Item 2. Management’s Discussion and Analysis
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2020 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.
Overview
Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic midstream infrastructure assets.
Our Operations
We are engaged primarily in the business of:
•
gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;
•
transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and
•
gathering, storing, terminaling, and purchasing and selling crude oil.
To provide these services, we operate in two primary segments: (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/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes 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.
Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.
Recent Developments
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”). The Legacy Plant is expected to begin operations in the fourth quarter of 2022.
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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”).
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.
For additional information about our debt-related transactions, see Note 5 - 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. 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. 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
29
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 . 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.
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.
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.
How We Evaluate Our Operations
The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.
Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability .
Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (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.
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Throughput Volumes, Facility Efficiencies and Fuel Consumption
Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.
In addition, we seek to increase adjusted operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.
Operating Expenses
Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.
Capital Expenditures
Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.
Capital spending associated with growth and maintenance projects is closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.
Non-GAAP Measures
We utilize non-GAAP measures to analyze our performance. Adjusted 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. 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. 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.
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Adjusted Gross Margin
We define adjusted 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.
Gathering and Processing segment adjusted gross margin consists primarily of:
•
service fees related to natural gas and crude oil gathering, treating and processing; and
•
revenues from the sale of natural gas, condensate, crude oil and NGLs less producer payments, natural gas and crude oil purchases, and our equity volume hedge settlements.
Logistics and Transportation segment adjusted gross margin consists primarily of:
•
service fees (including the pass-through of energy costs included in fee rates);
•
system product gains and losses; and
•
NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.
The adjusted 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 financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•
our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
•
the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
Management reviews business segment adjusted gross margin and operating margin 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.
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. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.
Distributable Cash Flow and Adjusted Free Cash Flow
We define distributable cash flow as adjusted EBITDA less 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 adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.
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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,
2021
2020
2021
2020
(In millions)
Reconciliation of Income (Loss) from Operations to Adjusted Operating Margin
Income (loss) from operations
$
366.5
$
295.5
$
956.4
$
(1,568.9
)
Depreciation and amortization expense
222.8
203.7
650.9
647.3
General and administrative expense
67.3
58.6
192.4
180.6
Impairment of long-lived assets
—
—
—
2,442.8
(Gain) loss on sale or disposition of business and assets
(1.5
)
58.0
(1.7
)
58.0
Write-down of assets
0.5
13.5
5.0
13.5
Other, net
—
0.7
0.1
2.3
Adjusted operating margin
$
655.6
$
630.0
$
1,803.1
$
1,775.6
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(In millions)
Reconciliation of Gross Margin to Adjusted Gross Margin
Gross Margin
$
622.2
$
588.5
$
1,697.5
$
1,635.1
Depreciation and amortization expense
222.8
203.7
650.9
647.3
Adjusted gross margin
$
845.0
$
792.2
$
2,348.4
$
2,282.4
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(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
$
182.2
$
69.3
$
384.8
$
(1,587.5
)
Income attributable to TRP preferred limited partners
—
2.8
—
8.4
Interest (income) expense, net
91.0
97.7
284.2
292.4
Income tax expense (benefit)
2.0
31.9
23.5
(286.6
)
Depreciation and amortization expense
222.8
203.7
650.9
647.3
Impairment of long-lived assets
—
—
—
2,442.8
(Gain) loss on sale or disposition of business and assets
(1.5
)
58.0
(1.7
)
58.0
Write-down of assets
0.5
13.5
5.0
13.5
(Gain) loss from financing activities (1)
—
13.7
16.6
(47.4
)
Equity (earnings) loss
(14.3
)
(18.6
)
(38.9
)
(54.1
)
Distributions from unconsolidated affiliates and preferred partner interests, net
28.2
28.2
88.4
81.6
Compensation on equity grants
14.7
16.4
44.6
49.5
Risk management activities
(12.6
)
(88.3
)
55.6
(214.2
)
Severance and related benefits
—
—
—
6.5
Noncontrolling interests adjustments (2)
(7.1
)
(9.2
)
(31.6
)
(211.7
)
TRC Adjusted EBITDA
$
505.9
$
419.1
$
1,481.4
$
1,198.5
Distributions to TRP preferred limited partners
—
(2.8
)
—
(8.4
)
Interest expense on debt obligations (3)
(91.6
)
(98.2
)
(285.8
)
(289.5
)
Maintenance capital expenditures
(31.1
)
(27.3
)
(78.4
)
(67.7
)
Noncontrolling interests adjustments of maintenance capital expenditures
1.5
3.9
5.5
1.6
Cash taxes
(0.8
)
—
(2.0
)
44.4
Distributable Cash Flow
$
383.9
$
294.7
$
1,120.7
$
878.9
Growth capital expenditures, net (4)
(86.7
)
(105.4
)
(227.9
)
(518.5
)
Adjusted Free Cash Flow
$
297.2
$
189.3
$
892.8
$
360.4
(1)
Gains or losses on debt repurchases or early debt extinguishments.
