Southcross”) for a purchase price of $201.9 million (the “South Texas Acquisition”), subject to customary closing adjustments. We made a final net working capital adjustment payment of approximately $1.5 million in the fourth quarter of 2022. We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the two joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and that have been consolidated beginning in the second quarter of 2022. We accounted for the purchase as an asset acquisition and capitalized $1.8 million of acquisition-related costs and assumed liabilities of $1.8 million as components of the cost of assets acquired. We allocated $28.1 million to our purchase of Southcross’ interest in the two joint ventures for purposes of consolidation and $169.7 million, $3.9 million and $5.3 million of the residual cost to property, plant and equipment, current assets and liabilities, net and other non-current assets, respectively. See Note 7 – Investments in Unconsolidated Affiliates for further discussion on South Texas Acquisition.

### Joint Ventures Acquisitions and Divestitures

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix NGL Pipeline (“Grand Prix”), Gulf Coast Express Pipeline (“GCX”) and a 110 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). For a four-year period beginning on the date that all three projects commenced commercial operations, we had the option to acquire all or part of Stonepeak’s interests in the DevCo JVs (the “DevCo JV Call Right”). The purchase price payable for such partial or full interests was based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs.

In January 2022, we exercised the DevCo JV Call Right and closed on the purchase of all of Stonepeak’s interests in the DevCo JVs for $926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we owned a 75% interest in the Permian to Mont Belvieu segment of Grand Prix through Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”) (prior to the Grand Prix Transaction, as defined below), a 100% interest in Train 6 and a 25% equity interest in GCX (prior to the GCX Sale as defined below in February 2022). The changes in our ownership interests were accounted for as equity transactions representing the acquisitions of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax was $53.2 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

In May 2022, we completed the sale of Targa GCX Pipeline LLC, which held a 25% equity interest in GCX, to a third party for $857.0 million (the “GCX Sale”). As a result of the GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations in 2022. See Note 7 – Investments in Unconsolidated Affiliates for further discussion on GCX Sale.

In January 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Joint Venture (the “Grand Prix Transaction”) for aggregate consideration of $1.05 billion in cash and a final closing adjustment of $41.9 million. Following the closing of the Grand Prix Transaction, we own 100% of the interest in Grand Prix. The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax, was $489.4 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

In December 2023, we completed the acquisition of the remaining 50% membership interest in Carnero G&P LLC (“Carnero”) from our joint venture partner for cash consideration of $27.0 million (the “Carnero Acquisition”). The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the consideration in excess of the carrying amount, net of tax, was $20.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

### Note 5 — Property, Plant and Equipment and Intangible Assets

#### Property, Plant and Equipment and Intangible Assets

|  | December 31, 2023 | December 31, 2022 | Estimated Useful Lives (In Years) |
| --- | ---: | ---: | --- |
| Gathering systems | $10,858.3 | $10,403.1 | 5 to 20 |
| Processing and fractionation facilities | 8,285.5 | 7,421.2 | 5 to 25 |
| Terminaling and storage facilities | 1,403.9 | 1,341.6 | 5 to 25 |
| Transportation assets | 3,294.0 | 2,919.3 | 10 to 50 |
| Other property, plant and equipment | 430.5 | 387.6 | 3 to 50 |
| Land | 185.0 | 163.3 | — |
| Construction in progress | 1,456.1 | 1,011.0 | — |
| Finance lease right-of-use assets | 351.9 | 266.1 | 5 to 14 |
| Property, plant and equipment | 26,265.2 | 23,913.2 |  |
| Accumulated depreciation, amortization and impairment | (10,458.8) | (9,698.6) |  |
| Property, plant and equipment, net | $15,806.4 | $14,214.6 |  |
| Intangible assets | 4,378.0 | 4,379.7 | 10 to 20 |
| Accumulated amortization and impairment | (2,027.4) | (1,645.1) |  |
| Intangible assets, net | $2,350.6 | $2,734.6 |  |

For each of the years ended December 31, 2023, 2022 and 2021 depreciation expense was $945.6 million, $853.8 million and $739.6 million, respectively.

#### Intangible Assets

Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.

For each of the years ended December 31, 2023, 2022 and 2021 amortization expense was $384.0 million, $242.2 million and $131.0 million, respectively.

The estimated annual amortization expense for intangible assets is approximately $373.2 million, $326.0 million, $279.8 million, $252.2 million and $234.0 million for each of the years 2024 through 2028. As of December 31, 2023, the weighted average amortization period for our intangible assets was approximately 11.4 years.

The changes in our intangible assets are as follows:

|  | December 31, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Balance at beginning of period | $2,734.6 | $1,094.8 |
| Additions from Delaware Basin Acquisition | — | 1,882.0 |
| Amortization | (384.0) | (242.2) |
| Balance at end of period | $2,350.6 | $2,734.6 |

#### Impairments of Long-Lived Assets

We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability.

#### 2021

In the fourth quarter of 2021, we recorded a non-cash pre-tax impairment charge of $452.3 million, comprised of $295.7 million for the impairment of certain gas processing facilities and gathering systems, and $156.6 million related to the impairment of intangible customer relationships associated with our Central operations in the Gathering and Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Underlying our assessment were lower expectations regarding volumes and rates associated with the renewal of future expiring contracts and negotiation of new contracts in the South Texas region.

For the 2021 impairment assessment discussed above, we determined fair value through the use of discounted estimated cash flows to measure the impairment loss for each asset group for which undiscounted future net cash flows were not sufficient to recover the net book value.

The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management’s projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs, and the use of an appropriate terminal value and discount rate. We believe our estimates and models used to determine fair value are similar to what a market participant would use.

The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and thus represents a Level 3 measurement. The significant unobservable inputs used include discount rates and determination of terminal values. We utilized a weighted average discount rate of 9.5% when deriving the fair value of the asset groups impaired during 2021. The weighted average discount rate and terminal values reflect management’s best estimate of inputs a market participant would utilize. The carrying value adjustments are included in Impairment of long-lived assets in our Consolidated Statements of Operations.

We may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the carrying value of our long-lived assets and may result in future impairments.

### Note 6 – Goodwill

As of December 31, 2023, we had $45.2 million of goodwill included in Other long-term assets on the Consolidated Balance Sheets related to the March 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin.

|  | December 31, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Permian Midland | $23.2 | $23.2 |
| Permian Delaware | 22.0 | 22.0 |
| Goodwill | $45.2 | $45.2 |

F-23

The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural gas and NGL prices. The direct and indirect effects of significant declines in commodity prices from the date of acquisition would likely cause the fair values of these reporting units to fall below their carrying values, and could result in an impairment of goodwill.

As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. For our 2023, 2022 and 2021 annual evaluations, we performed a qualitative assessment, which indicated that it is not more likely than not that the fair values of the Permian Midland and Permian Delaware reporting units were less than their carrying amounts, and therefore, a quantitative goodwill impairment test was not necessary. Our qualitative assessment considered, among other things, the overall financial performance and future outlook of the Permian Midland and Permian Delaware reporting units, industry and market considerations, and other relevant entity-specific events.

The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 15 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

### Note 7 – Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates consist of the following:

#### Gathering and Processing Segment

- 50% operated ownership interest in Little Missouri 4.

#### Logistics and Transportation Segment

- 38.8% operated ownership interest in GCF; and
- 50% operated ownership interest in Cayenne.

The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.

In April 2022, we completed the South Texas Acquisition. Prior to closing the South Texas Acquisition, we had two operated joint ventures in South Texas: a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”) and a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford” and, together with T2 LaSalle, the “T2 Joint Ventures”). Following the closing of the South Texas Acquisition, we own 100% of the interest in the T2 Joint Ventures.

In May 2022, we completed the GCX Sale. Prior to the GCX Sale, we owned a 25% non-operated ownership interest in GCX. Following the announcement of the GCX Sale in February 2022, we ceased recognizing equity earnings (loss) due to the terms of the sales agreement. As a result of the GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations in 2022.

The following table shows the activity related to our investments in unconsolidated affiliates:

|  | Balance at December 31, 2020 | Equity Earnings (Loss) | Cash Distributions | Disposition/ Consolidation | Contributions | Balance at December 31, 2021 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| GCX | $435.2 | $63.4 | $(78.1) | $— | $0.5 | $421.0 |
| Little Missouri 4 | 104.7 | 10.9 | (17.5) | — | — | 98.1 |
| T2 Eagle Ford | 79.8 | (57.0) | (1.0) | — | 0.1 | 21.9 |
| T2 LaSalle | 39.6 | (35.0) | (0.4) | — | — | 4.2 |
| GCF (1) | 38.5 | (8.6) | (1.1) | — | — | 28.8 |
| Cayenne | 16.2 | 2.4 | (6.1) | — | — | 12.5 |
| Total | $714.0 | $(23.9) | $(104.2) | $— | $0.6 | $586.5 |
|  | **Balance at December 31, 2021** | **Equity Earnings (Loss)** | **Cash Distributions** | **Disposition/ Consolidation** | **Contributions** | **Balance at December 31, 2022** |
| GCX | $421.0 | $5.7 | $(14.3) | $(412.4) | $— | $— |
| Little Missouri 4 | 98.1 | 5.5 | (12.9) | — | — | 90.7 |
| GCF (1) | 28.8 | (3.2) | — | — | 1.5 | 27.1 |
| T2 Eagle Ford (2) | 21.9 | (0.6) | (0.8) | (20.5) | — | — |
| T2 LaSalle (2) | 4.2 | (0.3) | — | (3.9) | — | — |
| Cayenne | 12.5 | 2.0 | (1.0) | — | — | 13.5 |
| Total | $586.5 | $9.1 | $(29.0) | $(436.8) | $1.5 | $131.3 |
|  | **Balance at December 31, 2022** | **Equity Earnings (Loss)** | **Cash Distributions** | **Disposition/ Consolidation** | **Contributions** | **Balance at December 31, 2023** |
| Little Missouri 4 | $90.7 | $7.7 | $(11.3) | $— | $— | $87.1 |
| GCF (1) | 27.1 | (4.1) | (2.0) | — | 24.6 | 45.6 |
| Cayenne | 13.5 | 5.4 | (5.3) | — | — | 13.6 |
| Total | $131.3 | $9.0 | $(18.6) | $— | $24.6 | $146.3 |

(1) In January 2021, the GCF facility was temporarily idled and Targa assumed operatorship in the first half of 2021. In January 2023, we reached an agreement with our partners to reactivate the GCF facility. The facility is expected to be operational in the second quarter of 2024.

(2) Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100% owned and consolidated by Targa.

Our equity loss for the year ended December 31, 2021 included the effect of impairments in the carrying values of our investments in the T2 Joint Ventures. As a result of the decrease in current and expected future utilization of the underlying assets, we determined that factors indicated that a decrease in the value of our investments occurred that was other than temporary. As a result of the evaluation, we recorded non-cash pre-tax impairment losses of $47.3 million and $29.9 million on our investments in T2 Eagle Ford and T2 LaSalle, respectively, in the fourth quarter of 2021. The impairment losses represented our proportionate share of impairment charges recorded by the joint ventures, as well as impairments of the unamortized excess fair values resulting from the purchase accounting related to the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015.

### Note 8 — Debt Obligations

| Current: | December 31, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Partnership accounts receivable securitization facility, due August 2024 (1) | $575.0 | $800.0 |
| Finance lease liabilities | 45.7 | 34.3 |
| Current debt obligations | 620.7 | 834.3 |
| **Long-term:** |  |  |
| Term loan facility, variable rate, due July 2025 | 500.0 | 1,500.0 |
| TRGP senior revolving credit facility, variable rate, due February 2027 (2) | 175.0 | 1,298.7 |
| Senior unsecured notes issued by TRGP: |  |  |
| 5.200% fixed rate, due July 2027 | 750.0 | 750.0 |
| 6.150% fixed rate, due March 2029 | 1,000.0 | — |
| 4.200% fixed rate, due February 2033 | 750.0 | 750.0 |
| 6.125% fixed rate, due March 2033 | 900.0 | — |
| 6.500% fixed rate, due March 2034 | 1,000.0 | — |
| 4.950% fixed rate, due April 2052 | 750.0 | 750.0 |
| 6.250% fixed rate, due July 2052 | 500.0 | 500.0 |
| 6.500% fixed rate, due February 2053 | 850.0 | — |
| Unamortized discount | (29.5) | (8.4) |
| Senior unsecured notes issued by the Partnership: (3) |  |  |
| 6.500% fixed rate, due July 2027 | 705.2 | 705.2 |
| 5.000% fixed rate, due January 2028 | 700.3 | 700.3 |
| 6.875% fixed rate, due January 2029 | 679.3 | 679.3 |
| 5.500% fixed rate, due March 2030 | 949.6 | 949.6 |
| 4.875% fixed rate, due February 2031 | 1,000.0 | 1,000.0 |
| 4.000% fixed rate, due January 2032 | 1,000.0 | 1,000.0 |
|  | 12,179.9 | 10,574.7 |
| Debt issuance costs, net of amortization | (90.8) | (65.6) |
| Finance lease liabilities | 244.1 | 193.0 |
| Long-term debt | 12,333.2 | 10,702.1 |
| Total debt obligations | $12,953.9 | $11,536.4 |
| **Irrevocable standby letters of credit: (2)** |  |  |
| Letters of credit outstanding under the TRGP senior revolving credit facility | $22.3 | $33.2 |

(1) As of December 31, 2023, the Partnership had $575.0 million of qualifying receivables under its $600.0 million accounts receivable securitization facility (the “Securitization Facility”), resulting in $25.0 million of availability.

(2) We maintain an unsecured commercial paper note program (the “Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program. As of December 31, 2023, the TRGP Revolver had no borrowings outstanding and the Commercial Paper Program had $175.0 million borrowings outstanding, resulting in approximately $2.6 billion of available liquidity, after accounting for outstanding letters of credit.

(3) As of February 2022, we guarantee all of the Partnership’s outstanding senior unsecured notes.

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2023:

|  | Range of Interest Rates Incurred | Weighted Average Interest Rate Incurred |
| --- | --- | ---: |
| TRGP Revolver and Commercial Paper Program | 5.2% - 6.2% | 5.9% |
| Securitization Facility | 5.2% - 6.3% | 5.8% |
| Term Loan Facility | 5.8% - 6.8% | 6.5% |

### Compliance with Debt Covenants

As of December 31, 2023, we were in compliance with the covenants contained in our various debt agreements.

In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes.

### Debt Obligations

#### Partnership’s Accounts Receivable Securitization Facility

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.

The Securitization Facility provides up to $600.0 million of borrowing capacity at SOFR rates plus a margin through August 29, 2024. Under the Securitization Facility, certain Partnership subsidiaries sell or contribute certain qualifying receivables, without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to third-party financial institutions. Sold or contributed receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of the selling or contributing subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims.

#### TRGP Credit Agreement

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

In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC (“S&P”) and Fitch Ratings Inc., and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”). As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations thereunder.

The revolving credit facility bears interest at the Company’s option at: (a) the Base Rate, which is the highest of Bank of America’s prime rate, the federal funds rate plus 0.5% and the Term SOFR (as such term is defined in the TRGP Revolver) rate plus 1.0% (subject in each case to a floor of 0.0%), plus an applicable margin ranging from 0.125% to 0.75%, dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt Rating”), or (b) Term SOFR (which includes, for Term SOFR loans, a SOFR adjustment of plus 0.10%) plus an applicable margin ranging from 1.125% to 1.75%, dependent on the Company’s Debt Rating.

The Company is required to pay a commitment fee equal to an applicable rate ranging from 0.125% to 0.35% (dependent on the Company’s Debt Rating), in each case times the actual daily unused portion of the revolving credit facility.

The obligations under the TRGP Revolver are guaranteed by substantially all material wholly-owned domestic subsidiaries of the Company, including by the Partnership.

The TRGP Revolver requires the Company to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA (the “Consolidated Leverage Ratio”), determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, of no more than 5.50 to 1.00.

The TRGP Revolver restricts the Company’s ability to make dividends to stockholders if an event of default (as defined in the TRGP Revolver) exists or would result from such distribution. In addition, the TRGP Revolver contains various covenants that may limit, among other things, the Company’s ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates.

