Item 1. Financial Statements
Item 1. Financial Statements.
TARGA RESOURCES CORP.
CONSOLIDATED BALANCE SHEETS
March 31, 2022
December 31, 2021
(Unaudited)
(In millions)
ASSETS
Current assets:
Cash and cash equivalents
$
135.9
$
158.5
Trade receivables, net of allowances of $ 0.1 million and $ 0.1 million at March 31, 2022 and December 31, 2021
1,567.2
1,331.9
Inventories
97.5
153.4
Assets from risk management activities
22.0
43.1
Other current assets
77.9
82.9
Total current assets
1,900.5
1,769.8
Property, plant and equipment, net
11,653.0
11,667.7
Intangible assets, net
1,066.8
1,094.8
Long-term assets from risk management activities
7.3
7.7
Investments in unconsolidated affiliates
579.8
586.5
Other long-term assets
88.0
81.7
Total assets
$
15,295.4
$
15,208.2
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Accounts payable
$
1,803.5
$
1,402.3
Accrued liabilities
202.5
272.2
Distributions payable
46.3
64.5
Interest payable
74.5
138.5
Liabilities from risk management activities
499.8
258.2
Current debt obligations
283.8
162.8
Total current liabilities
2,910.4
2,298.5
Long-term debt
6,964.9
6,434.4
Long-term liabilities from risk management activities
267.2
109.3
Deferred income taxes, net
88.0
136.0
Other long-term liabilities
297.9
301.6
Contingencies (see Note 15)
Series A Preferred 9.5 % Stock, $ 1,000 per share liquidation preference ( 1,200,000 shares authorized, 919,300 shares issued and outstanding as of March 31, 2022 and December 31, 2021), net of discount (see Note 9)
749.7
749.7
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock ($ 0.001 par value, 450,000,000 shares authorized as of March 31, 2022 and December 31, 2021)
0.2
0.2
Issued Outstanding
March 31, 2022 237,199,124 228,180,573
December 31, 2021 236,105,293 228,221,122
Preferred stock ($ 0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, no shares issued and outstanding)
—
—
Additional paid-in capital
4,125.8
4,268.9
Retained earnings (deficit)
( 1,734.3
)
( 1,822.3
)
Accumulated other comprehensive income (loss)
( 418.4
)
( 230.9
)
Treasury stock, at cost ( 9,018,551 shares as of March 31, 2022 and 7,884,171 shares as of December 31, 2021)
( 276.3
)
( 204.1
)
Total Targa Resources Corp. stockholders' equity
1,697.0
2,011.8
Noncontrolling interests
2,320.3
3,166.9
Total owners' equity
4,017.3
5,178.7
Total liabilities, Series A Preferred Stock and owners' equity
$
15,295.4
$
15,208.2
See notes to consolidated financial statements.
4
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended March 31,
2022
2021
(Unaudited)
(In millions, except per share amounts)
Revenues:
Sales of commodities
$
4,566.2
$
3,367.7
Fees from midstream services
392.9
265.0
Total revenues
4,959.1
3,632.7
Costs and expenses:
Product purchases and fuel
4,204.1
2,836.3
Operating expenses
183.5
171.1
Depreciation and amortization expense
209.1
216.2
General and administrative expense
67.1
61.4
Other operating (income) expense
( 0.5
)
3.6
Income (loss) from operations
295.8
344.1
Other income (expense):
Interest expense, net
( 93.6
)
( 98.4
)
Equity earnings (loss)
5.6
11.8
Gain (loss) from financing activities
( 15.8
)
( 14.7
)
Other, net
( 0.5
)
0.1
Income (loss) before income taxes
191.5
242.9
Income tax (expense) benefit
( 22.9
)
( 15.0
)
Net income (loss)
168.6
227.9
Less: Net income (loss) attributable to noncontrolling interests
80.6
81.5
Net income (loss) attributable to Targa Resources Corp.
88.0
146.4
Premium on repurchase of noncontrolling interests, net of tax
53.1
—
Dividends on Series A Preferred Stock
21.8
21.8
Net income (loss) attributable to common shareholders
$
13.1
$
124.6
Net income (loss) per common share - basic
$
0.06
$
0.54
Net income (loss) per common share - diluted
$
0.06
$
0.53
Weighted average shares outstanding - basic
228.5
228.5
Weighted average shares outstanding - diluted
232.4
274.7
See notes to consolidated financial statements.
5
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Three Months Ended March 31,
2022
2021
Pre-Tax
Related Income Tax
After Tax
Pre-Tax
Related Income Tax
After Tax
(Unaudited)
(In millions)
Net income (loss)
$
168.6
$
227.9
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value
$
( 387.1
)
$
86.6
( 300.5
)
$
( 171.5
)
$
40.2
( 131.3
)
Settlements reclassified to revenues
145.7
( 32.7
)
113.0
149.7
( 35.0
)
114.7
Other comprehensive income (loss)
( 241.4
)
53.9
( 187.5
)
( 21.8
)
5.2
( 16.6
)
Comprehensive income (loss)
( 18.9
)
211.3
Less: Comprehensive income (loss) attributable to noncontrolling interests
80.6
81.5
Comprehensive income (loss) attributable to Targa Resources Corp.
$
( 99.5
)
$
129.8
See notes to consolidated financial statements.
