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What changed in Targa Resources's 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of Targa Resources's 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+501 added−513 removedSource: 10-K (2024-02-15) vs 10-K (2023-02-22)

Top changes in Targa Resources's 2023 10-K

501 paragraphs added · 513 removed · 402 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

181 edited+60 added−44 removed226 unchanged
Biggest changeCONSOLIDATED STATEMENTS OF CHANGES IN OWN ERS' EQUITY AND SERIES A PREFERRED STOCK Retained Accumulated Additional Earnings Other Treasury Total Series A Common Stock Paid in (Accumulated Comprehensive Shares Noncontrolling Owner's Preferred Shares Amount Capital Deficit) Income (Loss) Shares Amount Interests Equity Stock (In millions, except shares in thousands) Balance, December 31, 2019 232,844 $ 0.2 $ 5,221.2 $ ( 339.6 ) $ 92.5 1,010 $ ( 53.5 ) $ 3,522.1 $ 8,442.9 $ 278.8 Compensation on equity grants — — 66.2 — — — — — 66.2 — Distribution equivalent rights — — ( 5.4 ) — — — — — ( 5.4 ) — Shares issued under compensation program 939 — — — — — — — — — Shares tendered for tax withholding obligations ( 235 ) — — — — 235 ( 5.9 ) — ( 5.9 ) — Repurchases of common stock ( 5,486 ) — — — — 5,486 ( 91.5 ) ( 91.5 ) Series A Preferred Stock dividends Dividends - $ 95.00 per share — — — ( 91.7 ) — — — — ( 91.7 ) — Dividends in excess of retained earnings — — ( 91.7 ) 91.7 — — — — — — Deemed dividends - accretion of beneficial conversion feature / partial repurchase of Series A Preferred Stock — — ( 39.2 ) — — — — — ( 39.2 ) 37.6 Common stock dividends Dividends - $ 1.21 per share — — — ( 282.0 ) — — — — ( 282.0 ) — Dividends in excess of retained earnings — — ( 282.0 ) 282.0 — — — — — — Partial repurchase of Series A Preferred Stock — — ( 29.2 ) — — — — — ( 29.2 ) ( 15.0 ) Distributions to noncontrolling interests — — — — — — — ( 570.7 ) ( 570.7 ) — Contributions from noncontrolling interests — — — — — — — 41.5 41.5 — Non-cash allocation to noncontrolling interests — — — — — — — 27.5 27.5 — Other comprehensive income (loss) — — — — ( 234.3 ) — — — ( 234.3 ) — Net income (loss) — — — ( 1,553.9 ) — — — 228.9 ( 1,325.0 ) — 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 — Distribution 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 See notes to consolidated financial statements.
Biggest changeCONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY AND SERIES A PREFERRED STOCK Retained Accumulated Additional Earnings Other Treasury Total Series A Common Stock Paid in (Accumulated Comprehensive Shares Noncontrolling Owners’ Preferred Shares Amount Capital Deficit) Income (Loss) Shares Amount Interests Equity Stock (In millions, except shares in thousands) 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.
Sale of Targa GCX Pipeline LLC 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”).
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”).
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.
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.
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.
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.
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 preferred shareholders.
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.
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 contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets.
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.
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 for 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.
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 Partnership may redeem the senior unsecured notes, in whole or in part, at any time prior to their 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 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.
(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.
(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.
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.
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.
F- 28 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 .
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 .
F- 40 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.
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.
F- 14 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.
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.
Restricted Stock Units Awards – Restricted Stock Units (“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 .
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.
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 includes trade receivables of $ 211.0 million.
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 TRGP Revolver restricts the Company’s ability to make dividends to stockholders if a default or an event of default (as defined in the TRGP Revolver) exists or would result from such distribution.
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.
F- 35 Note 12 — C ommon 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”).
Note 12 — C ommon 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”).
We accounted for the purchase as an asset acquisition and have capitalized $ 1.8 million of acquisition-related costs and assumed liabilities of $ 1.8 million as components of the cost of assets acquired.
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.
Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $ 129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages.
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.
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 .
F- 33 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 Delaware Basin Acquisition assets increase 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 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 gross amount due under contract was $ 213.4 million, of which $ 2.4 million was expected to be uncollectible. Trade receivables, net of allowances, excludes $ 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 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.
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.
Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. F- 16 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.
F- 43 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.
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.
F- 48 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.
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.
F- 11 TARGA RESOURCES CORP. 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 — Organizati on and Operations Our Organization Targa Resources Corp.
F- 10 TARGA RESOURCES CORP. 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 — Organizati on and Operations Our Organization Targa Resources Corp.
Quantitative and Qualitative Disclosures About Market Risk, Note 15 – Fair Value Measurements and Note 24 – 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”).
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”).
Based on our interpretation of the IRA, the CAMT and related guidance and a number of 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.
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.
For the PSUs granted in 2020, 2021 and 2022, 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.
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.
Note 2 — Basis of Presentation These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2022 and 2021, and the results of operations, comprehensive income (loss), cash flows, and changes in owners’ equity for the years ended December 31, 2022, 2021 and 2020 .
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 .
As of December 31, 2022, 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”).
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”).
We received a final net working capital adjustment payment of approximately $ 11.4 million in the fourth F- 20 quarter of 2022. We funded the acquisition with (i) $ 1.5 billion in proceeds drawn under our Term Loan Agreement with Mizuho Bank, Ltd.
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.
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.
We recorded $ 16.9 million F- 19 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.
Note 6 – Goodwill As of December 31, 2022, 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.
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.
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. F- 46 Restricted Stock Awards - Restricted stock entitles the recipient to cash dividends.
F- 44 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.
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 F- 30 conditions.
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.
During 2020, 2021 and 2022 , 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, 2022.
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.
Note 4 – Acquisitions and Divestitures Acquisitions DevCo Joint Ventures 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”).
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”).
F- 21 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.
F- 20 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.
For the year ended December 31, 2022, we repurchased 3,412,354 shares of our common stock at a weighted average price of $ 65.87 for a total net cost of $ 224.8 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.
F- 33 Note 10 – L eases We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, storage and terminal assets. We have finance leases primarily associated with our substations, compressors, tractors and vehicles.
Note 10 – L eases 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.
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, 2022 2021 2020 Unvested restricted stock awards — 3.3 2.3 Series A Preferred (1) 14.9 44.3 46.4 (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 .
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 January 2023, we reached an agreement with our partners to reactivate GCF. The facility is expected to be operational during the first 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.
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.
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.
F- 14 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.
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”).
F- 21 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”).
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’s Notes are payable semi-annually.
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.
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.
F- 13 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.
December 31, 2022 December 31, 2021 Permian Midland $ 23.2 $ 23.2 Permian Delaware 22.0 22.0 Goodwill $ 45.2 $ 45.2 The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural gas and NGL prices.
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.
These notes are effectively subordinated to all secured indebtedness under the TRGP Revolver and 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.
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.
F- 17 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.
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.
Our obligations under the Term Loan Facility are guaranteed by substantially all material wholly-owned domestic restricted subsidiaries of the Company, including the Partnership.
F- 27 Our obligations under the Term Loan Facility are guaranteed by substantially all material wholly-owned domestic restricted subsidiaries of the Company, including the Partnership.
Common Share Repurchase Program In October 2020, our board of directors approved a share repurchase program (the "Share Repurchase Program") for the repurchase of up to $ 500.0 million of our outstanding common stock.
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.
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 Agreement between the Partnership and us, as general partner of the Partnership, governs the reimbursement of costs incurred on behalf of the Partnership. F- 40 The employees supporting the Partnership’s operations are our employees.
For our 2022, 2021 and 2020 annual evaluations, F- 24 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.
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.
Total expenses incurred under the above non-cancelable commitments were: 2022 2021 2020 Land sites and rights of way $ 5.8 $ 5.9 $ 6.5 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.
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.
F- 15 As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary.
As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary.
Our leases have remaining lease terms of 1 to 10 years, some of which include options to extend the lease term for up to 20 years.
