What changed in this filing

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Item 2. Management’s Discussion and Analysis

2022-05-05 compared with 2021-11-04 · 225 added, 248 removed, 271 unchanged (64% of the section changed)

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Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses.

The Logistics and Transportation segment also includes the Grand Prix NGL Pipeline (“Grand Prix”), which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas, as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline connecting the Waha hub in West Texas and other receipt points, including many of our Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points.

The associated assets, including these pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the 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.

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Permian Midland Processing Expansion

In November 2020, we announced the transfer of an existing cryogenic natural gas processing plant from our North Texas system (the “Longhorn Plant”), to our Permian Midland system.

The plant was relocated to and installed in Reagan County, Texas, in 2021, as a new 200 MMcf/d cryogenic natural gas processing plant (the “Heim Plant”).

The Heim Plant, which commenced operations in the third quarter of 2021, processes natural gas production from the Permian Basin.

In August 2021, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new 250 MMcf/d cryogenic natural gas processing plant in the Midland Basin (the “Legacy Plant”).

In August 2021, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Legacy plant”).

The Legacy plant is expected to begin operations in the fourth quarter of 2022.

In November 2021, we announced that we were ordering long-lead items for our next potential gas plant in Permian Midland to meet the future infrastructure needs of our producers given our expectation for increasing production beyond the Legacy Plant.

Capital Allocation

In November 2021, we announced an update to our capital allocation strategy, including that for the fourth quarter of 2021, we intend to recommend to our board of directors an increase to our common dividend to $0.35 per common share or $1.40 per common share annualized.

The initial recommended common dividend per share increase is expected to be effective for the fourth quarter of 2021 and payable in February 2022.

We expect to continue to simplify our capital structure through repurchase of our interests in our development company joint ventures from investment vehicles affiliated with Stonepeak Infrastructure Partners for approximately $925 million in January 2022 and the redemption of outstanding shares of our Series A Preferred Stock (“Series A Preferred”) over time, once the redemption price steps down in March 2022, while continuing to invest in accretive growth opportunities across our core integrated strategy.

We also may opportunistically repurchase common stock under our existing $500 million authorized share repurchase program (the “Share Repurchase Program”).

In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Legacy II plant”).

The Legacy II plant is expected to begin operations in the second quarter of 2023.

Permian Delaware Processing Expansion

The Midway plant is expected to begin operations in the third quarter of 2023.

In conjunction with the commencement of operations of the Midway plant, we expect to idle the Sand Hills plant.

Capital Investments and Divestitures

In January 2022, we closed on the purchase of all of Stonepeak Infrastructure Partners’ (“Stonepeak”) interests in our development company joint ventures (“DevCo JVs”) for $926.3 million (the “DevCo JV Repurchase”).

Following the DevCo JV Repurchase, we own a 75% interest in Grand Prix Pipeline LLC, a 100% interest in our Train 6 fractionator in Mont Belvieu, Texas and owned a 25% equity interest in Gulf Coast Express Pipeline (“GCX”), prior to the GCX Sale (as defined below) in February 2022.

The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests.

The amount of the redemption price in excess of the carrying amount, net of tax was $53.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.

In addition, the DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.

In February 2022, we announced that we executed agreements to sell Targa GCX Pipeline LLC, which held our 25 percent equity interest in GCX, for approximately $857 million (the “GCX Sale”).

We expect to receive the full proceeds from the sale in the second quarter of 2022 as the customary call right period has now expired.

In April 2022, we closed on the bolt-on acquisition of Southcross Energy Operating LLC and its subsidiaries in South Texas for a purchase price of approximately $200 million.

We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and which we will prospectively consolidate.

See Note 4 - Joint Ventures, Acquisitions and Divestitures and Note 6 - Investments in Unconsolidated Affiliates to our Consolidated Financial Statements .

Common Share Repurchases and Preferred Stock Redemption

In the first quarter of 2022, we repurchased 737,799 shares of our common stock at a weighted average price of $67.37 for a total net cost of $49.7 million.

There was $318.8 million remaining under our $500 million common share repurchase program as of March 31, 2022.

In May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022.

The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, which will be recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022.

Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated.

See Note 9 - Preferred Stock to our Consolidated Financial Statements.

Financing Activities

In February 2021, the Partnership issued $1.0 billion of 4% Senior Notes due 2032, resulting in net proceeds of approximately $991 million.

A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “February Tender Offer”) and subsequent redemption payment for the Partnership’s 5⅛% Senior Notes due 2025 (the “5⅛% Notes”), with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility (the “TRP Revolver”) and our senior secured revolving credit facility (the “TRC Revolver”) .

