What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2021-05-06 compared with 2020-11-05 · 152 added, 319 removed, 322 unchanged (59% of the section changed)

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(i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business).

Our Gathering and Processing segment includes assets used in the gathering and purchase and sale of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities;

and assets used for crude oil purchase and sale, gathering and terminaling.

Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs;

and assets used for the gathering and terminaling and/or purchase and sale of crude oil.

The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins);

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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”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast.

Grand Prix connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas.

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.

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Recent Developments

Response to Current Market Conditions

During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both supply and demand.

As the COVID-19 pandemic spread and travel and other restrictions were implemented globally, the demand for commodities declined substantially.

Additionally, certain major oil producing nations significantly increased their oil and gas production late in the first quarter which further contributed to the surplus production of commodities.

Despite these nations subsequently agreeing to reduce global commodity supplies and global economies beginning to re-open, commodity prices remain weak relative to historical levels and continue to remain volatile.

Reduced economic activity due to the COVID-19 pandemic, combined with uncertainty around global commodity supply and demand, has contributed to depressed crude oil, condensate, NGL and natural gas prices.

Furthermore, t he decline in commodity prices led many exploration and production companies to reduce planned capital expenditures for drilling and production activities and also led to some companies shutting in wells in the first half of 2020 .

Such price and activity declines negatively impact ed our operations by (i) reducing investments by third parties in the development of new oil and gas reserves, therefore reducing volumes coming onto our systems in the future, (ii) decreasing volumes processed in our facilities and transported on our pipelines and (iii) reducing the prices we receive from the sale of commodities .

While commodity prices remain low relative to historical levels and uncertainties associated with the impacts of COVID-19 continue , production from wells that were previously shut-in during the first half of 2020 across our operating areas has largely resumed.

Though energy demand has begun to recover compared to the first half of 2020, the pace and scope of recovery is uncertain at this time and may extend beyond 2020.

These circumstances have caused significant market volatility and business disruption.

In our Gathering and Processing areas of operation, producers have reduced their drilling activity to varying degrees, which may lead to lower volume growth in the near term and reduced demand for our services.

Producer activity also generates demand in our Downstream Business for transportation, fractionation, storage and other fee-based services, which may decrease in the near term.

There has been, and we believe will continue to be, significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices.

Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand will be throughout 2020, and, as a result, demand for our services may decrease.

Across our operations, particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered.

The significant level of margin we derive from fee-based arrangements, combined with our hedging arrangements, helps to mitigate our exposure to commodity price movements.

For additional information regarding our hedging activities, see “Item 3.

Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Due to the significant decline in commodity prices and the increased volatility in the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted.

In these conditions, investors may be more likely to limit the amounts of their investments as well as seek more restrictive terms and higher costs on any financing.

While these effects have increased the costs of debt and equity financing for the Company and others in our industry, we believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures through the remainder of 2020 and beyond.

In a response to current market conditions, in the first quarter of 2020, we announced that our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter.

This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt.

We also reduced our estimated 2020 net growth capital expenditures to about $700 million from our previously disclosed ranges of $700 million to $800 million in the first quarter of 2020 and $1.2 billion to $1.3 billion in the fourth quarter of 2019.

The vast majority of spending is for major ongoing growth capital projects where the capital is already predominantly spent.

We continue to work through numerous internal initiatives to respond to current market conditions, including identifying and implementing cost reduction measures such as reducing or deferring non-essential operating and general and administrative expenses.

We believe that our long-term strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows even in a low commodity price environment.

Geographic, business and customer diversity enhances our ability to generate sufficient cash flows to fund our requirements.

Our assets are positioned in strategic oil and gas producing areas across multiple basins and provide services under attractive contract terms to a diverse mix of customers across our operational areas.

Our contract portfolio has attractive rates and term characteristics, including a significant fee-based component, especially in our Downstream Business.

Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices.

We are currently experiencing no material issues with potential workforce disruptions, and we remain focused on safeguarding employee health and safety and ensuring safe and reliable operations in response to COVID-19.

Additionally, we are currently experiencing no material supply chain disruptions as a result of the COVID-19 pandemic, and our relationships with our major customers continues to be strong.