( 2 )
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.
( 3 )
Excludes amortization of interest expense.
( 4 )
Represents growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates.
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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,
2021
2020
2021 vs. 2020
2021
2020
2021 vs. 2020
(In millions)
Revenues:
Sales of commodities
$
4,118.1
$
1,840.8
$
2,277.3
124
%
$
10,577.3
$
4,900.8
$
5,676.5
116
%
Fees from midstream services
341.6
274.3
67.3
25
%
930.9
786.7
144.2
18
%
Total revenues
4,459.7
2,115.1
2,344.6
111
%
11,508.2
5,687.5
5,820.7
102
%
Product purchases and fuel (1)
3,614.7
1,322.9
2,291.8
173
%
9,159.8
3,405.1
5,754.7
169
%
Operating expenses (1)
189.4
162.2
27.2
17
%
545.3
506.8
38.5
8
%
Depreciation and amortization expense
222.8
203.7
19.1
9
%
650.9
647.3
3.6
1
%
General and administrative expense
67.3
58.6
8.7
15
%
192.4
180.6
11.8
7
%
Impairment of long-lived assets
—
—
—
—
—
2,442.8
(2,442.8
)
(100
%)
Other operating (income) expense
(1.0
)
72.2
(73.2
)
(101
%)
3.4
73.8
(70.4
)
(95
%)
Income (loss) from operations
366.5
295.5
71.0
24
%
956.4
(1,568.9
)
2,525.3
161
%
Interest expense, net
(91.0
)
(97.7
)
6.7
7
%
(284.2
)
(292.4
)
8.2
3
%
Equity earnings (loss)
14.3
18.6
(4.3
)
(23
%)
38.9
54.1
(15.2
)
(28
%)
Gain (loss) from financing activities
—
(13.7
)
13.7
100
%
(16.6
)
47.4
(64.0
)
(135
%)
Other, net
0.2
1.4
(1.2
)
NM
0.3
2.2
(1.9
)
NM
Income tax (expense) benefit
(2.0
)
(31.9
)
29.9
94
%
(23.5
)
286.6
(310.1
)
(108
%)
Net income (loss)
288.0
172.2
115.8
67
%
671.3
(1,471.0
)
2,142.3
146
%
Less: Net income (loss) attributable to noncontrolling interests
105.8
102.9
2.9
3
%
286.5
116.5
170.0
146
%
Net income (loss) attributable to Targa Resources Corp.
182.2
69.3
112.9
163
%
384.8
(1,587.5
)
1,972.3
124
%
Dividends on Series A Preferred Stock
21.8
22.9
(1.1
)
(5
%)
65.5
68.8
(3.3
)
(5
%)
Deemed dividends on Series A Preferred Stock
—
9.5
(9.5
)
(100
%)
—
27.7
(27.7
)
(100
%)
Net income (loss) attributable to common shareholders
$
160.4
$
36.9
$
123.5
NM
$
319.3
$
(1,684.0
)
$
2,003.3
119
%
Financial data:
Adjusted EBITDA (2)
$
505.9
$
419.1
$
86.8
21
%
$
1,481.4
$
1,198.5
$
282.9
24
%
Distributable cash flow (2)
383.9
294.7
89.2
30
%
1,120.7
878.9
241.8
28
%
Adjusted free cash flow (2)
297.2
189.3
107.9
57
%
892.8
360.4
532.4
148
%
(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.
(2)
Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”
NM
Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful 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.
34
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.
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.
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.
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.
35
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.
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.