As a result of the February Tender Offer and the subsequent redemption of the 5⅛% Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

Additionally, Targa Pipeline Partners LP (“TPL”) redeemed all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023 (collectively, the “TPL Notes”) on February 22, 2021 with available liquidity under the TRP Revolver.

As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.

The Partnership redeemed all of the outstanding 4¼% Senior Notes due 2023 (the “4¼% Notes”) on May 17, 2021 with available liquidity under the TRP Revolver.

As a result of the redemption of the 4¼% Notes, we recorded a loss due to debt extinguishment of $1.9 million.

We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise.

Additionally, we may redeem all or a portion of our Series A Preferred in the future pursuant to its terms or repurchase Series A Preferred shares in privately negotiated transactions.

Such repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

The amounts involved may be material.

On April 21, 2021, we amended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to increase the facility size from $350.0 million to $400.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2022.

In February 2022, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto (the “TRGP Revolver”).

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.

The TRGP Revolver matures in February 2027.

In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC (“S&P”) and Fitch Ratings Inc.

(“Fitch”), and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc.

As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations thereunder.

In connection with our entry into the TRGP Revolver, we terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership’s senior secured revolving credit facility (the “Partnership Revolver”).

As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss due to debt extinguishment of $0.8 million.

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

As of March 31, 2022, $6.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.

In March 2022, the Partnership redeemed all of the outstanding 5.375% Senior Notes due 2027 (the “5.375% Notes”) with available liquidity under the TRGP Revolver.

As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million comprised of $12.6 million of premiums paid and a write-off of $2.4 million of debt issuance costs.

In April 2022, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Senior Notes due 2033 (the “4.200% Notes”) and (ii) $750.0 million aggregate principal amount of our 4.950% Senior Notes due 2052 (the “4.950% Notes”), resulting in net proceeds of approximately $1.5 billion.

A portion of the net proceeds from the issuance were used to fund the March Tender Offer and the subsequent redemption payment of the Partnership’s 5.875% Notes, with the remainder used for repayment of borrowings under the TRGP Revolver.

As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we will record a loss due to debt extinguishment of $33.5 million in the second quarter of 2022.

In April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023 and replace the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR.

For additional information about our debt-related transactions, see Note 7 - Debt Obligations to our Consolidated Financial Statements.

COVID-19 Pandemic

The global spread of COVID-19 during 2020 and 2021 has caused significant commodity market volatility.

We are currently experiencing no material issues with potential workforce, supply chain or customer relationship disruptions.

The global spread of COVID-19 during 2020 and 2021 caused significant commodity market volatility.

Although significant progress has been made towards the development, distribution and administration of various COVID-19 vaccines, there continues to be significant uncertainty about the disruptions and other effects related to COVID-19.

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In February 2021, the Central region of the United States experienced unprecedented cold temperatures during a major winter storm that disrupted production operations, midstream infrastructure and many other services.

This extreme weather caused wide fluctuations in commodity prices, short-term disruptions to Targa’s operations across Texas, Oklahoma and Louisiana, including

reduced throughput volumes coming into our systems, and adversely affected the operations and financial condition of some of our counterparties.

Though certain Compan y facilities experienced temporary outages, all facilities have since returned to full operations without sustaining any long-term impacts or significant adverse financial impacts related to th e weather event , and throughput volumes have returned to pre-storm levels .

This extreme weather caused wide fluctuations in commodity prices, short-term disruptions to our operations across Texas, New Mexico, Oklahoma and Louisiana, including reduced throughput volumes coming into our systems, and adversely affected the operations and financial condition of some of our counterparties.

Though certain of our facilities experienced temporary outages, all facilities have since returned to full operation without sustaining any long-term impacts or significant adverse financial impacts related to the weather event, and throughput volumes have returned to pre-storm levels.

The full financial impact of the winter storm still remains uncertain as it is subject to recently proposed regulatory changes and potential customer and counterparty risk.

For further discussion, see “Item 1A.

Risk Factors .

Corporation Tax Matters

The IRS notified us on April 3, 2019, that it will examine Targa’s federal income tax returns (Form 1120) for 2014, 2015 and 2016.

The IRS completed their examination without proposing any adjustments, and the Joint Committee on Taxation approved the IRS’ findings without any exception.

The Joint Committee on Taxation sent Targa a closing letter dated February 23, 2021.

The closing letter effectively ends the IRS’ audit of Targa’s federal income tax returns for 2014, 2015 and 2016.

In January 2022, the IRS notified us that it will examine Targa’s net operating loss (“NOL”) carryback previously claimed under the Coronavirus Aid, Relief and Economic Security (“CARES”) Act.

The CARES Act was signed into law on March 27, 2020 and provided corporate taxpayers an expanded five-year NOL carryback period for losses generated in tax years 2018 through 2020.

We received a cash refund of approximately $44 million related to the CARES Act provisions in 2020.