COVID-19 Pandemic

The global spread of COVID-19 during 2020 and in the first quarter of 2021 has caused significant market volatility.

There has been, and likely will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices.

We are uncertain of what pricing and market demand, and the associated impact to demand for our services, will be throughout 2021.

We are currently experiencing no material issues with potential workforce disruptions and remain focused on safeguarding employee health and safety and ensuring safe and reliable operations in response to COVID-19.

Additionally, we are currently experiencing no material supply chain disruptions and our relationships with our major customers continue to be strong.

However, if any of these circumstances change, our business could be adversely affected.

Further, as there is significant uncertainty around the breadth and duration of the disruptions to global markets related to the aforementioned current events, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.

Gathering and Processing Segment Expansion

Additionally, although significant progress has been made towards the development, distribution and administration of various COVID-19 vaccines, there is significant uncertainty around the breadth and duration of the disruptions to global markets and other effects related to COVID-19.

As a result, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.

Impact of Winter Weather

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 Company facilities experienced temporary outages, all facilities have returned to full operations without sustaining any long-term impacts or significant adverse financial impacts related to this 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 including repricing, finalizing Commercial and Industrial meter and settlement data, and potential customer and counterparty risk.

For further discussion, see “Item 1A.

Risk Factors”.

While the full financial impact of the storm remains uncertain, we recognized an aggregate benefit of approximately $30 million in our consolidated results of operations in the first quarter of 2021.

The aggregate benefit is largely attributable to the substantial intramonth commodity price and operational volatility caused as a result of the storm.

Permian Midland Processing Expansion

In November 2020, we announced the transfer of an existing cryogenic natural gas processing plant from our North Texas

system to our Permian Midland system.

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

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 will be 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 will process natural gas production from the Permian Basin and is expected to begin operations in the fourth quarter of 2021.

In August 2019, we announced that we began construction of a new 250 MMcf/d cryogenic natural gas processing plant in the Midland Basin, the Gateway Plant, which commenced operations in the third quarter of 2020.

Permian Delaware Processing Expansions

In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services.

The agreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin.

In addition to high-pressure rich gas gathering pipelines and a natural gas processing plant, the Falcon Plant, which were placed into service in 2019, we commenced operations of a second 250 MMcf/d cryogenic natural gas processing plant, the Peregrine Plant, in the second quarter of 2020.

We provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLs from the Falcon and Peregrine Plants.

Logistics and Transportation Segment Expansion

Grand Prix NGL Pipeline Extension

In February 2019, we announced an extension to our Grand Prix NGL pipeline system (the “Central Oklahoma Extension”), which will extend from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with The Williams Companies, Inc.

(“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets.

In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities.

The Central Oklahoma Extension is expected to be operational by the end of the fourth quarter of 2020.

Transportation volumes on the Central Oklahoma Extension accrue solely to Targa’s benefit and are not included in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest.

Fractionation Expansion

In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7” and “Train 8”).

Train 7 commenced operations in the first quarter of 2020 and Train 8 commenced operations in the third quarter of 2020 .

In January 2019, Williams committed to Targa significant volumes which Targa will transport on Grand Prix and fractionate at Targa’s Mont Belvieu facilities (including Train 7).

Williams was also granted an option to purchase a 20% equity interest in the fractionation train, which was originally wholly owned by Targa.

Williams exercised its initial option and executed a joint venture agreement with us with respect to Train 7 in the second quarter of 2019.

Certain fractionation-related infrastructure for Train 7, such as storage caverns and brine handling, will be funded and owned 100% by Targa.

LPG Export Expansion

In February 2019, we announced plans to further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by increasing refrigeration capacity and associated load rates.

With the additional infrastructure, we increased our effective export capacity up to 15 MMBbl per month in the third quarter of 2020, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors.

In October 2020, we executed agreements to sell our assets in Channelview, Texas for approximately $58 million (the “October 2020 Sale”).

The sale closed in the fourth quarter of 2020.

In November 2019, we executed agreements to sell our crude and storage business in Permian Delaware for approximately $134 million.

The sale closed in the first quarter of 2020.

Financing Activities

On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023.

