Summary of Results of Operations — Third Quarter 2020 Compared with Third Quarter 2019
Financial results for FirstEnergy’s business segments in the third quarter of 2020 and 2019 were as follows:
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Third Quarter 2020 Financial Results
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Regulated Distribution
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Regulated Transmission
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Corporate/Other and Reconciling Adjustments
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FirstEnergy Consolidated
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(In millions)
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Revenues:
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Electric
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$
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2,600
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$
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408
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$
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(35)
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$
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2,973
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Other
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61
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5
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(17)
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49
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Total Revenues
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2,661
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413
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(52)
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3,022
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Operating Expenses:
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Fuel
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101
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—
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—
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101
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Purchased power
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762
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—
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4
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766
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Other operating expenses
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913
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86
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(62)
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937
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Provision for depreciation
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223
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79
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14
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316
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Deferral of regulatory assets, net
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(91)
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—
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—
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(91)
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General taxes
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199
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59
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14
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272
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Total Operating Expenses
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2,107
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224
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(30)
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2,301
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Operating Income (Loss)
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554
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189
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(22)
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721
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Other Income (Expense):
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Miscellaneous income, net
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81
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7
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12
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100
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Interest expense
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(124)
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(55)
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(87)
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(266)
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Capitalized financing costs
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11
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9
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1
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21
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Total Other Expense
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(32)
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(39)
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(74)
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(145)
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Income (Loss) Before Income Taxes (Benefits)
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522
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150
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(96)
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576
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Income taxes (benefits)
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109
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35
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(28)
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116
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Income (Loss) From Continuing Operations
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413
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115
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(68)
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460
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Discontinued operations, net of tax
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—
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—
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(6)
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(6)
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Net Income (Loss)
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$
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413
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$
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115
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$
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(74)
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$
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454
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Third Quarter 2019 Financial Results
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Regulated Distribution
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Regulated Transmission
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Corporate/Other and Reconciling Adjustments
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FirstEnergy Consolidated
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(In millions)
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Revenues:
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Electric
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$
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2,571
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$
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371
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$
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(33)
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$
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2,909
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Other
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65
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4
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(15)
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54
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Total Revenues
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2,636
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375
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(48)
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2,963
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Operating Expenses:
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Fuel
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122
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—
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—
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122
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Purchased power
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794
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—
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4
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798
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Other operating expenses
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715
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75
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(32)
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758
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Provision for depreciation
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215
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71
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18
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304
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Amortization of regulatory assets, net
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42
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1
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—
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43
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General taxes
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197
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53
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7
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257
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Total Operating Expenses
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2,085
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200
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(3)
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2,282
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Operating Income (Loss)
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551
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175
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(45)
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681
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Other Income (Expense):
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Miscellaneous income, net
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36
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4
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17
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57
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Interest expense
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(124)
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(49)
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(88)
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(261)
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Capitalized financing costs
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10
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9
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—
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19
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Total Other Expense
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(78)
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(36)
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(71)
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(185)
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Income (Loss) Before Income Taxes (Benefits)
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473
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139
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(116)
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496
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Income taxes (benefits)
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103
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26
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(22)
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107
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Income (Loss) From Continuing Operations
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370
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113
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(94)
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389
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Discontinued operations, net of tax
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—
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—
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2
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2
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Net Income (Loss)
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$
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370
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$
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113
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$
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(92)
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$
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391
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Changes Between Third Quarter 2020 and Third Quarter 2019 Financial Results
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Regulated Distribution
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Regulated Transmission
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Corporate/Other and Reconciling Adjustments
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FirstEnergy Consolidated
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(In millions)
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Revenues:
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Electric
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$
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29
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$
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37
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$
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(2)
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$
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64
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Other
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(4)
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1
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(2)
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(5)
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Total Revenues
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25
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38
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(4)
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59
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Operating Expenses:
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Fuel
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(21)
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—
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—
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(21)
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Purchased power
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(32)
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—
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—
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(32)
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Other operating expenses
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198
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11
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(30)
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179
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Provision for depreciation
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8
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8
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(4)
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12
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Amortization (deferral) of regulatory assets, net
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(133)
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(1)
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—
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(134)
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General taxes
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2
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6
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7
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15
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Total Operating Expenses
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22
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24
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(27)
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19
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Operating Income (Loss)
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3
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14
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23
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40
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Other Income (Expense):
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|
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Miscellaneous income, net
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45
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|
3
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(5)
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43
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|
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|
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|
|
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Interest expense
|
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—
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(6)
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1
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|
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(5)
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Capitalized financing costs
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1
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|
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—
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|
1
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|
2
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Total Other Expense
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46
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(3)
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(3)
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40
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Income (Loss) Before Income Taxes (Benefits)
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49
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11
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20
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|
80
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Income taxes (benefits)
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6
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|
9
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(6)
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9
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|
Income (Loss) From Continuing Operations
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43
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2
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26
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|
71
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|
Discontinued operations, net of tax
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—
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—
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(8)
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|
(8)
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Net Income (Loss)
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$
|
43
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$
|
2
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$
|
18
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|
$
|
63
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Regulated Distribution — Third Quarter 2020 Compared with Third Quarter 2019
Regulated Distribution’s net income increased $43 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to lower pension and OPEB non-service expenses, increased residential sales due to the continued impact of COVID-19, partially offset by higher operating and maintenance expenses, as further discussed below.