We are in the process of responding to information requests from the IRS and do not anticipate material changes in prior year taxable income.

FERC Regulatory Matters

On December 17, 2020, FERC issued an Order Establishing Index Level establishing an index level of the Producer Price Index for Finished Goods plus 0.78% for the five-year period commencing July 1, 2021, and ending June 30, 2026 (“December 2020 Order”).

On May 14, 2021, FERC published a revised oil pricing index factor utilizing the oil pricing index factor established in the December 2020 Order, resulting in a negative percent change for the index year July 1, 2021, through June 30, 2022.

This means that the ceiling level for certain oil pipelines’ rates may decrease and, if the actual transportation rate would be above such ceiling level, the rate must decrease to be equal to or less than the applicable ceiling.

However, a number of our pipeline rates, including all rates on Grand Prix Pipeline LLC (“Grand Prix Joint Venture”) and Targa Gulf Coast NGL Pipeline LLC, and certain rates on Targa NGL Pipeline Company LLC had not been adjusted in a number of years, and, therefore, these pipelines increased their rates to equal the applicable new ceiling level.

Certain rates on the Targa NGL Pipeline Company LLC system were reduced to equal the ceiling level.

However, requests for rehearing of the December 2020 Order were filed with FERC, and those requests remain pending, with rehearing granted for purposes of extending the time FERC has to review these requests.

FERC’s final application of its indexing rate methodology for the next five-year term of index rates will be determined based on the outcome of these requests for rehearing, and any changes to FERC’s index level may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by the FERC oil pipeline index.

On January 20, 2022, FERC issued an order on rehearing of its December 17, 2020 Order Establishing Index Level in which the Commission reduced the oil pricing index factor for oil pipelines to use for the current five-year period.

As a result, the ceiling levels computed for July 1, 2021 to June 30, 2022, and the resulting rates currently in effect for certain of Targa’s liquids pipelines were recomputed to account for the reduced index factor.

Recent Accounting Pronouncements

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

For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies to our Consolidated Financial Statements.

How We Evaluate Our Operations

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(1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures:

adjusted gross margin, adjusted operating margin, adjusted EBITDA, distributable cash flow and adjusted free cash flow.

adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment).

Throughput Volumes, Facility Efficiencies and Fuel Consumption

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Labor, contract services, repair and maintenance and ad valorem taxes comprise the most significant portion of our operating expenses.

These expenses remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.

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

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We utilize non-GAAP measures to analyze our performance.

Adjusted gross margin, adjusted operating margin, adjusted EBITDA, distributable cash flow, and adjusted free cash flow are non-GAAP measures.

The GAAP measure most directly comparable to these non-GAAP measures are gross margin, income (loss) from operations and net income (loss) attributable to TRC.

These non-GAAP measures should not be considered as an alternative to the comparable GAAP measures and have important limitations as analytical tools.

Adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures.

The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp.

and segment operating margin.

These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools.

Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP.

Additionally, because our non-GAAP measures exclude some, but not all, items that affect net income, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility.

Additionally, because our non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility.

Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.

Adjusted Gross Margin

We define adjusted gross margin as revenues less product purchases and fuel.

Adjusted Operating Margin

We define adjusted operating margin for our segments as revenues less product purchases and fuel.

It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing segment adjusted gross margin consists primarily of:

Gathering and Processing adjusted operating margin consists primarily of:

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

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

Logistics and Transportation segment adjusted gross margin consists primarily of:

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

Logistics and Transportation adjusted operating margin consists primarily of:

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

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

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

Adjusted Operating Margin

We define adjusted operating margin as adjusted gross margin less operating expenses.

Adjusted operating margin is an important performance measure of the core profitability of our operations.

Adjusted gross margin and adjusted operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess:

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

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

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

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

Management reviews business segment adjusted gross margin and operating margin monthly as a core internal management process.

Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management process.

We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results.

The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”

Adjusted EBITDA

We define adjusted EBITDA as net income (loss) attributable to TRC before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance.

We define adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp.

before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance.

The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes.

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Distributable Cash Flow and Adjusted Free Cash Flow

We define distributable cash flow as adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs).

The Preferred Units that were issued by the Partnership in October 2015 were redeemed in December 2020, and are no longer outstanding.

We define distributable cash flow as adjusted EBITDA less cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs).

We define adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates.

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

Three Months Ended September 30,

Nine Months Ended September 30,

(In millions)

Reconciliation of Income (Loss) from Operations to Adjusted Operating Margin

Income (loss) from operations

Depreciation and amortization expense

General and administrative expense

Impairment of long-lived assets

(Gain) loss on sale or disposition of business and assets

Write-down of assets

Adjusted operating margin

Three Months Ended September 30,

Nine Months Ended September 30,

(In millions)

Reconciliation of Gross Margin to Adjusted Gross Margin

Depreciation and amortization expense

Adjusted gross margin

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow

Net income (loss) attributable to TRC

Income attributable to TRP preferred limited partners

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.