In the third quarter of 2020, the Partnership issued $1.0 billion of 4⅞% Senior Notes due 2031, resulting in net proceeds of $991.0 million.

A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “Tender Offer”) and

redemption payments for the Partnership’s 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facili ty .

We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million and redeemed the remaining aggregate principal amount of the 6¾% Notes, which totaled $318.0 million.

We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.

Additionally, during the first half of 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes.

The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs.

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”) issued notices of redemption for all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023 (collectively, the “TPL Notes”).

These notes were redeemed 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 comprised of a write-off of $0.2 million of debt issuance premium.

On April 1, 2021, the Partnership issued a notice of redemption to redeem all of the outstanding 4¼% Senior Notes due 2023 on May 17, 2021.

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.

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The amounts involved may be material.

In the second quarter of 2020, we amended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to decrease the facility size from $400.0 million to $250.0 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, 2021.

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 million of our outstanding common stock.

As of November 2, 2020, we have repurchased 4,505,507 shares at a weighted average price of $16.33 for a total net cost of $73.6 million.

There is approximately $426 million remaining under the Share Repurchase Program.

We may discontinue the Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares.

Corporation Tax Matters

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act was signed into law.

The CARES Act provides corporate taxpayers an expanded five-year net operating loss carryback period for losses earned in tax years 2018 through 2020.

Additionally, the CARES Act allows corporate taxpayers to request an immediate refund of alternative minimum tax credits.

We requested a cash refund from the Internal Revenue Service (“IRS”) of approximately $44 million related to the CARES Act provisions and received the refund in the second quarter of 2020.

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.

We are cooperating with the IRS in the audit process and do not anticipate material changes in prior year taxable income.

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.

Recent Accounting Pronouncements

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Operating expenses are costs associated with the operation of specific assets.

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

These expenses, other than fuel and power, 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.

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

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

Capital Expenditures

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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.

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.

We define gross margin as revenues less product purchases.

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.

We define gross margin 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.

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system product gains and losses;

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

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

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

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

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

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

Adjusted EBITDA

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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 as of March 31, 2021.

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

Distributable cash flow and 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 or retirement of debt.

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:

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

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Write-down of assets

(Gain) loss from sale of equity-method investment

(Gain) loss from financing activities

Change in contingent considerations

Operating margin

Operating expenses

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

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Write-down of assets

(Gain) loss from sale of equity-method investment

(Gain) loss from financing activities (1)

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Distributions from unconsolidated affiliates and preferred partner interests, net

Change in contingent considerations

Compensation on equity grants

Risk management activities

Severance and related benefits (2)

Noncontrolling interests adjustments (2)

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Interest expense on debt obligations (3)

Cash tax refund

Maintenance capital expenditures

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Free Cash Flow

Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.

Represents one-time severance and related benefit expense related to our cost reduction measures.

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).

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

The Company has completed a number of announced growth capital projects since early 2019, and this has resulted in lower growth capital expenditures in 2020 and a transition to free cash flow.

The following table details construction and project completion timing of our announced major growth capital projects:

Three Months Ended

March 31, 2019

June 30, 2019

September 30, 2019

December 31, 2019

March 31, 2020

June 30, 2020

September 30, 2020

Major Growth Capital Project (1):

Gathering & Processing:

Hopson Plant (2)

Falcon Plant (3)

Pembrook Plant (2)

Little Missouri 4 Plant (4)

Peregrine Plant (3)

Gateway Plant (2)

Logistics & Transportation:

Grand Prix NGL Pipeline

Gulf Coast Express Pipeline

LPG Export Expansion

Grand Prix Central OK Extension

"UC" and "C" indicates under construction and project completed, respectively, as of the end of the period presented above.

Part of our Permian Midland operating area.

Part of our Permian Delaware operating area.

Part of our Badlands operating area.

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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Total revenues

Product purchases

Product purchases and fuel (1)

Gross margin (2)

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Gain (loss) from financing activities

Gain (loss) from sale of equity-method investment

Change in contingent considerations

Income tax (expense) benefit

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Free cash flow (2)

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.

Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and 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.