#### Term Loan Facility

In July 2022, we entered into the Term Loan Facility. The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility and matures in July 2025. We used the proceeds from the Term Loan Facility to fund a portion of the Delaware Basin Acquisition.

The Term Loan Facility bears interest at the Company’s option at: (a) the Base Rate (as defined in the Term Loan Facility), which is the highest of the (i) federal funds rate plus 0.5%, (ii) Mizuho’s prime rate, and (iii) the Term SOFR (as defined in the Term Loan Facility) rate plus 1.0% (subject in each case to a floor of 0.0%), plus an applicable margin ranging from 0.125% to 0.75% dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt Rating”), or (b) Term SOFR plus 0.10% plus an applicable margin ranging from 1.125% to 1.75% dependent on the Debt Rating.

Our obligations under the Term Loan Facility are guaranteed by substantially all material wholly-owned domestic restricted subsidiaries of the Company, including the Partnership.

The Term Loan Facility requires the Company to maintain a Consolidated Leverage Ratio (as defined in the Term Loan Facility), determined as of the last day of each quarter for the four-fiscal-quarter-period ending on the date of determination, of no more than 5.50 to 1.00. For any four-fiscal-quarter-period during which a material acquisition or disposition occurs, the total leverage ratio will be determined on a pro forma basis as though such event had occurred as of the first day of such four-fiscal-quarter-period.

The Term Loan Facility limits the Company’s ability to make dividends to stockholders if an event of default (as defined in the Term Loan Facility) exists or would result from such distribution. In addition, the Term Loan Facility contains various covenants that may limit, among other things, the Company’s ability to incur subsidiary indebtedness, grant liens, make investments, merge or consolidate, and engage in transactions with affiliates.

#### Commercial Paper Program

In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. We maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. The commercial paper notes are presented in Long-term debt on our Consolidated Balance Sheets.

#### TRGP’s Senior Unsecured Notes

All issues of our senior unsecured notes (the “TRGP Notes”) rank pari passu with our existing and future senior indebtedness, including debt issued under the TRGP Revolver, the Commercial Paper Program and the Term Loan Facility, and rank senior in right of payment to any of our future subordinated indebtedness. The TRGP Notes are unconditionally guaranteed by certain of our subsidiaries that guarantee the TRGP Revolver. Each guarantee ranks equally in right of payment with all of such guarantor’s existing and future unsecured senior debt and other unsecured guarantees of senior debt. The notes and the guarantees are effectively junior to any secured indebtedness of ours or any guarantor to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other obligations of our subsidiaries that do not guarantee the notes. Interest on all issues of TRGP Notes is payable semi-annually.

The indenture governing the TRGP Notes restricts (i) our ability and the ability of our subsidiaries to incur liens and (ii) TRGP’s ability to merge or consolidate with or sell, lease, convey, transfer or otherwise dispose of all or substantially all of its assets to another company. These covenants are subject to a number of important exceptions and qualifications.

We may redeem the TRGP Notes, in whole or in part, at any time prior to the applicable par call date at a redemption price equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest, to the redemption date, as specified in the indenture of each series. After the applicable par call date, the TRGP Notes may be redeemed at a price equal to par, plus accrued and unpaid interest to the redemption date, as specified in the indenture of each series.

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

#### Partnership’s Senior Unsecured Notes

All issues of the Partnership’s senior unsecured notes are pari passu with the Partnership’s existing and future senior indebtedness. They are senior in right of payment to any of the Partnership’s future subordinated indebtedness and are unconditionally guaranteed by the Partnership’s restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the Securitization Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.

The Partnership’s senior unsecured notes and associated indenture agreements restrict, among other things, (i) the Partnership’s ability and the ability of certain of its subsidiaries to incur liens and (ii) the Partnership’s ability to merge or consolidate with or sell, lease, convey, transfer or otherwise dispose of all or substantially all of its assets to another company. These covenants are subject to a number of important exceptions and qualifications.

The Partnership may redeem its senior unsecured notes, in whole or in part, at any time prior to their applicable maturity at a redemption price equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest and liquidation damages, if any, to the redemption date, as specified in the indenture of each series.

The Partnership may also redeem up to 35% of the aggregate principal amount of each series of its senior unsecured notes at the redemption dates and prices set forth in the indenture governing such series plus accrued and unpaid interest and liquidation damages, if any, to the redemption date with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each such notes (excluding notes held by the Partnership and its subsidiaries) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering.

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

### Senior Unsecured Notes Issuances

In February 2021, the Partnership issued $1.0 billion aggregate principal amount of 4.000% Senior Notes due 2032 (the “February 2021 Offering”), resulting in net proceeds of approximately $991 million. The 4.000% Senior Notes due 2032 have substantially similar terms and covenants as the Partnership’s other series of senior notes. A portion of the net proceeds from the issuance was used to fund the concurrent cash tender offer (the “February Tender Offer”) and subsequent redemption for the Partnership’s 5.125% Senior Notes due 2025 (the “5.125% Notes”), with the remainder used for repayment of borrowings under the Partnership's senior secured revolving credit facility (the “Partnership Revolver”) and our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”). See “Debt Repurchases and Extinguishments” for further details of the February Tender Offer.

In April 2022, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Senior Notes due 2033 (the “4.200% Notes”) and (ii) $750.0 million aggregate principal amount of our 4.950% Senior Notes due 2052 (the “4.950% Notes”), resulting in net proceeds of approximately $1.5 billion. The 4.200% Notes and the 4.950% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The 4.200% Notes and the 4.950% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain First Supplemental Indenture, dated as of April 6, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. A portion of the net proceeds from the issuance was used to fund the concurrent cash tender offer (the “March Tender Offer”) and the subsequent redemption of the Partnership’s 5.875% Senior Notes due April 2026 (the “5.875% Notes”), with the remainder of the net proceeds used for repayment of the outstanding borrowings under the TRGP Revolver. See “Debt Repurchases and Extinguishments” for further details of the March Tender Offer.

In July 2022, we completed an underwritten public offering of the 5.200% Notes and the 6.250% Notes, resulting in net proceeds of approximately $1.2 billion. The 5.200% Notes and the 6.250% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The 5.200% Notes and the 6.250% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Third Supplemental Indenture, dated as of July 7, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. We used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition.

In January 2023, we completed an underwritten public offering of (i) $900.0 million aggregate principal amount of our 6.125% Senior Notes due 2033 (the “6.125% Notes”) and (ii) $850.0 million aggregate principal amount of our 6.500% Senior Notes due 2053 (the “January 2023 6.500% Notes”), resulting in net proceeds of approximately $1.7 billion. The 6.125% Notes and the January 2023 6.500% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The 6.125% Notes and the January 2023 6.500% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Fifth Supplemental Indenture, dated as of January 9, 2023, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining proceeds for general corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.

In November 2023, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 6.150% Senior Notes due 2029 (the “2023 6.150% Notes”) and (ii) $1.0 billion aggregate principal amount of our 6.500% Senior Notes due 2034 (the “November 2023 6.500% Notes”), resulting in net proceeds of approximately $2.0 billion. The 2023 6.150% Notes and the November 2023 6.500% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. The 2023 6.150% Notes and the November 2023 6.500% Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Seventh Supplemental Indenture, dated as of November 9, 2023, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. 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.

### Debt Repurchases & Extinguishments

Concurrent with the February 2021 Offering, the Partnership commenced the February Tender Offer to redeem subject to certain terms and conditions, any and all of our outstanding 5.125% Notes. As a result of the February Tender Offer and the subsequent redemption of the 5.125% Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

Additionally, Targa Pipeline Partners LP (the “TPL”) redeemed all of the outstanding TPL 4.750% Senior Notes due 2021 and TPL 5.875% Senior Notes due 2023 (collectively, the “TPL Notes”) in February 2021 with available liquidity under the Partnership Revolver. As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.

The Partnership redeemed all of the outstanding 4.250% Senior Notes due 2023 (the “4.250% Senior Notes”) in May 2021 with available liquidity under the Partnership Revolver. As a result of the redemption of the 4.250% Senior Notes, we recorded a loss due to debt extinguishment of $1.9 million.

In February 2022, in connection with entering into the TRGP Revolver, we terminated the Previous TRGP Revolver and Partnership Revolver. As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss of $0.8 million due to a write-off of debt issuance costs.

The Partnership redeemed all of the outstanding 5.375% Senior Notes due 2027 (the “5.375% Notes”) in March 2022 with available liquidity under the TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million comprised of $12.6 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

Concurrent with the 4.200% Notes and the 4.950% Notes offering, we commenced the March Tender Offer to redeem subject to certain terms and conditions, any and all of the Partnership’s outstanding 5.875% Notes. As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we recorded a loss due to debt extinguishment of $33.8 million comprised of $29.3 million of premiums paid and a write-off of $4.5 million of debt issuance costs.

In November 2023, in connection with the 2023 6.150% Notes and November 2023 6.500% Notes, we repaid borrowings under the Term Loan Facility and 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.

The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2023, for the next five years, and in total thereafter:

|  | Scheduled Maturities of Debt Total | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| TRGP Revolver and Commercial Paper Program | $175.0 | $— | $— | $— | $175.0 | $— | $— |
| TRGP Senior unsecured notes | 6,500.0 | — | — | — | 750.0 | — | 5,750.0 |
| Term Loan Facility | 500.0 | — | 500.0 | — | — | — | — |
| Partnership’s Senior unsecured notes | 5,034.4 | — | — | — | 705.2 | 700.3 | 3,628.9 |
| Securitization Facility | 575.0 | 575.0 | — | — | — | — | — |
| Total | $12,784.4 | $575.0 | $500.0 | $— | $1,630.2 | $700.3 | $9,378.9 |

F-30

### Note 9 — Other Long-term Liabilities

Other long-term liabilities are comprised of the following obligations:

|  | December 31, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Deferred revenue | $248.8 | $198.8 |
| Asset retirement obligations | 103.0 | 97.9 |
| Operating lease liabilities | 56.5 | 28.6 |
| Other liabilities | 6.8 | 15.9 |
| Total other long-term liabilities | $415.1 | $341.2 |

### Deferred Revenue

Deferred revenue as of December 31, 2023 and 2022 was $248.8 million and $198.8 million, respectively, which includes $129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent on the outcome of current litigation with Vitol. See Note 18 - Contingencies for more information.

Deferred revenue includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement. The deferred revenue related to these amendments is being recognized through the end of the agreement’s term in 2035.

Deferred revenue also includes contributions in aid of construction received from customers for which revenue is recognized over the expected contract term.

For the years ended December 31, 2023, 2022 and 2021, we recognized $17.4 million, $7.5 million and $3.9 million of revenue for these transactions, respectively.

The following table shows the components of deferred revenue:

|  | December 31, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Splitter agreement | $129.0 | $129.0 |
| Gas contract amendment | 29.8 | 32.3 |
| Contributions in aid of construction (1) | 86.4 | 31.7 |
| Other | 3.6 | 5.8 |
| Total deferred revenue | $248.8 | $198.8 |

(1) Increase in contributions in aid of construction was due to additions of deferred revenue in West Texas and Badlands.

The following table shows the changes in deferred revenue:

|  | 2023 | 2022 |
| --- | ---: | ---: |
| Balance at beginning of period | $198.8 | $171.8 |
| Additions | 67.4 | 34.5 |
| Revenue recognized | (17.4) | (7.5) |
| Balance at end of period | $248.8 | $198.8 |

### Asset Retirement Obligations

Our ARO primarily relate to certain gas gathering pipelines and processing facilities and NGL pipelines. The changes in our ARO are as follows:

|  | 2023 | 2022 |
| --- | ---: | ---: |
| Beginning of period | $97.9 | $72.1 |
| Additions (1) | — | 20.2 |
| Accretion expense | 5.9 | 4.8 |
| Change in cash flow estimate | 4.9 | 0.8 |
| Retirements | (5.7) | — |
| End of period | $103.0 | $97.9 |

F-31

(1) Amount reflects additions of ARO in 2022 related to the Delaware Basin Acquisition.

### Note 10 – Leases

We have non-cancellable operating leases primarily associated with our office facilities, compressors, rail assets, land, storage and terminal assets. We have finance leases primarily associated with our substations, compressors, tractors and vehicles. Our leases have remaining lease terms of 1 to 9 years, some of which include options to extend the lease term for up to 20 years.

The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows:

| Right-of-use assets | Balance Sheet Location | December 31, 2023 | 2022 |
| --- | --- | ---: | ---: |
| Operating leases, gross | Other long-term assets | $101.1 | $57.3 |
| Finance leases, gross (1) | Property, plant and equipment | 351.9 | 266.1 |
| **Lease liabilities** |  |  |  |
| Current: |  |  |  |
| Operating leases | Accrued liabilities | $21.8 | $14.4 |
| Finance leases (1) | Current debt obligations | 45.7 | 34.3 |
| Non-current: |  |  |  |
| Operating leases | Other long-term liabilities | $56.5 | $28.6 |
| Finance leases (1) | Long-term debt | 244.1 | 193.0 |

(1) The December 31, 2022 balance includes $171.2 million of assets and $167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest expense, net in our Consolidated Statements of Operations. The components of lease expense were as follows:

| Lease cost | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Operating lease cost | $18.3 | $17.7 | $12.2 |
| Short-term lease cost | 56.7 | 35.0 | 20.4 |
| Variable lease cost | 26.0 | 17.9 | 5.7 |
| Finance lease cost |  |  |  |
| Amortization of right-of-use assets | 48.2 | 20.3 | 13.3 |
| Interest expense | 14.0 | 3.5 | 1.1 |
| Total lease cost | $163.2 | $94.4 | $52.7 |

F-32

Other supplemental information related to our leases are as follows:

| Cash paid for amounts included in the measurement of lease liabilities | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Operating cash flows for operating leases | $21.4 | $18.8 | $14.1 |
| Operating cash flows for finance leases | 13.9 | 2.7 | 1.0 |
| Financing cash flows for finance leases | 42.9 | 19.7 | 12.5 |

The weighted-average remaining lease terms for operating leases and finance leases are 5 years and 6 years, respectively. The weighted-average discount rates for operating leases and finance leases are 5.0% and 5.0%, respectively.

The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2023:

|  | Operating Leases | Finance Leases |
| --- | ---: | ---: |
| 2024 | $25.5 | $57.5 |
| 2025 | 16.8 | 56.5 |
| 2026 | 11.2 | 55.0 |
| 2027 | 10.3 | 48.9 |
| 2028 | 10.1 | 41.4 |
| Thereafter | 14.4 | 72.8 |
| Total undiscounted cash flows | 88.3 | 332.1 |
| Less imputed interest | (10.0) | (42.3) |
| Total lease liabilities | $78.3 | $289.8 |

### Note 11 – Preferred Stock

### Preferred Stock

Prior to the redemption in May 2022, our Series A Preferred had a liquidation value of $1,000 per share and bore a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter. The Series A Preferred had no mandatory redemption date, but was redeemable at our election on or prior to March 16, 2022 for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter.

The Series A Preferred ranked senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation. The holders of Series A Preferred generally only had voting rights in certain circumstances, subject to certain exceptions, which included:

- the issuance or the increase by the Company of any specific class or series of stock that was senior to the Series A Preferred,
- the issuance or the increase by any of the Company’s consolidated subsidiaries of any specific class or series of securities,
- changes to the Certificates of Incorporation or Designations of the Series A Preferred that would have materially and adversely affected the Preferred Stock holder,
- the issuance of stock on parity with the Series A Preferred, subject to certain exceptions, if the Company had exceeded a stipulated fixed charge coverage ratio or an aggregate amount of net proceeds from all future issuances of Parity Stock, or would have used the proceeds of such issuance to pay dividends,
- the incurrence of indebtedness, other than indebtedness that complies with a stipulated fixed charge coverage ratio or under the TRGP Revolver (or replacement commercial bank facilities) in an aggregate amount up to $2.75 billion.