Interest (income) expense, net

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Depreciation and amortization expense

Impairment of long-lived assets

(Gain) loss on sale or disposition of business and assets

(Gain) loss on sale or disposition of assets

Write-down of assets

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Risk management activities

Severance and related benefits

Noncontrolling interests adjustments (2)

TRC Adjusted EBITDA

Distributions to TRP preferred limited partners

Adjusted EBITDA

Interest expense on debt obligations (3)

Maintenance capital expenditures

Noncontrolling interests adjustments of maintenance capital expenditures

Maintenance capital expenditures, net (4)

Distributable Cash Flow

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Gains or losses on debt repurchases or early debt extinguishments.

Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests), net of non-cash accretion of noncontrolling interests.

Noncontrolling interest portion of depreciation and amortization expense.

Excludes amortization of interest expense.

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

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

Consolidated Results of Operations

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

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

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General and administrative expense

Impairment of long-lived assets

Other operating (income) expense

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Net income (loss) attributable to Targa Resources Corp.

Premium on repurchase of noncontrolling interests, net of tax

Dividends on Series A Preferred Stock

Deemed dividends on Series A Preferred Stock

Net income (loss) attributable to common shareholders

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Adjusted free cash flow (1)

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

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.”

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

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($2,259.0 million) and higher NGL and natural gas volumes ($226.6 million), partially offset by the unfavorable impact of hedges ($192.8 million).

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

The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes.

Operating expenses were higher due to increased labor costs and higher repairs and maintenance primarily due to increased activity levels and system expansions.

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

The increase in depreciation and amortization expense is primarily due to a full quarter of depreciation on major growth capital projects previously placed in service, including the addition of fractionation trains in Mont Belvieu, Texas and additional processing plants and associated infrastructure in the Permian Basin.

The increase in depreciation and amortization expense was partially offset by the sale of assets in Channelview, Texas, in October 2020.

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

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

The decrease in interest expense, net is primarily due to lower net borrowings, partially offset by lower capitalized interest resulting from lower growth capital investments .

During the third quarter of 2020, the Partnership redeemed the 6¾% Senior Notes due 2024, resulting in a $13.7 million net loss from financing activities.

The decrease in income tax expense is primarily due to a larger release of the valuation allowance in 2021 compared to 2020.

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

The decrease in deemed dividends on Series A Preferred is due to the adoption of Accounting Standards Update 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40):

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($5,840.0 million) and higher NGL and natural gas volumes ($650.5 million), partially offset by lower petroleum products, crude marketing and condensate volumes ($148.0 million) and the unfavorable impact of hedges ($666.0 million).

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

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

Operating expenses were higher due to increased labor costs, higher repairs and maintenance and higher ad valorem taxes primarily due to increased activity levels and system expansions.

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($1,385.7 million) and higher natural gas volumes ($20.3 million), partially offset by lower NGL volumes ($20.2 million) and the unfavorable impact of hedges ($188.0 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, transportation and fractionation fees and export volumes.

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

The increase in operating expenses was due to higher labor and maintenance costs primarily due to increased activity and system expansions, partially offset by lower taxes and the reduction in expense from a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana during the first quarter of 2021.

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

The increase in general and administrative expense is primarily due to higher compensation and benefits and an increase in insurance costs, partially offset by a decrease in professional fees.

In 2020, we recognized a non-cash pre-tax impairment charge of $2,442.8 million, primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations and full impairment of our Coastal operations.

The decrease in interest expense, net is primarily due to lower net borrowings, partially offset by lower capitalized interest resulting from lower growth capital investments.

The decrease in equity earnings is primarily due to lower earnings from our investments in Gulf Coast Fractionators and Cayenne Pipeline LLC, partially offset by an increase from Little Missouri 4 LLC (“Little Missouri 4”).

During 2021, the Partnership redeemed the 5⅛% Notes, the TPL Notes and the 4¼% Notes resulting in a $16.6 million net loss from financing activities.

During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, resulting in a $47.4 million net gain from financing activities.

The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a decrease in the valuation allowance.

The increase in net income attributable to noncontrolling interests is primarily due to impairment losses allocated to noncontrolling interest holders in the first quarter of 2020 and higher income allocated to noncontrolling interest holders in Grand Prix Joint Venture.

The increase in net income attributable to noncontrolling interests was partially offset by the impact of the redemption of the Partnership’s preferred units in December 2020.

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

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend.

The decrease in depreciation and amortization expense is primarily due to a lower depreciable base associated with assets that were impaired during the fourth quarter of 2021.

