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, 2021 (“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. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.
Recent Developments
Permian Midland Processing Expansion
In August 2021, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Legacy plant”). The Legacy plant is expected to begin operations late in the third quarter of 2022.
In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Legacy II plant”). The Legacy II plant is expected to begin operations in the second quarter of 2023.
30
In August 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Greenwood plant”). The Greenwood plant is expected to begin operations late in the fourth quarter of 2023.
Permian Delaware Processing Expansion
In February 2022, in response to increasing production and to meet the infrastructure needs of producers, we announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Midway plant”). The Midway plant is expected to begin operations in the third quarter of 2023. In conjunction with the commencement of operations of the Midway plant, we expect to idle the Sand Hills plant.
Fractionation Expansion
In August 2022, we announced plans to construct a new 120 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 9”). Train 9 is expected to begin operations in the second quarter of 2024.
Capital Investments and Divestitures
In January 2022, we closed on the purchase of all of Stonepeak Infrastructure Partners’ (“Stonepeak”) interests in our development company joint ventures (“DevCo JVs”) for $926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we own a 75% interest in Grand Prix Pipeline LLC, a 100% interest in the Train 6 fractionator in Mont Belvieu, Texas and owned a 25% equity interest in Gulf Coast Express Pipeline (“GCX”), prior to the GCX Sale (as defined below) in February 2022. The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax was $53.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. In addition, the DevCo JV Repurchase resulted in an $857.9 million reduction of Noncontrolling interests on our Consolidated Balance Sheets.
In April 2022, we closed on the bolt-on acquisition of Southcross Energy Operating LLC and its subsidiaries (“Southcross”) for a purchase price of $201.9 million (the “Southcross Acquisition”), subject to customary closing adjustments. We expect to make a final closing adjustment payment of approximately $4 million in the third quarter of 2022. We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and have been prospectively consolidated beginning in the second quarter of 2022. See Note 4 - Joint Ventures, Acquisitions and Divestitures and Note 6 - Investments in Unconsolidated Affiliates to our Consolidated Financial Statements .
In May 2022, we completed the sale of Targa GCX Pipeline LLC to a third party for $857.0 million (the “GCX Sale”). As a result of the GCX Sale, we recognized a gain of $435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations during the three and six months ended June 30, 2022.
On July 29, 2022, we closed on the acquisition of Lucid Energy Delaware, LLC (“Lucid”) from Riverstone Holdings LLC and Goldman Sachs Asset Management for approximately $3.55 billion in cash (the “Lucid Acquisition”), subject to customary closing adjustments. Lucid provides natural gas gathering, treating, and processing services in the Delaware Basin, and owns and operates 1,050 miles of natural gas pipelines and approximately 1.4 billion cubic feet per day (“Bcf/d”) of cryogenic natural gas processing capacity in service or under construction located primarily in Eddy and Lea counties of New Mexico. Lucid’s Delaware Basin assets are integrated into our Permian Delaware operations.
Common Share Repurchases and Preferred Stock Redemption
During the second quarter of 2022, we repurchased 1,121,925 shares of our common stock at a weighted average price of $66.07 for a total net cost of $74.1 million. From July 1 through July 29, 2022, we repurchased 512,336 shares of our common stock at a weighted average price of $58.57 for a total net cost of $30.0 million. There was $214.7 million remaining under our $500 million common share repurchase program as of July 29, 2022.
In May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, of which $215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A
31
Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to our C onsolidated F inancial S tatements.
Financing Activities
In February 2022, we entered into a Credit Agreement with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto (the “TRGP Revolver”). The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $2.75 billion (with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver), including a swing line sub-facility of up to $100.0 million. The TRGP Revolver matures on February 17, 2027. In connection with our entry into the TRGP Revolver, we terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership’s senior secured revolving credit facility (the “Partnership Revolver”). In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC (“S&P”) and Fitch Ratings Inc. (“Fitch”), and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”). As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations thereunder. As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss due to debt extinguishment of $0.8 million.
In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of June 30, 2022, $5.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.
In March 2022, the Partnership redeemed all of the outstanding 5.375% Senior Notes due 2027 (the “5.375% Notes”) with available liquidity under the TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million comprised of $12.6 million of premiums paid and a write-off of $2.4 million of debt issuance costs.