Revenues —
The $25 million increase in total revenues resulted from the following sources:
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For the Three Months Ended September 30,
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Revenues by Type of Service
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2020
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2019
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Increase (Decrease)
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(In millions)
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Distribution(1)
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$
|
1,528
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|
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$
|
1,482
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$
|
46
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Generation sales:
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Retail
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1,005
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|
989
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16
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Wholesale
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67
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|
100
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(33)
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Total generation sales
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1,072
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|
|
1,089
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|
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(17)
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Other
|
|
61
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|
|
65
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|
|
(4)
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Total Revenues
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$
|
2,661
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$
|
2,636
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$
|
25
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(1) Includes $25 million of ARP revenues for the three months ended September 30, 2020 and 2019.
Distribution revenues increased $46 million in the third quarter of 2020, as compared to the same period of 2019, primarily resulting from higher rates associated with incremental riders in Ohio and Pennsylvania, including the recovery of distribution capital investment programs and transmission expenses, increased residential sales due to the continued impact of COVID-19, and higher weather-related customer usage, partially offset by the absence of the NJ storm recovery rider, the expiration of a NUG contract in 2020, and lower commercial and industrial sales due to the continued impact of COVID-19. Distribution services by customer class are summarized in the following table:
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For the Three Months Ended September 30,
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|
|
|
|
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|
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Electric Distribution MWH Deliveries
|
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2020
|
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2019
|
|
Increase (Decrease)
|
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|
|
|
|
|
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(In thousands)
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|
|
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Residential
|
|
16,091
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|
|
15,306
|
|
|
5.1
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%
|
|
|
|
|
|
|
Commercial(1)
|
|
9,589
|
|
|
10,148
|
|
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(5.5)
|
%
|
|
|
|
|
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Industrial
|
|
13,560
|
|
|
14,477
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|
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(6.3)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total Electric Distribution MWH Deliveries
|
|
39,240
|
|
|
39,931
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(1.7)
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%
|
|
|
|
|
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(1) Includes street lighting.
Distribution services to residential customers primarily reflects an increase in customer load due to the continued impact of COVID-19 and higher weather-related usage. Deliveries to commercial customers were lower due to the continued impact of COVID-19, partially offset by higher weather-related usage. Cooling degree days were relatively flat compared to 2019, and 21% above normal. Deliveries to industrial customers were also negatively impacted due to the continued impact of COVID-19 contributing to lower steel, mining, and educational services customer usage, partially offset by higher shale customer usage.
The following table summarizes the price and volume factors contributing to the $17 million decrease in generation revenues for the third quarter of 2020, as compared to the same period of 2019:
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|
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|
|
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Source of Change in Generation Revenues
|
|
Increase (Decrease)
|
|
|
(In millions)
|
Retail:
|
|
|
Change in sales volumes
|
|
$
|
30
|
|
Change in prices
|
|
(14)
|
|
|
|
16
|
|
Wholesale:
|
|
|
Change in sales volumes
|
|
(21)
|
|
Change in prices
|
|
(1)
|
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Capacity revenue
|
|
(11)
|
|
|
|
(33)
|
|
Decrease in Generation Revenues
|
|
$
|
(17)
|
|
The increase in retail generation sales volumes was primarily due to decreased customer shopping in New Jersey and Pennsylvania, an increase in residential load due to the continued impact of COVID-19 in our service territories, and higher weather-related usage. Total generation provided by alternative suppliers as a percentage of total MWH deliveries decreased to 43% from 45% in New Jersey and to 63% from 66% in Pennsylvania. The decrease in retail generation prices primarily resulted from lower non-shopping generation rates at WPP.