The increase in general and administrative expense is primarily due to higher insurance costs and professional fees.

The decrease in interest expense, net is primarily due lower net borrowings and an increase in capitalized interest resulting from higher growth capital investments.

The decrease in equity earnings is primarily due to lower earnings from our investments in GCX DevCo JV and the Badlands, partially offset by lower losses from our investments in Gulf Coast Fractionators, T2 Eagle Ford Gathering Company L.L.C.

and T2 LaSalle Gathering Company L.L.C.

Lower equity earnings from our investments in GCX DevCo JV were due to the DevCo JV Repurchase in 2022.

See Note 4 – Investments in Joint Ventures, Divestitures and Acquisitions to our Consolidated Financial Statements for further discussion.

During 2022, we terminated the Previous TRGP Revolver and the Partnership Revolver, and the Partnership redeemed the 5.375% Notes, resulting in a net loss from financing activities.

During 2021, the Partnership redeemed its 5.125% Senior Notes due 2025, the Targa Pipeline Partners LP (“TPL”) 4.750% Senior Notes due 2021 and the TPL 5.875% Senior Notes due 2023, resulting in a net loss from financing activities.

See Note 7 – Debt Obligations for further discussion.

The increase in income tax expense is primarily due to a smaller release of the valuation allowance in 2022 compared to 2021, partially offset by a decrease in pre-tax book income.

During the first quarter of 2022, we closed on the purchase of all of Stonepeak’s interests in our DevCo JVs for $926.3 million.

The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests resulting in a $53.1 million premium on repurchase of noncontrolling interests, net of tax.

See Note 4 – Joint Ventures, Divestitures and Acquisitions to our Consolidated Financial Statements for further discussion .

Results of Operations—By Reportable Segment

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Three Months Ended:

September 30, 2021

September 30, 2020

Nine Months Ended:

September 30, 2021

September 30, 2020

March 31, 2022

March 31, 2021

Gathering and Processing Segment

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions, except operating statistics and price amounts)

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Operating expenses

Adjusted gross margin (1)

Adjusted operating margin

Operating statistics (1):

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Total Central

Badlands (5) (6)

NGL production, MBbl/d (3)

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Condensate, $/Bbl

Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation.

For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

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

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Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

Operations include facilities that are not wholly owned by us.

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

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The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator.

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

Three Months Ended September 30, 2021

Three Months Ended September 30, 2020

(In millions, except volumetric data and price amounts)

Natural gas (BBtu)

Crude oil (MBbl)

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

Nine Months Ended September 30, 2021

Nine Months Ended September 30, 2020

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:

Three Months Ended March 31, 2022

Three Months Ended March 31, 2021

(In millions, except volumetric data and price amounts)

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

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020

The increase in adjusted gross margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting in increased margin primarily in the Permian, partially offset by lower volumes in the Central region.

In the Permian, natural gas inlet volumes increased due to higher production and producer activity, as well as the addition of the Gateway and Heim plants during the third quarters of 2020 and 2021, respectively.

In the Badlands and Coastal regions, natural gas inlet volumes were relatively flat, while in the Central region the decrease was due to lower production and continued low producer activity.

Total crude oil volumes decreased in the Badlands and the Permian due to lower production.

Operating expenses were higher due to increased activity levels in the Permian and the addition of the Gateway and Heim plants in the third quarters of 2020 and 2021, respectively, which resulted in increased labor costs, materials and chemicals.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The increase in adjusted gross margin was due to higher realized commodity prices and higher natural gas inlet volumes resulting in higher margin primarily in the Permian, partially offset by the short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021.

In the Permian, natural gas inlet volumes increased due to higher production, higher producer activity, the addition of the Peregrine and Gateway plants in 2020 and the Heim Plant in the third quarter of 2021.

In the Badlands, natural gas inlet volumes were relatively flat, while the decrease in the Central and Coastal regions was due to continued low producer activity.

Total crude oil volumes decreased in the Badlands and the Permian due to lower production.

Operating expenses were higher due to increased activity levels in the Permian, the addition of the Peregrine and Gateway plants in 2020 and the Heim Plant in the third quarter of 2021, which resulted in increased labor costs and materials.

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

The increase in adjusted operating margin was due to higher realized commodity prices, natural gas inlet volumes and fees predominantly in the Permian.

The increase in natural gas inlet volumes in the Permian was attributable to higher production, higher producer activity and the addition of the Heim plant during the third quarter of 2021.

Prior year natural gas inlet volumes were impacted by the short-term operational disruption associated with a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana, that reduced our Permian and Central region volumes during the first quarter of 2021.

In the Badlands, the decrease in volumes was attributable to lower production and the impact of winter weather, while lower volumes in the Coastal region were due to lower production and continued low producer activity.