The Series A Preferred did not qualify as a liability instrument because it was not mandatorily redeemable. However, as SEC Regulation S-X, Rule 5-02-27 does not permit a probability assessment for a change of control provision, our Series A Preferred must be presented as mezzanine equity between liabilities and shareholders’ equity on our Consolidated Balance Sheets because a change of control event, although not considered probable, could have forced the Company to redeem the Series A Preferred. A maximum of 44,260,953 common shares would have been issued upon conversion of the Series A Preferred.

#### Preferred Stock Redemption

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

#### Preferred Stock Dividends

During the year ended December 31, 2022, we paid $51.8 million of dividends to Series A Preferred Shareholders. During the year ended December 31, 2021 we paid $87.3 million of dividends at a rate of $23.75 per share each quarter to Series A Preferred shareholders attributable to accretion of the preferred discount resulting from the beneficial conversion feature accounting model. Such accretion was included in the book value of the Series A Preferred. After adoption of ASU 2020-06, *Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity* in 2021, we no longer recognize such accretion.

### Note 12 — Common Stock and Related Matters

### Public Offerings of Common Stock

On May 9, 2017, we entered into an equity distribution agreement under the May 2016 Shelf (the “May 2017 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock (“2017 ATM Program”).

On September 20, 2018, we entered into an equity distribution agreement under the May 2016 Shelf (the “September 2018 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock (“2018 ATM Program”).

In March 2022, we filed with the SEC a universal shelf registration statement on Form S-3 that registers the issuance and sale of certain debt and equity securities from time to time in one or more offerings (the “March 2022 Shelf”). The March 2022 Shelf will expire in March 2025.

During 2023, 2022 and 2021, no shares of common stock were issued under either the May 2017 EDA or the September 2018 EDA. As a result, we have $382.1 million and $750.0 million remaining under the May 2017 EDA and September 2018 EDA, respectively, as of December 31, 2023.

### Common Share Repurchase Program

In October 2020, our Board of Directors approved a share repurchase program (the “2020 Share Repurchase Program”) for the repurchase of up to $500.0 million of our outstanding common stock. In May 2023, our Board of Directors approved a new share repurchase program (the “2023 Share Repurchase Program”) for the repurchase of up to $1.0 billion of our outstanding common stock. During the second quarter of 2023, we exhausted the 2020 Share Repurchase Program. As of December 31, 2023, there was $770.1 million remaining under the 2023 Share Repurchase Program. We are not obligated to repurchase any specific dollar amount or number of shares under the 2023 Share Repurchase Program and may discontinue the program at any time.

For the year ended December 31, 2023, we repurchased 4,870,559 shares of our common stock at a weighted average price per share of $76.72 for a total net cost of $373.7 million. For the year ended December 31, 2022, we repurchased 3,412,354 shares of our common stock at a weighted average price per share of $65.87 for a total net cost of $224.8 million. For the year ended December 31, 2021, we repurchased 756,478 shares of our common stock at a weighted average price per share of $52.81 for a total net cost of $40.0 million.

### Common Stock Dividends

In April 2023, we declared an increase to our common dividend to $0.50 per common share or $2.00 per common share annualized effective for the first quarter of 2023.

The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2023, 2022 and 2021:

*(In millions, except per share amounts)*

| Three Months Ended 2023 | 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 |
| --- | --- | ---: | ---: | ---: | ---: |
| 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 |
| **2022** |  |  |  |  |  |
| December 31, 2022 | February 15, 2023 | $80.5 | $79.3 | $1.2 | $0.35000 |
| September 30, 2022 | November 15, 2022 | 80.5 | 79.2 | 1.3 | 0.35000 |
| June 30, 2022 | August 15, 2022 | 80.7 | 79.3 | 1.4 | 0.35000 |
| March 31, 2022 | May 16, 2022 | 81.2 | 79.8 | 1.4 | 0.35000 |
| **2021** |  |  |  |  |  |
| 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 |

### Note 13 — Earnings per Common Share

In March 2023, the Compensation Committee amended the Restricted Stock Units Grant Agreements that govern the Restricted Stock Unit awards (“RSUs”) that vest no later than three years following the RSUs’ grant date. The amendment resulted in quarterly cash dividend payments to RSU holders beginning with the common stock dividend paid in May 2023. As the amended RSUs and certain four-year retention awards participate in nonforfeitable dividends with the common equity owners of the Company, they are considered participating securities.

We calculate earnings per share using the two-class method. Earnings are allocated to common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings to the extent that each security participates in earnings.

The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:

*(In millions, except per share amounts)*

|  | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Net income (loss) attributable to Targa Resources Corp. | $1,345.9 | $1,195.5 | $71.2 |
| Less: Premium on repurchase of noncontrolling interests, net of tax (1) | 510.1 | 53.2 | — |
| Less: Dividends on Series A Preferred Stock (2) | — | 30.0 | 87.3 |
| Less: Deemed dividends on Series A Preferred (3) | — | 215.5 | — |
| Net income (loss) attributable to common shareholders | 835.8 | 896.8 | (16.1) |
| Less: Participating share-based earnings (4) | 7.6 | — | — |
| Net income (loss) allocated to common shareholders for basic earnings per share | $828.2 | $896.8 | $(16.1) |
| Weighted average shares outstanding - basic | 224.6 | 227.3 | 228.6 |
| Dilutive effect of unvested stock awards (5) | 1.4 | 3.8 | — |
| Weighted average shares outstanding - diluted | 226.0 | 231.1 | 228.6 |
| Net income (loss) available per common share - basic | $3.69 | $3.95 | $(0.07) |
| Net income (loss) available per common share - diluted | $3.66 | $3.88 | $(0.07) |

F-35

(1) Represents premium paid on the Grand Prix Transaction, Carnero Acquisition and the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures.

(2) Includes $8.2 million attributable to the dividends paid upon the full redemption of Series A Preferred in 2022.

(3) Includes $215.5 million attributable to the full redemption of Series A Preferred in 2022. See Note 11 – Preferred Stock for further discussion.

(4) Represents the distributed and undistributed earnings of the Company attributable to the participating securities. The dilutive effect of the reallocation of participating securities to diluted net income attributable to common shareholders was immaterial.

(5) For the year ended December 31, 2021, all unvested restricted stock awards and Series A Preferred were antidilutive because a net loss existed in the period.

The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis):

|  | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Unvested restricted stock awards | 1.5 | — | 3.3 |
| Series A Preferred (1) | — | 14.9 | 44.3 |

(1) The Series A Preferred had no mandatory redemption date, but was redeemable at our election for a 5% premium to the liquidation preference subsequent to March 16, 2022. In May 2022, we redeemed all of our issued and outstanding Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. See Note 11 – Preferred Stock for further discussion.

### Note 14 — Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are primarily designated as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

We also enter into derivative instruments to help manage other short-term commodity-related business risks and take advantage of market opportunities. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues as current income.

At December 31, 2023, the notional volumes of our commodity derivative contracts were:

| Commodity | Instrument | Unit | 2024 | 2025 | 2026 | 2027 |
| --- | --- | --- | ---: | ---: | ---: | ---: |
| Natural Gas | Swaps | MMBtu/d | 107,242 | 58,179 | 14,297 | — |
| Natural Gas | Basis Swaps | MMBtu/d | 478,374 | 256,658 | 122,500 | 35,000 |
| NGL | Swaps | Bbl/d | 31,893 | 21,354 | 5,589 | — |
| NGL | Futures | Bbl/d | 14,511 | 4,767 | — | — |
| Condensate | Swaps | Bbl/d | 4,531 | 3,447 | 1,092 | — |

F-36

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. The master netting provisions reduced our maximum loss due to counterparty credit risk by $32.2 million as of December 31, 2023. The range of losses attributable to our individual counterparties would be between $0.2 million and $21.6 million, depending on the counterparty in default. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

| Derivatives designated as hedging instruments | Balance Sheet Location | Fair Value as of December 31, 2023 Derivative Assets | Derivative Liabilities | Fair Value as of December 31, 2022 Derivative Assets | Derivative Liabilities |
| --- | --- | ---: | ---: | ---: | ---: |
| Commodity contracts | Current | $103.5 | $(16.4) | $158.7 | $(93.8) |
|  | Long-term | 29.0 | (3.0) | 24.2 | (30.9) |
| **Total derivatives designated as hedging instruments** |  | $132.5 | $(19.4) | $182.9 | $(124.7) |
| **Derivatives not designated as hedging instruments** |  |  |  |  |  |
| Commodity contracts | Current | $8.4 | $(37.6) | $21.2 | $(226.3) |
|  | Long-term | 4.3 | (13.8) | 0.3 | (109.2) |
| **Total derivatives not designated as hedging instruments** |  | $12.7 | $(51.4) | $21.5 | $(335.5) |
| **Total current position** |  | $111.9 | $(54.0) | $179.9 | $(320.1) |
| **Total long-term position** |  | 33.3 | (16.8) | 24.5 | (140.1) |
| **Total derivatives** |  | $145.2 | $(70.8) | $204.4 | $(460.2) |

The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:

| December 31, 2023 Current Position | Gross Presentation Asset Liability Collateral | Pro Forma Net Presentation Asset Liability |
| --- | ---: | ---: |
| Counterparties with offsetting positions or collateral | $111.7 $(54.0) $3.6 | $69.2 $(7.9) |
| Counterparties without offsetting positions - assets | 0.2 — — | 0.2 — |
| Counterparties without offsetting positions - liabilities | — — — | — — |
|  | 111.9 (54.0) 3.6 | 69.4 (7.9) |
| **Long-Term Position** |  |  |
| Counterparties with offsetting positions or collateral | 31.7 (16.8) (0.1) | 17.0 (2.2) |
| Counterparties without offsetting positions - assets | 1.6 — — | 1.6 — |
| Counterparties without offsetting positions - liabilities | — — — | — — |
|  | 33.3 (16.8) (0.1) | 18.6 (2.2) |
| **Total Derivatives** |  |  |
| Counterparties with offsetting positions or collateral | 143.4 (70.8) 3.5 | 86.2 (10.1) |
| Counterparties without offsetting positions - assets | 1.8 — — | 1.8 — |
| Counterparties without offsetting positions - liabilities | — — — | — — |
|  | $145.2 $(70.8) $3.5 | $88.0 $(10.1) |
|  | **Gross Presentation** | **Pro Forma Net Presentation** |
| **December 31, 2022** | **Asset** **Liability** **Collateral** | **Asset** **Liability** |
| **Current Position** |  |  |
| Counterparties with offsetting positions or collateral | $162.2 $(316.7) $12.2 | $27.2 $(169.5) |
| Counterparties without offsetting positions - assets | 17.7 — — | 17.7 — |
| Counterparties without offsetting positions - liabilities | — (3.4) — | — (3.4) |
|  | 179.9 (320.1) 12.2 | 44.9 (172.9) |
| **Long-Term Position** |  |  |
| Counterparties with offsetting positions or collateral | 24.5 (137.4) 22.4 | 7.3 (97.8) |
| Counterparties without offsetting positions - assets | — — — | — — |
| Counterparties without offsetting positions - liabilities | — (2.7) — | — (2.7) |
|  | 24.5 (140.1) 22.4 | 7.3 (100.5) |
| **Total Derivatives** |  |  |
| Counterparties with offsetting positions or collateral | 186.7 (454.1) 34.6 | 34.5 (267.3) |
| Counterparties without offsetting positions - assets | 17.7 — — | 17.7 — |
| Counterparties without offsetting positions - liabilities | — (6.1) — | — (6.1) |
|  | $204.4 $(460.2) $34.6 | $52.2 $(273.4) |

Some of our hedges are futures contracts executed through brokers that clear the hedges through an exchange. We maintain a margin deposit with the brokers in an amount sufficient to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within Other current assets on our Consolidated Balance Sheets and is not offset against the fair value of our derivative instruments. Our derivative instruments other than our futures contracts are executed under International Swaps and Derivatives Association agreements (“ISDAs”), which govern the key terms with our counterparties. Our ISDAs contain credit-risk related contingent features. Following the release of the collateral securing our TRGP Revolver, our derivative positions are no longer secured. As of December 31, 2023, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $9.9 million. We have not been required to post any collateral related to these positions due to our credit rating. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of December 31, 2023, we would not be required to post collateral to any counterparties per the terms of our ISDAs.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $74.4 million as of December 31, 2023. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue for the periods indicated:

| Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Commodity contracts | $193.4 | $(5.6) | $(534.6) |
|  | **Gain (Loss) Reclassified from OCI into Income (Effective Portion)** |  |  |
| **Location of Gain (Loss)** | **2023** | **2022** | **2021** |
| Revenues | $153.4 | $(373.0) | $(417.3) |

Based on valuations as of December 31, 2023, we expect to reclassify commodity hedge related deferred gains of $103.4 million included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2026, with $77.5 million of gains to be reclassified over the next twelve months.

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial assets and liabilities (“financial instruments”) can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the year ended December 31, 2023, the unrealized mark-to-market gains are primarily attributable to favorable movements in natural gas forward basis prices, as compared to our positions.

| Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) Recognized in Income on Derivatives | Gain (Loss) Recognized in Income on Derivatives 2023 | 2022 | 2021 |
| --- | --- | ---: | ---: | ---: |
| Commodity contracts | Revenue | $287.7 | $(381.7) | $(73.3) |

See Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Note 15 – Fair Value Measurements and Note 23 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

### Note 15 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

### Fair Value of Derivative Financial Instruments

Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative instruments using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The derivatives at December 31, 2023, represent a net asset of $74.4 million, and reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $42.8 million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $192.0 million.

### Fair Value of Other Financial Instruments

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

- the TRGP Revolver, commercial paper notes, Securitization Facility and Term Loan Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and
- the TRGP senior unsecured notes and the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.

### Fair Value Hierarchy

We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

- Level 1 – observable inputs such as quoted prices in active markets;
- Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
- Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.

The following table shows a breakdown by fair value hierarchy category for (i) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (ii) supplemental fair value disclosures for other financial instruments:

| Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: | December 31, 2023 Carrying Value | Fair Value Total | Level 1 | Level 2 | Level 3 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Assets from commodity derivative contracts (1) | $144.6 | $144.6 | $— | $144.6 | $— |
| Liabilities from commodity derivative contracts (1) | 70.2 | 70.2 | — | 70.2 |  |
| **Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:** |  |  |  |  |  |
| Cash and cash equivalents | 141.7 | 141.7 | — | — | — |
| TRGP Revolver and Commercial Paper Program | 175.0 | 175.0 | — | 175.0 | — |
| TRGP Senior unsecured notes | 6,470.5 | 6,598.7 | — | 6,598.7 | — |
| Term Loan Facility | 500.0 | 500.0 | — | 500.0 | — |
| Partnership’s Senior unsecured notes | 5,034.4 | 4,945.1 | — | 4,945.1 | — |
| Securitization Facility | 575.0 | 575.0 | — | 575.0 | — |

| Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: | December 31, 2022 Carrying Value | Fair Value Total | Level 1 | Level 2 | Level 3 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Assets from commodity derivative contracts (1) | $201.6 | $201.6 | $— | $201.6 | $— |
| Liabilities from commodity derivative contracts (1) | 457.4 | 457.4 | — | 457.4 | — |
| **Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:** |  |  |  |  |  |
| Cash and cash equivalents | 219.0 | 219.0 | — | — | — |
| TRGP Revolver and Commercial Paper Program | 1,298.7 | 1,298.7 | — | 1,298.7 | — |
| TRGP Senior unsecured notes | 2,741.6 | 2,452.6 | — | 2,452.6 | — |
| Term Loan Facility | 1,500.0 | 1,500.0 | — | 1,500.0 | — |
| Partnership’s Senior unsecured notes | 5,034.4 | 4,711.3 | — | 4,711.3 | — |
| Securitization Facility | 800.0 | 800.0 | — | 800.0 | — |

(1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

### Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets

We have historically reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices or implied volatilities for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input was determined to be significant to the overall inputs, the entire valuation was categorized in Level 3. This included derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

The fair value of these swaps was determined using a discounted cash flow valuation technique based on a commodity forward curve. For these derivatives, the primary input to the valuation model was the commodity forward curve, which was based on observable or public data sources and extrapolated when observable prices were not available.

The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing. As of December 31, 2023 and December 31, 2022, we had no derivative contracts categorized as Level 3.

### Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis at acquisition or whenever impairment indicators are present. During the year ended December 31, 2021, we recorded a non-cash pre-tax impairment of $452.3 million. The impairment charge is primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations in the Gathering and Processing segment. For disclosures related to valuation techniques, see Note 4 – Acquisitions and Divestitures and Note 5 – Property, Plant and Equipment and Intangible Assets.

The techniques described above may produce a fair value calculation that may not be indicative or reflective of future fair values. Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a different fair value measurement at the reporting date.

### Note 16 — Related Party Transactions

#### Transactions with Unconsolidated Affiliates

The following table summarizes transactions with unconsolidated affiliates:

| 2023: | GCF | T2 Joint Ventures (1) | Cayenne | GCX (2) | Little Missouri 4 | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Revenues | $— | $— | $— | $— | $7.1 | $7.1 |
| Product purchases and fuel | — | — | (6.4) | — | — | (6.4) |
| Operating expenses | (4.4) | — | (0.3) | — | (2.0) | (6.7) |
| General and administrative expenses | — | — | — | — | (0.9) | (0.9) |
| **2022:** |  |  |  |  |  |  |
| Revenues | $— | $1.2 | $— | $— | $8.5 | $9.7 |
| Product purchases and fuel | — | — | (4.7) | (25.0) | — | (29.7) |
| Operating expenses | (1.7) | (0.7) | (0.3) | — | (2.6) | (5.3) |
| General and administrative expenses | — | — | — | — | (0.9) | (0.9) |
| **2021:** |  |  |  |  |  |  |
| Revenues | $— | $4.4 | $— | $— | $10.6 | $15.0 |
| Product purchases and fuel | — | — | (4.8) | (66.5) | — | (71.3) |
| Operating expenses | (1.1) | (2.3) | (0.2) | — | (2.5) | (6.1) |
| General and administrative expenses | — | — | — | — | (0.8) | (0.8) |

(1) Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100% owned and consolidated by Targa.

(2) Following the closing of the GCX Sale in May 2022, Targa no longer has an ownership interest in GCX.

#### Relationship with Targa Resources Partners LP

We provide general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from third parties. The Partnership Agreement between the Partnership and us, as general partner of the Partnership, governs the reimbursement of costs incurred on behalf of the Partnership.

The employees supporting the Partnership’s operations are our employees. The Partnership reimburses us for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to the Partnership’s assets, and for the provision of various general and administrative services for the benefit of the Partnership. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

### Note 17 — Commitments

Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter:

|  | In Aggregate | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Land sites and rights of way (1) | $297.4 | $8.5 | $8.6 | $10.3 | $11.7 | $17.3 | $241.0 |

(1) Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.

Total expenses incurred under the above non-cancelable commitments were:

|  | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Land sites and rights of way | $9.0 | $5.8 | $5.9 |

### Note 18 – Contingencies

### Legal Proceedings

We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties to various proceedings with governmental environmental agencies, including, but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.

On December 26, 2018, Vitol filed a lawsuit in the 80th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached the Splitter Agreement, which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol sought return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

On October 15, 2020, the District Court awarded Vitol $129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company appealed the award in the Fourteenth Court of Appeals in Houston, Texas. In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on crude oil. We filed a petition for review with the Supreme Court of Texas which was denied on October 20, 2023, but we are seeking rehearing and the appeal remains pending. The cumulative amount of interest on the award through December 31, 2023, if accrued, would have been approximately $55.5 million.

On July 24, 2023, we received a Notice of Violation from the New Mexico Environment Department, Air Quality Bureau, relating to alleged air permit violations between August 1, 2021 and June 30, 2022 by Lucid Energy Delaware, LLC, an entity we subsequently acquired in July 2022 in the Delaware Basin Acquisition and whose assets are now integrated into Targa Northern Delaware LLC, a wholly-owned subsidiary of the Company. We have been engaging with the New Mexico Environment Department to resolve this matter. Although this matter is ongoing and management cannot predict its ultimate outcome, the resolution of this matter may result in a fine or penalty in excess of $0.3 million. We do not expect that any expenditures related to this matter will be material to our consolidated financial statements.

On October 26, 2023, we received a final judgment in a lawsuit alleging a breach of contract related to the major winter storm in February 2021. The damages awarded against us are approximately $6.9 million, not including pre-judgment interest. Both parties are appealing the judgment.

We are also a defendant in two other breach of contract cases related to force majeure events arising during the major winter storm in February 2021. We believe that the likelihood of a partial loss could be reasonably possible, and, while it is not possible to predict the ultimate outcome of these cases on an individual or consolidated basis, we estimate that the total range of potential loss resulting from all of these cases could be between $0 and $10.0 million in the aggregate. We intend to continue to vigorously defend these cases.

### Note 19 – Revenue

#### Fixed consideration allocated to remaining performance obligations

The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 16 years.

|  | 2024 | 2025 | 2026 and after |
| --- | ---: | ---: | ---: |
| Fixed consideration to be recognized as of December 31, 2023 | $497.2 | $419.8 | $2,383.3 |

Based on the optional exemptions that we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.

For additional information on our revenue recognition policy, see Note 3 – Significant Accounting Policies, and for disclosures related to disaggregated revenue, see Note 23 – Segment Information.

### Note 20 – Income Taxes

Components of the federal and state income tax provisions are as follows:

|  | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Current expense (benefit) | $13.6 | $6.7 | $2.7 |
| Deferred expense (benefit) | 349.6 | 125.1 | 12.1 |
| Total income tax expense (benefit) | $363.2 | $131.8 | $14.8 |

F-42

Our deferred income tax assets and liabilities as of December 31, 2023 and 2022 consist of recognition differences related to certain types of costs as follows:

| Deferred tax assets: | 2023 | 2022 |
| --- | ---: | ---: |
| Net operating loss | $1,282.9 | $1,568.5 |
| Disallowed business interest expense carryforward | 79.3 | 10.3 |
| Deferred tax assets before valuation allowance | 1,362.2 | 1,578.8 |
| Valuation allowance | (7.1) | (36.9) |
| Deferred tax assets | 1,355.1 | 1,541.9 |
| Deferred tax liabilities: |  |  |
| Investments (1) | (1,867.9) | (1,842.0) |
| Property, plant, and equipment | (3.0) | (4.2) |
| Other | (20.0) | (23.4) |
| Deferred tax liabilities | (1,890.9) | (1,869.6) |
| Net deferred tax asset (liability) | $(535.8) | $(327.7) |
| Net deferred tax asset (liability) |  |  |
| Federal | $(507.0) | $(290.5) |
| State | (28.8) | (37.2) |
| Long-term deferred tax liability, net | $(535.8) | $(327.7) |

(1) Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership.

We are subject to tax in the U.S. and various state jurisdictions and we are subject to periodic audits and reviews by taxing authorities. As of December 31, 2023, IRS examinations are currently in process for the 2019, 2020 and 2021 taxable years of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes. We are responding to information requests from the IRS with respect to these audits. We are not aware of any potential audit findings that would give rise to adjustments to taxable income and do not anticipate material changes related to these audits.

Federal statutes of limitations for returns filed in 2020 (for calendar year 2019) have expired, except for the 2019 returns under examination that have a statute extension to April 2025. For Texas, the statute of limitations has expired for 2019 returns (for calendar year 2018). Similarly, the statute of limitations expired on substantially all 2019 state income tax returns that were filed prior to October 15, 2020. However, tax authorities could review and adjust carryover attributes (e.g., NOLs) generated in a closed tax year if utilized in an open tax year.

During the preparation of the Company’s 2021 consolidated financial statements, the Company identified errors related to its 2020 state tax provision. The Company does not believe these errors are material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. In 2021, the Company recorded an additional $23.3 million of income tax expense in the Consolidated Statements of Operations and corresponding increase to its deferred tax liabilities in the Consolidated Balance Sheets.

As of December 31, 2023, we have total U.S. federal NOL carryforwards of $5.5 billion, $857.4 million of which will expire in 2037. The remaining $4.7 billion NOL will not expire, but is limited to offsetting 80% of taxable income per year. As of December 31, 2023, our tax effected valuation allowance was $7.1 million, a decrease of $29.8 million from December 31, 2022. Of this valuation allowance, $6.4 million is federal and the remaining $0.7 million is state.

Set forth below is the reconciliation between our Income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in our Consolidated Statements of Operations for the periods indicated:

| Income tax reconciliation: | 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Income (loss) before income taxes | $1,942.5 | $1,663.2 | $436.9 |
| Less: Net income attributable to noncontrolling interest | (233.4) | (335.9) | (350.9) |
| Income attributable to Targa Resources Corp. before income taxes | 1,709.1 | 1,327.3 | 86.0 |
| Federal statutory income tax rate | 21% | 21% | 21% |
| Provision for federal income taxes | 358.9 | 278.7 | 18.1 |
| Valuation allowance | (29.8) | (177.5) | (46.2) |
| State income taxes, net of federal tax benefit | 37.8 | 33.6 | (5.4) |
| State tax provision error correction | — | — | 23.3 |
| Return-to-provision | (5.7) | (0.6) | (1.3) |
| Change in income tax rate | 11.5 | (1.7) | 21.0 |
| Permanent adjustments | 6.2 | 5.6 | 4.1 |
| Stock compensation shortfall/(windfall) | (15.8) | (6.3) | 1.4 |
| Other, net | 0.1 | — | (0.2) |
| Income tax provision (benefit) | $363.2 | $131.8 | $14.8 |

F-43

We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income tax positions have been recorded.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”) which, among other things, introduced a corporate alternative minimum tax (the “CAMT”), imposed a 1% excise tax on stock buybacks and tax incentives to promote clean energy. Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $1 billion.

The U.S. Department of the Treasury and the IRS have issued guidance on the application of the CAMT which may be relied upon until final regulations are released. Based on our interpretation of the IRA, the CAMT and related guidance and several operational, economic, accounting and regulatory assumptions, we do not anticipate qualifying as an “applicable corporation” in the near term, but we are likely to become an applicable corporation in a subsequent tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for the future. As a result, our current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA and the CAMT, we will continue to monitor and evaluate the potential future impact to our financial statements.

### Note 21 - Supplemental Cash Flow Information

| Cash: | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Interest paid, net of capitalized interest (1) | $618.6 | $401.3 | $356.0 |
| Income taxes (received) paid, net | 8.5 | 1.6 | 1.3 |
| Non-cash investing activities: |  |  |  |
| Change in deadstock commodity inventory | $(13.7) | $(3.8) | $(15.0) |
| Impact of capital expenditure accruals on property, plant and equipment, net | 58.2 | 60.1 | 53.0 |
| Transfers from materials and supplies inventory to property, plant and equipment | — | — | 2.4 |
| Change in ARO liability and property, plant and equipment due to revised cash flow estimate and additions | 4.9 | 0.8 | (0.2) |
| Non-cash financing activities: |  |  |  |
| Changes in accrued distributions to noncontrolling interests | $8.9 | $(26.1) | $(50.9) |
| Reduction of owner's equity related to accrued dividends on unvested equity awards under share compensation arrangements | 3.9 | 7.1 | 3.1 |
| Non-cash distributions to noncontrolling interests (2) | — | 64.2 | — |
| Lease liabilities arising from recognition of right-of-use assets: |  |  |  |
| Operating lease | $53.1 | $9.7 | $20.1 |
| Finance lease (3) | 104.8 | 220.7 | 24.7 |

(1) Interest capitalized on major projects was $41.1 million, $16.3 million and $4.1 million for the years ended December 31, 2023, 2022 and 2021.

(2) Represents the transfer of an undivided interest in certain gas gathering and processing facilities to a joint owner upon Targa’s recovery of a specified payout amount for our initial full funding of the facilities.

(3) The December 31, 2022 amount includes $171.2 million related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

### Note 22 – Compensation Plans

### 2010 Targa Resources Corp. Stock Incentive Plan

In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan (the “2010 TRGP Plan”) for employees, consultants and non-employee directors of the Company. In May 2017, the 2010 TRGP Plan was amended and restated. In August 2023, the 2010 TRGP Plan was amended and restated for a second time. Total authorized shares of common stock under the plan is 15,000,000, comprised of 5,000,000 shares originally available and an additional 10,000,000 shares that became available in May 2017. The 2010 TRGP Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as Incentive Options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards, (v) phantom stock awards, (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards.

Unless otherwise specified, the compensation costs for the awards listed below were recognized as expenses over related vesting periods based on the grant-date fair values, reduced by forfeitures incurred.

*Restricted Stock Awards* - Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. Upon issuance, the restricted stock awards will be included in the outstanding shares of our common stock. The Compensation Committee of the Targa board of directors (the “Compensation Committee”) awarded our common stock to our outside directors. In 2023, 2022 and 2021, we issued 23,518, 31,117 and 67,591 shares of director grants with weighted average grant-date fair values of $74.13, $56.32 and $30.33, respectively.

*Restricted Stock Units Awards –* RSUs are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The vesting periods generally vary from one to six years. In March 2023, the Compensation Committee amended the Restricted Stock Units Grant Agreements that govern the RSUs that vest no later than three years following the RSUs’ grant date. The amendment resulted in quarterly cash dividend payments to RSU holders beginning with the common stock dividend paid in May 2023. In 2023, 2022 and 2021, we issued 587,326, 943,352 and 848,630 shares of RSUs with weighted average grant-date fair values of $78.69, $63.87 and $37.94.

*Restricted Stock Units in Lieu of Bonus –* In 2020 and 2019, we granted 81,336 and 95,687 shares of RSUs in lieu of cash bonuses for certain of our executives at the weighted average grant-date fair value of $41.39 and $42.83. The 2020 and 2019 grants vested in 2021 and 2022, respectively.

The following table summarizes the restricted stock and RSUs under the 2010 TRGP Plan in shares and in dollars for the year indicated.

|  | Number of shares | Weighted Average Grant-Date Fair Value |
| --- | ---: | ---: |
| Outstanding at December 31, 2022 | 3,228,418 | $42.60 |
| Granted | 610,844 | 78.52 |
| Forfeited | (95,643) | 61.92 |
| Vested | (1,435,823) | 32.05 |
| Outstanding at December 31, 2023 | 2,307,796 | 57.84 |

#### Performance Share Units

During 2023, 2022 and 2021, we granted 140,020, 173,011 and 319,320 performance share units (“PSUs”) to executive management for the 2023, 2022 and 2021 compensation cycle that will vest/have vested in January 2026, January 2025 and January 2024. The PSUs granted under the 2010 TRGP Plan are three-year equity-settled awards linked to the performance of shares of our common stock. The awards also include dividend equivalent rights (“DERs”) that are based on the notional dividends accumulated during the vesting period.

The vesting of the PSUs is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s total shareholder return (“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. For the PSUs granted in 2021, 2022 and 2023, the TSR performance factor is determined by the Compensation Committee based on relative TSR over a cumulative three-year performance period. The Compensation Committee determines a guideline performance percentage for the performance period and the percentage may then be decreased or increased by the Compensation Committee at its discretion. The grantee will become vested in a number of PSUs equal to the target number awarded multiplied by the TSR performance factor, and vested PSUs will be settled by the issuance of Company common stock. The value of dividend equivalent rights will be paid in cash when the awards vest.

Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant date. The compensation cost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERs associated with equity-settled PSUs were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model and historical volatility assumption with an expected term of three years. The expected volatilities were 38%, 80% and 80% for PSUs granted in 2023, 2022 and 2021.

The following table summarizes the PSUs under the 2010 TRGP Plan in shares and in dollars for the years indicated.

|  | Number of shares | Weighted Average Grant-Date Fair Value |
| --- | ---: | ---: |
| Outstanding at December 31, 2022 | 769,917 | $72.81 |
| Granted | 140,020 | 128.71 |
| Forfeited | (22,272) | 117.52 |
| Vested | (291,365) | 69.70 |
| Outstanding at December 31, 2023 | 596,300 | 85.78 |

### Stock Compensation Expenses

Stock compensation expense under our plans totaled $62.4 million, $57.5 million and $59.2 million for the years ended December 31, 2023, 2022 and 2021. As of December 31, 2023, we have $87.5 million of unrecognized compensation expense associated with share-based awards and an approximate remaining weighted average vesting periods of 2.3 years related to our various compensation plans.