6
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK
Retained
Accumulated
Additional
Earnings
Other
Treasury
Total
Series A
Common Stock
Paid in
(Accumulated
Comprehensive
Shares
Noncontrolling
Owner's
Preferred
Shares
Amount
Capital
Deficit)
Income (Loss)
Shares
Amount
Interests
Equity
Stock
(Unaudited)
(In millions, except shares in thousands)
Balance, December 31, 2021
228,221
$
0.2
$
4,268.9
$
( 1,822.3
)
$
( 230.9
)
7,884
$
( 204.1
)
$
3,166.9
$
5,178.7
$
749.7
Compensation on equity grants
—
—
13.5
—
—
—
—
—
13.5
—
Distribution equivalent rights
—
—
( 1.7
)
—
—
—
—
—
( 1.7
)
—
Shares issued under compensation program
1,095
—
—
—
—
—
—
—
—
—
Shares tendered for tax withholding obligations
( 397
)
—
—
—
—
397
( 22.5
)
—
( 22.5
)
—
Repurchases of common stock
( 738
)
—
—
—
—
738
( 49.7
)
—
( 49.7
)
—
Series A Preferred Stock dividends
Dividends - $ 23.75 per share
—
—
—
( 21.8
)
—
—
—
—
( 21.8
)
—
Dividends in excess of retained earnings
—
—
( 21.8
)
21.8
—
—
—
—
—
—
Common stock dividends
Dividends - $ 0.35 per share
—
—
—
( 80.0
)
—
—
—
—
( 80.0
)
—
Dividends in excess of retained earnings
—
—
( 80.0
)
80.0
—
—
—
—
—
—
Distributions to noncontrolling interests
—
—
—
—
—
—
—
( 72.2
)
( 72.2
)
—
Contributions from noncontrolling interests
—
—
—
—
—
—
—
2.9
2.9
—
Repurchase of noncontrolling interests, net of tax
—
—
( 53.1
)
—
—
—
—
( 857.9
)
( 911.0
)
—
Other comprehensive income (loss)
—
—
—
—
( 187.5
)
—
—
—
( 187.5
)
—
Net income (loss)
—
—
—
88.0
—
—
—
80.6
168.6
—
Balance, March 31, 2022
228,181
$
0.2
$
4,125.8
$
( 1,734.3
)
$
( 418.4
)
9,019
$
( 276.3
)
$
2,320.3
$
4,017.3
$
749.7
See notes to consolidated financial statements.
7
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK
Retained
Accumulated
Additional
Earnings
Other
Treasury
Total
Series A
Common Stock
Paid in
(Accumulated
Comprehensive
Shares
Noncontrolling
Owner's
Preferred
Shares
Amount
Capital
Deficit)
Income (Loss)
Shares
Amount
Interests
Equity
Stock
(Unaudited)
(In millions, except shares in thousands)
Balance, December 31, 2020
228,062
$
0.2
$
4,839.9
$
( 1,893.5
)
$
( 141.8
)
6,731
$
( 150.9
)
$
3,249.3
$
5,903.2
$
301.4
Impact of accounting standard adoption
—
—
( 448.3
)
—
—
—
—
—
( 448.3
)
448.3
Compensation on equity grants
—
—
15.0
—
—
—
—
—
15.0
—
Distribution equivalent rights
—
—
( 0.4
)
—
—
—
—
—
( 0.4
)
—
Shares issued under compensation program
878
—
—
—
—
—
—
—
—
—
Shares tendered for tax withholding obligations
( 285
)
—
—
—
—
285
( 8.6
)
—
( 8.6
)
—
Series A Preferred Stock dividends
Dividends - $ 23.75 per share
—
—
—
( 21.8
)
—
—
—
—
( 21.8
)
—
Dividends in excess of retained earnings
—
—
( 21.8
)
21.8
—
—
—
—
—
—
Common stock dividends
Dividends - $ 0.10 per share
—
—
—
( 22.9
)
—
—
—
—
( 22.9
)
—
Dividends in excess of retained earnings
—
—
( 22.9
)
22.9
—
—
—
—
—
—
Distributions to noncontrolling interests
—
—
—
—
—
—
—
( 107.1
)
( 107.1
)
—
Contributions from noncontrolling interests
—
—
—
—
—
—
—
2.0
2.0
—
Other comprehensive income (loss)
—
—
—
—
( 16.6
)
—
—
—
( 16.6
)
—
Net income (loss)
—
—
—
146.4
—
—
—
81.5
227.9
—
Balance, March 31, 2021
228,655
$
0.2
$
4,361.5
$
( 1,747.1
)
$
( 158.4
)
7,016
$
( 159.5
)
$
3,225.7
$
5,522.4
$
749.7
See notes to consolidated financial statements.
8
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended March 31,
2022
2021
(Unaudited)
(In millions)
Cash flows from operating activities
Net income (loss)
$
168.6
$
227.9
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense
2.4
2.7
Compensation on equity grants
13.5
15.0
Depreciation and amortization expense
209.1
216.2
(Gain) loss on sale or disposition of assets
( 1.0
)
—
Write-downs of assets
0.5
3.5
Accretion of asset retirement obligations
1.1
0.9
Increase (decrease) in redemption value of mandatorily redeemable preferred interests
( 0.7
)
—
Deferred income tax expense (benefit)
21.1
14.5
Equity (earnings) loss of unconsolidated affiliates
( 5.6
)
( 11.8
)
Distributions of earnings received from unconsolidated affiliates
6.0
24.3
Risk management activities
178.2
( 1.5
)
(Gain) loss from financing activities
15.8
14.7
Changes in operating assets and liabilities:
Receivables and other assets
( 216.2
)
( 41.9
)
Inventories
55.9
139.9
Accounts payable, accrued liabilities and other liabilities
363.5
121.2
Interest payable
( 64.0
)
( 45.8
)
Net cash provided by operating activities
748.2
679.8
Cash flows from investing activities
Outlays for property, plant and equipment
( 204.4
)
( 96.2
)
Proceeds from sale of assets
1.0
—
Investments in unconsolidated affiliates
( 0.4
)
—
Return of capital from unconsolidated affiliates
6.8
5.9
Other, net
—
0.3
Net cash used in investing activities
( 197.0
)
( 90.0
)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities
1,805.0
65.0
Repayments of credit facilities
( 810.0
)
( 825.0
)
Proceeds from borrowings under accounts receivable securitization facility
250.0
350.0
Repayments of accounts receivable securitization facility
( 130.0
)
( 430.0
)
Proceeds from issuance of senior notes
—
1,000.0
Redemption of senior notes
( 480.7
)
( 548.1
)
Principal payments of finance leases
( 3.2
)
( 3.1
)
Costs incurred in connection with financing arrangements
( 10.9
)
( 9.0
)
Repurchase of shares
( 72.2
)
( 8.6
)
Contributions from noncontrolling interests
2.9
2.0
Distributions to noncontrolling interests
( 90.4
)
( 129.3
)
Repurchase of noncontrolling interests
( 926.3
)
—
Dividends paid to common and Series A Preferred shareholders
( 108.0
)
( 48.0
)
Net cash provided by (used in) financing activities
( 573.8
)
( 584.1
)
Net change in cash and cash equivalents
( 22.6
)
5.7
Cash and cash equivalents, beginning of period
158.5
242.8
Cash and cash equivalents, end of period
$
135.9
$
248.5
See notes to consolidated financial statements.
9
TARGA RESOURCES CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Note 1 — Organization and Operations
Our Organization
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 infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic midstream infrastructure assets.
In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” “Targa” or “TRGP” are intended to mean our consolidated business and operations. TRGP controls the general partner of and owns all of the outstanding common units representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership”. Targa consolidates the Partnership and its subsidiaries under accounting principles generally accepted in the United States of America (“GAAP”). Targa’s consolidated financial statements include differences from the consolidated financial statements of the Partnership. The most noteworthy differences are:
•
the inclusion of the TRGP revolving credit facility;
•
the inclusion of Series A Preferred Stock (“Series A Preferred”); and
•
the impacts of TRGP’s treatment as a corporation for U.S. federal income tax purposes.
Our Operations
The Company is primarily engaged 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.
See Note 19 – Segment Information for certain financial information regarding our business segments.
Note 2 — Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all information and disclosures required by GAAP. Therefore, this information should be read in conjunction with our consolidated financial statements and notes contained in our Annual Report. The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for a fair statement of the results of the interim periods reported. All intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods have been reclassified to conform to the current year presentation. Operating results for the three months ended March 31, 2022 are not necessarily indicative of the results that may be expected for the year ending December 31, 2022.
10
Note 3 — Significant Accounting Policies
The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. There were no significant updates or revisions to our accounting policies during the three months ended March 31, 2022.
Note 4 – Joint Ventures, Divestitures and Acquisitions
DevCo Joint Ventures
In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix NGL Pipeline (“Grand Prix”), Gulf Coast Express Pipeline (“GCX”) and an approximately 110 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). For a four-year period beginning on the date that all three projects commenced commercial operations, we had the option to acquire all or part of Stonepeak’s interests in the DevCo JVs (the “DevCo JV Call Right”). The purchase price payable for such partial or full interests was based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs.
In January 2022, we exercised the DevCo JV Call Right and closed on the purchase of all of Stonepeak’s interests in the DevCo JVs for $ 926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we own a 75 % interest in Grand Prix Pipeline LLC, a 100 % interest in Train 6 and owned a 25 % equity interest in 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.
Divestitures
In February 2022, we announced that we executed agreements to sell Targa GCX Pipeline LLC, which held our 25 percent equity interest in GCX, for approximately $ 857 million (the “GCX Sale”). We expect to receive the full proceeds from the sale in the second quarter of 2022 as the customary call right period has now expired.
Acquisitions
In April 2022, we closed on the acquisition of Southcross Energy Operating LLC and its subsidiaries in South Texas for a purchase price of approximately $ 200 million (the “Southcross Acquisition”). We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the two operated joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and which we will prospectively consolidate. See Note 6 – Investments in Unconsolidated Affiliates .
Note 5 — Property, Plant and Equipment and Intangible Assets
March 31, 2022
December 31, 2021
Estimated Useful Lives (In Years)
Gathering systems
$
9,368.0
$
9,318.2
5 to 20
Processing and fractionation facilities
6,423.0
6,388.8
5 to 25
Terminaling and storage facilities
1,325.5
1,313.8
5 to 25
Transportation assets
2,696.6
2,671.0
10 to 50
Other property, plant and equipment
334.2
340.9
3 to 50
Land
160.8
160.8
—
Construction in progress
392.4
347.0
—
Finance lease right-of-use assets
56.8
55.6
5 to 7
Property, plant and equipment
20,757.3
20,596.1
Accumulated depreciation, amortization and impairment
( 9,104.3
)
( 8,928.4
)
Property, plant and equipment, net
$
11,653.0
$
11,667.7
Intangible assets
2,497.7
2,642.9
10 to 20
Accumulated amortization and impairment
( 1,430.9
)
( 1,548.1
)
Intangible assets, net
$
1,066.8
$
1,094.8
During the three months ended March 31, 2022 and 2021, depreciation expense was $ 181.1 million and $ 183.4 million, respectively.
11
Impairments of Long-Lived Assets
We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. No impairments of long-lived assets were recorded for the three months ended March 31, 2022 and 2021.
Intangible Assets
Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.
The estimated annual amortization expense for intangible assets is approximately $ 112.0 million, $ 106.8 million, $ 103.0 million, $ 99.9 million and $ 97.6 million for each of the years 2022 through 2026, respectively.
The changes in our intangible assets are as follows:
March 31, 2022
Balance at December 31, 2021
$
1,094.8
Amortization
( 28.0
)
Balance at March 31, 2022
$
1,066.8
Note 6 – Investments in Unconsolidated Affiliates
Our investments in unconsolidated affiliates consist of the following:
Gathering and Processing Segment
•
two operated joint ventures in South Texas: a 75 % interest (prior to closing on the Southcross Acquisition) in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”) and a 50 % interest (prior to closing on the Southcross Acquisition) in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford” and, together with T2 Lasalle, the “T2 Joint Ventures”) ; and
•
a 50 % operated ownership interest in Little Missouri 4 LLC (“Little Missouri 4”).
Logistics and Transportation Segment
•
a 25 % non-operated ownership interest in GCX (prior to the GCX Sale) ;
•
a 38.8 % operated ownership interest in Gulf Coast Fractionators (“GCF”); and
•
a 50 % operated ownership interest in Cayenne Pipeline LLC (“Cayenne”) .
The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.
See Note 4 – Joint Ventures, Divestitures and Acquisitions for further discussion of the T2 Joint Ventures and GCX.
The following table shows the activity related to our investments in unconsolidated affiliates:
Balance at December 31, 2021
Equity Earnings (Loss)
Cash Distributions
Contributions
Balance at March 31, 2022
GCX (1)
$
421.0
$
5.7
$
( 7.3
)
$
—
$
419.4
Little Missouri 4
98.1
0.3
( 4.7
)
—
93.7
GCF (2)
28.8
( 0.7
)
—
0.5
28.6
T2 Eagle Ford (3)
21.9
( 0.6
)
( 0.8
)
—
20.5
T2 LaSalle (3)
4.2
( 0.2
)
—
—
4.0
Cayenne
12.5
1.1
—
—
13.6
Total
$
586.5
$
5.6
$
( 12.8
)
$
0.5
$
579.8
12
(1)
Following the DevCo JV Repurchase in January 2022, we owned a 25 % equity interest in GCX. In February 2022, we announced the GCX Sale, at which time we ceased the recognition of equity earnings (loss) due to the terms of the sales agreement. See Note 4 – Joint Ventures, Divestitures and Acquisitions for further discussion.
(2)
Targa assumed operatorship of GCF in the first half of 2021.
(3)
In April 2022, we closed on the Southcross Acquisition. Following the closing of the Southcross Acquisition, we own 100 % of the interests in the T2 Joint Ventures. See Note 4 – Joint Ventures, Divestitures and Acquisitions for further discussion.
Note 7 — Debt Obligations
March 31, 2022
December 31, 2021
Current:
Partnership accounts receivable securitization facility, due April 2022 (1)
$
270.0
$
150.0
Finance lease liabilities
13.8
12.8
Current debt obligations
283.8
162.8
Long-term:
TRGP senior revolving credit facility, variable rate, due February 2027 (2)
995.0
—
Senior unsecured notes issued by the Partnership: (3)
5.875 % fixed rate, due April 2026 (4)
963.2
963.2
5.375 % fixed rate, due February 2027 (5)
—
468.1
6.500 % fixed rate, due July 2027
705.2
705.2
5.000 % fixed rate, due January 2028
700.3
700.3
6.875 % fixed rate, due January 2029
679.3
679.3
5.500 % fixed rate, due March 2030
949.6
949.6
4.875 % fixed rate, due February 2031
1,000.0
1,000.0
4.000 % fixed rate, due January 2032
1,000.0
1,000.0
6,992.6
6,465.7
Debt issuance costs, net of amortization
( 41.3
)
( 45.0
)
Finance lease liabilities
13.6
13.7
Long-term debt (6)
6,964.9
6,434.4
Total debt obligations
$
7,248.7
$
6,597.2
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRGP senior revolving credit facility (3)
$
58.7
$
—
Letters of credit outstanding under the Partnership senior
secured revolving credit facility (3)
—
71.3
$
58.7
$
71.3
(1)
As of March 31, 2022, the Partnership had $ 270.0 million of qualifying receivables under its $ 400.0 million accounts receivable securitization facility (“Securitization Facility”), resulting in $ 130.0 million of availability. In April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023.
(2)
In February 2022, we entered into a new $ 2.75 billion TRGP senior revolving credit facility, (the “TRGP Revolver”) which matures in February 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”). As of March 31, 2022, availability under the TRGP Revolver was $ 1.7 billion. As of December 31, 2021, we had no balance outstanding under the Previous TRGP Revolver or the Partnership Revolver.
( 3 )
As of February 2022, we guarantee all of the Partnership’s outstanding senior unsecured notes.
(4)
In April 2022, the Partnership purchased $ 484.3 million aggregate principal amount of its outstanding 5.875 % Senior Notes due 2026 (the “ 5.875 % Notes”) pursuant to an offer to purchase for cash (the “Tender Offer”) any and all outstanding 5.875 % Notes. Concurrent with the launch of the Tender Offer, the Partnership exercised its right to redeem any of the 5.875 % Notes not validly tendered and purchased in the Tender Offer, and such 5.875 % Notes were redeemed in April 2022.
(5)
In March 2022, the Partnership redeemed all of the outstanding 5.375 % Senior Notes due 2027 (the “ 5.375 % Notes”) with the available liquidity under the TRGP Revolver.
(6)
In April 2022, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of (i) $ 750.0 million aggregate principal amount of our 4.200 % Senior Notes due 2033 (the “ 4.200 % Notes”) and (ii) $ 750.0 million aggregate principal amount of our 4.950 % Senior Notes due 2052 (the “ 4.950 % Notes”), resulting in net proceeds of approximately $ 1.5 billion.
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2022:
Range of Interest Rates Incurred
Weighted Average Interest Rate Incurred
TRGP Revolver
1.5% - 1.8%
1.6 %
Securitization Facility
1.1% - 1.2%
1.2 %
13
Compliance with Debt Covenants
As of March 31, 2022, we were in compliance with the covenants contained in our various debt agreements.
In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of March 31, 2022, $ 6.0 billion of the Partnership Issuers’ senior unsecured notes was outstanding.
Debt Obligations
TRGP Revolver
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 on February 17, 2027 . In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver and 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., 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.
Senior Unsecured Notes Redemption
In March 2022 , the Partnership redeemed all of the outstanding 5.375 % Notes at a redemption price equal to $ 1,026.88 for each $ 1,000 principal amount of 5.375 % Notes redeemed, plus accrued and unpaid interest to, but not including, March 30, 2022, or a maximum combined aggregate redemption price (exclusive of accrued and unpaid interest) of $ 480.7 million. The 5.375 % Notes were redeemed 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 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 or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material .
Shelf Registration
In March 2022, we filed with the SEC a universal shelf registration statement on Form S-3 that registers the issuance and sale of certain debt and equity securities from time to time in one or more offerings (the “March 2022 Shelf”). The March 2022 Shelf will expire in March 2025. See Note 10 – Common Stock and Related Matters.
Contractual Obligations
The following table summarizes payment obligations as of March 31, 2022, for debt instruments after giving effect to the debt extinguishments detailed above:
Payments Due By Period
Less Than
More Than
Total
1 Year
1-3 Years
3-5 Years
5 Years
Long-term debt obligations (1)
$
6,992.6
$
—
$
—
$
1,958.2
$
5,034.4
Interest on debt obligations (2)
2,232.6
325.1
650.3
596.0
661.2
$
9,225.2
$
325.1
$
650.3
$
2,554.2
$
5,695.6
(1)
Represents scheduled future maturities of consolidated debt obligations for the periods indicated.
(2)
Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing March 31, 2022 rates for floating debt.
14
Subsequent Events
Senior Unsecured Notes Issuances and Redemptions
In April 2022, we, along with certain of our subsidiaries as guarantors thereto, completed an underwritten public offering of (i) $ 750.0 million aggregate principal amount of our 4.200 % Notes and (ii) $ 750.0 million aggregate principal amount of our 4.950 % Notes, resulting in net proceeds of approximately $ 1.5 billion. Both of the 4.200 % Notes and the 4.950 % Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. Both of the 4.200 % Notes and the 4.950 % Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain First Supplemental Indenture, dated as of April 6, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee.
A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “March Tender Offer”) and the subsequent redemption payment of the Partnership’s 5.875 % Notes, with the remainder used for repayment of borrowings under the TRGP Revolver. As a result of the March Tender Offer and the subsequent redemption of the 5.875 % Notes, we will record a loss due to debt extinguishment of $ 33.5 million in the second quarter.
Partnership’s Accounts Receivable Securitization Facility
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.
Note 8 — Other Long-term Liabilities
Other long-term liabilities are comprised of deferred revenue, asset retirement obligations and operating lease liabilities.
Deferred Revenue
We have certain long-term contractual arrangements for which we have received consideration that we are not yet able to recognize as revenue. The resulting deferred revenue will be recognized once all conditions for revenue recognition have been met.
Deferred revenue as of March 31, 2022 and December 31, 2021, was $ 170.6 million and $ 171.8 million, respectively, which includes $ 129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent on the outcome of current litigation with Vitol. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment to a gas gathering and processing agreement and consideration received for other construction activities of facilities connected to our systems. See Part II—Item 1. Legal Proceedings for further details on the related litigation.
Note 9 — Preferred Stock
Preferred Stock Dividends
As of March 31, 2022, we had accrued cumulative preferred dividends of $ 21.8 million on our Series A Preferred, which were paid on May 2, 2022 . During the three months ended March 31, 2022, we paid $ 21.8 million of dividends to preferred shareholders.
Subsequent Event
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, which will be recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated.
15
Note 10 — Common Stock and Related Matters
Shelf Registration Statement
In March 2022, we filed the March 2022 Shelf. The March 2022 Shelf will expire in March 2025. See Note 7 – Debt Obligations.
Common Stock Dividends
In January 2022, we declared an increase to our common dividend to $ 0.35 per common share or $ 1.40 per common share annualized effective for the fourth quarter of 2021, which was paid in February 2022.
The following table details the dividends declared and/or paid by us to common shareholders for the three months ended March 31, 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)
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.
Note 11 — Partnership Units and Related Matters
Distributions
We are entitled to receive all Partnership distributions from available cash on the Partnership’s common units each quarter.
The following table details the distributions declared and paid by the Partnership for the three months ended March 31, 2022:
Three Months Ended
Date Paid or To Be Paid
Total Distributions
Distributions to
Targa Resources Corp.
(In millions, except per share amounts)
March 31, 2022
May 12, 2022
$
103.7
$
103.7
December 31, 2021
February 11, 2022
103.7
103.7
Contributions
All capital contributions to the Partnership continue to be allocated 98 % to the limited partner and 2 % to the general partner; however, no units will be issued for those contributions. During the three months ended March 31, 2022, we made a total of $ 140.0 million in contributions to the Partnership.
Note 12 — Earnings per Common Share
The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:
Three Months Ended March 31,
2022
2021
(In millions, except per share amounts)
Net income (loss) attributable to Targa Resources Corp.
$
88.0
$
146.4
Less: Premium on repurchase of noncontrolling interests, net of tax
53.1
—
Less: Dividends on Series A Preferred (1)
21.8
21.8
Net income (loss) attributable to common shareholders for basic earnings per share
$
13.1
$
124.6
Weighted average shares outstanding - basic
228.5
228.5
Dilutive effect of unvested stock awards
3.9
1.9
Dilutive effect of Series A Preferred (1)
—
44.3
Weighted average shares outstanding - diluted
232.4
274.7
Net income (loss) available per common share - basic
$
0.06
$
0.54
Net income (loss) available per common share - diluted
$
0.06
$
0.53
16
The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis):
Three Months Ended March 31,
2022
2021
Unvested restricted stock awards
0.1
—
Series A Preferred (1)
44.3
—
(1)
The Series A Preferred had no mandatory redemption date, but was redeemable at our election for a 5 % premium to the liquidation preference subsequent to March 16, 2022 . In May 2022, we redeemed all of our issued and outstanding 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 . See Note 9 – Preferred Stock for further discussion.
Note 13 — Derivative Instruments and Hedging Activities
The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are primarily designated as cash flow hedges for accounting purposes.
The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.
We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
We also enter into derivative instruments to help manage other short-term commodity-related business risks and take advantage of market opportunities. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues as current income.
At March 31, 2022, the notional volumes of our commodity derivative contracts were:
Commodity
Instrument
Unit
2022
2023
2024
2025
2026
2027
Natural Gas
Swaps
MMBtu/d
157,714
102,943
49,068
7,479
—
—
Natural Gas
Basis Swaps
MMBtu/d
449,755
295,000
280,000
244,267
55,000
10,000
NGL
Swaps
Bbl/d
37,524
23,760
11,209
230
—
—
NGL
Futures
Bbl/d
6,429
—
—
—
—
—
Condensate
Swaps
Bbl/d
5,106
3,687
1,702
37
—
—
Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements.
The following schedules reflect the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
17
Fair Value as of March 31, 2022
Fair Value as of December 31, 2021
Balance Sheet
Derivative
Derivative
Derivative
Derivative
Location
Assets
Liabilities
Assets
Liabilities
Derivatives designated as hedging instruments
Commodity contracts
Current
$
22.0
$
( 447.8
)
$
25.5
$
( 252.6
)
Long-term
4.6
( 126.7
)
6.2
( 84.3
)
Total derivatives designated as hedging instruments
$
26.6
$
( 574.5
)
$
31.7
$
( 336.9
)
Derivatives not designated as hedging instruments
Commodity contracts
Current
$
—
$
( 52.0
)
$
17.6
$
( 5.6
)
Long-term
2.7
( 140.5
)
1.5
( 25.0
)
Total derivatives not designated as hedging instruments
$
2.7
$
( 192.5
)
$
19.1
$
( 30.6
)
Total current position
$
22.0
$
( 499.8
)
$
43.1
$
( 258.2
)
Total long-term position
7.3
( 267.2
)
7.7
( 109.3
)
Total derivatives
$
29.3
$
( 767.0
)
$
50.8
$
( 367.5
)
The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:
Gross Presentation
Pro Forma Net Presentation
March 31, 2022
Asset
Liability
Collateral
Asset
Liability
Current Position
Counterparties with offsetting positions or collateral
$
22.0
$
( 69.1
)
$
3.7
$
—
$
( 43.4
)
Counterparties without offsetting positions - assets
—
—
—
—
—
Counterparties without offsetting positions - liabilities
—
( 430.7
)
—
—
(430.7
)
22.0
( 499.8
)
3.7
—
( 474.1
)
Long-Term Position
Counterparties with offsetting positions or collateral
7.3
( 203.7
)
15.5
—
( 180.9
)
Counterparties without offsetting positions - assets
—
—
—
—
—
Counterparties without offsetting positions - liabilities
—
( 63.5
)
—
—
( 63.5
)
7.3
( 267.2
)
15.5
—
( 244.4
)
Total Derivatives
Counterparties with offsetting positions or collateral
29.3
( 272.8
)
19.2
—
( 224.3
)
Counterparties without offsetting positions - assets
—
—
—
—
—
Counterparties without offsetting positions - liabilities
—
( 494.2
)
—
—
( 494.2
)
$
29.3
$
( 767.0
)
$
19.2
$
—
$
( 718.5
)
Gross Presentation
Pro Forma Net Presentation
December 31, 2021
Asset
Liability
Collateral
Asset
Liability
Current Position
Counterparties with offsetting positions or collateral
$
39.2
$
( 241.9
)
$
5.0
$
0.3
$
( 198.0
)
Counterparties without offsetting positions - assets
3.9
—
—
3.9
—
Counterparties without offsetting positions - liabilities
—
( 16.3
)
—
—
( 16.3
)
43.1
( 258.2
)
5.0
4.2
( 214.3
)
Long-Term Position
Counterparties with offsetting positions or collateral
7.4
( 95.1
)
3.1
—
( 84.6
)
Counterparties without offsetting positions - assets
0.3
—
—
0.3
—
Counterparties without offsetting positions - liabilities
—
( 14.2
)
—
—
( 14.2
)
7.7
( 109.3
)
3.1
0.3
( 98.8
)
Total Derivatives
Counterparties with offsetting positions or collateral
46.6
( 337.0
)
8.1
0.3
( 282.6
)
Counterparties without offsetting positions - assets
4.2
—
—
4.2
—
Counterparties without offsetting positions - liabilities
—
( 30.5
)
—
—
( 30.5
)
$
50.8
$
( 367.5
)
$
8.1
$
4.5
$
( 313.1
)
18
Some of our hedges are futures contracts executed through brokers that clear the hedges through an exchange. We maintain a margin deposit with the brokers in an amount sufficient to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within Other current assets on our Consolidated Balance Sheets and is not offset against the fair value of our derivative instruments. Our derivative instruments other than our futures contracts are executed under International Swaps and Derivatives Association (“ISDA”) agreements, which govern the key terms with our counterparties. Our ISDA agreements contain credit-risk related contingent features. Pursuant to the terms of the TRGP Revolver, our derivative positions are no longer secured by the collateral securing the TRGP Revolver. As of March 31, 2022, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of approximately ($ 718 ) million. We have not been required to post any collateral related to these positions due to our credit rating. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of March 31, 2022, we would be required to post approximately $ 126 million of collateral to certain counterparties per the terms of our ISDAs.
The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of ($ 737.7 ) million as of March 31, 2022. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.
The following tables reflect amounts recorded in Other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue for the periods indicated:
Gain (Loss) Recognized in OCI on
Derivatives (Effective Portion)
Derivatives in Cash Flow
Three Months Ended March 31,
Hedging Relationships
2022
2021
Commodity contracts
$
( 387.1
)
$
( 171.5
)
Gain (Loss) Reclassified from OCI into
Income (Effective Portion)
Three Months Ended March 31,
Location of Gain (Loss)
2022
2021
Revenues
$
( 145.7
)
$
( 149.7
)
Based on valuations as of March 31, 2022, we expect to reclassify commodity hedge-related deferred losses of ($ 545.4 ) million included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2025, with ($ 423.3 ) million of losses to be reclassified over the next twelve months.
Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the three months ended March 31, 2022, the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward prices, as compared to our positions.
Location of Gain (Loss)
Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated
Recognized in Income on
Three Months Ended March 31,
as Hedging Instruments
Derivatives
2022
2021
Commodity contracts
Revenue
$
( 177.0
)
$
15.0
See Note 14 – Fair Value Measurements and Note 19 – Segment Information for additional disclosures related to derivative instruments and hedging activities.
Note 14 — Fair Value Measurements
Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
19
Fair Value of Derivative Financial Instruments
Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at March 31, 2022, a net liability position of ($ 737.7 ) million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of ($ 930.6 ) million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net liability of ($ 544.8 ) million.
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
•
the TRGP Revolver and the Partnership’s Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and
•
the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.
Fair Value Hierarchy
We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
•
Level 1 – observable inputs such as quoted prices in active markets;
•
Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
•
Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.
The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
March 31, 2022
Carrying
Fair Value
Value
Total
Level 1
Level 2
Level 3
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)
$
25.0
$
25.0
$
—
$
25.0
$
—
Liabilities from commodity derivative contracts (1)
762.7
762.7
—
762.7
—
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents
135.9
135.9
—
—
—
TRGP Revolver
995.0
995.0
—
995.0
—
Partnership's Senior unsecured notes
5,997.6
6,134.7
—
6,134.7
—
Securitization Facility
270.0
270.0
—
270.0
—
20
December 31, 2021
Carrying
Fair Value
Value
Total
Level 1
Level 2
Level 3
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)
$
46.6
$
46.6
$
—
$
46.6
$
—
Liabilities from commodity derivative contracts (1)
363.3
363.3
—
363.3
—
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents
158.5
158.5
—
—
—
Partnership's Senior unsecured notes
6,465.7
6,924.5
—
6,924.5
—
Securitization Facility
150.0
150.0
—
150.0
—
(1)
The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes .
Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets
We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices or implied volatilities for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. As of March 31, 2022, we had no derivative contracts categorized as Level 3.
Note 15 — Contingencies
Legal Proceedings
We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties to various proceedings with governmental environmental agencies, including but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.
On December 26, 2018, Vitol filed a lawsuit in the 80 th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $ 129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached the Splitter Agreement, which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $ 129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.
21
On October 15, 2020, the District Court awarded Vitol $ 129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $ 10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company has filed an appeal challenging the award, and the appeal is currently pending in the Fourteenth Court of Appeals in Houston, Texas.
In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings.
Note 16 — Revenue
Fixed consideration allocated to remaining performance obligations
The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 17 years .
2022
2023
2024 and after
Fixed consideration to be recognized as of March 31, 2022
$
346.9
$
398.5
$
2,319.0
Based on the optional exemptions that we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.
For disclosures related to disaggregated revenue, see Note 19 – Segment Information.
Note 17 — Income Taxes
The Company records income taxes using an estimated annual effective tax rate and recognizes specific events discretely as they occur. We regularly evaluate the realizable tax benefits of deferred tax assets and record a valuation allowance, if required, based on an estimate of the amount of deferred tax assets that we believe does not meet the more-likely-than-not criteria of being realized.
As of March 31, 2022, our valuation allowance was $ 192.8 million, a decrease of $ 17.8 million from December 31, 2021. After the change in valuation allowance, we have a net deferred tax liability of $ 88.0 million.
As we begin achieving sustained profitability, increased consideration will be given to projections of future taxable income to determine whether such projections provide an adequate source of taxable income for the realization of our deferred tax assets and may result in a change to our valuation allowance in the next twelve months. We will continue to evaluate the valuation allowance based on current and expected earnings and other factors and adjust accordingly.
In January 2022, the IRS notified us that it will examine Targa’s net operating loss carryback previously claimed under the Coronavirus Aid, Relief and Economic Security Act. We are in the process of responding to information requests from the IRS and do not anticipate material changes in prior year taxable income.
Note 18 — Supplemental Cash Flow Information
Three Months Ended March 31,
2022
2021
Cash:
Interest paid, net of capitalized interest (1)
$
151.3
$
141.1
Income taxes (received) paid, net
( 0.2
)
0.8
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net
$
( 41.9
)
$
( 12.9
)
Transfers from materials and supplies inventory to property, plant and equipment
—
0.1
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests
$
( 18.2
)
$
( 22.2
)
(1)
Interest capitalized on major projects was $ 2.4 million and $ 0.7 million for the three months ended March 31, 2022 and 2021.
22
Note 19 — Segment Information
We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.
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 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. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.
Reportable segment information is shown in the following tables:
Three Months Ended March 31, 2022
Gathering and Processing
Logistics and Transportation
Other
Corporate
and
Eliminations
Total
Revenues
Sales of commodities
$
134.6
$
4,609.9
$
( 178.3
)
$
—
$
4,566.2
Fees from midstream services
210.4
182.5
—
—
392.9
345.0
4,792.4
( 178.3
)
—
4,959.1
Intersegment revenues
Sales of commodities
2,030.6
124.3
—
( 2,154.9
)
—
Fees from midstream services
0.3
10.8
—
( 11.1
)
—
2,030.9
135.1
—
( 2,166.0
)
—
Revenues
$
2,375.9
$
4,927.5
$
( 178.3
)
$
( 2,166.0
)
$
4,959.1
Operating margin (1)
$
397.6
$
352.1
$
( 178.3
)
Other financial information:
Total assets (2)
$
7,951.0
$
7,196.0
$
1.6
$
146.8
$
15,295.4
Goodwill
$
45.2
$
—
$
—
$
—
$
45.2
Capital expenditures
$
133.0
$
25.2
$
—
$
4.3
$
162.5
(1)
Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.
(2)
Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.
23
Three Months Ended March 31, 2021
Gathering and Processing
Logistics and Transportation
Other
Corporate
and
Eliminations
Total
Revenues
Sales of commodities
$
142.7
$
3,223.5
$
1.5
$
—
$
3,367.7
Fees from midstream services
119.4
145.6
—
—
265.0
262.1
3,369.1
1.5
—
3,632.7
Intersegment revenues
Sales of commodities
969.7
82.5
—
( 1,052.2
)
—
Fees from midstream services
1.6
8.2
—
( 9.8
)
—
971.3
90.7
—
( 1,062.0
)
—
Revenues
$
1,233.4
$
3,459.8
$
1.5
$
( 1,062.0
)
$
3,632.7
Operating margin (1)
$
275.1
$
348.7
$
1.5
Other financial information:
Total assets (2)
$
8,635.2
$
6,743.9
$
90.8
$
178.5
$
15,648.4
Goodwill
$
45.2
$
—
$
—
$
—
$
45.2
Capital expenditures
$
69.5
$
10.4
$
—
$
3.5
$
83.4
(1)
Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.
(2)
Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.
The following table shows our consolidated revenues disaggregated by product and service for the periods presented:
Three Months Ended March 31,
2022
2021
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas
$
964.3
$
841.4
NGL
3,806.5
2,594.4
Condensate and crude oil
118.1
66.6
4,888.9
3,502.4
Non-customer revenue:
Derivative activities - Hedge
( 145.7
)
( 149.7
)
Derivative activities - Non-hedge (1)
( 177.0
)
15.0
( 322.7
)
( 134.7
)
Total sales of commodities
4,566.2
3,367.7
Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing
206.0
116.3
NGL transportation, fractionation and services
65.8
47.2
Storage, terminaling and export
100.9
88.8
Other
20.2
12.7
Total fees from midstream services
392.9
265.0
Total revenues
$
4,959.1
$
3,632.7
(1)
Represents derivative activities that are not designated as hedging instruments under ASC 815.
24
The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the periods presented:
Three Months Ended March 31,
2022
2021
Reconciliation of reportable segment operating
margin to income (loss) before income taxes:
Gathering and Processing operating margin
$
397.6
$
275.1
Logistics and Transportation operating margin
352.1
348.7
Other operating margin
( 178.3
)
1.5
Depreciation and amortization expense
( 209.1
)
( 216.2
)
General and administrative expense
( 67.1
)
( 61.4
)
Interest expense, net
( 93.6
)
( 98.4
)
Equity earnings (loss)
5.6
11.8
Gain (loss) on sale or disposition of assets
1.0
—
Write-down of assets
( 0.5
)
( 3.5
)
Gain (loss) from financing activities
( 15.8
)
( 14.7
)
Other, net
( 0.4
)
—
Income (loss) before income taxes
$
191.5
$
242.9
25
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.