In April 2022, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.200% Senior Notes due 2033 (the “4.200% Notes”) and (ii) $750.0 million aggregate principal amount of our 4.950% Senior Notes due 2052 (the “4.950% Notes”), resulting in net proceeds of approximately $1.5 billion. A portion of the net proceeds from the issuance was used to fund the concurrent cash tender offer (the “March Tender Offer”) and the subsequent redemption payment of the Partnership’s 5.875% Senior Notes due 2026 (the “5.875% Notes”), with the remainder of the net proceeds used for repayment of the outstanding borrowings under the TRGP Revolver. As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we recorded a loss due to debt extinguishment of $33.8 million comprised of $29.3 million of premiums paid and a write-off of $4.5 million of debt issuance costs.
In April 2022, the Partnership amended the $400.0 million accounts receivable securitization facility (“Securitization Facility”) to, among other things, extend the facility termination date to April 19, 2023 and replace the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR.
In July 2022, we completed an underwritten public offering of (i) $750.0 million in aggregate principal amount of our 5.200% Senior Notes due 2027 (the “5.200% Notes”) and (ii) $500.0 million in aggregate principal amount of our 6.250% Senior Notes due 2052 (the “6.250% Notes”), resulting in net proceeds of approximately $1.2 billion. We used the net proceeds from the issuance to fund a portion of the Lucid Acquisition.
In July 2022, we entered into the Term Loan Agreement with Mizuho Bank, Ltd. as the Administrative Agent and a lender, and other lenders party thereto (the “Term Loan Facility”). The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility. The Term Loan Facility matures in July 2025. We used the proceeds to fund a portion of the Lucid Acquisition.
In July 2022, we established an unsecured commercial paper note program (the “Commercial Paper Program”). Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. We had no amounts outstanding under the Commercial Paper Program as of July 29, 2022.
For additional information about our debt-related transactions, see Note 7 - Debt Obligations to our Consolidated Financial Statements.
32
Corporation Tax Matters
In January 2022, the Internal Revenue Service (“IRS”) notified us that it will examine Targa’s net operating loss (“NOL”) carryback previously claimed under the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. The CARES Act was signed into law on March 27, 2020 and provided corporate taxpayers an expanded five-year NOL carryback period for losses generated in tax years 2018 through 2020. We received a cash refund of approximately $44 million related to the CARES Act provisions in 2020. We have responded to information requests from the IRS and do not anticipate material changes in prior year taxable income.
On October 6, 2021 and April 7, 2022, we received notice from the IRS that it intends to audit three direct and indirectly wholly-owned subsidiaries of the Company (Targa Resources Partners LP, Targa Downstream LLC and Targa Midstream Services LLC) treated as partnerships for federal tax purposes for the 2019 and 2020 tax years. We are responding to the information requests from the IRS on these audits. The Company is not aware of any potential audit findings that would give rise to adjustments to taxable income and does not anticipate material changes related to these audits.
FERC Regulatory Matters
On January 20, 2022, FERC issued an order on rehearing of its December 17, 2020 Order Establishing Index Level in which the Commission reduced the oil pricing index factor for oil pipelines to use for the current five-year period. As a result, the ceiling levels computed for July 1, 2021 to June 30, 2022, and the resulting rates for certain of Targa’s liquids pipelines were recomputed to account for the reduced index factor.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies to 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 EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment).
Throughput Volumes, Facility Efficiencies and Fuel Consumption
Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our
33
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 EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.
Adjusted Operating Margin
We define adjusted operating margin for our segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.
34
Gathering and Processing adjusted operating margin consists primarily of:
•
service fees related to natural gas and crude oil gathering, treating and processing; and
•
revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and our equity volume hedge settlements.
Logistics and Transportation adjusted operating margin consists primarily of:
•
service fees (including the pass-through of energy costs included in certain fee rates);
•
system product gains and losses; and
•
NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.
The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Adjusted operating margin for our segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of our financial statements, including investors and commercial banks, to assess:
•
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•
our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
•
the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”
Adjusted EBITDA
We define adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.
Distributable Cash Flow and Adjusted Free Cash Flow
We define distributable cash flow as adjusted EBITDA less cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). We define adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.
35
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 June 30,
Six Months Ended June 30,
2022
2021
2022
2021
(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.