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.
For additional information on our revenue recognition policy, see Note 3 – Significant Accounting Policies, and for disclosures related to disaggregated revenue, see Note 24 – Segment Information.
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.
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, 2022: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRGP Revolver and Commercial Paper Program 1.5 % - 5.9 % 3.6 % Securitization Facility 1.1 % - 5.2 % 3.0 % Term Loan Facility 4.1 % - 5.8 % 4.6 % Compliance with Debt Covenants As of December 31, 2022, we were in compliance with the covenants contained in our various debt agreements.
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.
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.
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.
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
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.
Not e 16 — Related Party Transactions Transactions with Unconsolidated Affiliates The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures (1) Cayenne GCX (2) Little Missouri 4 Total 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 ) 2020: Revenues $ 0.4 $ 4.5 $ — $ 0.2 $ 12.6 $ 17.7 Product purchases and fuel — — ( 5.9 ) ( 67.2 ) — ( 73.1 ) Operating expenses ( 16.0 ) ( 1.2 ) ( 0.2 ) — ( 2.2 ) ( 19.6 ) 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.
Not e 16 — Related Party Transactions Transactions with Unconsolidated Affiliates The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures (1) Cayenne GCX (2) Little Missouri 4 Total 2023: 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.
We estimate the allowance for doubtful accounts 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.
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. F- 12 We continuously evaluate our ability to collect amounts owed to us.
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 South Texas Acquisition and 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.
The 4.000 % Senior Notes due 2032 have substantially similar terms and covenants as our other series of Senior Notes.
The 4.000 % Senior Notes due 2032 have substantially similar terms and covenants as the Partnership’s other series of senior notes.
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, (v) estimating contingencies, guarantees and indemnifications and (vi) estimating redemption value of mandatorily redeemable preferred interests.
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.
For the 2021 and 2020 impairment assessments 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.
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 Partnership may also redeem up to 35 % of the aggregate principal amount of each series of notes at the redemption dates and prices set forth in the indentures 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 of the notes (excluding notes held by us) 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.
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.
Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets We report 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.
F- 39 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.
F- 29 Partnership’s Senior Unsecured Notes All issues of the Partnership's senior unsecured notes are pari passu with existing and future senior indebtedness. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by the Partnership and the Partnership’s restricted subsidiaries.
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.
The Partnership’s senior unsecured notes and associated indenture agreements restrict (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.
F- 28 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.
As of December 31, 2022, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $ 266.7 million. We have not been required to post any collateral related to these positions due to our credit rating.
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.
Our derivative instruments other than our futures contracts are executed under International Swaps and Derivatives Association (“ISDA”) agreements, which govern the key terms with our counterparties. Our ISDA agreements contain credit-risk related contingent features. Following the release of the collateral securing our TRGP Revolver, our derivative positions are no longer secured.
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 F- 37 related contingent features. Following the release of the collateral securing our TRGP Revolver, our derivative positions are no longer secured.
The components of lease expense were as follows: Year Ended December 31, 2022 2021 2020 Lease cost Operating lease cost $ 17.7 $ 12.2 $ 11.6 Short-term lease cost 35.0 20.4 20.7 Variable lease cost 17.9 5.7 5.5 Finance lease cost Amortization of right-of-use assets 20.3 13.3 13.6 Interest expense 3.5 1.1 1.4 Total lease cost $ 94.4 $ 52.7 $ 52.8 Other supplemental information related to our leases are as follows: Year Ended December 31, 2022 2021 2020 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 18.8 $ 14.1 $ 12.3 Operating cash flows for finance leases 2.7 1.0 1.4 Financing cash flows for finance leases 19.7 12.5 12.4 The weighted-average remaining lease terms for operating leases and finance leases are 5 years and 7 years , respectively.
The components of lease expense were as follows: Year Ended December 31, 2023 2022 2021 Lease cost 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: Year Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of lease liabilities 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 associated assets are generally connected to and supplied in part by our Gathering and Processing segment, and 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.
The associated F- 46 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.
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 consolidated the Partnership and its subsidiaries under GAAP, and prepared accompanying consolidated financial statements under the rules and regulations of the SEC.
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.
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. F- 13 Allowance for Doubtful Accounts Estimated losses on accounts receivable are provided through an allowance for doubtful accounts.
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. Allowanc e for Credit Losses Estimated losses on accounts receivable are provided through an allowance for credit losses.
The fair value of these swaps is determined using a discounted cash flow valuation technique, for which the primary input to the valuation model is the forward commodity basis curve, and is based on observable or public data sources and extrapolated when observable prices are not available.
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.
Note 22 - S upplemental Cash Flow Information Year Ended December 31, 2022 2021 2020 Cash: Interest paid, net of capitalized interest (1) $ 401.3 $ 356.0 $ 374.1 Income taxes (received) paid, net 1.6 1.3 43.7 Non-cash investing activities: Change in deadstock commodity inventory $ ( 3.8 ) $ ( 15.0 ) $ 5.3 Impact of capital expenditure accruals on property, plant and equipment, net 60.1 53.0 ( 226.9 ) Transfers from materials and supplies inventory to property, plant and equipment — 2.4 2.1 Change in ARO liability and property, plant and equipment due to revised cash flow estimate and additions 0.8 ( 0.2 ) ( 1.8 ) Non-cash financing activities: Non-cash distributions to noncontrolling interests (2) $ 64.2 $ — $ — Changes in accrued distributions to noncontrolling interests ( 26.1 ) ( 50.9 ) ( 5.2 ) Reduction of owner's equity related to accrued dividends on unvested equity awards under share compensation arrangements 7.1 3.1 5.4 Accretion of deemed dividends on Series A Preferred — — 37.6 Lease liabilities arising from recognition of right-of-use assets: Operating lease $ 9.7 $ 20.1 $ 13.2 Finance lease (3) 220.7 24.7 6.0 (1) Interest capitalized on major projects was $ 16.3 million, $ 4.1 million and $ 33.0 million for the years ended December 31, 2022, 2021 and 2020 .
Note 21 - S upplemental Cash Flow Information Year Ended December 31, 2023 2022 2021 Cash: 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 .
See Note 24 – Segment Information for certain financial information regarding our business segments.
See Note 23 – Segment Information for certain financial information regarding our business segments.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeRisks Related to Regulatory Matters • Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide. • Increasing stakeholder and market attention to ESG matters 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. • Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more rigorous enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation. • Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. • We are or may become subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing of personal information. 28 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.
Biggest changeRisks 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. 27 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.
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, 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.
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; 36 • 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.
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; 35 • 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.
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.
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) 31 contact the Texas Railroad Commission if a facility sustains a weather-related forced stoppage during a weather emergency.
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. • Climatic 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.
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.
With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, Targa Midland Gas Pipeline LLC, Midland-Permian Pipeline LLC, Targa SouthTex Mustang Transmission Ltd., and Targa SouthTex Transmission LP, 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.
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.
In addition, the federal Occupational Safety and Health Administration’s (“OSHA”) hazard communication standard, the EPA 47 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.
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.
The impacts of these actions, orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, 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.
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.
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.
Certain environmental laws impose strict, joint and several liability for 47 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.
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 ESG 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.
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.
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, 48 and as a result of historical industry operations and waste disposal practices.
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.
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 ESG practices, our Board of Directors has established a Sustainability Committee.
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 ESG 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 ESG matters to our Board of Directors.
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.
Inspectors from the Critical Infrastructure Division of the Texas Railroad Commission began inspections on December 1, 2022. If, upon inspection, 32 we are required to further weatherize or update weatherization of certain facilities, we may incur significant costs to complete any additional weatherization.
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.
The methane emissions charge 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.
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.
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 29 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.
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 28 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.
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. 40 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.
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. 39 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.
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. 33 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.
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. 32 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.
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.
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 44 infrastructure or the permitting of liquefied natural gas export facilities.
These agreements 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.
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.
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 44 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.
Supreme Court has held that GHG emissions constitute 43 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.
The jurisdictions in which we operate (including the United States) may have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure, or loss of personal information.