Operating expenses were higher due to increased activity levels in the Permian and the addition of the Heim plant in the third quarter of 2021, which resulted in increased labor costs, materials and chemicals.

Logistics and Transportation Segment

Three Months Ended September 30,

Nine Months Ended September 30,

(In millions, except operating statistics and price amounts)

Three Months Ended March 31,

(In millions, except operating statistics)

Operating margin

Operating expenses

Adjusted gross margin (1)

Adjusted operating margin

Operating statistics MBbl/d (1):

Pipeline throughput (3)

NGL pipeline transportation volumes (2)

Fractionation volumes

Export volumes (3)

Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation.

For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

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

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

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.

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020

The increase in adjusted gross margin was primarily due to higher pipeline transportation and fractionation volumes, partially offset by lower LPG export volumes and lower marketing margin.

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

The increase in adjusted operating margin was primarily due to higher pipeline transportation and fractionation volumes and higher LPG export volumes, partially offset by lower marketing margin.

Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems.

LPG export volumes were lower due to reduced short-term loading capacity as a result of repairs and maintenance that were completed in the third quarter of 2021.

Marketing margin decreased due to fewer optimization opportunities.

Operating expenses were higher due to higher repairs and maintenance, increased system throughput expenses and higher ad valorem taxes primarily due to system expansions, partially offset by cost reduction measures and the sale of assets in Channelview, Texas, in 2020.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

The increase in adjusted gross margin was primarily due to higher pipeline transportation and fractionation volumes that benefited from higher supply volumes from our Permian Gathering and Processing systems, partially offset by short-term operational disruptions and impacts associated with the major winter storm during the first quarter of 2021.

Other drivers included higher marketing margin due to greater optimization opportunities and higher LPG export volumes, partially offset by lower LPG export terminal fees.

Three Months Ended September 30,

Nine Months Ended September 30,

Prior year Downstream system volumes were impacted by the short-term operational disruption and impacts associated with a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana, that reduced our Permian and Central region volumes during the first quarter of 2021.

Higher optimization margin attributable to the winter storm resulted in higher marketing margin in the first quarter of 2021.

Operating expenses were slightly higher due to higher repairs and maintenance.

Three Months Ended March 31,

(In millions)

Operating margin

Adjusted operating margin

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.

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Our Liquidity and Capital Resources

As of September 30, 2021, inclusive of our consolidated joint venture accounts, we had $228.6 million of “Cash and cash equivalents” on our Consolidated Balance Sheets.

As of March 31, 2022, inclusive of our consolidated joint venture accounts, we had $135.9 million of Cash and cash equivalents on our Consolidated Balance Sheets.

We believe our cash positions, our cash flows from operating activities, our free cash flow after dividends and remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”) are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

Our liquidity and capital resources are managed on a consolidated basis.

We have the ability to access the Partnership’s liquidity, subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements, as well as the ability to contribute capital to the Partnership, subject to any restrictions contained in the covenants of our debt agreements.

We have the ability to access the Partnership’s liquidity as well as the ability to contribute capital to the Partnership.

On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, meeting our collateral requirements and to pay dividends declared by our board of directors will depend on our ability to generate cash in the future.

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We are entitled to the entirety of distributions made by the Partnership on its equity interests.

The actual amount we declare as distributions depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.

The Partnership’s debt agreements may restrict or prohibit the payment of distributions if the Partnership is in default or threat of default.

If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our common stock or Series A Preferred shares.

In addition, so long as any of our Series A Preferred shares are outstanding, certain common stock distribution limitations exist.

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRC Revolver, the TRP Revolver, and the Partnership’s Securitization Facility and access to debt and equity capital markets.

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.

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver and the Partnership’s Securitization Facility and access to debt and equity capital markets.

We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales.

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Short-term Liquidity

Our short-term liquidity on a consolidated basis as of October 29, 2021, was:

October 29, 2021

Our short-term liquidity on a consolidated basis as of May 3, 2022, was:

(In millions)

Cash on hand (1)

Total availability under the TRC Revolver

Total availability under the TRP Revolver

Total availability under the Partnership's Securitization Facility

Outstanding borrowings under the TRC Revolver

Outstanding borrowings under the TRP Revolver

Outstanding borrowings under the Partnership's Securitization Facility

Outstanding letters of credit under the TRP Revolver

Total availability under the TRGP Revolver

Total availability under the Securitization Facility

Outstanding borrowings under the TRGP Revolver

Outstanding borrowings under the Securitization Facility

Outstanding letters of credit under the TRGP Revolver

Total liquidity

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Includes cash held in our consolidated joint venture accounts.

Other potential capital resources associated with our existing arrangements include:

Our right to request an additional $200 million in commitment increases under the TRC Revolver, subject to the terms therein.