Wholesale generation revenues decreased $33 million in the third quarter of 2020, as compared to the same period in 2019, primarily due to decreased volumes associated with lower economic dispatch of MP’s generating units resulting from low spot market energy prices, the expiration of a NUG contract, and lower capacity revenues. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings.
Operating Expenses —
Total operating expenses increased $22 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to the following:
•Fuel expense decreased $21 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to lower unit costs and lower fuel consumption as a result of economic dispatch.
•Purchased power costs were $32 million lower in the third quarter of 2020, as compared to the same period in 2019, primarily due to lower prices and capacity expenses and fewer purchases resulting from the expiration of a NUG contract, partially offset by increased volumes as described above.
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Source of Change in Purchased Power
|
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Increase (Decrease)
|
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(In millions)
|
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|
|
|
|
|
|
|
|
|
|
|
Purchases
|
|
|
Change due to unit costs
|
|
$
|
(40)
|
|
Change due to volumes
|
|
13
|
|
|
|
(27)
|
|
Capacity expense
|
|
(5)
|
|
|
|
|
Decrease in Purchased Power Costs
|
|
$
|
(32)
|
|
•Other operating expenses increased $198 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to the following:
•Increased storm restoration costs of $136 million, primarily related to tropical storm Isaias, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.
•Higher incremental uncollectible and other COVID-19 related expenses of $49 million, of which $22 million was deferred for future recovery.
•Higher network transmission expenses of $15 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.
•Higher pension and OPEB service costs of $11 million.
•Higher other operating and maintenance expenses of $4 million primarily associated with regulated generation maintenance activities.
•Lower energy efficiency program costs and vegetation management spend of $17 million. These costs are deferred for future recovery, resulting in no material impact on earnings.
•Depreciation expense increased $8 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to a higher asset base.
•Deferral of regulatory assets increased $133 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to higher storm restoration, uncollectible and other COVID-19 related costs, partially offset by lower generation and transmission deferrals, the recovery of distribution investment programs and lower energy efficiency related costs.
Other Expenses —
Other expense decreased $46 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to higher net miscellaneous income resulting from lower pension non-service costs.
Income Taxes —
Regulated Distribution’s effective tax rate was 20.9% and 21.8% for the three months ended September 30, 2020 and 2019, respectively.
Regulated Transmission — Third Quarter 2020 Compared with Third Quarter 2019
Regulated Transmission’s net income increased $2 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to higher rate base at ATSI and MAIT associated with Energizing the Future transmission plan, partially offset by higher interest expense and the absence of tax benefits in the third quarter of 2019.
Revenues —
Total revenues increased $38 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to recovery of incremental operating expenses and a higher rate base at ATSI and MAIT.
The following table shows revenues by transmission asset owner:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30,
|
|
|
Increase
|
Revenues by Transmission Asset Owner
|
|
2020
|
|
|
2019
|
|
|
|
|
(In millions)
|
ATSI
|
|
$
|
203
|
|
|
|
$
|
185
|
|
|
|
$
|
18
|
|
TrAIL
|
|
63
|
|
|
|
57
|
|
|
|
6
|
|
MAIT
|
|
70
|
|
|
|
59
|
|
|
|
11
|
|
JCP&L
|
|
43
|
|
|
|
40
|
|
|
|
3
|
|
Other
|
|
34
|
|
|
|
34
|
|
|
|
—
|
|
Total Revenues
|
|
$
|
413
|
|
|
|
$
|
375
|
|
|
|
$
|
38
|
|
Operating Expenses —
Total operating expenses increased $24 million in the third quarter of 2020, as compared to the same period of 2019, primarily due to higher property taxes and depreciation due to a higher asset base, and higher operating and maintenance expenses. The majority of operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
Other Expense —
Other expenses increased $3 million due to the impact of higher net financing costs from money pool borrowing and lending activities at FET and debt issuances at ATSI, MAIT and FET, partially offset by lower pension and OPEB non-service costs.
Income Taxes —
Regulated Transmission’s effective tax rate was 23.3% and 18.7% for the three months ended September 30, 2020 and 2019, respectively, primarily due to changes in the amortization of excess deferred income taxes and the absence of tax benefits in 2019.