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.
In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recent laws such as the IRA advance numerous climate-related objectives. However, because the U.S.
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.
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, Targa SouthTex Mustang Transmission Ltd., and Targa SouthTex Transmission LP, 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.
While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, TPL SouthTex Pipeline Company LLC, Targa Midland Gas Pipeline LLC, 49 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.
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. 41 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.
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. 40 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.
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. 42 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.
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. 41 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.
Litigation risks are also increasing, as a number of cities, local governments, and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
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.
Climatic 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 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.
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 ESG impact instead of actual changes in our ESG performance.
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.
Furthermore, public statements with respect to ESG 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 ESG benefits.
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.
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 2023 equals approximately $1.5 million per violation per day, as well as authority to order disgorgement of profits associated with any violation.
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.
Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-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 ESG efforts.
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.
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 climatic events.
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.
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 ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
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.
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 (“ISDA”) agreements contain credit-risk related contingent features.
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.
If we incur additional debt, this could increase the risks associated with compliance with our financial covenants. 43 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.
If we incur additional debt, this could increase the risks associated with compliance with our financial covenants. 42 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.
In the event that an ownership change were 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.
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.
A decline in the volumes on our systems could have a material adverse effect on our business, results of operations and financial condition. 31 We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.
A decline in the volumes on our systems could have a material adverse effect on our business, results of operations and financial condition. 30 We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.
Any unusual or prolonged severe climatic events or increased frequency thereof, such as freezing weather or rain, earthquakes, hurricanes, droughts, 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.
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.
The implementation of the final rule and the resultant 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.
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.
Unfavorable ESG 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.
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.
Quantitative and Qualitative Disclosures About Market Risk.” 39 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.
Quantitative and Qualitative Disclosures About Market Risk.” 38 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.
Also, certain institutional lenders may decide not to provide funding to us or our customers’ companies based on ESG concerns, which could adversely affect our financial condition and access to capital for potential growth projects.
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.
The ICA requires that we maintain tariffs on file with FERC for each of the Targa NGL, Targa Gulf Coast and Grand Prix Joint Venture common carrier pipelines that have not been granted a waiver. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services.
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.
We also published our 2021 Sustainability Report, which provides updates on our performance related to certain ESG topics and sets certain ESG goals, such as reductions in methane intensity in line with the ONE Future goals. While we may elect to seek out various additional voluntary ESG targets now or in the future, such targets are aspirational.
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.
Our operations are subject to many hazards inherent in purchasing, gathering, compressing, treating, processing and/or selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; and purchasing, gathering, storing and/or terminaling crude oil, including: • damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism; • inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment; • damage that is the result of our negligence or any of our employees’ negligence; • leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; • spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural resources; and • other hazards that could also result in personal injury, loss of life, pollution and/or suspension of operations.
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.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs.
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.
Climatic 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.
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.
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. 49 Targa NGL, Targa Gulf Coast, and Grand Prix Joint Venture have pipelines that are considered common carrier pipelines subject to regulation by FERC under the ICA.
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.
Moreover, ESG-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.
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.
Finally, 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 climatic events, as well as chronic shifts in temperature and precipitation patterns.
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 45 shifts in temperature and precipitation patterns.
District Court issued a permanent injunction that blocked President Biden’s order suspending new leases. Litigation concerning this issue remains pending. Notwithstanding these recent legal developments, further restrictions may be adopted by the Biden Administration that could restrict hydraulic fracturing activities on federal lands and waters.
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.
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. • 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. • 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.
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.
Department of the Treasury and the Internal Revenue Service 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.
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.
Moreover, despite our governance oversight in place, we may not be able to adequately identify ESG-related risks and opportunities and, further, may not be able to meet ESG targets 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, 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.
Potential climatic changes may have significant physical effects, such as increased frequency and severity of storms, floods and wintry conditions and could have an adverse effect on our 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, and third party insurance providers that make insuring products available to defray our costs or offset any damages and losses we incur.
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.
If we are unable to develop accretive growth projects or make accretive acquisitions because we are unable to (1) develop growth projects economically or identify attractive acquisition candidates and negotiate acceptable acquisition agreements or, (2) obtain financing for these projects or acquisitions on economically acceptable terms, or (3) compete successfully for growth projects or acquisitions, then our future growth and ability to return increasing capital to our shareholders may be limited.
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.
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 2023 was up to approximately $15,662 per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability.
In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA 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.
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, including the Delaware Basin Acquisition and South Texas Acquisition, with our operations.
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.
For the years ended December 31, 2022, 2021 and 2020, our consolidated interest expense, net was $446.1 million, $387.9 million and $391.3 million. 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.
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.
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.
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.
Following the release of the collateral securing our TRGP Revolver as a result of our credit rating, our derivative positions are no longer secured. As of December 31, 2022, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $266.7 million.
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.
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.
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.
We additionally had $1.4 billion of additional borrowing capacity available under the TRGP Revolver after accounting for $33.2 million of letters of credit, under which borrowing is exposed to such increases in variable interest rates.
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.
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, 2022, we would be required to post $31.4 million of collateral to certain counterparties per the terms of our ISDAs.
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.
We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues, would negatively impact our business, financial condition and results of operations.
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.
The US also announced, in conjunction with the European Union 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.
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.
A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $36.0 million based on our December 31, 2022 debt balances.
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.
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.
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.
Increasing attention to climate change, increasing societal expectations on companies to address climate change, 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 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.
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 is not expected until 2023.
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.
Relatedly, at COP26, the United States and European Union 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.
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.
The new rules became effective in December 2020 but have a general compliance date of January 1, 2022 for covered future positions and 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 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.
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 and certain of our joint venture partners may fail or refuse to fund their respective portions of capital projects that we believe are necessary to expand or maintain such joint venture’s business. 27 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, 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. 26 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.
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 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.
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.
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.
Any such transaction could result in our partnering with different or additional parties. 36 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.
Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, and/or mandated changes in our business practices. 51 Item 1B. Unresolve d Staff Comments. None.
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. 50 Item 1B. Unresolve d Staff Comments. None.
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, 2022, we have U.S. federal NOL carryforwards of $6.8 billion, some of which expire between 2036 to 2037 while others have no expiration date.
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.
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, 2022, we had 226,042,229 outstanding shares of common stock.
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.
While we cannot predict what policies may result from these developments, 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.
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.

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Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeWe have filed a petition for review with the Supreme Court of Texas, and the appeal remains pending. The cumulative amount of interest on the award through December 31, 2022, if accrued, would have been approximately $42.6 million.
Biggest changeWe 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.
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.
Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit. 52 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.
Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages.
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.
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. Item 4. Mine Saf ety Disclosures. Not applicable. 52 PART II
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. Item 4. Mine Saf ety Disclosures. Not applicable. 53 PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest change(2) In the fourth quarter 2020, our board of directors approved a share repurchase program for the repurchase of up to $500 million of our outstanding common stock. We may discontinue this share repurchase program at any time and are not obligated to repurchase any specific dollar amount or number of shares. Item 6. Reserved. 54
Biggest changeDuring the second quarter of 2023, we exhausted the 2020 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. Item 6. Reserved. 55
Item 5. Market for Registrant’s Common Equity, Related Stoc kholder Matters and Issuer Purchases of Equity Securities. Market Information Our common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, 2022, there were 182 stockholders of record of our common stock.
Item 5. Market for Registrant’s Common Equity, Related Stoc kholder Matters and Issuer Purchases of Equity Securities. Market Information Our common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, 2023, there were 170 stockholders of record of our common stock.
Recent Sales of Unregistered Equity Securities There were no sales of unregistered equity securities for the year ended December 31, 2022.
Recent Sales of Unregistered Equity Securities There were no sales of unregistered equity securities for the year ended December 31, 2023.
The graph below compares the cumulative total return to holders of Targa Resources Corp.’s common stock, the NYSE Index, the S&P 500 Index and the Alerian US Midstream Energy Index (the “AMUS Index”) during the period beginning on December 31, 2017 and ending on December 31, 2022.