The fair values of share-based awards vested in 2023, 2022 and 2021 were $96.8 million, $93.0 million and $73.8 million. Cash dividends paid for the vested awards were $8.3 million, $9.6 million and $8.7 million for 2023, 2022 and 2021.

In relation to our equity compensation plans, we recognized $17.0 million and $6.7 million in windfall tax benefits for the years ended December 31, 2023 and 2022, respectively. We recognized $1.6 million of tax deficiencies for the year ended December 31, 2021.

#### Subsequent Events

In January 2024, the Compensation Committee made the following awards under the 2010 TRGP Plan.

- 20,414 shares of restricted stock to our outside directors that will vest in January 2025.
- 128,316 shares of RSUs to executive management for the 2024 compensation cycle that will vest in January 2027.
- 128,316 shares of PSUs to executive management for the 2024 compensation cycle that will vest in January 2027.

In January 2024, 23,518 shares of director grants vested with no shares withheld to satisfy tax withholding obligations.

In January 2024, 320,549 shares of RSUs vested with 127,443 shares withheld to satisfy tax withholding obligations.

In January 2024, 765,478 shares of 2021 PSUs vested with 296,600 shares withheld to satisfy tax withholding obligations.

### Targa 401(k) Plan

We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $32.3 million, $26.6 million and $21.8 million during 2023, 2022 and 2021.

### Note 23 — Segment Information

We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.

Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes Grand Prix, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

Reportable segment information is shown in the following tables:

| Revenues | Year Ended December 31, 2023 Gathering and Processing | Logistics and Transportation | Other | Corporate and Eliminations | Total |
| --- | ---: | ---: | ---: | ---: | ---: |
| Sales of commodities | $1,076.1 | $12,610.5 | $275.5 | $— | $13,962.1 |
| Fees from midstream services | 1,366.5 | 731.7 | — | — | 2,098.2 |
|  | 2,442.6 | 13,342.2 | 275.5 | — | 16,060.3 |
| Intersegment revenues |  |  |  |  |  |
| Sales of commodities | 4,786.3 | 267.9 | — | (5,054.2) | — |
| Fees from midstream services | 2.6 | 45.7 | — | (48.3) | — |
|  | 4,788.9 | 313.6 | — | (5,102.5) | — |
| Revenues | $7,231.5 | $13,655.8 | $275.5 | $(5,102.5) | $16,060.3 |
| Operating margin (1) | $2,082.2 | $1,948.7 | $275.5 |  |  |
| Other financial information: |  |  |  |  |  |
| Total assets (2) | $12,685.2 | $7,777.8 | $4.2 | $204.6 | $20,671.8 |
| Goodwill | $45.2 | $— | $— | $— | $45.2 |
| Capital expenditures | $1,514.7 | $910.0 | $— | $18.9 | $2,443.6 |

| Revenues | Year Ended December 31, 2022 Gathering and Processing | Logistics and Transportation | Other | Corporate and Eliminations | Total |
| --- | ---: | ---: | ---: | ---: | ---: |
| Sales of commodities | $919.7 | $18,448.7 | $(302.4) | $— | $19,066.0 |
| Fees from midstream services | 1,157.3 | 706.5 | — | — | 1,863.8 |
|  | 2,077.0 | 19,155.2 | (302.4) | — | 20,929.8 |
| Intersegment revenues |  |  |  |  |  |
| Sales of commodities | 9,169.4 | 541.7 | — | (9,711.1) | — |
| Fees from midstream services | 0.6 | 45.2 | — | (45.8) | — |
|  | 9,170.0 | 586.9 | — | (9,756.9) | — |
| Revenues | $11,247.0 | $19,742.1 | $(302.4) | $(9,756.9) | $20,929.8 |
| Operating margin (1) | $1,981.0 | $1,456.3 | $(302.4) |  |  |
| Other financial information: |  |  |  |  |  |
| Total assets (2) | $12,133.6 | $7,175.7 | $— | $250.7 | $19,560.0 |
| Goodwill | $45.2 | $— | $— | $— | $45.2 |
| Capital expenditures | $918.1 | $453.0 | $— | $23.3 | $1,394.4 |

| Revenues | Year Ended December 31, 2021 Gathering and Processing | Logistics and Transportation | Other | Corporate and Eliminations | Total |
| --- | ---: | ---: | ---: | ---: | ---: |
| Sales of commodities | $606.8 | $15,111.6 | $(115.9) | $— | $15,602.5 |
| Fees from midstream services | 747.3 | 600.0 | — | — | 1,347.3 |
|  | 1,354.1 | 15,711.6 | (115.9) | — | 16,949.8 |
| Intersegment revenues |  |  |  |  |  |
| Sales of commodities | 6,067.9 | 409.5 | — | (6,477.4) | — |
| Fees from midstream services | 3.5 | 38.6 | — | (42.1) | — |
|  | 6,071.4 | 448.1 | — | (6,519.5) | — |
| Revenues | $7,425.5 | $16,159.7 | $(115.9) | $(6,519.5) | $16,949.8 |
| Operating margin (1) | $1,325.3 | $1,264.3 | $(115.9) |  |  |
| Other financial information: |  |  |  |  |  |
| Total assets (2) | $7,998.1 | $7,041.9 | $14.0 | $154.2 | $15,208.2 |
| Goodwill | $45.2 | $— | $— | $— | $45.2 |
| Capital expenditures | $471.7 | $78.1 | $— | $10.7 | $560.5 |

(1) Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.

(2) Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

The following table shows our consolidated revenues disaggregated by product and service for the periods presented:

| Sales of commodities: Revenue recognized from contracts with customers: | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Natural gas | $2,421.3 | $5,470.2 | $3,523.9 |
| NGL | 10,580.2 | 13,785.2 | 12,210.8 |
| Condensate and crude oil | 519.5 | 565.3 | 358.4 |
|  | 13,521.0 | 19,820.7 | 16,093.1 |
| **Non-customer revenue:** |  |  |  |
| Derivative activities - Hedge | 153.4 | (373.0) | (417.3) |
| Derivative activities - Non-hedge (1) | 287.7 | (381.7) | (73.3) |
|  | 441.1 | (754.7) | (490.6) |
| Total sales of commodities | 13,962.1 | 19,066.0 | 15,602.5 |
| **Fees from midstream services:** |  |  |  |
| **Revenue recognized from contracts with customers:** |  |  |  |
| Gathering and processing | 1,342.8 | 1,137.2 | 730.3 |
| NGL transportation, fractionation and services | 261.1 | 285.1 | 190.6 |
| Storage, terminaling and export | 440.7 | 372.2 | 379.7 |
| Other | 53.6 | 69.3 | 46.7 |
| Total fees from midstream services | 2,098.2 | 1,863.8 | 1,347.3 |
| Total revenues | $16,060.3 | $20,929.8 | $16,949.8 |

(1) Represents derivative activities that are not designated as hedging instruments under ASC 815.

The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the periods presented:

| Reconciliation of reportable segment operating margin to income (loss) before income taxes: | Year Ended December 31, 2023 | 2022 | 2021 |
| --- | ---: | ---: | ---: |
| Gathering and Processing operating margin | $2,082.2 | $1,981.0 | $1,325.3 |
| Logistics and Transportation operating margin | 1,948.7 | 1,456.3 | 1,264.3 |
| Other operating margin | 275.5 | (302.4) | (115.9) |
| Depreciation and amortization expense | (1,329.6) | (1,096.0) | (870.6) |
| General and administrative expense | (348.7) | (309.7) | (273.2) |
| Other operating income (expense) | (1.5) | (0.2) | (12.4) |
| Impairment of long-lived assets | — | — | (452.3) |
| Interest expense, net | (687.8) | (446.1) | (387.9) |
| Equity earnings (loss) | 9.0 | 9.1 | (23.9) |
| Gain (loss) from financing activities | (2.1) | (49.6) | (16.6) |
| Gain (loss) from sale of equity method investment | — | 435.9 | — |
| Other, net | (3.2) | (15.1) | 0.1 |
| Income (loss) before income taxes | $1,942.5 | $1,663.2 | $436.9 |

F-48

## Risk factors

As filed, 139,957 characters.

The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all the other information contained in this report. If any of the following risks were to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.

### Summary Risk Factors

#### Risks Related to our Results of Operations

- Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in commodity prices and/or activity levels could adversely affect our results of operations and financial condition.
- A reduction in demand for NGL products by the petrochemical, refinery or other industries or by the fuel or export markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of operations and financial condition.
- The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.
- Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
- We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our business.
- If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.
- We typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems; therefore, volumes on our systems in the future could be less than we anticipate.
- We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.
- If we lose any of our named executive officers, our business may be adversely affected.
- Weather events may damage our pipelines and other facilities, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.
- Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.
- Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.
- Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, which expenditures or resulting loss of revenue due to pipeline age or condition could have a material adverse effect on our business and results of operations.
- Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued global and domestic hostilities may adversely impact our results of operations.
- We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
- We may incur significant costs and liabilities resulting from performance of pipeline integrity testing programs and related repairs, as well as from initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more rigorous enforcement of applicable legal requirements.
- We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption, disclosure of business sensitive, confidential or personally identifiable information, misdirected wire transfers, reputational harm, and financial loss.
- The widespread outbreak of illnesses or any other public health crises that impacts operations and/or the global demand for energy commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.

#### Risks Related to our Capital Projects and Future Growth

- Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
- If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to pay dividends to stockholders. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a negative impact on our operations and financial condition.
- We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.

#### Risks Related to our Financial Condition

- If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.
- We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
- Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.
- Changes in future business conditions could have a negative impact on the demand for our services and could cause recorded long-lived assets to become further impaired, and our financial condition and results of operations could suffer if there is a negative impact on the demand for our services and an additional impairment of long-lived assets.
- Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.
- If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.
- The amounts we pay in dividends may vary from anticipated amounts and circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.
- Our future tax liability may be greater than expected if our NOL carryforwards are limited, we do not generate expected deductions, or tax authorities successfully challenge certain of our tax positions.
- Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes may adversely affect our financial condition, results of operations and cash flows.
- Derivatives legislation and its implementing regulations could have a material adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

#### Risks Related to the Ownership of our Common Stock

- Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
- Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
- We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

#### Risks Related to our Indebtedness

- Continued increases in interest rates, due to associated Federal Reserve policies or otherwise, could adversely affect our cost of capital, which could increase our funding costs and reduce the overall profitability of our business.
- We have a substantial amount of indebtedness which may adversely affect our financial position and we may still be able to incur substantially more debt, which could collectively increase the risks associated with compliance with our financial covenants.
- The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions, including to pay dividends to our stockholders.

#### Risks Related to Regulatory Matters

- Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change, including increasingly stringent regulations for methane or other emissions from the oil and gas sector, that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, reduce demand for the products and services we provide, and reduce our or our customers’ ability to access capital.
- Increasing stakeholder and market attention to sustainability matters and disclosure obligations may impact our business.
- We could incur significant costs in complying with more stringent occupational safety and health requirements.
- Laws, regulations and executive orders limiting hydraulic fracturing activities could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.
- Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the environment may cause us to incur significant costs and liabilities.
- A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may (i) cause our revenues to decline and operating expenses to increase or (ii) delay or increase the cost of expansion projects.
- Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
- We are or may become subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing of personal information.

### Risks Related to our Results of Operations

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

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

- the impact of seasonality and weather, including severe weather conditions and other natural disasters, such as flooding, droughts and winter storms, the frequency, severity and impact of which could be increased by the effects of climate change;
- general economic conditions and economic conditions impacting our primary markets, including the impact of continued inflation and rising interest rates and associated changes in monetary policy;
- the economic conditions of our customers;
- the level of domestic crude oil and natural gas production and consumption;
- the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;
- actions taken by major foreign oil and gas producing nations;
- the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;
- the availability of domestic storage for crude oil;
- the availability and marketing of competitive fuels and/or feedstocks;
- the impact of energy conservation efforts and the related transition to a low carbon economy, as a result of the IRA or otherwise;
- stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil and natural gas; and
- the extent and nature of governmental regulation and taxation, including those related to the prorationing of oil and gas production.

Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

*A reduction in demand for NGL products by the petrochemical, refinery or other industries or by the fuel or export markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of operations and financial condition.*

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

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

*Propane*. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial

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

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

*Isobutane.* Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

*Natural Gasoline*. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could adversely affect demand for natural gasoline.

NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect both demand for the services we provide and NGL prices, which could negatively impact our results of operations and financial condition.

*The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.*

Our gathering systems are connected to crude oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. Our logistics assets are similarly impacted by declines in NGL supplies in the regions in which we operate as well as other regions from which we source NGLs. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that we gather and process, NGLs that we transport or NGL products delivered to our fractionation facilities. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near our gathering systems and, in part, on the level of successful drilling and production in other areas from which we source NGL and crude oil supplies. We have no control over the level of such activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling, completion or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Even if new natural gas or crude oil reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. In response to depressed commodity prices, operators may engage in curtailment or shut-ins or substantially reduce their estimated capital expenditures, rig count and completion crews. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced utilization of our gathering, treating, processing, transportation and fractionation assets.

*Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.*

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large crude oil, natural gas and NGL companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than we do. Some of these competitors may expand or construct gathering, processing, storage, terminaling and transportation systems that would create additional competition for the services we provide to our customers. In addition, customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using those operated by us. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.

*We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our business.*

We operate in areas in which industry activity has increased rapidly. As a result, demand for qualified personnel in these areas, particularly those related to our Permian and Badlands assets, and the cost to attract and retain such personnel, has increased over the past few years due to competition, and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development projects, or any significant increases in costs with respect to the hiring, training or retention of qualified personnel, could have a material adverse effect on our business, financial condition and results of operations.

*If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.*

We depend upon third-party pipelines, storage and other facilities that provide delivery options to and from our gathering and processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, our revenues could be adversely affected.

*We typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems; therefore, volumes on our systems in the future could be less than we anticipate.*

We typically do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of supply, then the volumes of natural gas or crude oil transported on our gathering systems in the future could be less than we anticipate. A decline in the volumes on our systems could have a material adverse effect on our business, results of operations and financial condition.

*We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.*

We do not own most of the land on which our pipelines, terminals and compression facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Additionally, the federal Tenth Circuit Court of Appeals has held that tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way without experiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew rights of way contracts or leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.

*If we lose any of our named executive officers, our business may be adversely affected.*

Our success is dependent upon the efforts of our named executive officers. Our named executive officers are responsible for executing our business strategies. There is substantial competition for qualified personnel in the midstream oil and gas industry. We may not be able to retain our existing named executive officers or fill new positions or vacancies created by expansion or turnover. We have not entered into employment agreements with any of our named executive officers. In addition, we do not maintain “key man” life insurance on the lives of any of our named executive officers. A loss of one or more of our named executive officers could harm our business and prevent us from implementing our business strategies.

*Weather events may damage our pipelines and other facilities, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.*

Weather events in the areas in which we or our customers operate can cause disruptions and in some cases suspension of our operations and development activities. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes, among other disruptive weather patterns, may cause a loss of throughput from temporary cessation of activities or lost, damaged or ineffective equipment. Our planning for normal climatic variation, insurance programs and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated or insured against. Potential climatic changes may have significant physical effects, such as increased frequency and severity of storms, floods, droughts, extreme temperatures, wildfires and wintry conditions and could have an adverse effect on our infrastructure or continued operations as well as the operations of our oil and gas exploration and production customers that deliver natural gas to us for processing and throughput, our third party vendors that supply us with goods, utilities necessary for our, our suppliers’, or our customers’ continued operations, and third party insurance providers that make insuring products available to defray our costs or offset any damages and losses we incur. Any unusual or prolonged severe weather events or increased frequency thereof, such as freezing weather or rain, earthquakes, hurricanes, droughts, extreme temperatures, wildfires or floods in our oil and gas exploration and production customers’ or our third party vendors’ areas of operations or markets, whether due to climatic change or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

Our operations along the Gulf Coast, in offshore waters and at major river crossings in particular could be adversely impacted by changing climatic conditions, as rising sea levels, subsidence and erosion are potential causes for serious damage to our pipelines and other facilities, which could affect our ability to provide services. These damages could result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater or to the Gulf of Mexico and could result in liability, remedial obligations or otherwise have a negative impact on continued operations. Additionally, rising sea levels, subsidence and erosion processes could impact our oil and gas exploration and production customers who operate along the Gulf Coast, and they may be unable to utilize our services. Adverse climatic impacts, whether inland or along the coast or offshore, could also affect our third-party suppliers, which could limit their ability to provide us with the necessary products and services enabling us to maintain operation of our pipelines and other facilities. As a result, we may incur significant costs to repair, preserve or make more efficient our pipeline infrastructure and other facilities. Such costs could adversely affect our business, financial condition, results of operations and cash flows.

