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 147 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 reporting currency is U.S. dollars, and all references to “dollars” are U.S. dollars, unless stated otherwise. 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 2019 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.
COVID-19
The COVID-19 pandemic-related reduction in energy demand and the sharp decline in commodity prices related to the combined impact of falling demand and recent increases in production from Organization of Petroleum Exporting Countries (OPEC) members and other international suppliers have caused significant disruptions and volatility in the global marketplace during the first quarter of 2020. In the first quarter of 2020, we were negatively affected by these events, which, among many other inputs, resulted in $950 million of losses from impairments in our CO2 business segment. These non-cash impairments are further discussed in Note 2.
There remains a continuing significant uncertainty regarding the length and impact of COVID-19 and decreased commodity prices on the energy industry and potential future impacts to our business.
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 available to shareholders of Class P shares and participating securities (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
|
Net (Loss) Income Available to Common Stockholders
|
$
|
(306
|
)
|
|
$
|
556
|
|
|
Participating securities:
|
|
|
|
|
Less: Net Income allocated to restricted stock awards(a)
|
(3
|
)
|
|
(3
|
)
|
|
Net (Loss) Income Allocated to Class P Stockholders
|
$
|
(309
|
)
|
|
$
|
553
|
|
|
|
|
|
|
|
Basic Weighted Average Common Shares Outstanding
|
2,264
|
|
|
2,262
|
|
|
Basic (Loss) Earnings Per Common Share
|
$
|
(0.14
|
)
|
|
$
|
0.24
|
|
________
|
|
|
|
(a)
|
As of March 31, 2020, 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 (in millions on a weighted-average basis):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
|
Unvested restricted stock awards
|
12
|
|
|
13
|
|
|
Convertible trust preferred securities
|
3
|
|
|
3
|
|
2. Impairments
During the first quarter of 2020, the decrease in the worldwide demand for crude oil primarily due to COVID-19 and sharp decline in commodity prices related to the combined impact of falling demand and recent increases in production from OPEC members and other international suppliers resulted in decreases in current and expected long-term crude oil and NGL sale prices, along with reductions to the market capitalization of peer companies in the energy industry. We determined that these conditions represented a triggering event that required us to perform impairment testing of 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.
Long-lived Assets
For our CO2 assets, the long lived asset impairment test involved a Step 1 assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows.
|
|
|
|
•
|
To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer’s estimates of proved and risk adjusted probable reserves. These estimates of proved and probable reserves are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.
|
|
|
|
|
•
|
To compute estimated future cash flows for our CO2 source and transportation assets, volume forecasts were developed based on projected demand for our CO2 services based upon management’s projections of the availability of CO2 supply and the future demand for CO2 for use in enhanced oil recovery projects. The CO2 pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO2 pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.
|
Certain oil and gas properties failed the first step. For these assets, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represents the estimated weighted average cost of capital of a
theoretical market participant. Based on step two of our long lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.
Goodwill
The following goodwill impairment test for our CO2 and Natural Gas Pipelines Non-Regulated reporting units reflects our adoption of the Accounting Standards Updates (ASU) No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” on January 1, 2020. This new accounting method simplifies the goodwill impairment test by removing Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation.
For our CO2 and Natural Gas Pipelines Non-Regulated reporting units, we applied an income approach to evaluate the fair value of these reporting units based on the present value of cash flows these reporting units are expected to generate in the future. Due to the uncertainty and volatility in market conditions within our peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.
|
|
|
|
•
|
In determining the fair value for our CO2 reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO2 reporting unit of approximately $600 million as of March 31, 2020.
|
|
|
|
|
•
|
For our Natural Gas Pipelines Non-Regulated reporting unit, the income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6 years of projections and application of a year 6 exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. The discounted cash flows included various assumptions on volumes and prices for each underlying asset within the reporting unit including, as applicable, current commodity prices. The results of our impairment analysis for our Natural Gas Pipelines Non-Regulated reporting unit did not indicate an impairment of goodwill with the reporting unit’s fair value in excess of its carrying value by less than 10% as of March 31, 2020.
|
We consider the inputs for our long-lived asset and goodwill impairment calculations to be Level 3 inputs in the fair value hierarchy.