Stock Performance Graph The graph below compares the cumulative total return to holders of Targa Resources Corp.’s common stock, the Standard & Poor's 500 Stock Index (the “S&P 500 Index”) and the Alerian US Midstream Energy Index (the “AMUS Index”) during the period beginning on December 31, 2018 and ending on December 31, 2023.
This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater than the number of holders of record. As of February 17, 2023, there were 226,639,398 shares of common stock outstanding.
This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater than the number of holders of record. As of February 9, 2024, there were 223,155,363 shares of common stock outstanding.
Repurchase of Equity by Targa Resources Corp, or Affiliated Purchasers Period Total number of shares purchased (1) Average price per share Total number of shares purchased as part of publicly announced plans (2) Maximum approximate dollar value of shares that may yet be purchased under the plan (in thousands) (2) October 1, 2022 - October 31, 2022 135,863 $ 62.51 61,845 $ 167,765 November 1, 2022 - November 30, 2022 165,697 $ 72.53 165,442 $ 155,763 December 1, 2022 - December 31, 2022 168,511 $ 71.22 168,511 $ 173,762 _________________________________ (1) Includes 395,798 shares purchased under our $500 million common share repurchase program, as well as 74,273 shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictions on restricted stock.
Repurchase of Equity by Targa Resources Corp, or Affiliated Purchasers Period Total number of shares purchased (1) Average price per share Total number of shares purchased as part of publicly announced plans (2) Maximum approximate dollar value of shares that may yet be purchased under the plan (in thousands) (2) October 1, 2023 - October 31, 2023 109,772 $ 81.82 108,550 $ 801,820 November 1, 2023 - November 30, 2023 92,066 $ 87.74 91,165 $ 793,820 December 1, 2023 - December 31, 2023 275,325 $ 86.23 275,325 $ 770,080 _________________________________ (1) Includes 475,040 shares purchased under our 2023 Share Repurchase Program, as well as 2,123 shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictions on restricted stock.
The stock price performance included in this graph is historical and not necessarily indicative of future stock price performance. 53 Year Ended December 31, 2017 2018 2019 2020 2021 2022 Targa Resources Corp. $ 100.00 $ 80.09 $ 99.46 $ 66.93 $ 133.87 $ 192.20 NYSE Index $ 100.00 $ 91.05 $ 114.28 $ 122.26 $ 147.54 $ 133.75 S&P 500 Index $ 100.00 $ 95.62 $ 125.72 $ 148.85 $ 191.58 $ 156.88 AMUS Index $ 100.00 $ 89.09 $ 102.95 $ 77.26 $ 112.04 $ 145.15 Pursuant to Instruction 7 to Item 201(e) of Regulation S-K, the above stock performance graph and related information is being furnished and is not being filed with the SEC, and as such shall not be deemed to be incorporated by reference into any filing that incorporates this Annual Report by reference.
The stock price performance included in this graph is historical and not necessarily indicative of future stock price performance. 54 Year Ended December 31, 2018 2019 2020 2021 2022 2023 Targa Resources Corp. $ 100.00 $ 124.19 $ 83.58 $ 167.16 $ 240.00 $ 290.34 S&P 500 Index $ 100.00 $ 131.49 $ 155.68 $ 200.37 $ 164.08 $ 207.21 AMUS Index $ 100.00 $ 115.56 $ 86.72 $ 125.75 $ 162.92 $ 194.13 Pursuant to Instruction 7 to Item 201(e) of Regulation S-K, the above stock performance graph and related information is being furnished and is not being filed with the SEC, and as such shall not be deemed to be incorporated by reference into any filing that incorporates this Annual Report by reference.
Removed
Stock Performance Graph On October 12, 2022, we were added to the Standard & Poor's 500 Stock Index (the "S&P 500 Index"). We replaced the NYSE Composite Index (the “NYSE Index”) with the S&P 500 Index, as we believe this index is a more relevant benchmark to measure the Company's performance.
Added
(2) In the fourth quarter 2020, our board of directors approved a share repurchase program for the repurchase of up to $500 million of our outstanding common stock. In May 2023, our Board of Directors approved the 2023 Share Repurchase Program for the repurchase of up to $1.0 billion of our outstanding common stock.
Removed
We have continued to present the NYSE Index in this Annual Report for 2022 as a transitional measure.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

67 edited+3 added−26 removed100 unchanged
Biggest changeSummarized Combined Balance Sheet and Statement of Operations information for the Obligated Group follows: Summarized Combined Balance Sheet Information December 31, 2022 (In millions) ASSETS Current assets $ 1,386.9 Current assets - affiliates 6.0 Long-term assets 10,163.5 Long-term assets - affiliates 10.5 Total assets $ 11,566.9 LIABILITIES AND OWNERS' EQUITY Current liabilities $ 1,779.3 Current liabilities - affiliates 64.2 Long-term liabilities 11,315.6 Targa Resources Corp. stockholders' equity (1,592.2 ) Total liabilities and owners' equity $ 11,566.9 Summarized Combined Statement of Operations Information Year Ended December 31, 2022 (In millions) Revenues $ 21,264.0 Operating income (loss) 205.3 Net income (loss) 101.6 Dividends on Series A Preferred 30.0 68 Common Stock Dividends The following table details the dividends declared and/or paid by us to common shareholders for 2022: Three Months Ended Date Paid or To Be Paid Total Common Dividends Declared Amount of Common Dividends Paid or To Be Paid Accrued Dividends (1) Dividends Declared per Share of Common Stock (In millions, except per share amounts) December 31, 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 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
Biggest changeSignificant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information. 68 Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group as of the end of the most recent period presented follows: Summarized Combined Balance Sheet Information December 31, 2023 December 31, 2022 (In millions) ASSETS Current assets $ 966.3 $ 1,425.4 Current assets - affiliates 11.2 6.0 Long-term assets 15,267.6 14,398.8 Long-term assets - affiliates — 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: Three Months Ended Date Paid or To Be Paid Total Common Dividends Declared Amount of Common Dividends Paid or To Be Paid Dividends on Share-Based Awards Dividends Declared per Share of Common Stock (In millions, except per share amounts) December 31, 2023 February 15, 2024 $ 112.8 $ 111.6 $ 1.2 $ 0.50000 September 30, 2023 November 15, 2023 113.0 111.5 1.5 0.50000 June 30, 2023 August 15, 2023 113.6 111.8 1.8 0.50000 March 31, 2023 May 15, 2023 114.7 113.0 1.7 0.50000 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.
(3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes. (4) Permian Midland includes operations in WestTX, of which we own 72.8% undivided interest, and other plants that are owned 100% by us.
(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.
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.
In an effort to reduce the volatility of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated 71 with a portion of our expected natural gas, NGL, and condensate equity volumes, future commodity purchases and sales, and transportation basis risk.
These expenses remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period. Capital Expenditures Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures.
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.
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 65 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.
The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels, which we closely manage, and valuation; (iii) changes in payables and accruals 66 related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.
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. 59 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.
Distributable cash flow and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements. 60 Our Non-GAAP Financial Measures The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated.
We have entered into derivative instruments to hedge the commodity price associated with a portion of 64 our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment.
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.
Risk Factors.” Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 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, 2021.
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.
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 ESG matters may impact our business” under Item 1A. of this Annual Report.
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.
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. 58 Adjusted Operating Margin We define adjusted operating margin for our segments as revenues less product purchases and fuel.
Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes. 59 Adjusted Operating Margin We define adjusted operating margin for our segments as revenues less product purchases and fuel.
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 transportation and fractionation volumes, partially offset by lower export fees.
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.
Contracts that will be settled at future spot prices are valued using prices as of December 31, 2022. (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.
Contracts that will be settled at future spot prices are valued using prices as of December 31, 2023. 70 (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.
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 during 2022. See Note 11 – Preferred Stock for further discussion.
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.
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, 2022, we did not have any interest rate hedges.
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.
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 potential for variable rate borrowing under the Commercial Paper Program.
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.