Corporate / Other — Third Quarter 2020 Compared with Third Quarter 2019
Financial results at Corporate/Other resulted in a $26 million decrease in loss from continuing operations in the third quarter of 2020, as compared to the same period of 2019, primarily due to higher tax benefits and lower other operating expenses, partially offset by lower returns on certain equity method investments.
For the three months ended September 30, 2020, FirstEnergy recorded a loss from discontinued operations, net of tax, of $6 million compared to income, net of tax, of $2 million for the three months ended September 30, 2019.
Summary of Results of Operations — First Nine Months of 2020 Compared with First Nine Months of 2019
Financial results for FirstEnergy’s business segments in the first nine months of 2020 and 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Nine Months 2020 Financial Results
|
|
Regulated Distribution
|
|
Regulated Transmission
|
|
Corporate/Other and Reconciling Adjustments
|
|
FirstEnergy Consolidated
|
|
|
(In millions)
|
Revenues:
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
7,031
|
|
|
$
|
1,185
|
|
|
$
|
(105)
|
|
|
$
|
8,111
|
|
Other
|
|
176
|
|
|
13
|
|
|
(47)
|
|
|
142
|
|
Total Revenues
|
|
7,207
|
|
|
1,198
|
|
|
(152)
|
|
|
8,253
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
Fuel
|
|
276
|
|
|
—
|
|
|
—
|
|
|
276
|
|
Purchased power
|
|
2,062
|
|
|
—
|
|
|
11
|
|
|
2,073
|
|
Other operating expenses
|
|
2,345
|
|
|
201
|
|
|
(130)
|
|
|
2,416
|
|
|
|
|
|
|
|
|
|
|
Provision for depreciation
|
|
672
|
|
|
233
|
|
|
49
|
|
|
954
|
|
|
|
|
|
|
|
|
|
|
Amortization (deferral) of regulatory assets, net
|
|
(32)
|
|
|
6
|
|
|
—
|
|
|
(26)
|
|
General taxes
|
|
583
|
|
|
177
|
|
|
32
|
|
|
792
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
5,906
|
|
|
617
|
|
|
(38)
|
|
|
6,485
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
1,301
|
|
|
581
|
|
|
(114)
|
|
|
1,768
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous income, net
|
|
246
|
|
|
21
|
|
|
36
|
|
|
303
|
|
Pension and OPEB mark-to-market adjustment
|
|
(257)
|
|
|
(19)
|
|
|
(147)
|
|
|
(423)
|
|
Interest expense
|
|
(374)
|
|
|
(162)
|
|
|
(256)
|
|
|
(792)
|
|
Capitalized financing costs
|
|
28
|
|
|
28
|
|
|
1
|
|
|
57
|
|
Total Other Expense
|
|
(357)
|
|
|
(132)
|
|
|
(366)
|
|
|
(855)
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes (Benefits)
|
|
944
|
|
|
449
|
|
|
(480)
|
|
|
913
|
|
Income taxes (benefits)
|
|
144
|
|
|
103
|
|
|
(125)
|
|
|
122
|
|
Income (Loss) From Continuing Operations
|
|
800
|
|
|
346
|
|
|
(355)
|
|
|
791
|
|
Discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
46
|
|
|
46
|
|
Net Income (Loss)
|
|
$
|
800
|
|
|
$
|
346
|
|
|
$
|
(309)
|
|
|
$
|
837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Nine Months 2019 Financial Results
|
|
Regulated Distribution
|
|
Regulated Transmission
|
|
Corporate/Other and Reconciling Adjustments
|
|
FirstEnergy Consolidated
|
|
|
(In millions)
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
7,214
|
|
|
$
|
1,090
|
|
|
$
|
(96)
|
|
|
$
|
8,208
|
|
Other
|
|
187
|
|
|
13
|
|
|
(46)
|
|
|
154
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
7,401
|
|
|
1,103
|
|
|
(142)
|
|
|
8,362
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
Fuel
|
|
382
|
|
|
—
|
|
|
—
|
|
|
382
|
|
Purchased power
|
|
2,177
|
|
|
—
|
|
|
13
|
|
|
2,190
|
|
Other operating expenses
|
|
2,116
|
|
|
205
|
|
|
(178)
|
|
|
2,143
|
|
|
|
|
|
|
|
|
|
|
Provision for depreciation
|
|
644
|
|
|
211
|
|
|
55
|
|
|
910
|
|
|
|
|
|
|
|
|
|
|
Amortization of regulatory assets, net
|
|
79
|
|
|
6
|
|
|
—
|
|
|
85
|
|
General taxes
|
|
572