We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
|
Products Pipelines
|
|
|
|
|
Impairments of long-lived and intangible assets(a)
|
$
|
21
|
|
|
$
|
—
|
|
|
CO2
|
|
|
|
|
Impairments of long-lived assets
|
350
|
|
|
—
|
|
|
Impairment of goodwill
|
600
|
|
|
—
|
|
|
Kinder Morgan Canada
|
|
|
|
|
Losses on divestiture of long-lived assets
|
—
|
|
|
2
|
|
|
Other gains on divestitures of long-lived assets
|
—
|
|
|
(2
|
)
|
|
Pre-tax losses on divestitures and impairments, net
|
$
|
971
|
|
|
$
|
—
|
|
_______
|
|
|
|
(a)
|
2020 impairment amount is associated with our Belton terminal.
|
Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us. In addition, the revenues, cash flows, profitability and future growth of some of our
businesses depend to a large degree on prevailing crude oil, NGL and natural gas prices. Our CO2 business segment (and the carrying value of our crude oil, NGL and natural gas producing properties) and certain midstream businesses within our Natural Gas Pipelines business segment depend to a large degree, and certain businesses within our Product Pipelines business segment depend to a lesser degree, on prevailing crude oil, NGL and natural gas prices.
As conditions warrant, we routinely evaluate our assets for potential triggering events such as those described above that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. In the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. In addition, we are required to perform our annual goodwill impairment test on May 31st. Because certain of our assets have been written down to fair value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.
3. Debt
The following table provides information on the principal amount of our outstanding debt balances (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2020
|
|
December 31, 2019
|
|
Current portion of debt
|
|
|
|
|
$4 billion credit facility due November 16, 2023
|
$
|
—
|
|
|
$
|
—
|
|
|
Commercial paper notes(a)
|
—
|
|
|
37
|
|
|
Current portion of senior notes
|
|
|
|
|
6.85%, due February 2020(b)
|
—
|
|
|
700
|
|
|
6.50%, due April 2020(c)
|
535
|
|
|
535
|
|
|
5.30%, due September 2020
|
600
|
|
|
600
|
|
|
6.50%, due September 2020
|
349
|
|
|
349
|
|
|
5.00%, due February 2021
|
750
|
|
|
—
|
|
|
3.50%, due March 2021
|
750
|
|
|
—
|
|
|
5.80%, due March 2021
|
400
|
|
|
—
|
|
|
Trust I preferred securities, 4.75%, due March 2028
|
111
|
|
|
111
|
|
|
Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d)
|
—
|
|
|
100
|
|
|
Current portion of other debt
|
45
|
|
|
45
|
|
|
Total current portion of debt
|
3,540
|
|
|
2,477
|
|
|
|
|
|
|
|
Long-term debt (excluding current portion)
|
|
|
|
|
Senior notes
|
29,242
|
|
|
30,164
|
|
|
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035
|
377
|
|
|
381
|
|
|
Trust I preferred securities, 4.75%, due March 2028
|
110
|
|
|
110
|
|
|
Other
|
226
|
|
|
228
|
|
|
Total long-term debt
|
29,955
|
|
|
30,883
|
|
|
Total debt(e)
|
$
|
33,495
|
|
|
$
|
33,360
|
|
_______
|
|
|
|
(a)
|
Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%.
|
|
|
|
|
(b)
|
On January 9, 2020, we sold the approximate 25 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to repay debt that matured in February 2020. The fair value of the Pembina common equity of$925 million as of December 31, 2019 was reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet.
|
|
|
|
|
(c)
|
As of March 31, 2020, funds for the repayment of these maturing notes, and associated accrued interest, were held in escrow and included in the accompanying consolidated balance sheet within “Restricted deposits.”
|
|
|
|
|
(d)
|
In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020.
|
|
|
|
|
(e)
|
Excludes our “Debt fair value adjustments” which, as of March 31, 2020 and December 31, 2019, increased our total debt balances by $1,450 million and $1,032 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements.
|
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 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $994 million. These notes are guaranteed through the cross guarantee agreement discussed above.