The TRC Revolver matures on June 29, 2023.

Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein.

The TRP Revolver matures on June 29, 2023.

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

Other potential capital resources associated with our existing arrangements includes 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.

These letters of credit reflect our non-investment grade status, as assigned to us by Fitch, Moody’s and S&P.

They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

They 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

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and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.

Working capital as of September 30, 2021 decreased $555.9 million compared to December 31, 2020.

The decrease was primarily due to higher product purchases payable as a result of higher commodity prices and an increase in the current liability position of our derivative contracts, partially offset by higher receivables resulting from higher commodity prices and an increase in NGLs inventory.

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

Working capital as of March 31, 2022 decreased $481.2 million compared to December 31, 2021.

The decrease was primarily due to higher product purchases and fuel payables as a result of higher commodity prices, an increase in the current liability position of our derivative contracts and higher net borrowing on the Securitization Facility, partially offset by higher receivables resulting from higher commodity prices.

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

Long-term Financing

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

In 2019, we closed on the sale of a 45% interest in Targa Badlands LLC to GSO Capital Partners and Blackstone Tactical Opportunities.

Targa Badlands LLC is a discrete entity and the assets and credit of Targa Badlands LLC are not available to satisfy the debts and other obligations of Targa or its other subsidiaries.

In February 2021, the Partnership issued $1.0 billion aggregate principal amount of 4% Senior Notes due 2032 (the “4% Notes”), resulting in net proceeds of approximately $991 million.

A portion of the net proceeds from the issuance were used to fund the February Tender Offer and subsequent redemption payment for the 5⅛% Notes, with the remainder used for repayment of borrowings under the TRP Revolver and TRC Revolver.

Additionally, TPL redeemed all of the outstanding TPL Notes on February 22, 2021 with available liquidity under the TRP Revolver.

As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million.

The Partnership redeemed all of the outstanding 4¼% Notes on May 17, 2021 with available liquidity under the TRP Revolver.

As a result of the redemption of the 4¼% Notes, we recorded a loss due to debt extinguishment of $1.9 million.

Additionally, we may redeem all or a portion of our Series A Preferred shares in the future pursuant to its terms or repurchase Series A Preferred shares in privately negotiated transactions.

Such repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

In February 2022, we entered into the TRGP Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto.

The TRGP Revolver matures in February 2027.

I n February 2022, TRGP and the Partnership received a corporate investment grade credit rating from S&P and Fitch, and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s.

As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations thereunder.

In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver and the Partnership Revolver.

As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss due to debt extinguishment of $0.8 million.

In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership Issuers under the respective indentures governing the Partnership Issuers’ senior unsecured notes.

As of March 31, 2022, $6.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.

In March 2022, the Partnership redeemed all of the outstanding 5.375% Notes with available liquidity under the TRGP Revolver.

In April 2022, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of $750.0 million aggregate principal amount of our 4.200% Notes and $750.0 million aggregate principal amount of our 4.950% Notes, resulting in net proceeds of approximately $1.5 billion.

A portion of the net proceeds from the issuance were used to fund the concurrent March Tender Offer and the subsequent redemption payment of the Partnership’s 5.875% Notes, with the remainder used for repayment of borrowings under the TRGP Revolver.

As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we will record a loss due to debt extinguishment of $33.5 million during the second quarter of 2022.

In the future, we or the Partnership may redeem, purchase or exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise.

Such calls, repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

The amounts involved may be material.

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

In 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.

Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated.

See Note 9 - Preferred Stock to our Consolidated Financial Statements.

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

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Compliance with Debt Covenants

As of September 30, 2021, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

As of March 31, 2022, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flows from Operating Activities

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

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Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

Net cash provided by operations increased in 2021 compared to 2020 primarily due to higher collections from customers, partially offset by higher payments for product purchases and fuel and hedge transactions.

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.

Cash Flows from Investing Activities

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

Cash used in investing activities decreased in 2021 compared to 2020, primarily due to lower outlays for property, plant and equipment of $481.5 million, resulting from the completion of additional fractionation trains in Mont Belvieu, Texas (collectively, “Trains 7 and 8”), the LPG export expansion, the Grand Prix Central Oklahoma extension, and the Gateway and Peregrine plants and additional processing plants and associated infrastructure in the Permian Basin in 2020, partially offset by higher proceeds from the sale of business and assets of $128.0 million including from the sale of our Delaware crude system in 2020.

The increase in net cash used in investing activities was primarily due to higher outlays for property, plant and equipment resulting from construction activities of the Legacy, Legacy II and Midway plants.