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, 2022 rates for floating debt. See Note 8 - Debt Obligations for more information. (3) Includes minimum payments on operating lease obligations for office space and railcars.
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.
(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: 2022: 43% ethane, 32% propane, 12% normal butane, 4% isobutane and 9% natural gasoline 2021: 45% ethane, 31% propane, 11% 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. 55 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.
(2) “Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following composition for the periods noted: 2023: 44% ethane, 32% propane, 11% normal butane, 4% isobutane and 9% natural gasoline 2022: 43% ethane, 32% propane, 12% normal butane, 4% isobutane and 9% natural gasoline (3) Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX. 56 Volumes and Demand for our Services Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves.
The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and an indirect wholly-owned subsidiary of ours. 56 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.
The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and a wholly-owned subsidiary of ours. 57 Volatile Capital Markets and Competition We continuously consider and enter into discussions regarding potential growth projects and acquisitions and may contemplate external funding for potential growth projects and acquisitions.
Compliance with Debt Covenants As of December 31, 2022, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
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.
(8) Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes.
(8) Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to our equity volumes.
Cash Flow Analysis Cash Flows from Operating Activities Year Ended December 31, 2022 2021 2022 vs. 2021 (In millions) $ 2,380.8 $ 2,302.9 $ 77.9 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.
Cash Flow Analysis Cash Flows from Operating Activities Year Ended December 31, 2023 2022 2023 vs. 2022 (In millions) $ 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.
As of December 31, 2022, we had $33.2 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.
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.
(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. 2022 Compared to 2021 The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing margin, partially offset by lower LPG export 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.
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, 2022, inclusive of our consolidated joint venture accounts, we had $219.0 million of Cash and cash equivalents on our Consolidated Balance Sheets.
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.
(2) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $168.1 million and $131.7 million for the years ended December 31, 2022 and 2021. The increase in total growth capital expenditures was primarily due to system expansions in the Permian in response to forecasted production growth and higher activity levels, and expansions in our downstream business.
(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.
Other Year Ended December 31, 2022 2021 2022 vs. 2021 (In millions) Operating margin $ (302.4 ) $ (115.9 ) $ (186.5 ) Adjusted operating margin $ (302.4 ) $ (115.9 ) $ (186.5 ) 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.
Other Year Ended December 31, 2023 2022 2023 vs. 2022 (In millions) Operating margin $ 275.5 $ (302.4 ) $ 577.9 Adjusted operating margin $ 275.5 $ (302.4 ) $ 577.9 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.
These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment). 57 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.
These include: (i) throughput volumes, facility efficiencies and fuel consumption, (ii) operating expenses, (iii) capital expenditures and (iv) the following non-GAAP measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment). 58 Throughput Volumes, Facility Efficiencies and Fuel Consumption Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems.
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.
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.
Future growth capital expenditures may vary based on 69 investment opportunities. We expect that 2023 maintenance capital expenditures, net of noncontrolling interests, will be approximately $175 million. Off-Balance Sheet Arrangements As of December 31, 2022, there were $243.2 million in surety bonds outstanding related to various performance obligations.
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.
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 and the Partnership Issuers’ senior notes, the payment of the notes under the Commercial Paper Program and our obligations under the Term Loan Facility, subject to certain limited exceptions.
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.
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 fractionator in Mont Belvieu, we currently estimate that in 2023 we will invest between $1.8 to $1.9 billion in net growth capital expenditures for announced projects.
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.
The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator. 63 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: Year Ended December 31, 2022 Year Ended December 31, 2021 (In millions, except volumetric data and price amounts) Volume Settled Price Spread (1) Gain (Loss) Volume Settled Price Spread (1) Gain (Loss) Natural gas (BBtu) 74.8 $ (2.13 ) $ (159.2 ) 76.8 $ (1.41 ) $ (108.0 ) NGL (MMgal) 717.6 (0.30 ) (213.0 ) 581.5 (0.26 ) (153.1 ) Crude oil (MBbl) 2.2 (31.73 ) (69.8 ) 2.1 (14.33 ) (30.1 ) $ (442.0 ) $ (291.2 ) (1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. 2022 Compared to 2021 The increase in adjusted operating margin was due to higher realized commodity prices, higher natural gas inlet volumes, and higher fees resulting in increased margin predominantly in the Permian.
The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees. 64 The following table presents the realized commodity hedge gain (loss) attributable to our equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment: Year Ended December 31, 2023 Year Ended December 31, 2022 (In millions, except volumetric data and price amounts) Volume Settled Price Spread (1) Gain (Loss) Volume Settled Price Spread (1) Gain (Loss) Natural gas (BBtu) 63.2 $ 1.22 $ 77.4 74.8 $ (2.13 ) $ (159.2 ) NGL (MMgal) 680.3 0.07 49.9 717.6 (0.30 ) (213.0 ) Crude oil (MBbl) 2.4 (6.92 ) (16.6 ) 2.2 (31.73 ) (69.8 ) $ 110.7 $ (442.0 ) (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, higher producer activity and the addition of the Legacy and Red Hills VI plants during the third quarter of 2022.
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.
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. A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements.
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.
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: Natural Gas $/MMBtu (1) Illustrative Targa NGL $/gal (2) Crude Oil $/Bbl (3) 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 2021 4th Quarter $ 5.84 $ 0.94 $ 77.17 3rd Quarter 4.01 0.86 70.55 2nd Quarter 2.83 0.66 66.06 1st Quarter 2.70 0.65 57.80 2021 Average 3.85 0.78 67.90 (1) Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.
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: Natural Gas $/MMBtu (1) Illustrative Targa NGL $/gal (2) Crude Oil $/Bbl (3) 2023 4th Quarter $ 2.88 $ 0.60 $ 78.33 3rd Quarter 2.54 0.62 82.18 2nd Quarter 2.09 0.56 73.75 1st Quarter 3.45 0.70 76.11 2023 Average 2.74 0.62 77.59 2022 4th Quarter $ 6.27 $ 0.72 $ 82.63 3rd Quarter 8.19 0.94 91.64 2nd Quarter 7.17 1.09 108.42 1st Quarter 4.92 1.04 94.38 2022 Average 6.64 0.95 94.27 (1) Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.
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, the Securitization Facility, proceeds from debt and equity offerings, and joint ventures and/or asset sales.
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.
Year Ended December 31, 2022 2021 (In millions) Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow Net income (loss) attributable to Targa Resources Corp. $ 1,195.5 $ 71.2 Interest (income) expense, net 446.1 387.9 Income tax expense (benefit) 131.8 14.8 Depreciation and amortization expense 1,096.0 870.6 Impairment of long-lived assets — 452.3 (Gain) loss on sale or disposition of assets (9.6 ) 2.0 Write-down of assets 9.8 10.3 (Gain) loss from financing activities (1) 49.6 16.6 (Gain) loss from sale of equity method investment (435.9 ) — Transaction costs related to business acquisition (2) 23.9 — Equity (earnings) loss (9.1 ) 23.9 Distributions from unconsolidated affiliates and preferred partner interests, net 27.2 116.5 Change in contingent considerations — 0.1 Compensation on equity grants 57.5 59.2 Risk management activities 302.5 116.0 Noncontrolling interests adjustments (3) 15.8 (89.4 ) Adjusted EBITDA $ 2,901.1 $ 2,052.0 Interest expense on debt obligations (4) (447.6 ) (376.2 ) Maintenance capital expenditures, net (5) (168.1 ) (131.7 ) Cash taxes (6.7 ) (2.7 ) Distributable Cash Flow $ 2,278.7 $ 1,541.4 Growth capital expenditures, net (5) (1,177.2 ) (407.7 ) Adjusted Free Cash Flow $ 1,101.5 $ 1,133.7 (1) Gains or losses on debt repurchases or early debt extinguishments.