Credit Facility
As of March 31, 2020, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $83 million in letters of credit. Our availability under our credit facility as of March 31, 2020 was $3,917 million. As of March 31, 2020, 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 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2020
|
|
December 31, 2019
|
|
|
Carrying
value
|
|
Estimated
fair value
|
|
Carrying
value
|
|
Estimated
fair value
|
|
Total debt
|
$
|
34,945
|
|
|
$
|
34,198
|
|
|
$
|
34,392
|
|
|
$
|
38,016
|
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, 2020 and December 31, 2019.
4. Stockholders’ Equity
Class P Common Stock
On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the three months ended March 31, 2020, we repurchased approximately 3.6 million of our Class P shares for approximately $50 million at an average price of approximately $13.94 per share. 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.
For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2019 Form 10-K.
Common Stock Dividends
Holders of our common stock participate in common stock dividends declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
|
Per common share cash dividend declared for the period
|
$
|
0.2625
|
|
|
$
|
0.25
|
|
|
Per common share cash dividend paid in the period
|
0.25
|
|
|
0.20
|
|
On April 22, 2020, our board of directors declared a cash dividend of $0.2625 per common share for the quarterly period ended March 31, 2020, which is payable on May 15, 2020 to common shareholders of record as of the close of business on May 4, 2020.
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 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjustments
|
|
Total
accumulated other
comprehensive loss
|
|
Balance as of December 31, 2019
|
$
|
(7
|
)
|
|
$
|
—
|
|
|
$
|
(326
|
)
|
|
$
|
(333
|
)
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjustments
|
|
Total
accumulated other
comprehensive loss
|
|
Balance as of December 31, 2018
|
$
|
164
|
|
|
$
|
(91
|
)
|
|
$
|
(403
|
)
|
|
$
|
(330
|
)
|
|
Other comprehensive (loss) gain before reclassifications
|
(215
|
)
|
|
16
|
|
|
8
|
|
|
(191
|
)
|
|
Loss reclassified from accumulated other comprehensive loss
|
13
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
Net current-period change in accumulated other comprehensive income (loss)
|
(202
|
)
|
|
16
|
|
|
8
|
|
|
(178
|
)
|
|
Balance as of March 31, 2019
|
$
|
(38
|
)
|
|
$
|
(75
|
)
|
|
$
|
(395
|
)
|
|
$
|
(508
|
)
|
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.
During the three months ended March 31, 2020, we entered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $2,500 million, which was not designated as an accounting hedge. These agreements effectively fixed our LIBOR exposure for a portion of our fixed to floating rate interest rate swaps for 2020. As of March 31, 2020, the maximum length of time over which we have hedged a portion of our exposure to the variability in future interest payments is through December 31, 2020.
Energy Commodity Price Risk Management
As of March 31, 2020, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
|
|
|
|
|
|
|
|
|
|
Net open position long/(short)
|
|
Derivatives designated as hedging contracts
|
|
|
|
|
Crude oil fixed price
|
(18.9
|
)
|
|
MMBbl
|
|
Crude oil basis
|
(6.2
|
)
|
|
MMBbl
|
|
Natural gas fixed price
|
(35.7
|
)
|
|
Bcf
|
|
Natural gas basis
|
(31.3
|
)
|
|
Bcf
|
|
NGL fixed price
|
(1.2
|
)
|
|
MMBbl
|
|
Derivatives not designated as hedging contracts
|
|
|
|
|
|
Crude oil fixed price
|
(0.7
|
)
|
|
MMBbl
|
|
Crude oil basis
|
(2.4
|
)
|
|
MMBbl
|
|
Natural gas fixed price
|
(17.3
|
)
|
|
Bcf
|
|
Natural gas basis
|
23.4
|
|
|
Bcf
|
|
NGL fixed price
|
(1.7
|
)
|
|
MMBbl
|
As of March 31, 2020, 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 2023.