Moreover, we could incur significant costs to weatherize or upgrade weatherization of our facility equipment in anticipation of future weather events. For example, following Texas Governor Greg Abbott’s direction to adopt rules related to weather resiliency, in August 2022, the Texas Railroad Commission adopted the Weather Emergency Preparedness Standards rule, which requires critical gas facilities on the state’s Electricity Supply Chain Map (including gas pipelines that directly serve electricity generation) to (i) weatherize to help ensure sustained operations during a weather emergency, (ii) correct known issues that caused weather-related forced stoppages and (iii)

contact the Texas Railroad Commission if a facility sustains a weather-related forced stoppage during a weather emergency. Inspectors from the Critical Infrastructure Division of the Texas Railroad Commission began inspections on December 1, 2022. If, upon inspection, we are required to further weatherize or update weatherization of certain facilities, we may incur significant costs to complete any additional weatherization. Additionally, issues beyond our control, such as grid reliability or the severity of any such weather event, might undermine any winterization or emergency weather preparedness efforts we make. Furthermore, our operations in western Texas and New Mexico may be sensitive to drought and restrictions on water use.

*Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.*

Our operations are subject to many hazards inherent in gathering, compressing, treating, processing, transporting, purchasing and selling natural gas; transporting, storing, fractionating, treating and purchasing and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling and purchasing and selling crude oil, including:

- damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires, extreme temperatures, and other natural disasters, explosions, cyber attacks, and acts of terrorism;
- inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment;
- damage that is the result of our negligence or any of our employees’ negligence;
- leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
- spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural resources; and
- other hazards that could also result in personal injury, loss of life, pollution and/or suspension of operations.

These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural resource damage, and may result in delay, curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. Additionally, while we are insured against pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example, following the occurrence of severe hurricanes along the U.S. Gulf Coast in recent years, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes, with some coverage unavailable at any cost. Further, due to the impacts of recent weather events, certain major insurance companies are either reducing, or no longer offering, certain coverages in Texas, among other states. If a significant accident or event occurs for which we are not fully insured or if we fail to acquire insurance for certain of our operations generally, our operations and financial results could be adversely affected.

*Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.*

We sell processed natural gas at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances, which, in conjunction with movements in commodity prices, could materially impact our income from operations and cash flow.

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

Some portions of the pipeline systems that we operate have been in service for several decades prior to our purchase of them. Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of some of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of some portions of our pipeline systems could adversely affect our business and results of operations.

*Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued global and domestic hostilities may adversely impact our results of operations.*

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general and on us in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase our costs. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued global and domestic hostilities may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets, or indirect casualties, of an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage or coverage may be reduced or unavailable. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

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

We have experienced, and may encounter from time to time, opposition to the operation and expansion of our pipelines and facilities from governmental officials, non-governmental environmental organizations and groups, landowners, tribal groups, local groups and other advocates. In some instances, we encounter opposition which disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay, denial or termination of required governmental permits or approvals, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets or lawsuits or other actions designed to prevent, disrupt, delay or terminate the operation or expansion of our assets and business. Similar actions pursued against our oil and gas customers could result in interruptions or limitations to their businesses, which could reduce demand for our services. Any such event that restricts, delays or prevents the expansion of our or our customers’ businesses, interrupts the revenues generated by our or our customers’ operations or causes us or our customers to make significant expenditures not covered by insurance could adversely affect our business, results of operations, and financial condition, as well as reduce the demand for our services. Increased regulatory attention to environmental justice matters at the federal and state level may also provide communities opposed to our operations with greater opportunities to challenge or delay the permitting approval process.

*We may incur significant costs and liabilities resulting from performance of pipeline integrity testing programs and related repairs, as well as from initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more rigorous enforcement of applicable legal requirements.*

Pursuant to the authority under the NGPSA and HLPSA, PHMSA has established rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquids pipelines located where a pipeline leak or rupture could affect higher and moderate consequence risk areas, known as HCAs and MCAs, which are areas where a release could have the most significant adverse consequences. Among other things, these regulations require operators of covered pipelines to:

- perform ongoing assessments of pipeline integrity;
- identify and characterize applicable threats to pipeline segments that could impact an HCA, MCA or Class 3 or 4 area;
- maintain processes for data collection, integration and analysis;
- repair and remediate pipelines as necessary; and
- implement preventive and mitigating actions.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020, require PHMSA to impose more stringent pipeline safety standards on pipeline operators. As a result of those legislative enactments, PHMSA has issued several significant rulemakings. In August 2022, PHMSA finalized the last of three rules known collectively as the “Gas Mega Rule,” which collectively, among other items, imposed safety regulations on previously unregulated onshore gas gathering lines, required updated inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities and adjusted and strengthened repair, maintenance and integrity management assessment criteria for pipelines in HCAs and non-HCAs. The integrity-related requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and the PIPES Act of 2020, as well as any implementation of PHMSA rules thereunder, could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis and incur increased operating costs that could have a material adverse effect on our costs of transportation services as well as our business, results of operations and financial condition.

In addition, certain states, including Texas, Louisiana, Oklahoma, New Mexico, and North Dakota, where we conduct operations, have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquids pipelines. We plan to continue our pipeline integrity inspection programs to assess and maintain the integrity of our pipelines. The results of these inspections may cause us to incur material and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

The imposition of new or enhanced safety requirements, or any issuance or reinterpretation of guidance by PHMSA or any other state or federal agencies with respect thereto, may require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which could result in increased operating costs that could have an adverse effect on our results of operations or financial position.

*We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption ,disclosure of business sensitive, confidential or personally identifiable information, misdirected wire transfers, reputational harm, and financial loss.*

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct business. For example, we depend on digital technologies to operate our facilities, serve our customers and record financial data. At the same time, cyber incidents, including deliberate attacks, have increased. Our technologies, systems, networks, including our operational technology systems, and those of our business partners may become the target of cyber-attacks or security breaches. In May 2021, a ransomware attack on a major U.S. refined products pipeline forced the operator to temporarily shut down the pipeline, resulting in disruption of fuel supplies along the East Coast. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. Our technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could adversely disrupt our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient, and no security measure is infallible. As cyber incidents continue to evolve, we will be required to expend additional resources to enhance our security posture and cybersecurity defenses or to investigate and remediate any vulnerability to or consequences of cyber incidents. Advances in computer capabilities, rapid changes and innovation in the field of artificial intelligence, cryptography, inadequate facility security or other developments may result in a compromise or breach of the technology we use to safeguard confidential, personal, or otherwise protected information. As the breadth and complexity of the technologies we use continue to grow, including as a result of the use of mobile devices, cloud services, open source software, social media and the increased reliance on devices connected to the internet, the potential risk of security breaches and cybersecurity attacks also increases. Despite ongoing efforts to improve our ability to protect data from compromise, we may not be able to protect all of our data across our diverse systems. Our efforts to improve security and protect data may also identify previously undiscovered instances of security breaches or other cyber incidents. Our insurance coverages may not be sufficient to cover all the losses we may experience as a result of a cyber incident.

*The widespread outbreak of illnesses or any other public health crises that impacts operations and/or the global demand for energy commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.*

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. For example, the effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity.

### Risks Related to our Capital Projects and Future Growth

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

The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. For example, the construction of additional systems may be delayed or require greater capital investment if the commodity prices of certain supplies, such as steel pipe, increase due to imposed tariffs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gas processing plant, the construction may occur over an extended period of time and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct pipelines or facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing pipelines or facilities in such area. To the extent we rely on estimates of future production in any decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new pipelines or facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights of way prior to constructing new pipelines. We may be unable to obtain or renew such rights of way to connect new natural gas and crude oil supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights of way or to renew existing rights of way. If the cost of renewing or obtaining new rights of way increases, our cash flows could be adversely affected.

*If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to pay dividends to stockholders. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a negative impact on our operations and financial condition.*

Our ability to grow depends, in part, on our ability to develop growth projects and/or make acquisitions that result in an increase in cash generated from operations. If we are unable to develop accretive growth projects or make accretive acquisitions because we are unable to (i) develop growth projects economically or identify attractive acquisition candidates and negotiate acceptable acquisition agreements, (ii) obtain financing for these projects or acquisitions on economically acceptable terms, or (iii) compete successfully for growth projects or acquisitions, then our future growth and ability to return increasing capital to our shareholders may be limited.

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

- operating a significantly larger combined organization and adding new or expanded operations;
- difficulties in the assimilation of the assets and operations of the growth projects or acquired businesses, especially if the assets developed or acquired are in a new business segment and/or geographic area;
- the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
- the failure to realize expected volumes, revenues, profitability or growth;
- the failure to realize any expected synergies and cost savings;
- coordinating geographically disparate organizations, systems and facilities;
- the assumption of environmental and other unknown liabilities;
- limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects;
- the failure to attain or maintain compliance with environmental and other governmental regulations;
- inaccurate assumptions about the overall costs of equity or debt or the tightening of capital markets and access to new capital;
- the diversion of management’s and employees’ attention from other business concerns;
- challenges associated with joint venture relationships and minority investments, including dependence on joint venture partners, controlling shareholders or management who may have business interests, strategies or goals that are inconsistent with ours; and
- customer or key employee losses at the acquired businesses or to a competitor.

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

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

Growth projects may increase our concentration in a line of business or geographic region and acquisitions may significantly increase our size and diversify the geographic areas in which we operate. In addition, we may not achieve the desired effect from any future growth projects or acquisitions.

*We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.*

We participate in several joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities include, among others, large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business. Without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in our best interests or the particular joint venture.

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

As is common in the midstream industry, we may operate one or more of our properties with one or more joint venture partners where we own a minority interest and/or contract with a third party to control operations. These relationships could require us to share operational and other control, such that we may no longer have the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in such circumstances, our rights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions taken by a joint venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.

### Risks Related to our Financial Condition

*If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.*

Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002.

Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our results of operations, financial condition and ability to comply with our debt obligations.

*We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.*

Many of our customers may experience financial problems that could have a significant effect on their creditworthiness, especially in a depressed commodity price environment. A decline in natural gas, NGL and crude oil prices may adversely affect the business, financial condition, results of operations, creditworthiness, cash flows and prospects of some of our customers. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from a decline in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Additionally, a decline in the share price of some of our public customers may place them in danger of becoming delisted from a public securities exchange, limiting their access to the public capital markets and further restricting their liquidity. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Furthermore, some bankruptcy courts have found that, in certain cases, oil, gas and water gathering agreements do not create covenants running with the land under governing law and are thus subject to rejection in Chapter 11 proceedings. Whether a particular contract is subject to rejection depends on the wording of the contract, the governing law and the forum where a particular bankruptcy case is filed. Financial problems experienced by our customers could result in the impairment of our long-lived assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues. Any material nonpayment or nonperformance by our key customers or our derivative counterparties could reduce our ability to pay cash dividends to our stockholders.

*Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.*

The rate of inflation in the U.S. began to increase significantly beginning in the second half of 2021. Although the rate of inflation has generally declined since the second half of 2022, the rate of inflation remains higher than historical averages, and inflationary pressures remain volatile and have resulted in and may result in additional increases to the costs of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022 and 2023. Although it is currently anticipated that the U.S. Federal Reserve will make cuts to benchmark interest rates in 2024, such cuts may not occur and any continued increase in benchmark interest rates could have the effect of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could negatively impact the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations, including services, labor costs and equipment if our operating activity increases.

Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation, or any resultant changes in monetary policy, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues, and/or higher interest rates would negatively impact our business, financial condition and results of operations.

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

We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. Global oil and natural gas commodity prices, particularly crude oil, remain volatile. Decreases in commodity prices have previously had, and could continue to have, a negative impact on the demand for our services and our market capitalization.

Should energy industry conditions deteriorate, there is a possibility that long-lived assets may be impaired in a future period. For example, in the fourth quarter of 2021, we recorded a non-cash pre-tax impairment of $452.3 million primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Central operations in our Gathering and Processing segment. Any additional impairment charges that we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of long-lived assets. For further discussion of our impairments of long-lived assets, see Note 5 — Property, Plant and Equipment and Intangible Assets of the “Consolidated Financial Statements” included in this Annual Report.

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

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

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

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

We may not be successful in balancing our purchases and sales of the commodities we handle. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

*The amounts we pay in dividends may vary from anticipated amounts and circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.*

The determination of the amounts of cash dividends, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors, in consultation with management, deems relevant. Many of these matters are affected by factors beyond our control and therefore, the actual amount of cash that is available for dividends to our stockholders may vary from anticipated amounts.

Additionally, as events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, may decide to address those matters by utilizing capital that may otherwise be used for our dividend. For example, in March 2020, our board of directors approved a reduction in our quarterly cash dividend to $0.10 per share for the quarter ended March 31, 2020 and maintained such dividend amount through the quarter ended September 30, 2021. Our board of directors may also determine that an increase in our dividend is appropriate. For example, for the first quarter of 2024, management intends to recommend to our board of directors an increase to the Company’s common dividend to $0.75 per common share or $3.00 per common share annualized. The recommended common dividend per share increase, if approved, would be effective for the first quarter of 2024 and payable in May 2024. If we issue additional shares of common or preferred stock or we incur debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.

Further, dividends to our common stockholders are not cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

*Our future tax liability may be greater than expected if our NOL carryforwards are limited, we do not generate expected deductions, or tax authorities successfully challenge certain of our tax positions.*

As of December 31, 2023, we have U.S. federal NOL carryforwards of $5.5 billion, $857.4 million of which will expire in 2037 while others have no expiration date. Subject to the CAMT discussed below, we expect to be able to utilize these NOL carryforwards and generate deductions to offset all or a portion of our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and the current expectation that our NOL carryforwards will not become subject to future limitations under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”).

Section 382 generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change was to occur, utilization of our NOLs carryforwards would be subject to an annual limitation under Section 382, determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382, subject to certain adjustments.

While we expect to be able to utilize our NOL carryforwards and generate deductions to offset all or a portion of our future taxable income (subject to the CAMT discussed below), in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise) or our NOL carryforwards are subject to future limitations under Section 382, our future tax liability may be greater than expected.

*Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes may adversely affect our financial condition, results of operations and cash flows.*

U.S. federal and state legislation is periodically proposed that would, if enacted into law, make significant changes to tax laws and could materially increase our tax obligations, adversely affecting our financial condition, results of operations and cash flows. For example, on August 16, 2022, President Biden signed into law the IRA which includes, among other things, the CAMT. Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $1 billion.

Based on our current interpretation of the IRA, the CAMT and related guidance and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate being an applicable corporation in the near term, but we are likely to become an applicable corporation in a subsequent tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for a future year. As a result, our current expectation is that the impact of the CAMT is limited to timing differences in future tax years.

The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA, the CAMT and related guidance. In the future the U.S. Department of the Treasury and the IRS are expected to release regulations and additional interpretive guidance relating to such legislation, and any significant variance from our current interpretation could result in a change in our analysis of the application of the CAMT to us.

*Derivatives legislation and its implementing regulations could have a material adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.*

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted in July 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act, and most of these regulations have been finalized.

In October 2020, the CFTC adopted new rules that will place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain *bona fide* hedging transactions. The new rules required general compliance by January 1, 2022 for covered future positions and by January 1, 2023 for covered swaps positions. We have not experienced a material impediment to, and do not expect these regulations to materially impede, our hedging activity at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. The CFTC and the federal banking regulators have adopted regulations requiring certain counterparties to swaps to post initial and variation margin. However, our current hedging activities would qualify for the non-financial end user exemption from the margin requirements.