Year Ended December 31, 2023 2022 (In millions) Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow Net income (loss) attributable to Targa Resources Corp. $ 1,345.9 $ 1,195.5 Interest (income) expense, net 687.8 446.1 Income tax expense (benefit) 363.2 131.8 Depreciation and amortization expense 1,329.6 1,096.0 (Gain) loss on sale or disposition of assets (5.3 ) (9.6 ) Write-down of assets 6.9 9.8 (Gain) loss from financing activities (1) 2.1 49.6 (Gain) loss from sale of equity method investment — (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.
The increase in product purchases and fuel reflects higher natural gas, NGL and condensate prices and higher NGL, natural gas and condensate volumes.
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.
Our short-term liquidity on a consolidated basis as of February 17, 2023, was: Consolidated Total (In millions) Cash on hand (1) $ 209.5 Total availability under the Securitization Facility 800.0 Total availability under the TRGP Revolver and Commercial Paper Program 2,750.0 3,759.5 Less: Outstanding borrowings under the Securitization Facility (800.0 ) Outstanding borrowings under the TRGP Revolver and Commercial Paper Program (432.5 ) Outstanding letters of credit under the TRGP Revolver (35.2 ) Total liquidity $ 2,491.8 (1) Includes cash held in our consolidated joint venture accounts.
Our short-term liquidity on a consolidated basis as of December 31, 2023, was: Consolidated Total (In millions) Cash on hand (1) $ 141.7 Total availability under the Securitization Facility 600.0 Total availability under the TRGP Revolver and Commercial Paper Program 2,750.0 3,491.7 Less: Outstanding borrowings under the Securitization Facility (575.0 ) Outstanding borrowings under the TRGP Revolver and Commercial Paper Program (175.0 ) Outstanding letters of credit under the TRGP Revolver (22.3 ) Total liquidity $ 2,719.4 (1) Includes cash held in our consolidated joint venture accounts.
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.
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.
The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and South Texas, the shortening of depreciable lives of certain assets that have been, or will be, idled and the impact of system expansions on our asset base, partially offset by a lower depreciable base associated with assets that were impaired during the fourth quarter of 2021.
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.
(5) Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates. 60 Consolidated Results of Operations The following table and discussion is a summary of our consolidated results of operations: Year Ended December 31, 2022 2021 2022 vs. 2021 (In millions) Revenues: Sales of commodities $ 19,066.0 $ 15,602.5 $ 3,463.5 22 % Fees from midstream services 1,863.8 1,347.3 516.5 38 % Total revenues 20,929.8 16,949.8 3,980.0 23 % Product purchases and fuel 16,882.1 13,729.5 3,152.6 23 % Operating expenses 912.8 747.0 165.8 22 % Depreciation and amortization expense 1,096.0 870.6 225.4 26 % General and administrative expense 309.7 273.2 36.5 13 % Impairment of long-lived assets — 452.3 (452.3 ) (100 %) Other operating (income) expense 0.2 12.4 (12.2 ) (98 %) Income (loss) from operations 1,729.0 864.8 864.2 100 % Interest expense, net (446.1 ) (387.9 ) (58.2 ) 15 % Equity earnings (loss) 9.1 (23.9 ) 33.0 138 % Gain (loss) from financing activities (49.6 ) (16.6 ) (33.0 ) 199 % Gain (loss) from sale of equity method investment 435.9 — 435.9 100 % Other, net (15.1 ) 0.5 (15.6 ) NM Income tax (expense) benefit (131.8 ) (14.8 ) (117.0 ) NM Net income (loss) 1,531.4 422.1 1,109.3 263 % Less: Net income (loss) attributable to noncontrolling interests 335.9 350.9 (15.0 ) (4 %) Net income (loss) attributable to Targa Resources Corp. 1,195.5 71.2 1,124.3 NM Premium on repurchase of noncontrolling interests, net of tax 53.2 — 53.2 100 % Dividends on Series A Preferred Stock 30.0 87.3 (57.3 ) (66 %) Deemed dividends on Series A Preferred Stock 215.5 — 215.5 100 % Net income (loss) attributable to common shareholders $ 896.8 $ (16.1 ) $ 912.9 NM Financial data: Adjusted EBITDA (1) $ 2,901.1 $ 2,052.0 $ 849.1 41 % Distributable cash flow (1) 2,278.7 1,541.4 737.3 48 % Adjusted free cash flow (1) 1,101.5 1,133.7 (32.2 ) (3 %) (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, is not considered meaningful. 2022 Compared to 2021 The increase in commodity sales reflects higher natural gas, NGL and condensate prices ($3,116.3 million) and higher NGL, natural gas and condensate volumes ($615.9 million), partially offset by the unfavorable impact of hedges ($264.1 million).
(6) Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates. 61 Consolidated Results of Operations The following table and discussion is a summary of our consolidated results of operations: Year Ended December 31, 2023 2022 2023 vs. 2022 (In millions) Revenues: Sales of commodities $ 13,962.1 $ 19,066.0 $ (5,103.9 ) (27 %) Fees from midstream services 2,098.2 1,863.8 234.4 13 % Total revenues 16,060.3 20,929.8 (4,869.5 ) (23 %) Product purchases and fuel 10,676.4 16,882.1 (6,205.7 ) (37 %) Operating expenses 1,077.9 912.8 165.1 18 % Depreciation and amortization expense 1,329.6 1,096.0 233.6 21 % General and administrative expense 348.7 309.7 39.0 13 % Other operating (income) expense 1.5 0.2 1.3 NM Income (loss) from operations 2,626.2 1,729.0 897.2 52 % Interest expense, net (687.8 ) (446.1 ) (241.7 ) 54 % Equity earnings (loss) 9.0 9.1 (0.1 ) (1 %) Gain (loss) from financing activities (2.1 ) (49.6 ) 47.5 96 % Gain (loss) from sale of equity method investment — 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).
Capital Expenditures The following table details cash outlays for capital projects for the years ended December 31, 2022 and 2021: Year Ended December 31, 2022 2021 (In millions) Capital expenditures: Growth (1) $ 1,219.0 $ 421.9 Maintenance (2) 175.4 138.6 Gross capital expenditures 1,394.4 560.5 Transfers from materials and supplies inventory to property, plant and equipment — (2.4 ) Change in capital project payables and accruals, net (60.1 ) (53.0 ) Cash outlays for capital projects $ 1,334.3 $ 505.1 (1) Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $1,177.2 million and $407.7 million for the years ended December 31, 2022 and 2021.
During the year ended December 31, 2022, we paid $51.8 million of dividends to preferred shareholders. 69 Capital Expenditures The following table details cash outlays for capital projects for the years ended December 31, 2023 and 2022: Year Ended December 31, 2023 2022 (In millions) Capital expenditures: Growth (1) $ 2,211.0 $ 1,219.0 Maintenance (2) 232.6 175.4 Gross capital expenditures 2,443.6 1,394.4 Change in capital project payables and accruals, net (58.2 ) (60.1 ) Cash outlays for capital projects $ 2,385.4 $ 1,334.3 (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.
See “Recent Developments” for further details on our 2022 expansions. 67 Cash Flows from Financing Activities Year Ended December 31, 2022 2021 (In millions) Source of Financing Activities, net Debt, including financing costs $ 4,651.5 $ (1,189.1 ) Redemption of Series A Preferred Stock (965.2 ) — Repurchase of noncontrolling interests (926.3 ) — Dividends (379.7 ) (187.5 ) Contributions from (distributions to) noncontrolling interests (290.3 ) (484.2 ) Repurchase of shares (260.6 ) (53.2 ) Net cash provided by (used in) financing activities $ 1,829.4 $ (1,914.0 ) The change in net cash provided by (used in) financing activities was primarily due to net borrowings of debt in 2022, as compared to net repayments of debt in 2021, partially offset by the redemption of the Series A Preferred and repurchases of non-controlling interests in the DevCo JVs and common stock during 2022.
Cash Flows from Financing Activities Year Ended December 31, 2023 2022 (In millions) Source of Financing Activities, net Debt, including financing costs $ 1,300.0 $ 4,651.5 Redemption of Series A Preferred Stock — (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.
Additionally, higher volumes in the Permian, the addition of the Legacy and Red Hills VI plants during the third quarter of 2022 and the Heim plant in the third quarter of 2021, and inflation impacts, resulted in increased costs.