$
596.4
$
56.2
$
684.4
$
202.6
Interest (income) expense, net
81.2
94.8
174.7
193.2
Income tax expense (benefit)
87.1
6.6
110.1
21.6
Depreciation and amortization expense
269.9
211.9
479.0
428.0
(Gain) loss on sale or disposition of assets
(0.6
)
(0.4
)
(1.6
)
(0.2
)
Write-down of assets
0.5
1.1
1.0
4.7
(Gain) loss from financing activities (1)
33.8
1.9
49.6
16.6
(Gain) loss from sale of equity method investment
(435.9
)
—
(435.9
)
—
Equity (earnings) loss
(1.4
)
(12.8
)
(7.0
)
(24.6
)
Distributions from unconsolidated affiliates and preferred partner interests, net
6.8
26.9
19.3
60.2
Compensation on equity grants
13.8
15.0
27.3
29.9
Risk management activities
4.5
69.7
182.7
68.2
Noncontrolling interests adjustments (2)
10.3
(10.9
)
8.5
(24.5
)
Adjusted EBITDA
$
666.4
$
460.0
$
1,292.1
$
975.7
Interest expense on debt obligations (3)
(90.7
)
(95.5
)
(182.2
)
(194.2
)
Maintenance capital expenditures, net (4)
(39.7
)
(24.2
)
(77.4
)
(43.2
)
Cash taxes
(2.6
)
(0.8
)
(4.3
)
(1.3
)
Distributable Cash Flow
$
533.4
$
339.5
$
1,028.2
$
737.0
Growth capital expenditures, net (4)
(199.3
)
(83.4
)
(320.7
)
(144.4
)
Adjusted Free Cash Flow
$
334.1
$
256.1
$
707.5
$
592.6
(1)
Gains or losses on debt repurchases or early debt extinguishments.
( 2 )
Noncontrolling interest portion of depreciation and amortization expense.
( 3 )
Excludes amortization of interest expense.
( 4 )
Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates.
36
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations:
Three Months Ended June 30,
Six Months Ended June 30,
2022
2021
2022 vs. 2021
2022
2021
2022 vs. 2021
(In millions)
Revenues:
Sales of commodities
$
5,624.2
$
3,091.6
$
2,532.6
82
%
$
10,190.3
$
6,459.3
$
3,731.0
58
%
Fees from midstream services
431.6
324.3
107.3
33
%
824.6
589.4
235.2
40
%
Total revenues
6,055.8
3,415.9
2,639.9
77
%
11,014.9
7,048.7
3,966.2
56
%
Product purchases and fuel
5,047.3
2,709.0
2,338.3
86
%
9,251.5
5,545.3
3,706.2
67
%
Operating expenses
215.8
184.8
31.0
17
%
399.3
355.8
43.5
12
%
Depreciation and amortization expense
269.9
211.9
58.0
27
%
479.0
428.0
51.0
12
%
General and administrative expense
71.0
63.7
7.3
11
%
138.0
125.1
12.9
10
%
Other operating (income) expense
(0.1
)
0.7
(0.8
)
(114
%)
(0.6
)
4.6
(5.2
)
(113
%)
Income (loss) from operations
451.9
245.8
206.1
84
%
747.7
589.9
157.8
27
%
Interest expense, net
(81.2
)
(94.8
)
13.6
14
%
(174.7
)
(193.2
)
18.5
10
%
Equity earnings (loss)
1.4
12.8
(11.4
)
(89
%)
7.0
24.6
(17.6
)
(72
%)
Gain (loss) from financing activities
(33.8
)
(1.9
)
(31.9
)
NM
(49.6
)
(16.6
)
(33.0
)
199
%
Gain (loss) from sale of equity method investment
435.9
—
435.9
100
%
435.9
—
435.9
100
%
Other, net
0.5
0.1
0.4
NM
—
0.2
(0.2
)
(100
%)
Income tax (expense) benefit
(87.1
)
(6.6
)
(80.5
)
NM
(110.1
)
(21.6
)
(88.5
)
NM
Net income (loss)
687.6
155.4
532.2
NM
856.2
383.3
472.9
123
%
Less: Net income (loss) attributable to noncontrolling interests
91.2
99.2
(8.0
)
(8
%)
171.8
180.7
(8.9
)
(5
%)
Net income (loss) attributable to Targa Resources Corp.
596.4
56.2
540.2
NM
684.4
202.6
481.8
238
%
Premium on repurchase of noncontrolling interests, net of tax
—
—
—
—
53.1
—
53.1
100
%
Dividends on Series A Preferred Stock
8.2
21.8
(13.6
)
(62
%)
30.0
43.7
(13.7
)
(31
%)
Deemed dividends on Series A Preferred Stock
215.5
—
215.5
100
%
215.5
—
215.5
100
%
Net income (loss) attributable to common shareholders
$
372.7
$
34.4
$
338.3
NM
$
385.8
$
158.9
$
226.9
143
%
Financial data:
Adjusted EBITDA (1)
$
666.4
$
460.0
$
206.4
45
%
$
1,292.1
$
975.7
$
316.4
32
%
Distributable cash flow (1)
533.4
339.5
193.9
57
%
1,028.2
737.0
291.2
40
%
Adjusted free cash flow (1)
334.1
256.1
78.0
30
%
707.5
592.6
114.9
19
%
(1)
Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”
NM
Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful or material.
Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021
The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($2,506.1 million) and higher NGL and natural gas volumes ($98.0 million), partially offset by the unfavorable impact of hedges ($66.5 million).
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, and transportation and fractionation fees.
The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes.
The increase in operating expenses was due to higher labor and maintenance costs primarily due to increased activity, system expansions and inflation.
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
The increase in depreciation and amortization expense is primarily due to the impact of system expansions on our asset base and the shortening of the depreciable lives of certain assets that have been, or will be, idled.
The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.
37
The decrease in interest expense, net is primarily due to higher non-cash interest income related to a decrease in the mandatorily redeemable preferred interest liability.
The decrease in equity earnings is primarily due to the GCX Sale and lower earnings from our investment in Little Missouri 4 LLC, partially offset by lower losses from our investments in T2 Eagle Ford Gathering Company L.L.C., Gulf Coast Fractionators and T2 LaSalle Gathering Company L.L.C. See Note 4 – Joint Ventures, Acquisitions and Divestitures to our Consolidated Financial Statements for further discussion.
During 2022, the Partnership redeemed the 5.875% Notes, resulting in a net loss from financing activities. During 2021, the Partnership redeemed the 4.250% Senior Notes due 2023 (the “4.250% Notes”), resulting in a net loss from financing activities. See Note 7 – Debt Obligations for further discussion.
During 2022, we completed the GCX Sale resulting in a gain from sale of an equity method investment. See Note 4 – Joint Ventures, Acquisitions and Divestitures for further discussion.
The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a larger release of the valuation allowance in 2022 compared to 2021.
During 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, of which $215.5 million was recorded as deemed dividends. Dividends on Series A Preferred decreased as a result of the redemption. See Note 9 – Preferred Stock for further discussion.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($3,890.3 million) and higher NGL and natural gas volumes ($100.0 million), partially offset by the unfavorable impact of hedges ($254.5 million).
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, transportation and fractionation fees and export volumes.
The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes.
The increase in operating expenses was due to higher labor and maintenance costs primarily due to increased activity, system expansions and inflation, partially offset by lower taxes and the impact of a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana during the first quarter of 2021.
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
The increase in depreciation and amortization expense is primarily due to system expansions on our asset base and the shortening of the depreciable lives of certain assets that have been, or will be, idled, partially offset by a lower depreciable base associated with assets that were impaired during the fourth quarter of 2021.
The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.
The decrease in interest expense, net is primarily due to higher non-cash interest income related to a decrease in the mandatorily redeemable preferred interest liability, lower interest rates on debt and higher capitalized interest.
38
The decrease in equity earnings is primarily due to the GCX Sale and lower earnings from our investment in Little Missouri 4 LLC, partially offset by lower losses from our investments in T2 Eagle Ford Gathering Company L.L.C., Gulf Coast Fractionators and T2 LaSalle Gathering Company L.L.C. See Note 4 – Joint Ventures, Acquisitions and Divestitures to our Consolidated Financial Statements for further discussion.
During 2022, we terminated the Previous TRGP Revolver and the Partnership Revolver. In addition, the Partnership redeemed the 5.375% Notes and 5.875% Notes. These transactions resulted in a net loss from financing activities. During 2021, the Partnership redeemed its 5.125% Senior Notes due 2025 and the 4.250% Notes. In addition, Targa Pipeline Partners LP redeemed its 4.750% Senior Notes due 2021 and the 5.875% Senior Notes due 2023. These transactions resulted in a net loss from financing activities. See Note 7 – Debt Obligations for further discussion.
During 2022, we completed the GCX Sale resulting in a gain from sale of an equity method investment. See Note 4 – Joint Ventures, Acquisitions and Divestitures for further discussion.
The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a larger release of the valuation allowance in 2022 compared to 2021.
During 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, of which $215.5 million was recorded as deemed dividends. Dividends on Series A Preferred decreased as a result of the redemption. See Note 9 – Preferred Stock for further discussion.