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

The increase in commodity sales reflects higher NGL and natural gas prices ($133.5 million), higher NGL, condensate and petroleum products volumes ($100.7 million) and the favorable impact of hedges ($171.0 million), partially offset by lower crude marketing and natural gas volumes ($128.9 million) and lower condensate and petroleum product prices ($29.6 million).

The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower gas processing volumes, partially offset by increased export and terminaling and storage volumes.

The decrease in product purchases reflects lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower natural gas volumes, partially offset by higher NGL and natural gas prices.

Higher operating margin and gross margin in 2020 reflect in creased segment results for Gathering and Processing and Logistics and Transportation .

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($1,869.3 million) and higher NGL volumes ($162.9 million), partially offset by lower crude marketing, petroleum product, natural gas and condensate volumes ($149.8 million) and the unfavorable impact of hedges ($294.6 million).

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

The lower gross margin and operating margin in 2021 reflect lower Other segment results from the Company’s commodity derivative mark-to-market activity.

The lower gross margin and operating margin are partially offset by both increased Gathering and Progressing and Logistics and Transportation segment results.

See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense decreased primarily due to a lower depreciable base associated with assets that were impaired during the first quarter of 2020 and the sale of the Delaware crude system, which was effective December 1, 2019.

The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian Basin.

General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by 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.

Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower earnings from Gulf Coast Fractionators LP (“GCF”).

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.

During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.

The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including our two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7” and “Train 8”) and the additional processing plants and associated infrastructure in the Permian Basin.

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.

Other operating (income) expense in 2021 and 2020 consisted primarily of write-downs of certain assets to their recoverable amounts.

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

During 2021, the Partnership redeemed the 5⅛% Notes, the TPL 4¾% Senior Notes due 2021 and the TPL 5⅞% Senior Notes due 2023, resulting in a $14.7 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 $39.3 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 valuation allowance.

Net income attributable to noncontrolling interests was higher in 2020 primarily due to income allocated to noncontrolling interest holders in the Grand Prix Joint Venture, Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

The decrease in commodity sales reflects lower NGL, condensate, natural gas and petroleum product prices ($1,112.5 million) and lower crude marketing volumes ($254.7 million), partially offset by higher NGL, condensate, natural gas and petroleum product volumes ($664.3 million), the favorable impact of hedges ($345.1 million) and higher crude marketing prices ($3.8 million).

The decrease in product purchases reflects lower NGL, condensate, natural gas and petroleum product prices, as well as lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, partially offset by higher NGL, condensate, natural gas and petroleum product volumes.

Higher operating margin and gross margin in 2020 reflect increased segment results for Gathering and Processing and Logistics and Transportation.

See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses , partially offset by an increase in insurance costs.

The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems in the first quarter of 2020 associated with our Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment.

Based on then-current market conditions, our first quarter impairment assessment projected further decline in natural gas production across the Mid-Continent and Gulf of Mexico.

We did not recognize any impairments of long-lived assets during the nine months ended September 30, 2019.

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

Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4, partially offset by lower earnings from GCF.

During the nine months ended September 30, 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024, paying $831.0 million plus accrued interest to repurchase $883.4 million of the notes, resulting in a $47.4 million net gain from financing activities.

During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.

The increase in income tax benefit is primarily due to a higher pre-tax book loss and benefit of a net operating loss carryback from the CARES Act.

Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of impairment losses recognized during the first quarter of 2020 to noncontrolling interest holders, partially offset by higher income allocated to noncontrolling interest holders in Targa Badlands LLC (“Targa Badlands”), the DevCo Joint Ventures and the Grand Prix Joint Venture.

Net income attributable to noncontrolling interests was higher in 2021 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 the Venice Energy Services Company, L.L.C.

joint venture, Grand Prix Pipeline LLC (“Grand Prix Joint Venture”) and a development joint venture with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of the Grand Prix NGL Pipeline (“Grand Prix DevCo JV”).

The increase in net income attributable to noncontrolling interests was partially offset by lower income allocated to Cedar Bayou Fractionators and the redemption of the Partnership’s preferred units in December 2020.

Dividends on Series A Preferred Stock decreased due to the partial repurchase of our Series A Preferred Stock in December 2020.