|
|
|
156
|
|
|
29
|
|
|
757
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
5,970
|
|
|
578
|
|
|
(81)
|
|
|
6,467
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
1,431
|
|
|
525
|
|
|
(61)
|
|
|
1,895
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous income, net
|
|
128
|
|
|
12
|
|
|
51
|
|
|
191
|
|
Pension and OPEB mark-to-market adjustment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest expense
|
|
(370)
|
|
|
(142)
|
|
|
(261)
|
|
|
(773)
|
|
Capitalized financing costs
|
|
27
|
|
|
25
|
|
|
1
|
|
|
53
|
|
Total Other Expense
|
|
(215)
|
|
|
(105)
|
|
|
(209)
|
|
|
(529)
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes (Benefits)
|
|
1,216
|
|
|
420
|
|
|
(270)
|
|
|
1,366
|
|
Income taxes (benefits)
|
|
259
|
|
|
87
|
|
|
(65)
|
|
|
281
|
|
Income (Loss) From Continuing Operations
|
|
957
|
|
|
333
|
|
|
(205)
|
|
|
1,085
|
|
Discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
(62)
|
|
|
(62)
|
|
Net Income (Loss)
|
|
$
|
957
|
|
|
$
|
333
|
|
|
$
|
(267)
|
|
|
$
|
1,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes Between First Nine Months 2020 and First Nine Months 2019 Financial Results
|
|
Regulated Distribution
|
|
Regulated Transmission
|
|
Corporate/Other and Reconciling Adjustments
|
|
FirstEnergy Consolidated
|
|
|
(In millions)
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
(183)
|
|
|
$
|
95
|
|
|
$
|
(9)
|
|
|
$
|
(97)
|
|
Other
|
|
(11)
|
|
|
—
|
|
|
(1)
|
|
|
(12)
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
(194)
|
|
|
95
|
|
|
(10)
|
|
|
(109)
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
Fuel
|
|
(106)
|
|
|
—
|
|
|
—
|
|
|
(106)
|
|
Purchased power
|
|
(115)
|
|
|
—
|
|
|
(2)
|
|
|
(117)
|
|
Other operating expenses
|
|
229
|
|
|
(4)
|
|
|
48
|
|
|
273
|
|
|
|
|
|
|
|
|
|
|
Provision for depreciation
|
|
28
|
|
|
22
|
|
|
(6)
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
Amortization (deferral) of regulatory assets, net
|
|
(111)
|
|
|
—
|
|
|
—
|
|
|
(111)
|
|
General taxes
|
|
11
|
|
|
21
|
|
|
3
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
(64)
|
|
|
39
|
|
|
43
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
(130)
|
|
|
56
|
|
|
(53)
|
|
|
(127)
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous income (expense), net
|
|
118
|
|
|
9
|
|
|
(15)
|
|
|
112
|
|
Pension and OPEB mark-to-market adjustment
|
|
(257)
|
|
|
(19)
|
|
|
(147)
|
|
|
(423)
|
|
Interest expense
|
|
(4)
|
|
|
(20)
|
|
|
5
|
|
|
(19)
|
|
Capitalized financing costs
|
|
1
|
|
|
3
|
|
|
—
|
|
|
4
|
|
Total Other Expense
|
|
(142)
|
|
|
(27)
|
|
|
(157)
|
|
|
(326)
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes (Benefits)
|
|
(272)
|
|
|
29
|
|
|
(210)
|
|
|
(453)
|
|
Income taxes (benefits)
|
|
(115)
|
|
|
16
|
|
|
(60)
|
|
|
(159)
|
|
Income (Loss) From Continuing Operations
|
|
(157)
|
|
|
13
|
|
|
(150)
|
|
|
(294)
|
|
Discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
108
|
|
|
108
|
|
Net Income (Loss)
|
|
$
|
(157)
|
|
|
$
|
13
|
|
|
$
|
(42)
|
|
|
$
|
(186)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Distribution — First Nine Months of 2020 Compared with First Nine Months of 2019
Regulated Distribution’s net income decreased $157 million in the first nine months of 2020, as compared to the same period of 2019, primarily resulting from the pension and OPEB mark-to-market adjustment in 2020, lower weather-related customer usage, the absence of the DMR revenues that ended in July 2019, partially offset by lower pension and OPEB non-service costs, higher revenues from incremental riders in Ohio and Pennsylvania and increased residential sales due to the continued impact of COVID-19.