The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts or potentially reduce the availability of derivatives to protect against risks we encounter. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

The European Union (the “EU”) and other non-U.S. jurisdictions are also implementing regulations with respect to the derivatives market. To the extent we enter into swaps with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may be impacted by such regulations. The implementing regulations adopted by the EU and by other non-U.S. jurisdictions could have a material adverse effect on us, our financial condition and our results of operations.

### Risks Related to the Ownership of our Common Stock

*Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.*

We or our stockholders may sell shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. As of December 31, 2023, we had 222,611,259 outstanding shares of common stock. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

*Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.*

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including provisions which require:

- a classified board of directors, so that only approximately one-third of our directors are elected each year;
- limitations on the removal of directors; and
- limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

*We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.*

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations and powers, preferences, including preferences over our common stock respecting dividends and distributions, rights, qualifications, limitations and restrictions as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

### Risks Related to Our Indebtedness

*Continued increases in interest rates, due to associated Federal Reserve policies or otherwise, could adversely affect our cost of capital, which could increase our funding costs and reduce the overall profitability of our business.*

We have significant exposure to increases in interest rates. As of December 31, 2023, our total indebtedness was $13,074.2 million, excluding $29.5 million of unamortized discounts and $90.8 million of debt issuance costs, of which $11,534.4 million was at fixed interest rates, $1,250.0 million was at variable interest rates and $289.8 million consisted of finance lease liabilities. A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $12.5 million based on our December 31, 2023 debt balances. We additionally had $2.6 billion of additional borrowing capacity available under the TRGP Revolver after accounting for $22.3 million of letters of credit, under which borrowing is exposed to such increases in variable interest rates. As a result of our variable interest debt, our results of operations could be adversely affected by increases in interest rates, due to associated Federal Reserve policies or otherwise.

Additionally, like all equity investments, an investment in our equity securities is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments.

Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline.

*We have a substantial amount of indebtedness which may adversely affect our financial position and we may still be able to incur substantially more debt, which could collectively increase the risks associated with compliance with our financial covenants.*

We have a substantial amount of indebtedness. As of December 31, 2023, we had $6.5 billion outstanding TRGP senior unsecured notes, excluding $29.5 million of unamortized discounts and $5.0 billion outstanding of the Partnership’s senior unsecured notes. We also had $575.0 million outstanding under the Securitization Facility. In addition, we had $500.0 million of borrowings outstanding under the Term Loan Facility, no borrowings outstanding under the TRGP Revolver, $22.3 million of letters of credit outstanding, $175.0 million of borrowings outstanding under the Commercial Paper Program and $2.6 billion of additional borrowing capacity available under the TRGP Revolver. For the years ended December 31, 2023, 2022 and 2021, our consolidated interest expense, net was $687.8 million, $446.1 million and $387.9 million, respectively.

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

- our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
- satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;
- we will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;
- our debt level may influence how counterparties view our creditworthiness, which could limit our ability to enter into commercial transactions at favorable rates or require us to post additional collateral in commercial transactions;
- our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
- our debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.

Our long-term unsecured debt is currently rated by Fitch, Moody’s and S&P. As of December 31, 2023, Targa’s senior unsecured debt was rated “BBB-” by Fitch, “Baa3” by Moody’s and “BBB-” by S&P. In February 2024, S&P upgraded Targa’s rating to “BBB”. Any future downgrades in our credit ratings could negatively impact our cost of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.

Our International Swaps and Derivatives Association agreements (“ISDAs”) contain credit-risk related contingent features. Following the release of the collateral securing our TRGP Revolver in 2022 as a result of our investment grade credit rating, our derivative positions are no longer secured. As of December 31, 2023, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $9.9 million. If our credit rating is downgraded below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of December 31, 2023, we would not be required to post collateral to any counterparties per the terms of our ISDAs.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, investments or capital expenditures, acquisitions, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cash dividends. We may not be able to affect any of these actions on satisfactory terms, or at all.

We may be able to incur substantial additional indebtedness in the future. The TRGP Revolver provides an available commitment of $2.75 billion and allows us to request increases in commitments up to an additional $500.0 million. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If we incur additional debt, this could increase the risks associated with compliance with our financial covenants.

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

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

- incur or guarantee additional indebtedness or issue additional preferred stock;
- pay dividends on our equity securities or to our equity holders or redeem, repurchase or retire our equity securities or subordinated indebtedness;
- make investments and certain acquisitions;
- sell or transfer assets, including equity securities of our subsidiaries;
- engage in affiliate transactions;
- consolidate or merge;
- incur liens;
- prepay, redeem and repurchase certain debt, subject to certain exceptions;
- enter into sale and lease-back transactions or take-or-pay contracts; and
- change business activities conducted by us.

In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

A breach of any of these covenants could result in an event of default under our debt agreements. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the accounts receivables of Targa Receivables LLC under the Securitization Facility. If the indebtedness under our debt agreements is accelerated, we cannot assure you that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

### Risks Related to Regulatory Matters

*Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change, including increasingly stringent regulations for methane and other emissions from the oil and gas sector, that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, reduce demand for the products and services we provide, and reduce our or our customers’ ability to access capital.*

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

In the United States, no comprehensive climate change legislation has been implemented at the federal level, though laws such as the IRA advance numerous climate-related objectives. However, because the U.S. Supreme Court has held that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, in August 2022, the IRA was signed into law, which appropriates significant federal funding for renewable energy initiatives and amends the federal Clean Air Act to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions fee would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA. In order to support implementation of the methane emissions fee, including exemptions from the same, the EPA proposed revisions to its Greenhouse Gas Reporting Rule in late July 2023, which, per the Unified Regulatory Agenda, is expected to be finalized in 2024. The revisions would amend requirements applicable to the petroleum and natural gas systems source category to ensure reporting is based on empirical data and accurately reflects total methane and waste emissions. The methane emissions fee and renewable and low carbon energy funding provisions of the law could increase our and our customers’ operating costs and accelerate the transition away from fossil fuels, which could in turn reduce demand for our products and services and adversely affect our business and results of operations.

In recent years, there has been considerable focus on the regulation of methane emissions from the oil and gas sector. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources known as OOOOc, in December 2023. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. It is likely, however, that the final rule and its requirements will be subject to legal challenges. Moreover, compliance with the new rules may effect the amount we owe under the IRA’s methane fee described above because compliance with EPA’s methane rules would exempt an otherwise covered facility from the requirement to pay the methane fee. The requirements of the EPA’s final methane rules have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief.

Various states and groups of states have also adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on areas of coverage similar to what the federal government has or may consider, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is an agreement for nations to submit non-binding targets to limit their GHG emissions through individually-determined reduction goals every five years after 2020. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. In November 2021 at the 26th Conference of the Parties (“COP26”), the United States and the EU jointly announced the launch of a Global Methane Pledge, an initiative which over 100 countries joined, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The U.S. also announced, in conjunction with the EU and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At COP28 in December 2023, parties agreed to transition away from fossil fuels in energy systems and increase renewable energy capacity, although no timeline for doing so was set. The impacts of these actions, orders, pledges, and agreements, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, COP28, or other international conventions cannot be predicted at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects on our operations. Additionally, such agreements could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for, and increased potential opposition to, the production and use of fossil fuels.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, that may limit hydraulic fracturing of oil and natural gas wells, restrict flaring and venting during natural gas production on federal properties, and ban or restrict new or existing leases for production of minerals on federal properties. President Biden has issued several executive orders and strategies focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas. Other actions relating to oil and natural gas production activities that could be pursued by the Biden Administration may include more restrictive requirements for the establishment of oil and natural gas pipeline infrastructure or the permitting of liquefied natural gas export facilities. For example, on January 26, 2024, President Biden announced a temporary pause on pending decisions on new exports of liquified natural gas to countries that the United States does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorizations. The pause is intended to provide time to integrate certain considerations, including potential energy cost increases for consumers and manufacturers and the latest assessment of the impact of GHG emissions, to ensure adequate guards against health risks are in place. With respect to oil and gas activities, in November 2022, the BLM proposed a rule that would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if BLM finds that an operator’s methane waste minimization plan is insufficient. The rule is expected to be finalized in early 2024. The Biden Administration has also called for revisions and restrictions to the leasing and permitting programs for oil and gas development on federal lands and, for a time, suspended federal oil and gas leasing activities. The U.S. Department of the Interior’s comprehensive review of the federal leasing program resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate. Any regulatory changes that restrict or require modifications to our or our suppliers’ existing operations or future expansions plans could reduce the demand for the products and services we provide, increase our operating costs and may have a negative impact on our financial condition.

Litigation risks are also increasing, as a number of cities, local governments, and other plaintiffs have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or consumers by failing to adequately disclose those impacts. Increasingly, companies in the energy and infrastructure industries are being, and may increasingly be, subject to allegations that they are responsible for climate change impacts and/or responsible for the physical impacts of climate change. Should we be targeted by any similar litigation, involvement in such a case could have adverse financial and reputational impacts and an unfavorable ruling could significantly impact our operations and adversely impact our financial condition.

Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in fossil fuel energy companies but concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies have also become more attentive to sustainability lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding to the fossil fuel sector. Various financial regulators have adopted, or are considering adopting, guidance or requirements regarding the management of climate-related risk by financial institutions. While we cannot predict how financial institutions will respond to these various actions, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our and our suppliers’ and customers’ businesses and operations. In addition, in March 2022, the SEC released a proposed rule that would establish a framework for the reporting of climate risks, targets, and metrics. Recently, the State of California adopted several laws that require similar, or in some situations more extensive, disclosure. While implementing rules on certain of these laws are outstanding, both the California laws and the SEC rule, to the extent finalized, may result in increased legal, accounting and financial compliance costs for us and our suppliers and customers to comply, including the implementation of significant additional internal controls processes and procedures regarding matters that have not been subject to such controls in the past, and impose increased oversight obligations on our management and board of directors. We may also face increased litigation risks related to disclosures made pursuant to these requirements. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders in restricting or seeking more stringent conditions with respect to their investments in our customers in the energy industry and companies like ours that support the energy industry.

The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation, and financial risks may result in our oil and natural gas customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other extreme weather events, as well as chronic shifts in temperature and precipitation patterns. For further discussion, please see *Weather events may damage our pipelines and other facilities, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.*

*Increasing stakeholder and market attention to sustainability matters and disclosure obligations may impact our business.*

Companies across industries are facing increasing scrutiny from a variety of stakeholders related to their sustainability practices. Increasing societal expectations regarding sustainability initiatives and disclosures and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our customers’ products and our services, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for our or our customers’ hydrocarbon products and additional governmental investigations and private litigation against us or those customers.

As part of our ongoing effort to enhance our sustainability practices, our Board of Directors has established a Sustainability Committee. Committee members oversee management’s implementation of sustainability policies and provide insight to the Board on the effectiveness of integrating sustainability into our various business activities. We have also appointed a senior vice president of sustainability, who reports directly to our CEO and also regularly provides reports on relevant sustainability matters to our Board of Directors. We also published our 2022 Sustainability Report, which provides updates on our performance related to certain sustainability topics and sets certain sustainability goals, such as reductions in methane intensity in line with the ONE Future goals. While we may elect to seek out various additional voluntary sustainability targets now or in the future, such targets are aspirational. Moreover, despite our governance oversight in place, many of our sustainability targets and goals are ambitious, and we may not be able to adequately identify sustainability-related risks and opportunities and, further, may not be able to meet our sustainability targets and goals in the manner or on such a timeline as initially contemplated, or at all, including as a result of unforeseen costs or technical difficulties associated with achieving such results. Moreover, even if we are to achieve our targets and goals or complete other sustainability initiatives, there is no guarantee that doing so will have the desired effect. Sustainability-related actions or statements that we may make or take are sometimes based on expectations, assumptions, or third-party information that we currently believe to be reasonable, but which may subsequently be determined to be erroneous or be subject to misinterpretation. For example, methodologies regarding the monitoring and calculation of climate risks and GHG emissions are evolving, and it is possible that stakeholders, either currently or at some point in future, may not agree with our approach. Moreover, to the extent we elected to pursue such targets and were able to achieve the desired target levels, such achievement may have been accomplished as a result of entering into various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our sustainability impact instead of actual changes in our sustainability performance. However, we cannot guarantee that there will be sufficient offsets for purchase or that, notwithstanding our reliance on any reputable third party registries, that the offsets we do purchase will successfully achieve the emissions reductions they represent. Notwithstanding our election to pursue aspirational targets now or in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other sustainability-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles. If we fail to, or are perceived to fail to, comply with or advance certain sustainability initiatives (including the timeline and manner in which we complete such initiatives), we may be subject to various adverse impacts, including reputational damage and potential stakeholder engagement and/or litigation, even if such initiatives are currently voluntary.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to sustainability matters. Additionally, we and other companies in our industry publish sustainability reports that are made available to investors. Such ratings and reports are used by some investors to inform their investment and voting decisions. Unfavorable sustainability ratings may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. Also, certain institutional lenders may decide not to provide funding to us or our customers’ companies based on sustainability concerns, which could adversely affect our financial condition and access to capital for potential growth projects. Increasingly, investors, lenders, and other stakeholders are focusing on issues related to environmental justice and natural capital, which may result in increased scrutiny of our processes on such issues.

Furthermore, public statements with respect to sustainability matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential sustainability benefits. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain sustainability -statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our sustainability efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. We expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to sustainability matters, and we could face increasing costs as we attempt to comply with and navigate further regulatory sustainability-related focus and scrutiny. Additionally, many of our customers and suppliers may be subject to similar expectations and challenges, which may augment or create additional risks, including risks that may not be known to us.

*We could incur significant costs in complying with more stringent occupational safety and health requirements.*

We are subject to stringent federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the federal Occupational Safety and Health Administration’s (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, any of which could have a material adverse effect on our business, financial condition and results of operations.

*Laws, regulations and executive orders limiting hydraulic fracturing activities could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.*

While we do not conduct hydraulic fracturing, many of our oil and gas exploration and production customers do perform such activities. Hydraulic fracturing is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over, proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the process, including the EPA.

In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. Moreover, President Biden issued an executive order in January 2021 suspending the issuance of new leases on federal lands and waters pending completion of a study of current oil and gas practices but, in August 2022, a U.S. District Court issued a permanent injunction that blocked President Biden’s order suspending new leases. Litigation concerning this issue is ongoing. Notwithstanding these legal developments, further restrictions may be adopted by the Biden Administration that could restrict hydraulic fracturing activities on federal lands and waters. Many states have adopted legal requirements that have imposed new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, including in states where we or our customers conduct operations. States could further elect to suspend or prohibit hydraulic fracturing activities in the future. While governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, non-governmental organizations may also seek to restrict hydraulic fracturing through ballot initiatives, such as those that have been pursued in Colorado. New or more stringent laws, regulations, executive orders or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gas drilling activities using hydraulic fracturing techniques, while increased public opposition to activities using such techniques may result in operational delays, restrictions, cessations, or increased litigation. Any one or more of such developments could reduce demand for our gathering, processing and fractionation services and have a material adverse effect on our business, financial condition and results of operations.

*Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the environment may cause us to incur significant costs and liabilities.*

Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational health and safety, the discharge of pollutants into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including acquisition of a permit or other approval before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements, and imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and BLM, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits and approvals issued under them, which can often require difficult and costly actions. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, and the issuance of orders enjoining or conditioning performance of some or all of our operations in a particular area. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or waste products have been released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator or the activities conducted and from which a release emanated complied with applicable law. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by noise, odor, or the release of hazardous substances, hydrocarbons or wastes into the environment.

The risk of incurring environmental costs and liabilities in connection with our operations is significant due to our handling of natural gas, NGLs, crude oil and other petroleum products, because of air emissions and product-related discharges arising out of our operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations.

Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. For example, in October 2021 the EPA announced plans to reconsider the Trump Administration’s December 2020 decision to retain the 2015 ground ozone standard, rather than making it more stringent, a decision on which has been delayed until 2024. Further, in March 2023, the EPA issued its Good Neighbor Plan rule, which imposes emissions-related requirements on fossil fuel-fired power plants and other industrial users in 22 states, including Texas and Louisiana, which could reduce demand for our products and accelerate the transition away from oil and gas to other sources of energy. The Good Neighbor Plan has been subject to extensive litigation and, in various states, is stayed pending additional action.