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, 2020 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional amount
|
|
Accounting treatment
|
|
Maximum term
|
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-variable interest rate contracts(a)
|
|
$8,025
|
|
Fair value hedge
|
|
March 2035
|
|
|
Variable-to-fixed interest rate contracts
|
|
$250
|
|
Cash flow hedge
|
|
January 2023
|
|
|
Variable-to-fixed interest rate contracts
|
|
$2,500
|
|
Mark-to-Market
|
|
December 2020
|
|
_______
|
|
|
|
(a)
|
The principal amount of hedged senior notes consisted of $1,300 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet.
|
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, 2020 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional amount
|
|
Accounting treatment
|
|
Maximum term
|
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
EUR-to-USD cross currency swap contracts(a)
|
|
$1,358
|
|
Cash flow hedge
|
|
March 2027
|
|
_______
(a) These swaps eliminate the foreign currency risk associated with all of our Euro-denominated debt.
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivative Contracts
|
|
|
|
|
|
Derivatives Asset
|
|
Derivatives Liability
|
|
|
|
|
|
March 31,
2020
|
|
December 31,
2019
|
|
March 31,
2020
|
|
December 31,
2019
|
|
|
|
Location
|
|
Fair value
|
|
Fair value
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
$
|
279
|
|
|
$
|
31
|
|
|
$
|
(7
|
)
|
|
$
|
(43
|
)
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
135
|
|
|
17
|
|
|
—
|
|
|
(8
|
)
|
|
Subtotal
|
|
|
|
414
|
|
|
48
|
|
|
(7
|
)
|
|
(51
|
)
|
|
Interest rate contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
126
|
|
|
45
|
|
|
(2
|
)
|
|
—
|
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
666
|
|
|
313
|
|
|
(9
|
)
|
|
(1
|
)
|
|
Subtotal
|
|
|
|
792
|
|
|
358
|
|
|
(11
|
)
|
|
(1
|
)
|
|
Foreign currency contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
—
|
|
|
—
|
|
|
(30
|
)
|
|
(6
|
)
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
11
|
|
|
46
|
|
|
(24
|
)
|
|
—
|
|
|
Subtotal
|
|
|
|
11
|
|
|
46
|
|
|
(54
|
)
|
|
(6
|
)
|
|
Total
|
|
|
|
1,217
|
|
|
452
|
|
|
(72
|
)
|
|
(58
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
43
|
|
|
8
|
|
|
(2
|
)
|
|
(7
|
)
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Subtotal
|
|
|
|
47
|
|
|
8
|
|
|
(2
|
)
|
|
(7
|
)
|
|
Interest rate contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
Subtotal
|
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
Total
|
|
|
|
47
|
|
|
8
|
|
|
(6
|
)
|
|
(7
|
)
|
|
Total derivatives
|
|
|
|
$
|
1,264
|
|
|
$
|
460
|
|
|
$
|
(78
|
)
|
|
$
|
(65
|
)
|
The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC (in millions). 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
|
|
As of March 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
6
|
|
|
$
|
455
|
|
|
$
|
—
|
|
|
$
|
461
|
|
|
$
|
(9
|
)
|
|
$
|
(25
|
)
|
|
$
|
427
|
|
|
Interest rate contracts
|
—
|
|
|
792
|
|
|
—
|
|
|
792
|
|
|
(2
|
)
|
|
—
|
|
|
790
|
|
|
Foreign currency contracts
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
As of December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
19
|
|
|
$
|
37
|
|
|
$
|
—
|
|
|
$
|
56
|
|
|
$
|
(19
|
)
|
|
$
|
(21
|
)
|
|
$
|
16
|
|
|
Interest rate contracts
|
—
|
|
|
358
|
|
|
—
|
|
|
358
|
|
|
—
|
|
|
—
|
|
|
358
|
|
|
Foreign currency contracts
|
—
|
|
|
46
|
|
|
—
|
|
|
46
|
|
|
(6
|
)
|
|
—
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
As of March 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(7
|
)
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
(9
|
)
|
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Interest rate contracts
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
(15
|
)
|
|
2
|
|
|
—
|
|
|
(13
|
)
|
|
Foreign currency contracts
|
—
|
|
|
(54
|
)
|
|
—
|
|
|
(54
|
)
|
|
11
|
|
|
—
|
|
|
(43
|
)
|
|
As of December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(3
|
)
|
|
$
|
(55
|
)
|
|
$
|
—
|
|
|
$
|
(58
|
)
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
(39
|
)
|
|
Interest rate contracts
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
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 (loss) income (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in fair value hedging relationships
|
|
Location
|
|
Gain/(loss) recognized in income
on derivative and related hedged item
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
Interest, net
|
|
$
|
433
|
|
|
$
|
128
|
|
|
|
|
|
|
|
|
|
|
Hedged fixed rate debt(a)
|
|
Interest, net
|
|
$
|
(440
|
)
|
|
$
|
(138
|
)
|
_______
|
|
|
|
(a)
|
As of March 31, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $799 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,
|
|
|
|
2020
|
|
2019
|
|
|
|
2020
|
|
2019
|
|
Energy commodity derivative contracts
|
|
$
|
379
|
|
|
$
|
(245
|
)
|
|
Revenues—Commodity sales
|
|
$
|
(8
|
)
|
|
$
|
13
|
|
|
Interest rate contracts
|
|
(8
|
)
|
|
—
|
|
|
Costs of sales
|
|
(17
|
)
|
|
1
|
|
|
Foreign currency contracts
|
|
(82
|
)
|
|
(34
|
)
|
|
Other, net
|
|
(23
|
)
|
|
(31
|
)
|
|
Total
|
|
$
|
289
|
|
|
$
|
(279
|
)
|
|
Total
|
|
$
|
(48
|
)
|
|
$
|
(17
|
)
|
_______
|
|
|
|
(a)
|
We expect to reclassify an approximate $257 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of March 31, 2020 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)
|
Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in net investment hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2020
|
|
2019
|
|
Foreign currency contracts
|
|
$
|
—
|
|
|
$
|
(8
|
)
|
|
Total
|
|
$
|
—
|
|
|
$
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
Location
|
|
Gain/(loss) recognized in income on derivatives
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2020
|
|
2019
|
|
Energy commodity derivative contracts
|
|
Revenues—Commodity sales
|
|
$
|
117
|
|
|
$
|
10
|
|
|
|
|
Costs of sales
|
|
4
|
|
|
(2
|
)
|
|
Total(a)
|
|
|
|
$
|
121
|
|
|
$
|
8
|
|
_______
|
|
|
|
(a)
|
The three months ended March 31, 2020 and 2019 amounts include approximate gains of $74 million and $8 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, 2020 and December 31, 2019, we had no outstanding letters of credit supporting our commodity price risk management program. As of March 31, 2020 and December 31, 2019, we had cash margins of $19 million and $15 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at March 31, 2020 represents the net of our initial margin requirements of $6 million, offset by counterparty variation margin requirements of $25 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, 2020, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post 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 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2020
|
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Corporate and Eliminations
|
|
Total
|
|
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)
|
|
180
|
|
|
47
|
|
|
129
|
|
|
64
|
|
|
—
|
|
|
420
|
|
|
Total revenues
|
|
$
|
1,875
|
|
|
$
|
495
|
|
|
$
|
442
|
|
|
$
|
309
|
|
|
$
|
(15
|
)
|
|
$
|
3,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2019
|
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Corporate and Eliminations
|
|
Total
|
|
Revenues from contracts with customers(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm services(b)
|
|
$
|
930
|
|
|
$
|
80
|
|
|
$
|
250
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
1,259
|
|
|
Fee-based services
|
|
192
|
|
|
235
|
|
|
148
|
|
|
16
|
|
|
(1
|
)
|
|
590
|
|
|
Total services
|
|
1,122
|
|
|
315
|
|
|
398
|
|
|
16
|
|
|
(2
|
)
|
|
1,849
|
|
|
Commodity sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
754
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(2
|
)
|
|
753
|
|
|
Product sales
|
|
240
|
|
|
66
|
|
|
2
|
|
|
268
|
|
|
(6
|
)
|
|
570
|
|
|
Total commodity sales
|
|
994
|
|
|
66
|
|
|
2
|
|
|
269
|
|
|
(8
|
)
|
|
1,323
|
|
|
Total revenues from contracts with customers
|
|
2,116
|
|
|
381
|
|
|
400
|
|
|
285
|
|
|
(10
|
)
|
|
3,172
|
|
|
Other revenues(c)
|
|
85
|
|
|
43
|
|
|
109
|
|
|
20
|
|
|
—
|
|
|
257
|
|
|
Total revenues
|
|
$
|
2,201
|
|
|
$
|
424
|
|
|
$
|
509
|
|
|
$
|
305
|
|
|
$
|
(10
|
)
|
|
$
|
3,429
|
|
_______
|
|
|
|
(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 above (see note (c) below).
|
|
|
|
|
(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 and primarily include leases of $294 million and $218 million and derivative contracts of $104 million and $23 million for the three months ended March 31, 2020 and 2019, respectively. See Note 5 for additional information related to our derivative contracts.
|
Contract Balances
Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections.
As of March 31, 2020 and December 31, 2019, our contract asset balances were $32 million and $27 million, respectively. Of the contract asset balance at December 31, 2019, $10 million was transferred to accounts receivable during the three months ended March 31, 2020. As of March 31, 2020 and December 31, 2019, our contract liability balances were $257 million and $232 million, respectively. Of the contract liability balance at December 31, 2019, $32 million was recognized as revenue during the three months ended March 31, 2020.
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, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):
|
|
|
|
|
|
|
|
|
Year
|
|
Estimated Revenue
|
|
Nine months ended December 31, 2020
|
|
$
|
3,309
|
|
|
2021
|
|
3,845
|
|
|
2022
|
|
3,121
|
|
|
2023
|
|
2,529
|
|
|
2024
|
|
2,206
|
|
|
Thereafter
|
|
13,988
|
|
|
Total
|
|
$
|
28,998
|
|
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 expedients that we elected to apply, remaining performance obligations for: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation and (ii) contracts with an original expected duration of one year or less.
7. Reportable Segments
Financial information by segment follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
|
Revenues
|
|
|
|
|
Natural Gas Pipelines
|
|
|
|
|
Revenues from external customers
|
$
|
1,861
|
|
|
$
|
2,192
|
|
|
Intersegment revenues
|
14
|
|
|
9
|
|
|
Products Pipelines
|
495
|
|
|
424
|
|
|
Terminals
|
|
|
|
|
Revenues from external customers
|
441
|
|
|
508
|
|
|
Intersegment revenues
|
1
|
|
|
1
|
|
|
CO2
|
309
|
|
|
305
|
|
|
Corporate and intersegment eliminations
|
(15
|
)
|
|
(10
|
)
|
|
Total consolidated revenues
|
$
|
3,106
|
|
|
$
|
3,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
|
Segment EBDA(a)
|
|
|
|
|
Natural Gas Pipelines
|
$
|
1,196
|
|
|
$
|
1,203
|
|
|
Products Pipelines
|
269
|
|
|
276
|
|
|
Terminals
|
257
|
|
|
299
|
|
|
CO2
|
(755)
|
|
|
198
|
|
|
Kinder Morgan Canada
|
—
|
|
|
(2
|
)
|
|
Total Segment EBDA
|
967
|
|
|
1,974
|
|
|
DD&A
|
(565
|
)
|
|
(593
|
)
|
|
Amortization of excess cost of equity investments
|
(32
|
)
|
|
(21
|
)
|
|
General and administrative and corporate charges
|
(165
|
)
|
|
(161
|
)
|
|
Interest, net
|
(436
|
)
|
|
(460
|
)
|
|
Income tax expense
|
(60
|
)
|
|
(172
|
)
|
|
Total consolidated net (loss) income
|
$
|
(291
|
)
|
|
$
|
567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2020
|
|
December 31, 2019
|
|
Assets
|
|
|
|
|
Natural Gas Pipelines
|
$
|
49,393
|
|
|
$
|
50,310
|
|
|
Products Pipelines
|
9,310
|
|
|
9,468
|
|
|
Terminals
|
8,840
|
|
|
8,890
|
|
|
CO2
|
2,926
|
|
|
3,523
|
|
|
Corporate assets(b)
|
3,061
|
|
|
1,966
|
|
|
Total consolidated assets
|
$
|
73,530
|
|
|
$
|
74,157
|
|
_______
|
|
|
|
(a)
|
Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, 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 are as follows (in millions, except percentages):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
|
Income tax expense
|
$
|
60
|
|
|
$
|
172
|
|
|
Effective tax rate
|
(26.0
|
)%
|
|
23.3
|
%
|
Total tax expense for the three months ended March 31, 2020 is approximately $60 million resulting in an effective tax rate of (26.0)%, as compared with $172 million tax expense and an effective tax rate of 23.3%, for the same period of 2019.
The effective tax rate for the three months ended March 31, 2020 is “negative” in relation to the statutory federal rate of 21% primarily due to the $600 million CO2 reporting unit impairment of non tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit, partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus Corporation (Citrus) and Plantation Pipe Line Company (Plantation). 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 the tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period.
The effective tax rate for the three months ended March 31, 2019 is higher than the statutory federal rate of 21% primarily due to state and foreign taxes. These increases were partially offset by dividend-received deductions from our investments in Citrus, NGPL Holdings LLC and Plantation.
9. Litigation, Environmental and Other Contingencies
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.
FERC Inquiry Regarding the Commission’s Policy for Determining Return on Equity
On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI sought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC and there is no deadline or requirement for the FERC to take action on this matter.
SFPP FERC Proceedings
The tariffs and rates charged by SFPP are subject to a number of ongoing shipper-initiated proceedings at the FERC. These include IS08-390, filed in June 2008, in which various shippers are challenging SFPP’s West Line rates (on appeal to the D.C. Circuit Court); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (pending before the FERC on rehearing); OR11-13/16/18, filed in June 2011, in which various shippers are seeking to challenge SFPP’s North Line, Oregon Line, and West Line rates (pending before the FERC for an order on the complaint); OR14-35/36, filed in June 2014, in which various shippers are challenging SFPP’s index increases in 2012 and 2013 (dismissed by the FERC, but remanded back to the FERC from the D.C. Circuit for further consideration); OR16-6, filed in December 2015, in which various shippers are challenging SFPP’s East line rates (pending before the FERC for an order on the initial decision); and OR19-21/33/37, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 (pending before the FERC for an order on the complaints). 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 (OR cases) and/or prospective refunds in protest cases from the date of protest (IS cases), and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.
SFPP paid refunds to shippers in May 2019, in the IS08-390 proceeding as ordered by the FERC based on its denial of an income tax allowance. With respect to the various SFPP related complaints and protest proceedings at the FERC (including IS08-390), we estimate that the shippers are seeking approximately $50 million in annual rate reductions and approximately $400 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, as well as the compliance filing methodology recently approved by the FERC to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.
EPNG FERC Proceedings
The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it would apply its findings in Opinion 517-A to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. With respect to the 2010 rate case, the FERC issued its
decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC the refund calculations, and that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. EPNG’s appeals in the 2008 and 2010 rate cases as well as the intervenors’ delayed appeal in the 2010 rate case were consolidated. Oral argument was heard by the U.S. Court of Appeals for the D.C. Circuit on March 13, 2020.
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 September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On February 1, 2019, the 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.
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 seeks 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 January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. The Delaware appeals and arbitration proceeding remain 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.
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 these claims and will vigorously defend against any action in which they are asserted.
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, 2020 and December 31, 2019, our total reserve for legal matters was $243 million and $203 million, respectively. In addition, as of March 31, 2020 and December 31, 2019, we have recorded a receivable of $31 million and $2 million, respectively, for expected cost recoveries that have been deemed probable.
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 federal, state and local 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, 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, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act. 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, individually or in the aggregate, will be material. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the remediation.
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 and 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 approximately $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 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 acquired from GATX Terminals Corporation) 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. 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. 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, given the U.S. is the owner of the Navajo Reservation, the U.S.’s exploration and reclamation activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. After a trial which concluded in March 2019, 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 was not appealed by any party. 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 this decision 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. On June 30, 2018 and July 13, 2018, respectively, OCC filed two separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018.
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. 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 this FS is completed and the RI/FS is finalized and allocations are determined, the scope of potential EPA claims for the Site and liability therefor are not reasonably estimable.
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). The Plaintiffs allege the defendants’ operations caused substantial damage to the coastal waters of Louisiana and nearby lands, including marsh (Coastal Zone). The alleged damages include erosion of property within the Coastal Zone, and discharge of pollutants that are alleged to have adversely impacted the Coastal Zone, including plants and wildlife. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected Coastal Zone to its original condition. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) routinely intervene in these cases, and we expect the LDNR and LAG to intervene in any additional cases that may be filed. 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 that those operations caused substantial damage to the Coastal Zone. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. In 2016, the LAG and LDNR intervened in the lawsuit. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana on several grounds including federal officer liability. Plaquemines Parish, along with the intervenors, moved to remand the case to the state district court. On May 28, 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified the federal officer liability jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals and on June 11, 2019, the U.S. District Court stayed the remand order pending the outcome of that review. The case is effectively stayed pending resolution of the federal officer liability issue 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 Zone. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. On April 5, 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. On May 28, 2019, Orleans moved to remand the case to the state district court. On January 30, 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 two cases against TGP, two cases against SNG, and two cases 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 that 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, attorneys’ 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 allege that the defendants are obligated to restore and remediate the affected property without regard to the value of the property. The plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. In one case filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant that was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana,
$80 million was sought in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. On May 4, 2018, the District Court entered a judgment dismissing the tort and negligence claims against all of the defendants, and dismissing certain of the contract claims against TGP. In ruling in favor of the plaintiffs on the remaining contract claims, the District Court ordered the defendants to pay $1,104 in money damages, and issued a permanent injunction ordering the defendants to restore a total of 9.6 acres of land and maintain certain canals at widths designated by the right of way agreements in effect. The Court stayed the judgment and the injunction pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. On September 13, 2018, the third-party defendant filed a motion to vacate the judgment and dismiss all of the appeals for lack of subject matter jurisdiction. On October 2, 2018 the Court of Appeals dismissed the appeals and on April 17, 2019 the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. The case is set for trial July 27, 2020. We will continue to vigorously defend these 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, financial position, results of operations or cash flows. As of March 31, 2020 and December 31, 2019, we have accrued a total reserve for environmental liabilities in the amount of $256 million and $259 million, respectively. In addition, as of March 31, 2020 and December 31, 2019, we have recorded a receivable of $12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable.
10. Recent Accounting Pronouncements
ASU No. 2018-14
On August 28, 2018, the FASB issued ASU No. 2018-14, “Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU amends existing annual disclosure requirements applicable to all employers that sponsor defined benefit pension and other postretirement plans by adding, removing, and clarifying certain disclosures. ASU No. 2018-14 will be effective for us for the fiscal year ending December 31, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2020-04
On March 12, 2020, the FASB issued 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 this 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. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of this ASU to our financial statements.