Results of Operations—By Reportable Segment
Our operating margins by reportable segment are:
Gathering and
Processing
Logistics and Transportation
Other
(In millions)
Three Months Ended:
June 30, 2022
$
474.7
$
322.3
$
(4.5
)
June 30, 2021
301.2
291.4
(70.5
)
Six Months Ended:
June 30, 2022
$
872.3
$
674.5
$
(182.7
)
June 30, 2021
576.6
640.1
(69.1
)
39
Gathering and Processing Segment
Three Months Ended June 30,
Six Months Ended June 30,
2022
2021
2022 vs. 2021
2022
2021
2022 vs. 2021
(In millions, except operating statistics and price amounts)
Operating margin
$
474.7
$
301.2
$
173.5
58
%
$
872.3
$
576.6
$
295.7
51
%
Operating expenses
141.4
115.1
26.3
23
%
258.0
220.5
37.5
17
%
Adjusted operating margin
$
616.1
$
416.3
$
199.8
48
%
$
1,130.3
$
797.1
$
333.2
42
%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)
2,132.0
1,929.7
202.3
10
%
2,103.7
1,794.7
309.0
17
%
Permian Delaware
993.3
836.2
157.1
19
%
985.1
787.2
197.9
25
%
Total Permian
3,125.3
2,765.9
359.4
3,088.8
2,581.9
506.9
SouthTX (5)
271.2
194.9
76.3
39
%
216.9
185.7
31.2
17
%
North Texas
175.3
181.4
(6.1
)
(3
%)
175.3
178.4
(3.1
)
(2
%)
SouthOK (5)
460.4
411.4
49.0
12
%
434.0
393.4
40.6
10
%
WestOK
212.0
212.5
(0.5
)
—
207.2
207.6
(0.4
)
—
Total Central
1,118.9
1,000.2
118.7
1,033.4
965.1
68.3
Badlands (5) (6)
129.4
143.4
(14.0
)
(10
%)
127.2
139.1
(11.9
)
(9
%)
Total Field
4,373.6
3,909.5
464.1
4,249.4
3,686.1
563.3
Coastal
553.6
616.6
(63.0
)
(10
%)
577.7
634.5
(56.8
)
(9
%)
Total
4,927.2
4,526.1
401.1
9
%
4,827.1
4,320.6
506.5
12
%
NGL production, MBbl/d (3)
Permian Midland (4)
310.6
279.4
31.2
11
%
305.7
258.4
47.3
18
%
Permian Delaware
135.8
111.7
24.1
22
%
132.8
104.1
28.7
28
%
Total Permian
446.4
391.1
55.3
438.5
362.5
76.0
SouthTX (5)
33.5
25.8
7.7
30
%
26.9
21.7
5.2
24
%
North Texas
19.6
20.4
(0.8
)
(4
%)
19.4
19.8
(0.4
)
(2
%)
SouthOK (5)
55.8
50.4
5.4
11
%
53.1
47.1
6.0
13
%
WestOK
16.6
17.0
(0.4
)
(2
%)
15.8
16.5
(0.7
)
(4
%)
Total Central
125.5
113.6
11.9
115.2
105.1
10.1
Badlands (5)
14.7
16.2
(1.5
)
(9
%)
14.7
15.9
(1.2
)
(8
%)
Total Field
586.6
520.9
65.7
568.4
483.5
84.9
Coastal
36.7
35.7
1.0
3
%
36.9
37.8
(0.9
)
(2
%)
Total
623.3
556.6
66.7
12
%
605.3
521.3
84.0
16
%
Crude oil, Badlands, MBbl/d
111.8
138.9
(27.1
)
(20
%)
117.2
137.6
(20.4
)
(15
%)
Crude oil, Permian, MBbl/d
28.8
36.7
(7.9
)
(22
%)
29.7
35.8
(6.1
)
(17
%)
Natural gas sales, BBtu/d (3)
2,277.1
2,207.5
69.6
3
%
2,202.1
2,082.4
119.7
6
%
NGL sales, MBbl/d (3)
440.4
391.9
48.5
12
%
432.7
370.5
62.2
17
%
Condensate sales, MBbl/d
15.7
15.2
0.5
3
%
15.0
15.2
(0.2
)
(1
%)
Average realized prices - inclusive of hedges (7):
Natural gas, $/MMBtu
6.12
2.45
3.67
150
%
5.15
2.48
2.67
108
%
NGL, $/gal
0.89
0.51
0.38
75
%
0.84
0.49
0.35
71
%
Condensate, $/Bbl
103.10
59.06
44.04
75
%
90.06
52.97
37.09
70
%
(1)
Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
(2)
Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands.
( 3 )
Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.
( 4 )
Permian Midland includes operations in WestTX, of which we own 72.8% undivided interest, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
( 5 )
Operations include facilities that are not wholly owned by us.
( 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.