Cash Flows from Financing Activities

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

Source of Financing Activities, net

Repurchase of noncontrolling interests

Debt, including financing costs

Contributions from (distributions to) noncontrolling interests

Dividends and distributions

Contributions from (distributions to) noncontrolling interests

Net cash provided by (used in) financing activities

In 2021 , net cash used in financing activities is primarily due to repayments of debt, including repayment of borrowings under the TRP Revolver and TRC Revolver and the redemptions of the 5⅛% Notes, TPL Notes and 4¼% Notes, net distributions to noncontrolling interests and payments of dividends to our common and Series A Preferred shareholders, partially offset by borrowings, including the issuance of the 4% Notes.

In 2020, net cash used in financing activities is primarily due to payments of dividends to our common and Series A Preferred shareholders, and net distributions to noncontrolling interests, partially offset by a net increase of debt outstanding.

Our debt outstanding increased due to net borrowings under our credit facilities, partially offset by redemptions and repurchases of a portion of the outstanding senior notes of the Partnership.

The decrease in net cash used in financing activities was primarily due to higher borrowings of debt and lower distributions to noncontrolling interests, partially offset by the repurchase of the non-controlling interests in the DevCo JVs, and higher dividends and distributions paid in 2022.

The higher dividends and distributions were due to the increase of our common dividends from $0.10 to $0.35 in January 2022.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

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

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

All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information.

The Obligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information.

Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information.

Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group follows:

Summarized Combined Balance Sheet Information

March 31, 2022

December 31, 2021

(In millions)

Current assets

Current assets - affiliates

Long-term assets

Long-term assets - affiliates

LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY

Current liabilities

Current liabilities - affiliates

Long-term liabilities

Series A Preferred

Targa Resources Corp.

stockholders' equity

Total liabilities and owners' equity

Summarized Combined Statement of Operations Information

Three Months Ended

March 31, 2022

December 31, 2021

(In millions)

Operating income (loss)

Dividends on Series A Preferred

Common Stock Dividends

The following table details the dividends on common stock declared and/or paid by us for the nine months ended September 30, 2021:

The following table details the dividends on common stock declared and/or paid by us for the three months ended March 31, 2022:

Three Months Ended

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(In millions, except per share amounts)

September 30, 2021

November 15, 2021

June 30, 2021

August 16, 2021

March 31, 2022

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

Preferred Stock Dividends

Preferred Dividends

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

Cash dividends of $65.5 million were paid to holders of the Series A Preferred during the nine months ended September 30, 2021.

As of September 30, 2021, cash dividends accrued for our Series A Preferred were $21.8 million, which will be paid on November 12, 2021.

Cash dividends of $21.8 million were paid to holders of the Series A Preferred during the three months ended March 31, 2022.

As of March 31, 2022, cash dividends accrued for our Series A Preferred were $21.8 million, which were paid on May 2, 2022.

Series A Preferred Redemption

Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated.

See Note 9 - Preferred Stock to our Consolidated Financial Statements.

Capital Expenditures

The following table details cash outlays for capital projects for the nine months ended September 30, 2021 and 2020:

Nine Months Ended September 30,

The following table details cash outlays for capital projects for the three months ended March 31, 2022 and 2021:

Three Months Ended March 31,

(In millions)

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Cash outlays for capital projects

Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $227.9 million and $518.5 million for the nine months ended September 30, 2021 and 2020.

Maintenance capital expenditures, net of contributions from noncontrolling interests, were $72.9 million and $66.1 million for the nine months ended September 30, 2021 and 2020.

We currently estimate that in 2021 we will invest approximately $350 to $450 million in net growth capital expenditures for announced projects.

Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $121.4 million and $61.0 million for the three months ended March 31, 2022 and 2021.

Maintenance capital expenditures, net of contributions from noncontrolling interests, were $37.7 million and $19.0 million for the three months ended March 31, 2022 and 2021.

The increase in total growth capital expenditures was primarily due to system expansions in the Permian in response to increasing activity levels.

The increase in total maintenance capital expenditures was primarily due to our growing infrastructure footprint.

We currently estimate that in 2022 we will invest between $700 to $800 million in net growth capital expenditures for announced projects.

Future growth capital expenditures may vary based on investment opportunities.

We expect that 2022 maintenance capital expenditures, net of noncontrolling interests, will be approximately $150 million.

Total growth capital expenditures were lower for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2020, including Trains 7 and 8, the LPG export expansion, the Grand Prix Central Oklahoma extension, and the Gateway and Peregrine plants and additional processing plants and associated infrastructure in the Permian Basin.

Total maintenance capital expenditures were higher for the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020, primarily due to timing of maintenance projects.

Off-Balance Sheet Arrangements

As of September 30, 2021, there were $65.7 million in surety bonds outstanding related to various performance obligations.

As of March 31, 2022, there were $67.6 million in surety bonds outstanding related to various performance obligations.

These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis