NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines and 144 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.
Basis of Presentation
General
Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation.
In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2020 Form 10-K.
The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and which include dividend equivalent payments, do not participate in excess distributions over earnings.
The following table sets forth the allocation of net income (loss) available to shareholders of Class P shares and participating securities:
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Three Months Ended March 31,
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2021
|
|
2020
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|
(In millions, except per share amounts)
|
|
Net Income (Loss) Available to Stockholders
|
|
|
|
|
$
|
1,409
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|
|
$
|
(306)
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|
|
Participating securities:
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|
|
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|
|
|
|
Less: Net Income allocated to restricted stock awards(a)
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(7)
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(3)
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|
|
Net Income (Loss) Allocated to Class P Stockholders
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$
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1,402
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$
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(309)
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|
Basic Weighted Average Shares Outstanding
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2,264
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|
2,264
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Basic Earnings (Loss) Per Share
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$
|
0.62
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|
$
|
(0.14)
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|
(a)As of March 31, 2021, there were approximately 12 million restricted stock awards outstanding.
The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:
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Three Months Ended March 31,
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2021
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2020
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|
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(In millions on a weighted average basis)
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Unvested restricted stock awards
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13
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12
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|
Convertible trust preferred securities
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3
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3
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|
2. Gains and Losses on Divestitures, Impairments and Other Write-downs
We recognized the following non-cash pre-tax (gains) losses on divestitures, impairments and other write-downs, net on assets during the three months ended March 31, 2021 and 2020:
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Three Months Ended March 31,
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2021
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2020
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(In millions)
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Natural Gas Pipelines
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|
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Gain on sale of interest in NGPL Holdings LLC(a)
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$
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(206)
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$
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—
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Loss on write-down of related party note receivable(a)
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117
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—
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Products Pipelines
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Impairment of long-lived and intangible assets
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—
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21
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Terminals
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Gain on divestitures of long-lived assets
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(1)
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—
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CO2
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Impairment of goodwill(a)
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|
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|
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—
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600
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Impairment of long-lived assets(a)
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|
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—
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350
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|
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Other gain on divestitures of long-lived assets
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(3)
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—
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|
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Pre-tax (gain) loss on divestitures, impairments and other write-downs, net
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$
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(93)
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$
|
971
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(a)See below for a further discussion of these items.
Sale of an Interest in NGPL Holdings
On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $413 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the three months ended March 31, 2021. Upon closing, we and Brookfield each hold a 37.5% interest in NGPL Holdings.
Impairments
During the first quarter of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment and conducted interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020, which resulted in impairments of long-lived assets and goodwill within our CO2 business segment shown in the above table during the three months ended March 31, 2020.
Other Write-downs
During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, driven by the recent impairment by Ruby of its assets, which is included within “Earnings from equity investments” in our accompanying consolidated statement of operations. The impairment at Ruby was the result of upcoming contract expirations and additional uncertainty identified in late February 2021 regarding the proposed development of a third party liquefied natural gas exporting facility that could significantly increase the demand for its services.
3. Debt
The following table provides information on the principal amount of our outstanding debt balances:
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March 31, 2021
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December 31, 2020
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(In millions, unless otherwise stated)
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Current portion of debt
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|
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$4 billion credit facility due November 16, 2023
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$
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—
|
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$
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—
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|
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Commercial paper notes
|
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—
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|
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—
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Current portion of senior notes
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5.00%, due February 2021(a)
|
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—
|
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750
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3.50%, due March 2021(a)
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—
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750
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5.80%, due March 2021(a)
|
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—
|
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400
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5.00%, due October 2021
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500
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500
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8.625%, due January 2022
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260
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|
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—
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4.15%, due March 2022
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375
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—
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1.50%, due March 2022(b)
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880
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—
|
|
|
Trust I preferred securities, 4.75%, due March 2028
|
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111
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111
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Current portion of other debt
|
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47
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47
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Total current portion of debt
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2,173
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|
|
2,558
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|
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Long-term debt (excluding current portion)
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|
|
|
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Senior notes
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29,314
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|
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30,141
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|
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EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035
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361
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|
|
364
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|
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Trust I preferred securities, 4.75%, due March 2028
|
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110
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110
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Other
|
|
222
|
|
|
223
|
|
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Total long-term debt
|
|
30,007
|
|
|
30,838
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|
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Total debt(c)
|
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$
|
32,180
|
|
|
$
|
33,396
|
|
(a)We repaid the principal amounts on these senior notes during the first quarter of 2021.
(b)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The March 31, 2021 balance is reported above at the exchange rate of 1.1730 U.S. dollars per Euro. As of March 31, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $65 million related to these notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance sheets. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 5 “Risk Management—Foreign Currency Risk Management”).
(c)Excludes our “Debt fair value adjustments” which, as of March 31, 2021 and December 31, 2020, increased our total debt balances by $1,054 million and $1,293 million, respectively.
We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.
On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million. These notes are guaranteed through the cross guarantee agreement discussed above.
Credit Facility
As of March 31, 2021, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of March 31, 2021 was $3,919 million. As of March 31, 2021, we were in compliance with all required covenants.
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances are disclosed below:
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March 31, 2021
|
|
December 31, 2020
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Carrying
value
|
|
Estimated
fair value
|
|
Carrying
value
|
|
Estimated
fair value
|
|
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(In millions)
|
|
Total debt
|
$
|
33,234
|
|
|
$
|
37,050
|
|
|
$
|
34,689
|
|
|
$
|
39,622
|
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, 2021 and December 31, 2020.
4. Stockholders’ Equity
Class P Stock
On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. Since December 2017, in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $575 million.
Dividends
The following table provides information about our per share dividends:
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Three Months Ended March 31,
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|
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2021
|
|
2020
|
|
Per share cash dividend declared for the period
|
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|
|
$
|
0.27
|
|
|
$
|
0.2625
|
|
|
Per share cash dividend paid in the period
|
|
|
|
|
0.2625
|
|
|
0.25
|
|
On April 21, 2021, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended March 31, 2021, which is payable on May 17, 2021 to shareholders of record as of the close of business on April 30, 2021.
Accumulated Other Comprehensive Loss
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:
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|
|
|
|
|
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|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjustments
|
|
Total
accumulated other
comprehensive loss
|
|
|
(In millions)
|
|
Balance as of December 31, 2020
|
$
|
(13)
|
|
|
$
|
—
|
|
|
$
|
(394)
|
|
|
$
|
(407)
|
|
|
Other comprehensive (loss) gain before reclassifications
|
(156)
|
|
|
—
|
|
|
17
|
|
|
(139)
|
|
|
Loss reclassified from accumulated other comprehensive loss
|
59
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
Net current-period change in accumulated other comprehensive loss
|
(97)
|
|
|
—
|
|
|
17
|
|
|
(80)
|
|
|
Balance as of March 31, 2021
|
$
|
(110)
|
|
|
$
|
—
|
|
|
$
|
(377)
|
|
|
$
|
(487)
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjustments
|
|
Total
accumulated other
comprehensive loss
|
|
|
(In millions)
|
|
Balance as of December 31, 2019
|
$
|
(7)
|
|
|
$
|
—
|
|
|
$
|
(326)
|
|
|
$
|
(333)
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|
|
Other comprehensive gain before reclassifications
|
222
|
|
|
1
|
|
|
11
|
|
|
234
|
|
|
Loss reclassified from accumulated other comprehensive loss
|
37
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|
Net current-period change in accumulated other comprehensive (loss) income
|
259
|
|
|
1
|
|
|
11
|
|
|
271
|
|
|
Balance as of March 31, 2020
|
$
|
252
|
|
|
$
|
1
|
|
|
$
|
(315)
|
|
|
$
|
(62)
|
|
5. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.
Energy Commodity Price Risk Management
As of March 31, 2021, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
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|
Net open position long/(short)
|
|
Derivatives designated as hedging contracts
|
|
|
|
|
Crude oil fixed price
|
(16.6)
|
|
|
MMBbl
|
|
Crude oil basis
|
(8.7)
|
|
|
MMBbl
|
|
Natural gas fixed price
|
(35.0)
|
|
|
Bcf
|
|
Natural gas basis
|
(30.5)
|
|
|
Bcf
|
|
NGL fixed price
|
(1.2)
|
|
|
MMBbl
|
|
Derivatives not designated as hedging contracts
|
|
|
|
|
Crude oil fixed price
|
(1.0)
|
|
|
MMBbl
|
|
Crude oil basis
|
(12.6)
|
|
|
MMBbl
|
|
Natural gas fixed price
|
(8.2)
|
|
|
Bcf
|
|
Natural gas basis
|
(10.6)
|
|
|
Bcf
|
|
NGL fixed price
|
(1.1)
|
|
|
MMBbl
|
As of March 31, 2021, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2025.
Interest Rate Risk Management
We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of March 31, 2021:
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|
|
Notional amount
|
|
Accounting treatment
|
|
Maximum term
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-variable interest rate contracts(a)
|
|
$
|
7,100
|
|
|
Fair value hedge
|
|
March 2035
|
|
|
Variable-to-fixed interest rate contracts
|
|
250
|
|
|
Cash flow hedge
|
|
January 2023
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
Variable-to-fixed interest rate contracts
|
|
2,500
|
|
|
Mark-to-Market
|
|
December 2021
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
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|
(a)The principal amount of hedged senior notes consisted of $250 million included in “Current portion of debt” and $6,850 million included in “Long-term debt” on our accompanying consolidated balance sheet.
During the three months ended March 31, 2021, we entered into fixed-to-variable interest rate swap agreements with a combined notional principal amount of $375 million. These agreements were designated as accounting hedges and convert a portion of our fixed rate debt to variable rate through February 2028.
Foreign Currency Risk Management
We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of March 31, 2021:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional amount
|
|
Accounting treatment
|
|
Maximum term
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
EUR-to-USD cross currency swap contracts(a)
|
|
$
|
1,358
|
|
|
Cash flow hedge
|
|
March 2027
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivative Contracts
|
|
|
|
|
|
Derivatives Asset
|
|
Derivatives Liability
|
|
|
|
|
|
March 31,
2021
|
|
December 31,
2020
|
|
March 31,
2021
|
|
December 31,
2020
|
|
|
|
Location
|
|
Fair value
|
|
Fair value
|
|
|
|
|
|
(In millions)
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
$
|
13
|
|
|
$
|
42
|
|
|
$
|
(92)
|
|
|
$
|
(33)
|
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
6
|
|
|
33
|
|
|
(29)
|
|
|
(8)
|
|
|
Subtotal
|
|
|
|
19
|
|
|
75
|
|
|
(121)
|
|
|
(41)
|
|
|
Interest rate contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
126
|
|
|
119
|
|
|
(3)
|
|
|
(3)
|
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
364
|
|
|
575
|
|
|
(19)
|
|
|
(7)
|
|
|
Subtotal
|
|
|
|
490
|
|
|
694
|
|
|
(22)
|
|
|
(10)
|
|
|
Foreign currency contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
56
|
|
|
—
|
|
|
(12)
|
|
|
(6)
|
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
43
|
|
|
138
|
|
|
—
|
|
|
—
|
|
|
Subtotal
|
|
|
|
99
|
|
|
138
|
|
|
(12)
|
|
|
(6)
|
|
|
Total
|
|
|
|
608
|
|
|
907
|
|
|
(155)
|
|
|
(57)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
23
|
|
|
24
|
|
|
(33)
|
|
|
(21)
|
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
23
|
|
|
24
|
|
|
(34)
|
|
|
(21)
|
|
|
Total derivatives
|
|
|
|
$
|
631
|
|
|
$
|
931
|
|
|
$
|
(189)
|
|
|
$
|
(78)
|
|
The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet asset fair value measurements by level
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross amount
|
|
Contracts available for netting
|
|
Cash collateral held(b)
|
|
Net amount
|
|
|
(In millions)
|
|
As of March 31, 2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
10
|
|
|
$
|
32
|
|
|
$
|
—
|
|
|
$
|
42
|
|
|
$
|
(37)
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
Interest rate contracts
|
—
|
|
|
490
|
|
|
—
|
|
|
490
|
|
|
(9)
|
|
|
—
|
|
|
481
|
|
|
Foreign currency contracts
|
—
|
|
|
99
|
|
|
—
|
|
|
99
|
|
|
(12)
|
|
|
—
|
|
|
87
|
|
|
As of December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
6
|
|
|
$
|
93
|
|
|
$
|
—
|
|
|
$
|
99
|
|
|
$
|
(35)
|
|
|
$
|
—
|
|
|
$
|
64
|
|
|
Interest rate contracts
|
—
|
|
|
694
|
|
|
—
|
|
|
694
|
|
|
(2)
|
|
|
—
|
|
|
692
|
|
|
Foreign currency contracts
|
—
|
|
|
138
|
|
|
—
|
|
|
138
|
|
|
(6)
|
|
|
—
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet liability
fair value measurements by level
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross amount
|
|
Contracts available for netting
|
|
Cash collateral posted(b)
|
|
Net amount
|
|
|
(In millions)
|
|
As of March 31, 2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(12)
|
|
|
$
|
(143)
|
|
|
$
|
—
|
|
|
$
|
(155)
|
|
|
$
|
37
|
|
|
$
|
6
|
|
|
$
|
(112)
|
|
|
Interest rate contracts
|
—
|
|
|
(22)
|
|
|
—
|
|
|
(22)
|
|
|
9
|
|
|
—
|
|
|
(13)
|
|
|
Foreign currency contracts
|
—
|
|
|
(12)
|
|
|
—
|
|
|
(12)
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
As of December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(7)
|
|
|
$
|
(56)
|
|
|
$
|
—
|
|
|
$
|
(63)
|
|
|
$
|
35
|
|
|
$
|
(8)
|
|
|
$
|
(36)
|
|
|
Interest rate contracts
|
—
|
|
|
(10)
|
|
|
—
|
|
|
(10)
|
|
|
2
|
|
|
—
|
|
|
(8)
|
|
|
Foreign currency contracts
|
—
|
|
|
(6)
|
|
|
—
|
|
|
(6)
|
|
|
6
|
|
|
—
|
|
|
—
|
|
(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
(b)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.
The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of operations and comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in fair value hedging relationships
|
|
Location
|
|
|
|
|
|
Gain/(loss) recognized in income
on derivative and related hedged item
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
2021
|
|
2020
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Interest rate contracts
|
|
Interest, net
|
|
|
|
|
|
$
|
(217)
|
|
|
$
|
433
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged fixed rate debt(a)
|
|
Interest, net
|
|
|
|
|
|
$
|
219
|
|
|
$
|
(440)
|
|
(a)As of March 31, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $484 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in cash flow hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative(a)
|
|
Location
|
|
Gain/(loss) reclassified from Accumulated OCI
into income(b)
|
|
|
|
Three Months Ended March 31,
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2021
|
|
2020
|
|
|
|
2021
|
|
2020
|
|
|
|
(In millions)
|
|
|
|
(In millions)
|
|
Energy commodity derivative contracts
|
|
$
|
(158)
|
|
|
$
|
379
|
|
|
Revenues—Commodity sales
|
|
$
|
(20)
|
|
|
$
|
(8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
4
|
|
|
(17)
|
|
|
Interest rate contracts
|
|
1
|
|
|
(8)
|
|
|
Earnings from equity investments(c)
|
|
—
|
|
|
—
|
|
|
Foreign currency contracts
|
|
(46)
|
|
|
(82)
|
|
|
Other, net
|
|
(61)
|
|
|
(23)
|
|
|
Total
|
|
$
|
(203)
|
|
|
$
|
289
|
|
|
Total
|
|
$
|
(77)
|
|
|
$
|
(48)
|
|
(a)We expect to reclassify approximately $35 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of March 31, 2021 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the three months ended March 31, 2021 and 2020, we recognized gains of $6 million and $12 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as accounting hedges
|
|
Location
|
|
|
|
|
|
Gain/(loss) recognized in income on derivatives
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
2021
|
|
2020
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Energy commodity derivative contracts
|
|
Revenues—Commodity sales
|
|
|
|
|
|
$
|
(631)
|
|
|
$
|
117
|
|
|
|
|
Costs of sales
|
|
|
|
|
|
163
|
|
|
4
|
|
|
Total(a)
|
|
|
|
|
|
|
|
$
|
(468)
|
|
|
$
|
121
|
|
(a)The three months ended March 31, 2021 and 2020 amounts include approximate losses of $448 million and gains of $74 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of March 31, 2021 and December 31, 2020, we had no outstanding letters of credit supporting our commodity price risk management program. As of March 31, 2021, we had cash margins of $30 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2020, we had cash margins of $3 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at March 31, 2021 represents the net of our initial margin requirements of $24 million and counterparty variation margin requirements of $6 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of March 31, 2021, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $67 million of additional collateral.
6. Revenue Recognition
Disaggregation of Revenues
The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2021
|
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Corporate and Eliminations
|
|
Total
|
|
|
|
(In millions)
|
|
Revenues from contracts with customers(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm services(b)
|
|
$
|
866
|
|
|
$
|
59
|
|
|
$
|
191
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,116
|
|
|
Fee-based services
|
|
178
|
|
|
221
|
|
|
81
|
|
|
15
|
|
|
—
|
|
|
495
|
|
|
Total services
|
|
1,044
|
|
|
280
|
|
|
272
|
|
|
15
|
|
|
—
|
|
|
1,611
|
|
|
Commodity sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
3,319
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(5)
|
|
|
3,315
|
|
|
Product sales
|
|
220
|
|
|
125
|
|
|
5
|
|
|
229
|
|
|
(10)
|
|
|
569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commodity sales
|
|
3,539
|
|
|
125
|
|
|
5
|
|
|
230
|
|
|
(15)
|
|
|
3,884
|
|
|
Total revenues from contracts with customers
|
|
4,583
|
|
|
405
|
|
|
277
|
|
|
245
|
|
|
(15)
|
|
|
5,495
|
|
|
Other revenues(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leasing services(d)
|
|
119
|
|
|
43
|
|
|
143
|
|
|
12
|
|
|
(1)
|
|
|
316
|
|
|
Derivatives adjustments on commodity sales
|
|
(618)
|
|
|
—
|
|
|
—
|
|
|
(33)
|
|
|
—
|
|
|
(651)
|
|
|
Other
|
|
41
|
|
|
5
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
51
|
|
|
Total other revenues
|
|
(458)
|
|
|
48
|
|
|
143
|
|
|
(16)
|
|
|
(1)
|
|
|
(284)
|
|
|
Total revenues
|
|
$
|
4,125
|
|
|
$
|
453
|
|
|
$
|
420
|
|
|
$
|
229
|
|
|
$
|
(16)
|
|
|
$
|
5,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2020
|
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Corporate and Eliminations
|
|
Total
|
|
|
|
(In millions)
|
|
Revenues from contracts with customers(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm services(b)
|
|
$
|
865
|
|
|
$
|
79
|
|
|
$
|
189
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,133
|
|
|
Fee-based services
|
|
193
|
|
|
260
|
|
|
121
|
|
|
13
|
|
|
—
|
|
|
587
|
|
|
Total services
|
|
1,058
|
|
|
339
|
|
|
310
|
|
|
13
|
|
|
—
|
|
|
1,720
|
|
|
Commodity sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
501
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2)
|
|
|
499
|
|
|
Product sales
|
|
136
|
|
|
109
|
|
|
3
|
|
|
232
|
|
|
(13)
|
|
|
467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commodity sales
|
|
637
|
|
|
109
|
|
|
3
|
|
|
232
|
|
|
(15)
|
|
|
966
|
|
|
Total revenues from contracts with customers
|
|
1,695
|
|
|
448
|
|
|
313
|
|
|
245
|
|
|
(15)
|
|
|
2,686
|
|
|
Other revenues(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leasing services(d)
|
|
113
|
|
|
42
|
|
|
129
|
|
|
10
|
|
|
—
|
|
|
294
|
|
|
Derivatives adjustments on commodity sales
|
|
52
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
—
|
|
|
104
|
|
|
Other
|
|
15
|
|
|
5
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
22
|
|
|
Total other revenues
|
|
180
|
|
|
47
|
|
|
129
|
|
|
64
|
|
|
—
|
|
|
420
|
|
|
Total revenues
|
|
$
|
1,875
|
|
|
$
|
495
|
|
|
$
|
442
|
|
|
$
|
309
|
|
|
$
|
(15)
|
|
|
$
|
3,106
|
|
(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.
Contract Balances
As of March 31, 2021 and December 31, 2020, our contract asset balances were $31 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $9 million was transferred to accounts receivable during the three months ended March 31, 2021. As of March 31, 2021 and December 31, 2020, our contract liability balances were $243 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $24 million was recognized as revenue during the three months ended March 31, 2021.
Revenue Allocated to Remaining Performance Obligations
The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of March 31, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Estimated Revenue
|
|
|
|
(In millions)
|
|
Nine months ended December 31, 2021
|
|
$
|
3,276
|
|
|
2022
|
|
3,626
|
|
|
2023
|
|
2,924
|
|
|
2024
|
|
2,508
|
|
|
2025
|
|
2,124
|
|
|
Thereafter
|
|
13,585
|
|
|
Total
|
|
$
|
28,043
|
|
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedient that we elected to apply, remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
7. Reportable Segments
Financial information by segment follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
|
|
|
|
|
(In millions)
|
|
Revenues
|
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
|
|
|
|
|
|
|
|
Revenues from external customers
|
|
|
|
|
$
|
4,110
|
|
|
$
|
1,861
|
|
|
Intersegment revenues
|
|
|
|
|
15
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
Products Pipelines
|
|
|
|
|
453
|
|
|
495
|
|
|
|
|
|
|
|
|
|
|
|
Terminals
|
|
|
|
|
|
|
|
|
Revenues from external customers
|
|
|
|
|
419
|
|
|
441
|
|
|
Intersegment revenues
|
|
|
|
|
1
|
|
|
1
|
|
|
CO2
|
|
|
|
|
229
|
|
|
309
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and intersegment eliminations
|
|
|
|
|
(16)
|
|
|
(15)
|
|
|
Total consolidated revenues
|
|
|
|
|
$
|
5,211
|
|
|
$
|
3,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
|
|
|
|
|
(In millions)
|
|
Segment EBDA(a)
|
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
|
|
|
|
$
|
2,103
|
|
|
$
|
1,196
|
|
|
Products Pipelines
|
|
|
|
|
248
|
|
|
269
|
|
|
Terminals
|
|
|
|
|
227
|
|
|
257
|
|
|
CO2
|
|
|
|
|
286
|
|
|
(755)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Segment EBDA
|
|
|
|
|
2,864
|
|
|
967
|
|
|
DD&A
|
|
|
|
|
(541)
|
|
|
(565)
|
|
|
Amortization of excess cost of equity investments
|
|
|
|
|
(22)
|
|
|
(32)
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative and corporate charges
|
|
|
|
|
(148)
|
|
|
(165)
|
|
|
Interest, net
|
|
|
|
|
(377)
|
|
|
(436)
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
|
|
|
(351)
|
|
|
(60)
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated net income (loss)
|
|
|
|
|
$
|
1,425
|
|
|
$
|
(291)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021
|
|
December 31, 2020
|
|
|
(In millions)
|
|
Assets
|
|
|
|
|
Natural Gas Pipelines
|
$
|
48,262
|
|
|
$
|
48,597
|
|
|
Products Pipelines
|
9,152
|
|
|
9,182
|
|
|
Terminals
|
8,560
|
|
|
8,639
|
|
|
CO2
|
2,517
|
|
|
2,478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate assets(b)
|
2,717
|
|
|
3,077
|
|
|
|
|
|
|
|
Total consolidated assets
|
$
|
71,208
|
|
|
$
|
71,973
|
|
(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, (gain) loss on divestitures and impairments, net, and other income, net.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.
8. Income Taxes
Income tax expense included in our accompanying consolidated statements of operations is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
2021
|
|
2020
|
|
|
|
|
|
|
(In millions, except percentages)
|
|
Income tax expense
|
|
|
|
|
$
|
351
|
|
|
$
|
60
|
|
|
Effective tax rate
|
|
|
|
|
19.8
|
%
|
|
(26.0)
|
%
|
The effective tax rate for the three months ended March 31, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.
The effective tax rate for the three months ended March 31, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to a $600 million impairment of goodwill, which is a reduction to income but is not deductible for tax purposes. This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investment in Citrus and PPL. While we would normally expect a federal income tax benefit from our loss
before income taxes for the three months ended March 31, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period.
9. Litigation and Environmental
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.
SFPP FERC Proceedings
The FERC approved the SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the EL Settlement were fully accrued on or before December 31, 2020.
The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two-year period preceding the filing date of their complaints and/or prospective refunds in protest cases from the date of protest, and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings at the FERC that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million in rate refunds and unspecified rate reductions as of the date of their complaints in 2014 and 2018. The claims pleaded by the shippers are expected to change due to the passage of time and interest. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. We do not believe the ultimate resolution of the shipper complaints and protests seeking rate reductions or refunds in the ongoing proceedings will have a material adverse impact on our business.
Gulf LNG Facility Disputes
On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. On June 29, 2018, the arbitration panel delivered its Award, and the panel's ruling called for the termination of the agreement and Eni USA’s payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.
On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending.
On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from re-arbitrating both the breach of contract and negligent misrepresentation claims. On April 15, 2021, Eni USA filed a petition for writ of certiorari with the U.S. Supreme Court seeking review of the Delaware Supreme Court’s decision. This petition remains pending.
On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in this arbitration is expected before the end of the third quarter of 2021.
GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.
Continental Resources, Inc. v. Hiland Partners Holdings, LLC
On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies and will vigorously defend against these claims.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
General
As of March 31, 2021 and December 31, 2020, our total reserve for legal matters was $130 million and $273 million, respectively.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and
liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.
We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts.
In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas or CO2.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated by the EPA to be more than $3 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around June 2023. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.
In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a PRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey
EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins.
In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020. We anticipate the PRPs, including EPEC Polymers, will engage in further discussions with the EPA during 2021. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the PRPs engage in discussions with the EPA, the FS is completed, and the RI/FS is finalized, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.
Louisiana Governmental Coastal Zone Erosion Litigation
Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Court of Appeals. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’
operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
Louisiana Landowner Coastal Erosion Litigation
Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including three cases against TGP, two cases against SNG, and one case against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. We will continue to vigorously defend the remaining cases.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of March 31, 2021 and December 31, 2020, we have accrued a total reserve for environmental liabilities in the amount of $256 million and $250 million, respectively. In addition, as of both March 31, 2021 and December 31, 2020, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.
10. Recent Accounting Pronouncements
Reference Rate Reform (Topic 848)
On March 12, 2020, the FASB issued Accounting Standards Update (ASU) No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate. Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.
On January 7, 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.
The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of Topic 848 to our financial statements.
ASU No. 2020-06
On August 5, 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features; (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method; and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.