40
The following table presents the realized commodity hedge gain ( loss ) attributable to our equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment:
Three Months Ended June 30, 2022
Three Months Ended June 30, 2021
(In millions, except volumetric data and price amounts)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Natural gas (BBtu)
16.7
$
(3.29
)
$
(54.9
)
18.1
$
(0.71
)
$
(12.8
)
NGL (MMgal)
164.4
(0.47
)
(77.9
)
133.8
(0.18
)
(24.4
)
Crude oil (MBbl)
0.5
(51.00
)
(25.5
)
0.5
(12.69
)
(6.7
)
$
(158.3
)
$
(43.9
)
(1)
The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
Six Months Ended June 30, 2022
Six Months Ended June 30, 2021
(In millions, except volumetric data and price amounts)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Natural gas (BBtu)
34.2
$
(2.52
)
$
(86.1
)
36.1
$
(0.72
)
$
(26.0
)
NGL (MMgal)
334.8
(0.47
)
(155.8
)
269.6
(0.17
)
(46.9
)
Crude oil (MBbl)
1.0
(45.20
)
(45.2
)
1.1
(8.32
)
(8.9
)
$
(287.1
)
$
(81.8
)
(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 June 30, 2022 Compared to Three Months Ended June 30, 2021
The increase in adjusted operating margin was due to higher realized commodity prices, natural gas inlet volumes and fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to increased producer activity and the addition of a new 200 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Heim Plant”) during the third quarter of 2021. Natural gas inlet volumes in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity. The decrease in volumes in the Badlands was attributable to the impacts of winter weather, while lower volumes in the Coastal region were due to continued low producer activity.
The increase in operating expenses was due to higher activity levels in the Permian, the addition of the Heim Plant in the third quarter of 2021, the acquisition of certain assets in South Texas in the second quarter of 2022 and inflation impacts, which resulted in increased labor costs, materials and chemicals.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
The increase in adjusted operating margin was due to higher realized commodity prices, natural gas inlet volumes and fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to increased producer activity and the addition of the Heim Plant during the third quarter of 2021. Natural gas inlet volumes in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity. The decrease in volumes in the Badlands was attributable to the impacts of winter weather, while lower volumes in the Coastal region were due to continued low producer activity.
The increase in operating expenses was due to higher activity levels in the Permian, the addition of the Heim Plant in the third quarter of 2021, the acquisition of certain assets in South Texas in the second quarter of 2022 and inflation impacts, which resulted in increased labor costs, materials and chemicals.
41
Logistics and Transportation Segment
Three Months Ended June 30,
Six Months Ended June 30,
2022
2021
2022 vs. 2021
2022
2021
2022 vs. 2021
(In millions, except operating statistics)
Operating margin
$
322.3
$
291.4
$
30.9
11%
$
674.5
$
640.1
$
34.4
5%
Operating expenses
74.4
70.7
3.7
5%
141.3
136.5
4.8
4%
Adjusted operating margin
$
396.7
$
362.1
$
34.6
10%
$
815.8
$
776.6
$
39.2
5%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)
492.3
391.7
100.6
26%
476.1
367.2
108.9
30%
Fractionation volumes
737.2
643.7
93.5
15%
720.1
595.0
125.1
21%
Export volumes (3)
342.6
340.6
2.0
1%
341.7
312.1
29.6
9%
NGL sales
906.9
833.8
73.1
9%
890.0
830.6
59.4
7%
(1)
Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
(2)
Represents the total quantity of mixed NGLs that earn a transportation margin.
( 3 )
Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.
Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation volumes, partially offset by lower marketing margin and lower LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems. Marketing margin decreased due to fewer optimization opportunities. LPG export margin decreased primarily due to higher fuel and power costs, partially offset by higher fees.
The increase in operating expenses was due to higher repairs and maintenance.
Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation volumes and higher LPG export margin, partially offset by lower marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems. LPG export margin increased due to higher volumes and fees, partially offset by higher fuel and power costs. Higher optimization margin attributable to the winter storm resulted in higher marketing margin in 2021.
The increase in operating expenses was primarily due to higher repairs and maintenance, partially offset by lower taxes.
Other
Three Months Ended June 30,
Six Months Ended June 30,
2022
2021
2022 vs. 2021
2022
2021
2022 vs. 2021
(In millions)
Operating margin
$
(4.5
)
$
(70.5
)
$
66.0
$
(182.7
)
$
(69.1
)
$
(113.6
)
Adjusted operating margin
$
(4.5
)
$
(70.5
)
$
66.0
$
(182.7
)
$
(69.1
)
$
(113.6
)
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 June 30, 2022, inclusive of our consolidated joint venture accounts, we had $154.0 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.
42
Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity as well as the ability to contribute capital to the Partnership.
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 dividends depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.