Results of Operations—By Reportable Segment
Our operating margins by reportable segment are:
Gathering and
Processing
Logistics and Transportation
Other
Total
(In millions)
Three Months Ended:
September 30, 2021
$
361.4
$
280.7
$
13.5
$
655.6
September 30, 2020
261.0
280.4
88.6
630.0
Nine Months Ended:
September 30, 2021
$
938.2
$
920.5
$
(55.6
)
$
1,803.1
September 30, 2020
753.7
806.0
215.9
1,775.6
36
Gathering and Processing Segment
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021 vs. 2020
2021
2020
2021 vs. 2020
(In millions, except operating statistics and price amounts)
Operating margin
$
361.4
$
261.0
$
100.4
38
%
$
938.2
$
753.7
$
184.5
24
%
Operating expenses (1)
122.8
102.1
20.7
20
%
343.1
313.6
29.5
9
%
Adjusted gross margin (1)
$
484.2
$
363.1
$
121.1
33
%
$
1,281.3
$
1,067.3
$
214.0
20
%
Operating statistics (2):
Plant natural gas inlet, MMcf/d (3),(4)
Permian Midland (5)
2,109.2
1,811.5
297.7
16
%
1,900.7
1,722.1
178.6
10
%
Permian Delaware
842.7
758.1
84.6
11
%
805.9
712.4
93.5
13
%
Total Permian
2,951.9
2,569.6
382.3
2,706.6
2,434.5
272.1
SouthTX
180.5
233.6
(53.1
)
(23
%)
184.0
261.5
(77.5
)
(30
%)
North Texas
180.7
197.8
(17.1
)
(9
%)
179.2
206.3
(27.1
)
(13
%)
SouthOK
420.6
386.9
33.7
9
%
402.6
463.3
(60.7
)
(13
%)
WestOK
219.4
233.6
(14.2
)
(6
%)
211.6
258.7
(47.1
)
(18
%)
Total Central
1,001.2
1,051.9
(50.7
)
977.4
1,189.8
(212.4
)
Badlands (6)
135.2
137.0
(1.8
)
(1
%)
137.8
136.1
1.7
1
%
Total Field
4,088.3
3,758.5
329.8
3,821.8
3,760.4
61.4
Coastal
527.1
522.8
4.3
1
%
598.3
672.9
(74.6
)
(11
%)
Total
4,615.4
4,281.3
334.1
8
%
4,420.1
4,433.3
(13.2
)
—
NGL production, MBbl/d (4)
Permian Midland (5)
307.3
253.0
54.3
21
%
274.8
247.6
27.2
11
%
Permian Delaware
119.8
105.3
14.5
14
%
109.3
97.1
12.2
13
%
Total Permian
427.1
358.3
68.8
384.1
344.7
39.4
SouthTX
24.2
29.2
(5.0
)
(17
%)
22.6
28.7
(6.1
)
(21
%)
North Texas
21.0
23.7
(2.7
)
(11
%)
20.2
24.5
(4.3
)
(18
%)
SouthOK
52.1
45.9
6.2
14
%
48.8
54.6
(5.8
)
(11
%)
WestOK
15.7
19.3
(3.6
)
(19
%)
16.2
21.2
(5.0
)
(24
%)
Total Central
113.0
118.1
(5.1
)
107.8
129.0
(21.2
)
Badlands
16.2
17.0
(0.8
)
(5
%)
16.0
16.3
(0.3
)
(2
%)
Total Field
556.3
493.4
62.9
507.9
490.0
17.9
Coastal
28.0
32.5
(4.5
)
(14
%)
34.5
41.5
(7.0
)
(17
%)
Total
584.3
525.9
58.4
11
%
542.4
531.5
10.9
2
%
Crude oil, Badlands, MBbl/d
140.8
146.4
(5.6
)
(4
%)
138.7
160.4
(21.7
)
(14
%)
Crude oil, Permian, MBbl/d
34.1
44.6
(10.5
)
(24
%)
35.3
45.3
(10.0
)
(22
%)
Natural gas sales, BBtu/d (4)
2,319.9
2,032.3
287.6
14
%
2,162.5
2,079.3
83.2
4
%
NGL sales, MBbl/d (4)
412.6
389.5
23.1
6
%
384.7
406.0
(21.3
)
(5
%)
Condensate sales, MBbl/d
15.4
13.6
1.8
13
%
15.3
16.1
(0.8
)
(5
%)
Average realized prices - inclusive of hedges (7):
Natural gas, $/MMBtu
3.51
1.34
2.17
162
%
2.85
1.10
1.75
159
%
NGL, $/gal
0.69
0.29
0.40
138
%
0.56
0.24
0.32
133
%
Condensate, $/Bbl
64.41
43.49
20.92
48
%
56.86
38.56
18.30
47
%
(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.
(2)
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.
( 3 )
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.
( 4 )
Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.
( 5 )
Permian Midland includes operations in WestTX, of which we own 72.8%, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
( 6 )
Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.
( 7 )
Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator.
37
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)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Natural gas (BBtu)
20.5
$
(1.52
)
$
(31.2
)
17.5
$
0.20
$
3.5
NGL (MMgal)
150.4
(0.35
)
(52.4
)
126.4
0.08
10.5
Crude oil (MBbl)
0.5
(18.80
)
(9.4
)
0.5
16.75
8.0
$
(93.0
)
$
22.0
(1)
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
(In millions, except volumetric data and price amounts)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Natural gas (BBtu)
56.6
$
(1.01
)
$
(57.2
)
50.6
$
0.55
$
27.7
NGL (MMgal)
420.0
(0.24
)
(99.3
)
322.1
0.15
49.7
Crude oil (MBbl)
1.6
(11.38
)
(18.2
)
1.4
19.72
27.7
$
(174.7
)
$
105.1
(1)
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.