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

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

Results of Operations—By Reportable Segment

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Consolidated Operating Margin

(In millions)

Three Months Ended:

September 30, 2020

September 30, 2019

Nine Months Ended:

September 30, 2020

September 30, 2019

(In millions)

March 31, 2021

March 31, 2020

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)

Gross margin (1)

Operating expenses (1)

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Total Central

Badlands (7),(8)

NGL production, MBbl/d (4)

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Condensate, $/Bbl

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

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

SouthTX includes the Raptor Plant, of which we own a 50% interest through the Carnero Joint Venture.

The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants that are owned 100% by us.

Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

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

As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which we owned a 100% interest.

T arga Badlands is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

Permian crude oil volumes reflect the sale of the Delaware crude system, which was effective December 1, 2019.

Natural gas and NGL sales statistics in 2020 include statistics related to new commercial arrangements effective in January 2020, which resulted in a change from net presentation as “Fees from midstream services” to gross presentation as “Sales of commodities” and “Product purchases”.

This change in presentation did not result in an impact to our operating or gross margin.

Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes, previously shown in Other.

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

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 gross margin of Gathering and Processing segment:

Three Months Ended September 30, 2020

Three Months Ended September 30, 2019

(In millions, except volumetric data and price amounts)

Natural gas (BBtu)

Crude oil (MBbl)

Nine Months Ended September 30, 2020

Nine Months Ended September 30, 2019

Three Months Ended March 31, 2021

Three Months Ended March 31, 2020

(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, 2020 Compared to Three Months Ended September 30, 2019

Gathering and Processing segment gross margin contributions, attributable to higher system volumes and fee-based margin in the Permian region, were offset by lower volumes in the Central region and lower realized hedge gains.

In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020.

Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity.

In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019.

In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana.

Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures that resulted in decreases in compensation and benefits, contract labor and chemicals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Gathering and Processing segment gross margin contributions, attributable to higher inlet volumes and fee-based margin in the Permian region and Badlands and higher realized hedge gains, were offset by lower commodity prices and lower Central region volumes.

In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020.

Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity.

Operating expenses were lower due to cost reduction measures that resulted in decreases in contract labor, chemicals and compression rentals and lower ad valorem taxes, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020

The increase in gross margin was primarily due to higher realized commodity prices and higher Permian fee-based margin and was partially offset by the short-term operational disruption and impacts associated with a major winter storm during the first quarter of 2021.

The winter storm affected regions across Texas, Oklahoma and Louisiana and reduced our Permian and Central region volumes, which subsequently returned to pre-storm levels later in the quarter.

In the Permian, volumes were relatively flat, despite the short-term effects of the winter storm, while Central region volumes decreased due to continued low activity levels and the short-term effects of the winter storm.

In the Badlands, volumes decreased due to reduced producer activity.

In the Coastal region, volumes decreased due to continued low activity levels and the impacts of the winter storm.

Despite the addition of the Peregrine and Gateway processing facilities in the Permian, operating expenses were lower due to cost reduction measures that resulted in a decrease in chemicals, materials and contract labor expenses.

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)

Gross margin (1)

Operating expenses (1)

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Operating statistics MBbl/d (2):

Pipeline throughput (3)

Fractionation volumes

Export volumes (4)

Pipeline throughput (5)

Effective January 1, 2020, pursuant to amendments to contractual arrangements with our partners, our share of operating expenses associated with GCF, an investment in an unconsolidated affiliate, are included in operating expenses.

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.

Fractionation contracts include pricing terms composed of base fees and fuel and power components that vary with the cost of energy.

As such, the Logistics and Transportation segment results include effects of variable energy costs that impact both gross margin and operating expenses.

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.

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

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

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

The increase in Logistics and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin.

NGL transportation and fractionation margin increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020.

LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities.

Marketing margin decreased primarily due to less optimization margin realized in our marketing businesses.

Operating expenses were flat, despite the operations of a number of system expansions, including Grand Prix, additional incremental fractionation capacity and expansion of our LPG export capabilities.

Lower fuel and power costs and cost reduction measures that resulted in lower compensation and maintenance were offset by increased taxes primarily attributable to Grand Prix and the inclusion of our share of operating expenses associated with GCF.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

NGL transportation and fractionation margin increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 6 in the second quarter of 2019, Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020.

LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities.

Marketing margin decreased due to less optimization margin realized in our marketing businesses.

Operating expenses were higher primarily due to the inclusion of our share of operating expenses associated with GCF, increased costs attributable to our fractionation and LPG export expansions, higher taxes primarily attributable to Grand Prix and to additional incremental fractionation capacity , and higher maintenance primarily attributable to Grand Prix, partially offset by lower fuel and power costs.

Three Months Ended September 30,

Nine Months Ended September 30,

(In millions)

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 March 31, 2021 Compared to Three Months Ended March 31, 2020

The increase in gross margin was primarily due to higher marketing margin and higher pipeline throughput, despite the short-term operational disruptions and impacts associated with a major winter storm during the first quarter of 2021, partially offset by lower LPG export margin.

The winter storm affected regions across Texas, Oklahoma and Louisiana and reduced our downstream system volumes, which subsequently returned to pre-storm levels later in the quarter.

Marketing margin increased due to higher optimization margin.

Pipeline volumes were driven by higher supply volume primarily from the addition of new Permian processing plants in 2020, while lower fractionation volumes were largely due to the short-term operational disruption and impacts associated with the winter storm.

Operating expenses were lower in the first quarter of 2021 due to cost reduction measures, partially offset by higher taxes primarily due to system expansions that occurred throughout 2020.

Three Months Ended March 31,

(In millions)

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Our Liquidity and Capital Resources

As of September 30, 2020, we had $275.0 million of “Cash and cash equivalents,” on our Consolidated Balance Sheets.

We believe our cash position, our cash flows from operating activities 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.

As of March 31, 2021, inclusive of our consolidated joint venture accounts, we had $248.5 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.

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These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments – Response to Current Market Conditions”.

We are entitled to the entirety of distributions made by the Partnership on its equity interests, other than those made to the TRP Preferred Unitholders.

For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments”.

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 and obligations to its Preferred Unitholders may restrict or prohibit the payment of distributions if the Partnership is in default, threat of default or arrears.

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

In addition, so long as any shares of our Preferred Units 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 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 Stock (“Series A Preferred”).

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 accounts receivable securitization facility (the “Securitization Facility”) and access to debt and equity capital markets.

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

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Short-term Liquidity

Our short-term liquidity on a consolidated basis as of November 2, 2020, was:

November 2, 2020

Our short-term liquidity on a consolidated basis as of April 30, 2021, was:

April 30, 2021

(In millions)

Cash on hand (1)

Total availability under the TRC Revolver

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Total liquidity

_________________________________

Includes cash held in our consolidated joint venture accounts.

Other potential capital resources associated with our existing arrangements include:

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The TRP Revolver matures on June 29, 2023.

In the second quarter of 2020, we amended the Partnership’s Securitization Facility to decrease the facility size from $400.0 million to $250.0 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, 2021.

In the second quarter of 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.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements.

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(v) monthly swings in borrowings under the Partnership’s Securitization Facility;

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

Working capital as of September 30, 2020 increased $277.8 million compared to December 31, 2019.

The increase was primarily attributable to higher inventory balances, lower current maturities of debt from payments on our Securitization Facility and lower payables for capital expenditures and product purchases, partially offset by lower receivables resulting from lower commodity prices.

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 March 31, 2021 decreased $37.1 million compared to December 31, 2020.

The decrease was primarily attributable to the reduction in NGLs inventory, partially offset by lower borrowings on our Securitization Facility.

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.

Long-term Financing

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”), which committed a maximum of approximately $960 million of capital to the DevCo JVs.

As of September 30 , 20 20 , total contributions from Stonepeak to the DevCo JVs were $ 911.4 million .

As of September 30 , 20 20 , total contributions from funds managed by Blackstone Energy Partners (“ Blackstone ”) to the Grand Prix Joint Venture were $ 341.3 million.

These contributions from Stonepeak and Blackstone are included in noncontrolling interests.

From time to time, we issue long-term debt securities, which we refer to as senior notes.

Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums.

As of September 30, 2020 and December 31, 2019, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations, including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was $7,652.2 million and $7,440.2 million, respectively.

We consolidate the debt of the Partnership with that of our own;

however, we do not have the contractual obligation to make interest or principal payments with respect to the debt of the Partnership.

Our debt obligations do not restrict the ability of the Partnership to make distributions to us.

Our Credit Agreement has restrictions and covenants that may limit our ability to pay dividends to our stockholders.

See Note 5 – Debt Obligations for more information regarding our debt obligations.

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 TRC Revolver, the TRP Revolver and the Partnership’s Securitization Facility.

We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows.

As of September 30, 2020, we did not have any interest rate hedges.

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 February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak, which committed a maximum of approximately $960 million of capital to the DevCo JVs.

As of March 31, 2021 , total contributions from Stonepeak to the DevCo JVs were $911.9 million and are included in noncontrolling interests.

Additionally, we serve as operator of our consolidated subsidiary, the Grand Prix Joint Venture, in which Blackstone Energy Partners (“Blackstone”) owns a 25% interest.

As of March 31, 2021 , total contributions from funds managed by Blackstone to the Grand Prix Joint Venture were $347.4 million and are included in noncontrolling interests.

In 2019, we closed on the sale of a 45% interest in Targa Badlands to GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “GSO”) for $1.6 billion in cash.

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

As of September 30, 2020, the contributions from GSO were $74.0 million.

In a response to current market conditions as described under “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments,” in the first quarter of 2020, our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter.

This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt.

On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023.

In the third quarter of 2020, the Partnership issued $1.0 billion of 4⅞% Senior Notes due 2031, resulting in net proceeds of $991.0 million.

A portion of the net proceeds from the issuance were used to fund the Tender Offer and redemption payments for the 6¾% Notes, with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility.

We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.

The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs.

As of March 31, 2021 , the total contributions from GSO were $1.7 billion and are included in noncontrolling interests .

In 2019, Williams exercised its initial option to acquire a 20% equity interest in Targa Train 7 LLC and subsequently executed a joint venture agreement with us.

Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, was funded and is owned 100% by Targa.

As of March 31, 2021 , the total contributions from Williams were $47.6 million and are included in noncontrolling interests .

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

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

Additionally, TPL issued notices of redemption for all of the outstanding TPL Notes.

These notes were redeemed 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 comprised of a write-off of $0.2 million of debt issuance premiums.

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Compliance with Debt Covenants

As of September 30, 2020, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

As of March 31, 2021, 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)

The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil, (iii) changes in payables and accruals related to major growth capital projects, and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense.

The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil (iii) changes in payables and accruals related to major growth capital projects;

and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense.

In addition, we use derivative instruments to manage our exposure to commodity price risk.

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

Net cash provided by operations increased in 2020 compared to 2019 primarily due to higher operating margin and an increase in cash distributions received from unconsolidated affiliates, partially offset by an increase in interest payments as a result of higher average borrowings.

Net cash provided by operations increased in 2021 compared to 2020 primarily due to higher collections from customers, partially offset by an increase in payments for product purchases 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 2020 compared to 2019, primarily due to lower outlays for property, plant and equipment of $1,631.0 million, resulting from the completion of construction of Grand Prix, Train 6, Train 7, and additional processing plants and associated infrastructure in the Permian Basin in 2019 and early 2020.

The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system and a $241.5 million decrease in our contributions to unconsolidated affiliates primarily due to the completion of GCX Pipeline in 2019.

Cash used in investing activities decreased in 2021 compared to 2020, primarily due to lower outlays for property, plant and equipment of $245.5 million, resulting from the completion of construction of Train 7, Train 8, the LPG export expansion, the Grand Prix Central Oklahoma extension and additional processing plants and associated infrastructure in the Permian Basin in 2020.

The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system in 2020.

Cash Flows from Financing Activities

Nine Months Ended September 30,

Three Months Ended March 31,

(In millions)

Source of Financing Activities, net

Dividends and distributions

Contributions from (distributions to) noncontrolling interests

Debt, including financing costs

Sale of ownership interests in subsidiaries

Payment of contingent consideration

Net cash provided by financing activities

Contributions from (distributions to) noncontrolling interests

Dividends and distributions

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 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023, and net distributions to noncontrolling interests, partially offset by borrowings, including the issuance of the Partnership’s 4% Senior Notes due 2032.

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 distributions to noncontrolling interests are higher than our contributions from noncontrolling interests in 2020, primarily due to completion of major growth capital projects in 2019.

Our debt outstanding increased primarily due to the issuance of the 4⅞% Senior Notes due 2031 that resulted in cash proceeds of $991.0 million, partially offset by repurchasing a portion of our outstanding senior notes through open market purchases and the Tender Offer and redemption payments for the 6¾% Notes for a total of $831.0 million.

In 2019, we realized a net source of cash from financing activities primarily due to the sale of ownership interests in Targa Badlands and Train 7, net increase of debt outstanding and net contributions from noncontrolling interests.

The result was partially offset by payments of dividends and distributions, as well as the final contingent consideration payment associated with our 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin .

The issuance of 6½% Senior Notes due 2027 and 6⅞% Senior Notes due January 2029, partially offset by the redemption of 4⅛% Senior Notes due November 2019 contributed to the net increase of debt outstanding.

The contributions from noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth capital projects.

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.

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, 2020:

The following table details the dividends on common stock declared and/or paid by us for the three months ended March 31, 2021:

Three Months Ended

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(In millions, except per share amounts)

September 30, 2020

November 16, 2020

June 30, 2020

August 17, 2020

March 31, 2021

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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 $68.8 million were paid to holders of the Series A Preferred during the nine months ended September 30, 2020.

As of September 30, 2020, cash dividends accrued for our Series A Preferred were $22.9 million, which will be paid on November 13, 2020.

Cash dividends of $21.8 million were paid to holders of the Series A Preferred during the three months ended March 31, 2021.

As of March 31, 2021, cash dividends accrued for our Series A Preferred were $21.8 million, which will be paid on May 13, 2021.

Capital Expenditures

The following table details cash outlays for capital projects for the nine months ended September 30, 2020 and 2019:

Nine Months Ended September 30,

The following table details cash outlays for capital projects for the three months ended March 31, 2021 and 2020:

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, were $518.0 million and $1,870.8 million for the nine months ended September 30, 2020 and 2019.

Net contributions to investments in unconsolidated affiliates were $0.5 million and $75.4 million for the nine months ended September 30, 2020 and 2019.

Maintenance capital expenditures, net of contributions from noncontrolling interests, were $66.1 million and $95.5 million for the nine months ended September 30, 2020 and 2019.

We currently estimate that in 2020 we will invest approximately $700 million in growth capital expenditures, net of noncontrolling interests, and net contributions to investments in unconsolidated affiliates for announced projects.

Growth capital expenditures, net of contributions from noncontrolling interests, were $60.7 million and $260.9 million for the three months ended March 31, 2021 and 2020.

Net contributions to investments in unconsolidated affiliates were $0.3 million for both the three months ended March 31, 2021 and 2020.

Maintenance capital expenditures, net of contributions from noncontrolling interests, were $19.0 million and $26.3 million for the three months ended March 31, 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.

Future growth capital expenditures may vary based on investment opportunities.

We expect that 2021 maintenance capital expenditures, net of noncontrolling interests, will be approximately $130 million.

Total growth capital expenditures were lower for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019, primarily due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2019, including Grand Prix, Train 6 and additional processing plants and associated infrastructure in the Permian

Total maintenance capital expenditures were lower for the nine months ended September 30 , 20 20 as compared to the nine months ended September 3 0 , 201 9 , primarily due to timing of maintenance projects .

Total growth capital expenditures were lower for the three months ended March 31, 2021 as compared to the three ended March 31, 2020 due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2020, including Train 7, Train 8, the LPG export expansion, the Grand Prix Central Oklahoma extension and additional processing plants and associated infrastructure in the Permian Basin .

Total maintenance capital expenditures were lower for the three months ended March 31, 2021 as compared to the three ended March 31, 2020, primarily due to timing of maintenance projects.

Off-Balance Sheet Arrangements

As of September 30, 2020, there were $44.9 million in surety bonds outstanding related to various performance obligations.

As of March 31, 2021, there were $65.7 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.

1 unchanged sentence

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