On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver and the 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 July 29, 2022, was:
Consolidated Total
(In millions)
Cash on hand (1)
$
178.7
Total availability under the TRGP Revolver
2,750.0
Total availability under the Securitization Facility
400.0
3,328.7
Less: Outstanding borrowings under the TRGP Revolver
(1,600.0
)
Outstanding borrowings under the Securitization Facility
(400.0
)
Outstanding letters of credit under the TRGP Revolver
(61.6
)
Total liquidity
$
1,267.1
_________________________________
(1)
Includes cash held in our consolidated joint venture accounts.
Other potential capital resources associated with our existing arrangements includes our right to request an additional $500.0 million in commitment increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 17, 2027.
A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of June 30, 2022, we had $44.8 million letters of credit outstanding under the TRGP Revolver. They reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.
In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $2.75 billion. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. We had no amounts outstanding under the Commercial Paper Program as of July 29, 2022.
43
Working Capital
Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels, which we closely manage, and valuation; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.
Working capital as of June 30, 2022 decreased $460.6 million compared to December 31, 2021. The decrease was primarily due to higher product purchases and fuel payables as a result of higher commodity prices, higher net borrowing on the Securitization Facility and an increase in the current liability position of our derivative contracts, partially offset by higher receivables resulting from higher commodity prices.
Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the TRGP Revolver, Securitization Facility, Term Loan Facility and Commercial Paper Program, 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 February 2022, we entered into the TRGP Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto. The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $2.75 billion, with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver, including a swing line sub-facility of up to $100.0 million. The TRGP Revolver matures in February 2027. I n February 2022, TRGP and the Partnership received a corporate investment grade credit rating from S&P and Fitch, and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s. As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations thereunder. In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver and the Partnership Revolver. As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss due to debt extinguishment of $0.8 million.
In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership Issuers under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of June 30, 2022, $5.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.
In March 2022, the Partnership redeemed all of the outstanding 5.375% Notes with available liquidity under the TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $15.0 million comprised of $12.6 million of premiums paid and a write-off of $2.4 million of debt issuance costs.
In April 2022, we completed an underwritten public offering of $750.0 million aggregate principal amount of our 4.200% Notes and $750.0 million aggregate principal amount of our 4.950% Notes, resulting in net proceeds of approximately $1.5 billion. A portion of the net proceeds from the issuance was used to fund the concurrent March Tender Offer and the subsequent redemption payment of the Partnership’s 5.875% Notes, with the remainder of the net proceeds used for repayment of the outstanding borrowings under the TRGP Revolver. As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we recorded a loss due to debt extinguishment of $33.8 million comprised of $29.3 million of premiums paid and a write-off of $4.5 million of debt issuance costs.
In April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023 and replace the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR.
44
In July 2022, we completed an underwritten public offering of (i) $750.0 million in aggregate principal amount of our 5.200% Notes and (ii) $500.0 million in aggregate principal amount of our 6.250% Notes, resulting in net proceeds of approximately $1.2 billion. We used the net proceeds from the issuance to fund a portion of the Lucid Acquisition.
In July 2022, we entered into the Term Loan Facility with Mizuho Bank, Ltd. as the Administrative Agent and a lender, and other lenders party thereto. The Term Loan Facility provides for a three-year, $1.5 billion unsecured term loan facility. The Term Loan Facility matures in July 2025. We used the proceeds to fund a portion of the Lucid Acquisition.
In the future, we or the Partnership may redeem, purchase or exchange certain of our and the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In May 2022 , we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, of which $215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to our Consolidated Financial Statements.
To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness.
For additional information about our debt-related transactions, see Note 7 - 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.”
Compliance with Debt Covenants
As of June 30, 2022, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
Cash Flow
Cash Flows from Operating Activities
Six Months Ended June 30,
2022
2021
2022 vs. 2021
(In millions)
$
1,383.7
$
1,303.6
$
80.1
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.
The increase in net cash provided by operations was primarily due to higher commodity prices, resulting in higher collections from customers, partially offset by an increase in payments for product purchases and fuel and hedge transactions.
Cash Flows from Investing Activities
Six Months Ended June 30,
2022
2021
2022 vs. 2021
(In millions)
$
248.4
$
(185.9
)
$
434.3
45
The change in net cash provided by (used in) investing activities was primarily due to proceeds from the GCX Sale, partially offset by higher outlays for property, plant and equipment resulting from construction activities of the Legacy, Legacy II, Midway and Greenwood plants and outlays for the Southcross Acquisition.