Logistics and Transportation Segment
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021 vs. 2020
2021
2020
2021 vs. 2020
(In millions, except operating statistics and price amounts)
Operating margin
$
280.7
$
280.4
$
0.3
—
$
920.5
$
806.0
$
114.5
14%
Operating expenses (1)
67.3
61.7
5.6
9%
204.1
196.8
7.3
4%
Adjusted gross margin (1)
$
348.0
$
342.1
$
5.9
2%
$
1,124.6
$
1,002.8
$
121.8
12%
Operating statistics MBbl/d (2):
Pipeline throughput (3)
416.5
300.9
115.6
38%
383.8
273.0
110.8
41%
Fractionation volumes
662.0
589.5
72.5
12%
617.5
598.0
19.5
3%
Export volumes (4)
293.2
308.5
(15.3
)
(5%)
305.7
277.2
28.5
10%
NGL sales
857.3
724.1
133.2
18%
881.1
721.6
159.5
22%
38
(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.
(2)
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.
(3)
Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu.
( 4 )
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. 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.
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.
Other
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021 vs. 2020
2021
2020
2021 vs. 2020
(In millions)
Operating margin
$
13.5
$
88.6
$
(75.1
)
$
(55.6
)
$
215.9
$
(271.5
)
Gross margin
$
13.5
$
88.6
$
(75.1
)
$
(55.6
)
$
215.9
$
(271.5
)
Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 3. – Quantitative and Qualitative Disclosures About Market Risk.”
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. 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.
39
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. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, 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 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. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.
Short-term Liquidity
Our short-term liquidity on a consolidated basis as of October 29, 2021, was:
October 29, 2021
TRC
TRP
Consolidated
Total
(In millions)
Cash on hand (1)
$
26.4
$
280.7
$
307.1
Total availability under the TRC Revolver
670.0
—
670.0
Total availability under the TRP Revolver
—
2,200.0
2,200.0
Total availability under the Partnership's Securitization Facility
—
400.0
400.0
696.4
2,880.7
3,577.1
Less: Outstanding borrowings under the TRC Revolver
—
—
—
Outstanding borrowings under the TRP Revolver
—
—
—
Outstanding borrowings under the Partnership's Securitization Facility
—
(400.0
)
(400.0
)
Outstanding letters of credit under the TRP Revolver
—
(48.8
)
(48.8
)
Total liquidity
$
696.4
$
2,431.9
$
3,128.3
_________________________________
(1)
Includes cash held in our consolidated joint venture accounts.
Other potential capital resources associated with our existing arrangements include:
•
Our right to request an additional $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.
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.
40
Working Capital
Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels and valuation, which we closely manage; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Partnership’s Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.
Working capital as of 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.
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. 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, 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.
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 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. 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.
To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 5 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”
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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.
Cash Flow
Cash Flows from Operating Activities
Nine Months Ended September 30,
2021
2020
2021 vs. 2020
(In millions)
$
1,798.8
$
1,095.7
$
703.1
The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs and natural gas, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil (iii) changes in payables and accruals related to major growth capital projects; and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.
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.
Cash Flows from Investing Activities
Nine Months Ended September 30,
2021
2020
2021 vs. 2020
(In millions)
$
(299.6
)
$
(654.0
)
$
354.4
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.
Cash Flows from Financing Activities
Nine Months Ended September 30,
2021
2020
(In millions)
Source of Financing Activities, net
Debt, including financing costs
$
(996.0
)
$
130.1
Contributions from (distributions to) noncontrolling interests
(364.1
)
(277.3
)
Dividends and distributions
(140.2
)
(345.1
)
Other
(13.1
)
(5.5
)
Net cash provided by (used in) financing activities
$
(1,513.4
)
$
(497.8
)
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.
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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:
Three Months Ended
Date Paid or
To Be Paid
Total Common
Dividends Declared
Amount of Common
Dividends Paid or
To Be Paid
Accrued
Dividends (1)
Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
September 30, 2021
November 15, 2021
$
23.3
$
22.9
$
0.4
$
0.10000
June 30, 2021
August 16, 2021
23.3
22.9
0.4
0.10000
March 31, 2021
May 14, 2021
23.3
22.9
0.4
0.10000
December 31, 2020
February 16, 2021
23.3
22.9
0.4
0.10000
(1)
Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
Preferred Stock 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.
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,
2021
2020
(In millions)
Capital expenditures:
Growth (1)
$
238.1
$
542.6
Maintenance (2)
78.4
67.7
Gross capital expenditures
316.5
610.3
Transfers from materials and supplies inventory to property, plant and equipment
(2.4
)
(1.9
)
Change in capital project payables and accruals, net
7.5
194.7
Cash outlays for capital projects
$
321.6
$
803.1
(1)
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.
(2)
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. Future growth capital expenditures may vary based on investment opportunities. We expect that 2021 maintenance capital expenditures, net of noncontrolling interests, will be approximately $120 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. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.
43