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.
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 decreased primarily due to higher fuel and power costs. The increase in operating expenses was primarily due to higher repairs and maintenance.
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.
During 2022, we completed the GCX Sale resulting in a gain from sale of an equity method investment. See Note 4 - Acquisitions and Divestitures for further discussion.
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.
See Note 7 – Investments in Unconsolidated Affiliates for further discussion. During 2022, the Partnership redeemed the 5.375% Senior Notes due 2027 and the 5.875% Senior Notes due 2026. In addition, we terminated the Previous TRGP Revolver and the Partnership Revolver. These transactions resulted in a net loss from financing activities.
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.
The following is a summary of our material future contractual obligations: Contractual Obligations: Total Within 12 Months (in millions) Long-term debt obligations (1) $ 10,583.1 $ — Interest on debt obligations (2) 4,869.6 570.9 Operating leases (3) 47.1 15.7 Finance leases (4) 265.3 42.5 Land site lease and rights of way (5) 247.6 6.9 Purchase obligations (6) 2,437.8 1,341.4 Other long-term liabilities (7) 133.4 41.7 Total $ 18,583.9 $ 2,019.1 (1) Represents scheduled future maturities of long-term debt obligation.
The following is a summary of our material future contractual obligations: Contractual Obligations: Total Within 12 Months (in millions) 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.
The decrease in volumes in the Coastal region was due to lower producer activity. The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and the Delaware Basin in the second and third quarters of 2022, which included one-time acquisition costs.
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.
Logistics and Transportation Segment Year Ended December 31, 2022 2021 2022 vs. 2021 (In millions, except operating statistics) Operating margin $ 1,456.3 $ 1,264.3 $ 192.0 15% Operating expenses 300.2 273.0 27.2 10% Adjusted operating margin $ 1,756.5 $ 1,537.3 $ 219.2 14% Operating statistics MBbl/d (1): NGL pipeline transportation volumes (2) 488.6 396.2 92.4 23% Fractionation volumes 731.7 616.0 115.7 19% Export volumes (3) 314.5 316.9 (2.4 ) (1%) NGL sales 866.3 834.9 31.4 4% (1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation.
Logistics and Transportation Segment Year Ended December 31, 2023 2022 2023 vs. 2022 (In millions, except operating statistics) Operating margin $ 1,948.7 $ 1,456.3 $ 492.4 34% Operating expenses 332.0 300.2 31.8 11% Adjusted operating margin $ 2,280.7 $ 1,756.5 $ 524.2 30% Operating statistics MBbl/d (1): NGL pipeline transportation volumes (2) 635.5 488.6 146.9 30% Fractionation volumes 798.1 731.7 66.4 9% Export volumes (3) 365.2 314.5 50.7 16% NGL sales 1,019.8 866.3 153.5 18% (1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation.
See Note 4 – Acquisitions and Divestitures in our Consolidated Financial Statements. 70 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.
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 increase in net cash provided by operations was primarily due to higher commodity prices, resulting in higher collections from customers, partially offset by an increase in payments for product purchases and fuel and hedge transactions.
Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts. 67 The increase in net cash provided by operations was primarily due to higher settlements for hedge transactions and a decrease in payments for product purchases and fuel, partially offset by lower collections from customers.
Results of Operations—By Reportable Segment Our operating margins by reportable segment are: Gathering and Processing Logistics and Transportation Other (In millions) Year Ended: December 31, 2022 $ 1,981.0 $ 1,456.3 $ (302.4 ) December 31, 2021 1,325.3 1,264.3 (115.9 ) 62 Gathering and Processing Segment Year Ended December 31, 2022 2021 2022 vs. 2021 (In millions, except operating statistics and price amounts) Operating margin $ 1,981.0 $ 1,325.3 $ 655.7 49 % Operating expenses 611.8 476.2 135.6 28 % Adjusted operating margin $ 2,592.8 $ 1,801.5 $ 791.3 44 % Operating statistics (1): Plant natural gas inlet, MMcf/d (2) (3) Permian Midland (4) 2,223.6 1,928.4 295.2 15 % Permian Delaware (5) 1,536.1 839.8 696.3 83 % Total Permian 3,759.7 2,768.2 991.5 SouthTX (6) 276.5 177.7 98.8 56 % North Texas 187.0 178.9 8.1 5 % SouthOK (6) 406.8 405.9 0.9 — WestOK 208.7 212.6 (3.9 ) (2 %) Total Central 1,079.0 975.1 103.9 Badlands (6) (7) 134.9 139.8 (4.9 ) (4 %) Total Field 4,973.6 3,883.1 1,090.5 Coastal 537.6 587.2 (49.6 ) (8 %) Total 5,511.2 4,470.3 1,040.9 23 % NGL production, MBbl/d (3) Permian Midland (4) 321.7 277.9 43.8 16 % Permian Delaware (5) 193.9 114.1 79.8 70 % Total Permian 515.6 392.0 123.6 SouthTX (6) 31.2 22.2 9.0 41 % North Texas 21.2 20.1 1.1 5 % SouthOK (6) 47.6 49.5 (1.9 ) (4 %) WestOK 14.6 16.5 (1.9 ) (12 %) Total Central 114.6 108.3 6.3 Badlands (6) 16.1 16.2 (0.1 ) (1 %) Total Field 646.3 516.5 129.8 Coastal 32.0 33.9 (1.9 ) (6 %) Total 678.3 550.4 127.9 23 % Crude oil, Badlands, MBbl/d 117.6 140.9 (23.3 ) (17 %) Crude oil, Permian, MBbl/d 29.5 35.0 (5.5 ) (16 %) Natural gas sales, BBtu/d (3) 2,320.6 2,207.7 112.9 5 % NGL sales, MBbl/d (3) 438.7 394.6 44.1 11 % Condensate sales, MBbl/d 15.5 14.9 0.6 4 % Average realized prices - inclusive of hedges (8): Natural gas, $/MMBtu 5.35 3.27 2.08 64 % NGL, $/gal 0.75 0.61 0.14 23 % Condensate, $/Bbl 88.26 60.02 28.24 47 % (1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation.
Results of Operations—By Reportable Segment Our operating margins by reportable segment are: Gathering and Processing Logistics and Transportation Other (In millions) Year Ended: December 31, 2023 $ 2,082.2 $ 1,948.7 $ 275.5 December 31, 2022 1,981.0 1,456.3 (302.4 ) 63 Gathering and Processing Segment Year Ended December 31, 2023 2022 2023 vs. 2022 (In millions, except operating statistics and price amounts) Operating margin $ 2,082.2 $ 1,981.0 $ 101.2 5 % Operating expenses 746.6 611.8 134.8 22 % Adjusted operating margin $ 2,828.8 $ 2,592.8 $ 236.0 9 % Operating statistics (1): Plant natural gas inlet, MMcf/d (2) (3) Permian Midland (4) 2,535.2 2,223.6 311.6 14 % Permian Delaware (5) 2,526.5 1,536.1 990.4 64 % Total Permian 5,061.7 3,759.7 1,302.0 35 % SouthTX (6) 367.4 276.5 90.9 33 % North Texas 205.9 187.0 18.9 10 % SouthOK (6) 385.0 406.8 (21.8 ) (5 %) WestOK 207.1 208.7 (1.6 ) (1 %) Total Central 1,165.4 1,079.0 86.4 8 % Badlands (6) (7) 130.0 134.9 (4.9 ) (4 %) Total Field 6,357.1 4,973.6 1,383.5 28 % Coastal 541.1 537.6 3.5 1 % Total 6,898.2 5,511.2 1,387.0 25 % NGL production, MBbl/d (3) Permian Midland (4) 367.7 321.7 46.0 14 % Permian Delaware (5) 321.6 188.6 133.0 71 % Total Permian 689.3 510.3 179.0 35 % SouthTX (6) 40.9 31.2 9.7 31 % North Texas 24.0 21.2 2.8 13 % SouthOK (6) 43.1 47.6 (4.5 ) (9 %) WestOK 12.5 14.6 (2.1 ) (14 %) Total Central 120.5 114.6 5.9 5 % Badlands (6) 15.5 16.1 (0.6 ) (4 %) Total Field 825.3 641.0 184.3 29 % Coastal 39.2 32.0 7.2 23 % Total 864.5 673.0 191.5 28 % Crude oil, Badlands, MBbl/d 105.5 117.6 (12.1 ) (10 %) Crude oil, Permian, MBbl/d 27.4 29.5 (2.1 ) (7 %) Natural gas sales, BBtu/d (3) 2,685.8 2,383.4 302.4 13 % NGL sales, MBbl/d (3) 495.8 439.8 56.0 13 % Condensate sales, MBbl/d 18.5 15.5 3.0 19 % Average realized prices (8): Natural gas, $/MMBtu 1.94 5.21 (3.27 ) (63 %) NGL, $/gal 0.46 0.75 (0.29 ) (39 %) Condensate, $/Bbl 74.35 88.26 (13.91 ) (16 %) (1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation.