Cash Flows from Financing Activities
Six Months Ended June 30,
2022
2021
(In millions)
Source of Financing Activities, net
Debt, including financing costs
$
786.7
$
(802.8
)
Repurchase of Series A Preferred Stock
(965.2
)
—
Repurchase of noncontrolling interests
(926.3
)
—
Dividends and distributions
(217.8
)
(92.7
)
Contributions from (distributions to) noncontrolling interests
(167.7
)
(247.4
)
Repurchase of shares
(146.3
)
(8.6
)
Net cash provided by (used in) financing activities
$
(1,636.6
)
$
(1,151.5
)
The increase in net cash used in financing activities was primarily due to the redemption of the Series A Preferred Stock and repurchases of non-controlling interests in the DevCo JVs and common stock during 2022. Additionally, higher dividends and distributions were paid in 2022 due to the increase in our common stock dividends from $0.10 to $0.35 per common share in January 2022. These were partially offset by net borrowings of debt in 2022, as compared to net repayments of debt in 2021.
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
Our subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and severally, the payment of TRGP’s senior notes, subject to certain limited exceptions.
In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information.
46
Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group follows:
Summarized Combined Balance Sheet Information
June 30, 2022
December 31, 2021
(In millions)
ASSETS
Current assets
$
936.3
$
832.9
Current assets - affiliates
58.2
24.4
Long-term assets
6,405.7
6,253.9
Long-term assets - affiliates
10.5
10.5
Total assets
$
7,410.7
$
7,121.7
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities
$
1,955.7
$
1,525.6
Current liabilities - affiliates
220.5
195.8
Long-term liabilities
7,656.4
6,875.5
Series A Preferred
—
749.7
Targa Resources Corp. stockholders' equity
(2,421.9
)
(2,224.9
)
Total liabilities and owners' equity
$
7,410.7
$
7,121.7
Summarized Combined Statement of Operations Information
Six Months Ended
Year Ended
June 30, 2022
December 31, 2021
(In millions)
Revenues
$
11,206.3
$
16,900.5
Operating income (loss)
(19.5
)
5.7
Net income (loss)
157.3
(371.0
)
Dividends on Series A Preferred
30.0
87.3
Common Stock Dividends
The following table details the dividends on common stock declared and/or paid by us for the six months ended June 30, 2022:
Three Months Ended
Date Paid or
To Be Paid
Total Common
Dividends Declared
Amount of Common
Dividends Paid or
To Be Paid
Accrued
Dividends (1)
Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
June 30, 2022
August 15, 2022
$
80.7
$
79.3
$
1.4
$
0.35000
March 31, 2022
May 16, 2022
81.2
79.8
1.4
0.35000
December 31, 2021
February 15, 2022
81.4
80.1
1.3
0.35000
(1)
Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.
Preferred Dividends
Prior to the redemption of our Series A Preferred in May 2022, our Series A Preferred had a liquidation value of $1,000 per share and bore a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter. During the three and six months ended June 30, 2022, we paid $30.0 million and $51.8 million of dividends to preferred shareholders.
Series A Preferred Redemption
In May 2022, we redeemed in full all of our issued and outstanding shares of Series A Preferred at a redemption price of $1,050.00 per share, plus $8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022. The difference between the consideration paid of $973.4 million (including unpaid dividends of $8.2 million) and the net carrying value of the shares redeemed was $223.7 million, of which $215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. See Note 9 - Preferred Stock to our Consolidated Financial Statements.
47
Capital Expenditures
The following table details cash outlays for capital projects for the six months ended June 30, 2022 and 2021:
Six Months Ended June 30,
2022
2021
(In millions)
Capital expenditures:
Growth (1)
$
326.3
$
151.8
Maintenance (2)
79.9
47.2
Gross capital expenditures
406.2
199.0
Transfers from materials and supplies inventory to property, plant and equipment
—
(0.4
)
Change in capital project payables and accruals, net
13.3
0.3
Cash outlays for capital projects
$
419.5
$
198.9
(1)
Growth capital expenditures, net of contributions from noncontrolling interests and including net contributions to investments in unconsolidated affiliates, were $320.7 million and $144.4 million for the six months ended June 30, 2022 and 2021.
(2)
Maintenance capital expenditures, net of contributions from noncontrolling interests, were $77.4 million and $43.2 million for the six months ended June 30, 2022 and 2021.
The increase in total growth capital expenditures was primarily due to system expansions in the Permian in response to forecasted production growth and increasing activity levels. The increase in total maintenance capital expenditures was primarily due to our growing infrastructure footprint.
With the August 2022 announcements of construction of the Greenwood plant in Permian Midland and Train 9 fractionator in Mont Belvieu, we currently estimate that in 2022 we will invest between $1.0 to $1.1 billion in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investment opportunities. We expect that 2022 maintenance capital expenditures, net of noncontrolling interests, will be approximately $150 million.
Off-Balance Sheet Arrangements
As of June 30, 2022, there were $70.2 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.
48