There continues to be uncertainty on the federal government’s applicable jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands, as the EPA and the U.S. Army Corps of Engineers (“Corps”) under the Obama, Trump and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. In January 2023, the EPA and Corps released a final revised definition of “waters of the United States” founded upon the pre-2015 regulations and including updates to incorporate existing Supreme Court decisions and recognizing regional and geographic differences. However, the new rule was challenged by multiple states in 2023, resulting in the rule being enjoined in 27 states. Additionally, the U.S. Supreme Court released its opinion in *Sackett v. EPA*, which involved issues relating to the legal tests used to determine whether wetlands are “waters of the United States.” The *Sackett* decisions invalidated certain parts of the January 2023 rule, resulting in a revised rule being issued in September 2023. However, due to the injunction in certain states, the implementation of the September 2023 rule currently varies by state. In the 27 states where the rule has been enjoined, the agencies are interpreting the definition consistent with the pre-2015 regulatory regime and the changes made by the *Sackett* decision. In the remaining 23 states, the agencies are implementing the September 2023 rule. The implementation of the final rule, results of the litigation and any further expansion of the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, could lead to delays, restrictions or cessation of the development of projects, result in longer permitting timelines, or increased compliance expenditures or mitigation costs for our and our oil and natural gas customers’ operations, which may reduce the rate of production of natural gas or crude oil from operators with whom we have a business relationship and, in turn, have a material adverse effect on our business, results of operations and cash flows.

Separately, Nationwide Permit (“NWP”) 12, which is available under the Clean Water Act for certain oil and gas activities, has been subject to legal challenges and regulatory revision in recent years. Following legal challenges to NWP 12 in the federal district court for the District of Montana, the Corps reissued NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, an October 2021 decision by the District Court for the Northern District of California resulted in a vacatur of a 2020 rule revising the Clean Water Act Section 401 certification process. The U.S. Supreme Court stayed this vacatur and, in September 2023, the EPA finalized its Clean Water Act Section 401 Water Quality Certification Improvement Rule, effective on November 27, 2023. In March 2022, the Corps announced that it was seeking stakeholder input on a formal review of NWP 12. However, while this review is ongoing, the Corps has resumed permitting decisions. While the full extent and impact of these actions is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. This in turn could have an adverse effect on our business, financial condition and results of operation.

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

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

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

The classification of some of our gathering facilities, transportation pipelines, and purchase and sale transactions as FERC-jurisdictional or non-jurisdictional may be subject to change based on future determinations by FERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.

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

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

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

Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of the NGA or NGPA up to a maximum amount that is adjusted annually for inflation, which for 2024 equals approximately $1.5 million per violation per day, as well as authority to order disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, TPL SouthTex Pipeline Company LLC, Targa Midland Gas Pipeline LLC,

Midland-Permian Pipeline LLC, Delaware-Permian Pipeline LLC, and Targa SouthTex Mustang Transmission Ltd., have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA up to a maximum amount that is adjusted annually for inflation, which for 2024 was up to approximately $16,170 per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability. For more information regarding regulation of our operations, see “Item 1. Business—Regulation of Operations.” Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time.

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

The jurisdictions in which we operate (including the United States) have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure, or loss of personal information. Additionally, new laws and regulations governing data privacy and unauthorized disclosure of personal information and imposing certain cybersecurity-related requirements, including California legislation (which, among other things, provides for a private right of action and allows the California Attorney General to impose significant fines), pose increasingly complex compliance challenges. Other states, including Texas, have also enacted data privacy legislation. Some or all of such legislation will elevate our compliance costs over time. Our business involves collection, use, and other processing of personal information and personally identifiable information of our employees, investors, contractors, suppliers, and customer contacts. As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant resources to continue to modify or enhance our protective measures to comply with such legislation and to detect, investigate and remediate vulnerabilities to cyber incidents. Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, remediation costs, or mandated changes in our business practices. Each has the potential to materially impact our financial condition.

## Cybersecurity

As filed, 7,022 characters.

### Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks

Cybersecurity risk is an area of focus for Targa, particularly as our operations become increasingly dependent on digital technologies. Across the world, cybersecurity incidents are occurring more frequently, use increasingly sophisticated methods and could pose serious risks to the Company’s data integrity, reputation, operations and revenue. The Company has a cybersecurity program, which uses technology and processes to help mitigate cybersecurity risks, with our Security Operations team working to monitor, assess, identify, and respond to potential cybersecurity incidents that threaten the Company. The program also focuses on security awareness and training for employees and contractors with access to Company facilities or systems.

We utilize the National Institute of Standards and Technology Cybersecurity Framework as well as supplemental guidance for information and operational technologies to assess current risks against deployed current countermeasures. We seek to follow federal and state statutory and regulatory guidance and have adopted internal policies and standards that we believe are in alignment with these requirements. Our cybersecurity program covers Targa’s general corporate information and operational technology systems, which support our various lines of business.

Our cybersecurity program also follows defense in depth principles, which aim to implement various layered access control, detection, prevention, and response measures. Targa has formal disaster recovery and business continuity plans, as well as a Cyber Incident Response Plan, which is periodically tested using tabletop exercises.

We regularly engage with independent third parties to assess our vulnerabilities and help us mitigate cybersecurity-related risks. Targa’s security posture is also tested by internal Targa personnel and independent third parties to gauge its effectiveness.

Our cybersecurity program includes a formally documented process for oversight of cybersecurity risks associated with our third-party service providers. This process begins prior to engagement. Third-party service providers are evaluated using independent assessment tools to gauge their security posture.

The above cybersecurity risk management processes are integrated into our overall risk management program. While we seek to continually evaluate cybersecurity risks based upon emerging threats as a part of the Company’s risk management processes, overall cybersecurity risks to the Company are also evaluated annually by independent consultants and learnings are incorporated into the overall Company risk matrices.

Our Code of Conduct communicates our expectation that employees and contractors will maintain the security of our information technology systems. All employees are presented with Code of Conduct training annually. Each employee’s and contractor’s ability to recognize and report cyber threats is an important component of our cybersecurity program. As a result, security awareness and training are provided to employees and contractors with access to our facilities or systems. We focus on increasing employee awareness of phishing attempts and train employees to be aware of cyber risks.

We recognize that cybersecurity risks continue to emerge and evolve. Assessment and enhancement of our security posture in predicting and responding to the changing threat landscape are core goals of our cybersecurity program. Targa maintains relationships with various cybersecurity industry subject matter experts, governmental agencies, law enforcement research and benchmarking organizations, and industry peers as part of our effort to improve our program based on threat information and available countermeasures.

We continue to make investments in new technologies to protect our facilities, users, and stakeholders, and to protect the personally identifiable information we maintain.

### Board of Directors’ Oversight of Risks from Cybersecurity Risks

Cybersecurity risks are overseen at the board level through the Audit Committee. As part of this oversight, the Audit Committee, with several key members of management, meets quarterly to discuss ongoing initiatives and seek to ensure coordination between enterprise stakeholders. At these meetings, our Vice President of Security Operations and Senior Vice President of Technology, who oversee the Company’s cybersecurity program, review with our Audit Committee current and emerging cybersecurity-related threats as well as key performance indicators for cybersecurity process maturity, operational performance, and enterprise performance in countering these threats. Our Vice President of Security Operations and Senior Vice President of Technology also annually review our Company's cybersecurity program with our full board. Based on the information provided through these various processes, our board evaluates the risks facing us and provides guidance as to the appropriate risk management strategy.

### Management’s Role in Assessing and Managing Cybersecurity Risks

The Vice President of Security Operations and Senior Vice President of Technology are primarily responsible for assessing and managing Targa’s material risks from cybersecurity threats, and work to monitor the effectiveness of our cybersecurity detection and response processes in countering current threats and to provide updates to our executive team. Our Vice President of Security Operations has more than 25 years of experience working in the field of cybersecurity, including numerous years directing enterprise-level cybersecurity programs.

### No Previous Material Cybersecurity Threats

As of the date of this report, though the Company and our service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect the Company. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the security and risk management measures that we have implemented and any additional measures we may implement or adopt in the future, our facilities and systems, and those of our third-party service providers, have been and are vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, scams, burglary, human errors, acts of vandalism, misdirected wire transfers, or other malicious or criminal activities. A successful attack on our information or operational technology systems could have material consequences to the Company. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our information technology systems.

## Properties

As filed, 234 characters.

A description of our properties is contained in “Item 1. Business” in this Annual Report.

Our principal executive offices are located at 811 Louisiana Street, Suite 2100, Houston, Texas 77002 and our telephone number is 713-584-1000.

## Legal proceedings

As filed, 3,161 characters.

On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview and Noble Americas Corp. (the “Splitter Agreement”), which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol sought return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

On October 15, 2020, the District Court awarded Vitol $129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company appealed the award in the Fourteenth Court of Appeals in Houston, Texas. In October 2020, we sold Targa Channelview, but under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on crude oil. We filed a petition for review with the Supreme Court of Texas which was denied on October 20, 2023, but we are seeking rehearing and the appeal remains pending. The cumulative amount of interest on the award through December 31, 2023, if accrued, would have been approximately $55.5 million.

Additional information required for this item is provided in Note 18 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, which is incorporated by reference into this item.

## Management's discussion and analysis

As filed, 67,022 characters.

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:

| 2023 | Natural Gas $/MMBtu (1) | Illustrative Targa NGL $/gal (2) | Crude Oil $/Bbl (3) |
| --- | ---: | ---: | ---: |
| 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 |

(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.

#### 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.

#### 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).

#### 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.

#### 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.

### 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.

*(In millions)*

| Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow | Year Ended December 31, 2023 | 2022 |
| --- | ---: | ---: |
| 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 | — | (435.9) |
| Transaction costs related to business acquisition (2) | — | 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 | — |
| **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** |

(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.

### Consolidated Results of Operations

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

*(In millions)*

| Revenues: | Year Ended December 31, 2023 | 2022 | 2023 vs. 2022 |  |
| --- | ---: | ---: | ---: | ---: |
| 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 | — | 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 | — | 30.0 | (30.0) | (100%) |
| Deemed dividends on Series A Preferred Stock | — | 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%) |

(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.

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:

*(In millions)*

| Year Ended: | Gathering and Processing | Logistics and Transportation | Other |
| --- | ---: | ---: | ---: |
| December 31, 2023 | $2,082.2 | $1,948.7 | $275.5 |
| December 31, 2022 | 1,981.0 | 1,456.3 | (302.4) |

63

### Gathering and Processing Segment

*(In millions, except operating statistics and price amounts)*

|  | Year Ended December 31, 2023 | 2022 | 2023 vs. 2022 |  |
| --- | ---: | ---: | ---: | ---: |
| 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%) |

(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.

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:

*(In millions, except volumetric data and price amounts)*

|  | Year Ended December 31, 2023 Volume Settled | Price Spread (1) | Gain (Loss) | Year Ended December 31, 2022 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) |

(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

*(In millions, except operating statistics)*

|  | Year Ended December 31, 2023 | 2022 | 2023 vs. 2022 |  |
| --- | ---: | ---: | ---: | ---: |
| 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% |

(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

*(In millions)*

|  | Year Ended December 31, 2023 | 2022 | 2023 vs. 2022 |
| --- | ---: | ---: | ---: |
| Operating margin | $275.5 | $(302.4) | $577.9 |
| Adjusted operating margin | $275.5 | $(302.4) | $577.9 |

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:

*(In millions)*

|  | Consolidated Total |
| --- | ---: |
| 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 |

(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 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

*(In millions)*

| Year Ended December 31, 2023 | 2022 | 2023 vs. 2022 |
| ---: | ---: | ---: |
| $3,211.6 | $2,380.8 | $830.8 |

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

The increase in net cash provided by operations was primarily due to higher 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

*(In millions)*

| Year Ended December 31, 2023 | 2022 | 2023 vs. 2022 |
| ---: | ---: | ---: |
| $(2,400.8) | $(4,149.7) | $1,748.9 |

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

*(In millions)*

| Source of Financing Activities, net | Year Ended December 31, 2023 | 2022 |
| --- | ---: | ---: |
| Debt, including financing costs | $1,300.0 | $4,651.5 |
| Redemption of Series A Preferred Stock | — | (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 |

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.

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

*(In millions)*

*ASSETS*

| Summarized Combined Balance Sheet Information | December 31, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| 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 | — | 10.5 |
| Total assets | $16,245.1 | $15,840.7 |
| **LIABILITIES AND OWNERS’ 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’ equity | 832.2 | 2,139.7 |
| Total liabilities and owners’ 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 | — | 30.0 |

### Common Stock Dividends

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

*(In millions, except per share amounts)*

| 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 |
| --- | --- | ---: | ---: | ---: | ---: |
| 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 |

### Preferred Dividends

#### Series A Preferred Redemption

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

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

### Capital Expenditures

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

*(In millions)*

| Capital expenditures: | Year Ended December 31, 2023 | 2022 |
| --- | ---: | ---: |
| 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 |

(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:

*(in millions)*

| Contractual Obligations: | Total | Within 12 Months |
| --- | ---: | ---: |
| Long-term debt obligations (1) | $12,209.4 | $— |
| 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 |

(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.

(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 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.

## Market risk

As filed, 12,124 characters.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our risk management counterparties and customers.

### Risk Management

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. All of our commodity derivatives are with major financial institutions or major energy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil, NGL and natural gas prices are volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2027. Market conditions may also impact our ability to enter into future commodity derivative contracts.

### Commodity Price Risk

A portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of commodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2023, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. We also enter into commodity financial instruments to help manage other short term commodity related business risks of our ongoing operations and in conjunction with marketing opportunities available to us in the operations of our logistics and transportation assets. With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair values of our natural gas and NGL hedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

A majority of these commodity price hedges are documented pursuant to a ISDA with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. While we have no current obligation to post cash, letters of credit or other additional collateral to secure these hedges so long as we maintain our current credit rating, we could be obligated to post collateral to secure the hedges in the event of an adverse change in our creditworthiness where a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).

To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivative instruments are also influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.

The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of December 31, 2023:

*(In millions)*

|  | Fair Value | Result of 10% Price Decrease | Result of 10% Price Increase |
| --- | ---: | ---: | ---: |
| Natural gas | $12.9 | $43.2 | $(17.3) |
| NGLs | 59.0 | 124.4 | (6.2) |
| Crude oil | 2.5 | 24.4 | (19.3) |
| Total | $74.4 | $192.0 | $(42.8) |

The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk, which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.

During the years ended December 31, 2023 and 2022, our operating revenues increased (decreased) by $441.1 million and $(754.7) million as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved from a net liability position of $255.8 million at December 31, 2022 to a net asset position of $74.4 million at December 31, 2023. Forward commodity prices have decreased relative to the fixed prices on our derivative contracts, creating the net asset position.

### Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, and the Term Loan Facility. As of December 31, 2023, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRGP Revolver, the Commercial Paper Program, the Securitization Facility and the Term Loan Facility will also increase. As of December 31, 2023, we had $1.3 billion in outstanding variable rate borrowings. A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $12.5 million based on our December 31, 2023 debt balances.

### Counterparty Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the ISDAs with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by $32.2 million as of December 31, 2023. The range of losses attributable to our individual counterparties as of December 31, 2023 would be between $0.2 million and $21.6 million, depending on the counterparty in default.

### Customer Credit Risk

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.

We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. Our allowance for credit losses was $2.5 million and $2.2 million as of December 31, 2023 and December 31, 2022, respectively.

No customer comprised 10% or greater of our consolidated revenues during the years ended December 31, 2023 and 2022, respectively.

## Controls and procedures

As filed, 1,744 characters.

### Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Annual Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2023, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

### Internal Control Over Financial Reporting

### (a) Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included on page F-2 of this Annual Report and is incorporated herein by reference. Management concluded that our internal control over financial reporting was effective as of December 31, 2023.

### (b) Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2023, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Filed Feb 15, 2024.
Source: SEC EDGAR, the filing index for accession 0000950170-24-015841. Last ingested by Listed: Oct 24, 2026, 15:12 ET. No prices; not investment advice.