In April 2022, we completed an underwritten public offering of the 4.200% Notes and the 4.950% Notes, resulting in net proceeds of approximately $1.5 billion.
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.
Cash Flows from Investing Activities Year Ended December 31, 2022 2021 2022 vs. 2021 (In millions) $ (4,149.7 ) $ (473.2 ) $ (3,676.5 ) The increase in net cash used in investing activities was primarily due to the outlays for the Delaware Basin Acquisition and the South Texas Acquisition.
Cash Flows from Investing Activities Year Ended December 31, 2023 2022 2023 vs. 2022 (In millions) $ (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.
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.
The Obligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information.
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.
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 decrease was primarily due to higher net borrowing on the Securitization Facility, and higher accounts payable and accruals related to growth projects in the Permian, partially offset by an increase to NGL inventory, higher net assets from hedging activities, and an increase in receivables resulting from higher commodity prices.
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.
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.
In addition, we use derivative instruments to manage our exposure to commodity price risk.
The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. As of December 31, 2022, we had $1.0 billion outstanding under the Commercial Paper Program. In January 2023, we completed the underwritten public offering of the 6.125% Notes and the 6.500% Notes, resulting in net proceeds of approximately $1.7 billion.
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.
The increase in operating expenses is primarily due to increased activity and system expansions, the acquisition of certain assets in South Texas and the Delaware Basin, and inflation, partially offset by the impact of a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana during the first quarter of 2021.
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 decrease in net income (loss) attributable to noncontrolling interests is primarily due to the DevCo JV Repurchase, partially offset by impairment losses in 2021 allocated to noncontrolling interest holders in the Carnero Joint Venture, higher income allocation to noncontrolling interests holders in the Grand Prix Joint Venture and Centrahoma Processing, LLC., and an increase in noncontrolling interest for a joint venture partner in WestTX.
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.
Other operating (income) expense in 2021 consisted primarily of the write-down of certain assets to their recoverable amounts. The increase in interest expense, net is primarily due to higher net borrowings, partially offset by the change in fair value of the mandatorily redeemable preferred interests, higher capitalized interest resulting from higher growth capital investments, and lower commitment fees.
The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs, computer systems and professional fees. 62 The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates, partially offset by higher capitalized interest resulting from higher growth capital investments.
In September 2022, the Partnership amended the Securitization Facility to, among other things, increase the facility size from $400.0 million to $800.0 million and extend the facility termination date to September 1, 2023.
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.
(2) Includes financial advisory, legal and other professional fees, and other one-time transaction costs. (3) Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests). (4) Excludes amortization of interest expense.
(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 used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition. 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 to fund a portion of the Delaware Basin Acquisition.
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.
Removed
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
Added
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.
Removed
The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees. 61 In 2021, we recognized a non-cash pre-tax impairment loss of $452.3 million on assets in the South Texas region associated with our Central operations. See Note 5 - Property, Plant and Equipment and Intangible Assets for further discussion.
Added
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.
Removed
The increase in equity earnings is primarily due to lower losses resulting from the purchase of our remaining interests in the two joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and lower losses from GCF, partially offset by lower earnings resulting from the impact of the GCX Sale and lower earnings from our investment in Little Missouri 4 LLC.
Added
The increase in operating expenses was due to higher system volumes, higher compensation and benefits, higher repairs and maintenance and higher taxes.
Removed
During 2021, the Partnership redeemed the 5.125% Senior Notes due 2025 and the 4.250% Senior Notes due 2023 and Targa Pipeline Partners LP redeemed its TPL 4.750% Senior Notes due 2021 and TPL 5.875% Senior Notes due 2023, resulting in a net loss from financing activities.
Removed
The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a larger release of the valuation allowance in 2022 compared to 2021, the impact of statutory rate changes in Oklahoma and Louisiana in 2021 and the correction of a state tax error in 2021.
Removed
For additional discussion on recent factors impacting our liquidity and capital resources, see “Recent Developments.” Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership's liquidity as well as the ability to contribute capital to the Partnership.
Removed
The actual amount we declare as dividends depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.
Removed
Working capital as of December 31, 2022 decreased $181.4 million compared to December 31, 2021.
Removed
Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.” In February 2022, we entered into the TRGP Revolver.
Removed
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, including a swing line sub-facility of up to $100.0 million.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

20 edited+3 added−3 removed19 unchanged
Biggest changeA 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 standard International Swap Dealers Association form with customized credit and legal terms.
Biggest changeThe 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.
Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges. 72 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.
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.
In an effort to reduce the variability of our cash flows, as of December 31, 2022, 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.
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.
As of December 31, 2022, 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.
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.
No customer comprised 10% or greater of our consolidated revenues during the years ended December 31, 2022 and 2021, respectively.
No customer comprised 10% or greater of our consolidated revenues during the years ended December 31, 2023 and 2022, respectively.
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, 2022, we had $3.6 billion in outstanding variable rate borrowings.
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.
Forward commodity prices have increased relative to the fixed prices on our derivative contracts, creating the net liability 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.
Forward commodity prices have decreased relative to the fixed prices on our derivative contracts, creating the net asset position. 73 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.
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.
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.
A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $36.0 million based on our December 31, 2022 debt balances. Counterparty Credit Risk We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties.
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.
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 $19.1 million as of December 31, 2022.
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.
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 International Swap Dealers Association agreements with our derivative counterparties.
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.
The range of losses attributable to our individual counterparties as of December 31, 2022 would be between $1.9 million and $16.4 million, depending on the counterparty in default. 73 Customer Credit Risk We extend credit to customers and other parties in the normal course of business.
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.
The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of December 31, 2022: Fair Value Result of 10% Price Decrease Result of 10% Price Increase (In millions) Natural gas $ (267.6 ) $ (185.1 ) $ (350.1 ) NGLs 34.2 123.1 (54.7 ) Crude oil (22.4 ) 5.7 (50.5 ) Total $ (255.8 ) $ (56.3 ) $ (455.3 ) 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.
The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of December 31, 2023: Fair Value Result of 10% Price Decrease Result of 10% Price Increase (In millions) 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.
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 doubtful accounts was $2.2 million and $0.1 million as of December 31, 2022 and December 31, 2021, respectively. The change in the allowance for doubtful accounts was primarily due to the Delaware Basin Acquisition.
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.
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. 71 Risk Management We evaluate counterparty risks related to our commodity derivative contracts and trade credit.
Item 7A. Quantitative and Qualitati ve Disclosures About Market Risk. 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.
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.
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.
During the years ended December 31, 2022 and 2021, our operating revenues decreased by $(754.7) million and $(490.6) 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 $316.7 million at December 31, 2021 to $255.8 million at December 31, 2022.
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.
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.
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. 72 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.
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.
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 principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings.
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.
Removed
Item 7A. Quantitative and Qualitati ve Disclosures About Market Risk.
Added
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.
Removed
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.
Added
We may buy calls in connection with swap positions to create a price floor with upside.
Removed
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.
Added
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.

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