Revenues —
The $194 million decrease in total revenues resulted from the following sources:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
Revenues by Type of Service
|
|
2020
|
|
2019
|
|
Increase (Decrease)
|
|
|
(In millions)
|
Distribution services(1)
|
|
$
|
4,108
|
|
|
$
|
4,045
|
|
|
$
|
63
|
|
|
|
|
|
|
|
|
Generation sales:
|
|
|
|
|
|
|
Retail
|
|
2,735
|
|
|
2,853
|
|
|
(118)
|
|
Wholesale
|
|
188
|
|
|
316
|
|
|
(128)
|
|
Total generation sales
|
|
2,923
|
|
|
3,169
|
|
|
(246)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
176
|
|
|
187
|
|
|
(11)
|
|
Total Revenues
|
|
$
|
7,207
|
|
|
$
|
7,401
|
|
|
$
|
(194)
|
|
(1) Includes $108 million and $142 million of ARP revenues for the nine months ended September 30, 2020 and 2019, respectively.
Distribution services revenues increased $63 million in the first nine months of 2020, as compared to the same period of 2019, primarily resulting from the implementation of Ohio decoupling rates in 2020, higher rates associated with incremental riders in Ohio and Pennsylvania, including the recovery of distribution capital investment programs and transmission expenses, increased residential sales due to the continued impact of COVID-19 and the implementation of the New Jersey Zero Emission Program in June 2019, partially offset by the absence of the NJ storm recovery rider and DMR revenues that ended in 2019, lower weather-related customer usage, the expiration of a NUG contract and lower commercial and industrial sales due to the continued impact of COVID-19. Distribution services by customer class are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
Electric Distribution MWH Deliveries
|
|
2020
|
|
2019
|
|
Increase (Decrease)
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Residential
|
|
42,059
|
|
|
41,311
|
|
|
1.8
|
%
|
|
|
|
|
|
|
Commercial(1)
|
|
26,316
|
|
|
28,909
|
|
|
(9.0)
|
%
|
|
|
|
|
|
|
Industrial
|
|
39,118
|
|
|
42,032
|
|
|
(6.9)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Electric Distribution MWH Deliveries
|
|
107,493
|
|
|
112,252
|
|
|
(4.2)
|
%
|
|
|
|
|
|
|
(1) Includes street lighting.
Distribution services to residential customers primarily reflects an increase in customer load due to the continued impact of COVID-19, partially offset by lower weather related usage. Deliveries to commercial customers reflects lower weather-related usage and the continued impact of COVID-19. Heating degree days were 5% below 2019, and 10% below normal. Cooling degree days were 1% above 2019, and 16% above normal. Deliveries to industrial customers were also negatively impacted due to the continued impact of COVID-19 contributing to lower steel, mining, educational services and automotive customer usage, partially offset by higher shale customer usage.
The following table summarizes the price and volume factors contributing to the $246 million decrease in generation revenues for the first nine months of 2020, as compared to the same period of 2019:
|
|
|
|
|
|
|
|
|
Source of Change in Generation Revenues
|
|
Decrease
|
|
|
(In millions)
|
Retail:
|
|
|
Change in sales volumes
|
|
$
|
(46)
|
|
Change in prices
|
|
(72)
|
|
|
|
(118)
|
|
Wholesale:
|
|
|
Change in sales volumes
|
|
(69)
|
|
Change in prices
|
|
(5)
|
|
Capacity revenue
|
|
(54)
|
|
|
|
(128)
|
|
Decrease in Generation Revenues
|
|
$
|
(246)
|
|
The decrease in retail generation sales volumes was primarily due to lower weather-related usage, partially offset by an increase in residential load due to the continued impact of COVID-19. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates in New Jersey and Pennsylvania.
Wholesale generation revenues decreased $128 million in the first nine months of 2020, as compared to the same period in 2019, primarily due to decreased volumes associated with lower economic dispatch of MP’s generating units resulting from low spot market energy prices, the expiration of a NUG contract and lower capacity revenues. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings.
Operating Expenses —
Total operating expenses decreased $64 million, primarily due to the following:
•Fuel costs were $106 million lower during the first nine months of 2020, as compared to the same period of 2019, primarily due to lower unit costs and lower fuel consumption as a result of economic dispatch.
•Purchased power costs decreased $115 million during the first nine months of 2020, as compared to the same period of 2019, primarily due to lower prices and capacity expenses and decreased purchases resulting from the expiration of a NUG contract, partially offset by the implementation of the NJ Zero Emission Program in June 2019.
|
|
|
|
|
|
|
|
|
Source of Change in Purchased Power
|
|
Decrease
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases:
|
|
|
Change due to unit costs
|
|
$
|
(39)
|
|
Change due to volumes
|
|
(19)
|
|
|
|
(58)
|
|
Capacity
|
|
(57)
|
|
|
|
|
Decrease in Purchased Power Costs
|
|
$
|
(115)
|
|
•Other operating expenses increased $229 million in the first nine months of 2020, as compared to the same period of 2019, primarily due to:
•Higher incremental uncollectible and other COVID-19 related expenses of $117 million, of which $53 million was deferred for future recovery.
•Increased storm restoration costs of $59 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.
•Higher network transmission expenses of $36 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.
•Higher employee benefit costs of approximately $20 million.
•Higher pension and OPEB service costs of $24 million.
•Higher other operating and maintenance expense of $9 million, primarily associated with regulated generation maintenance activities.
•Lower vegetation management spend and energy efficiency program costs of $36 million, which are deferred for future recovery, resulting in no material impact on earnings.
•Depreciation expense increased $28 million in the first nine months of 2020, as compared to the same period of 2019, primarily due to a higher asset base.
•Deferral of regulatory assets increased $111 million in the first nine months of 2020, as compared to the same period of 2019, primarily due to higher storm restoration, uncollectible and other COVID-19 related costs, partially offset by lower generation and transmission deferrals, the recovery of distribution investment programs and lower energy efficiency related costs.
•General taxes increased $11 million in the first nine months of 2020, as compared to the same period of 2019, primarily due to higher Ohio property taxes and payroll taxes associated with employee benefits.
Other Expense —
Other expense increased $142 million in the nine months of 2020, as compared to the same period of 2019, primarily due to a $257 million pension and OPEB mark-to-market adjustment in the first quarter of 2020 and higher interest expense from debt issuances primarily at WP and MP, partially offset by higher net miscellaneous income primarily resulting from lower pension and OPEB non-service costs.
Income Taxes —
Regulated Distribution’s effective tax rate was 15.3% and 21.3% for the nine months ended September 30, 2020 and 2019, respectively. The change in the effective tax rate was primarily due to the recognition of $52 million in deferred gains relating to prior intercompany transfers of generation assets that were triggered by the deconsolidation of the FES Debtors from FirstEnergy’s consolidated federal income tax group as a result of their emergence from bankruptcy in the first quarter of 2020.
Regulated Transmission — First Nine Months of 2020 Compared with First Nine Months of 2019
Regulated Transmission’s net income increased $13 million in the first nine months of 2020, as compared to the same period of 2019, primarily resulting from the impact of a higher rate base at ATSI and MAIT, partially offset by higher interest expense and a true-up of the forward-looking formula rate at ATSI and MAIT.
Revenues —
Total revenues increased $95 million, primarily due to the recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by the impact of a true-up of the forward-looking rate.
The following table shows revenues by transmission asset owner:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
|
|
Revenues by Transmission Asset Owner
|
|
2020
|
|
|
2019
|
|
|
Increase (Decrease)
|
|
|
(In millions)
|
ATSI
|
|
$
|
601
|
|
|
|
$
|
545
|
|
|
|
$
|
56
|
|
TrAIL
|
|
188
|
|
|
|
178
|
|
|
|
10
|
|
MAIT
|
|
187
|
|
|
|
160
|
|
|
|
27
|
|
JCP&L
|
|
122
|
|
|
|
120
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
100
|
|
|
|
100
|
|
|
|
—
|
|
Total Revenues
|
|
$
|
1,198
|
|
|
|
$
|
1,103
|
|
|
|
$
|
95
|
|
Operating Expenses —
Total operating expenses increased $39 million in the first nine months of 2020, as compared to the same period of 2019, primarily due to higher property taxes and depreciation due to a higher asset base. The majority of operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.
Other Expense —
Total other expense increased $27 million in the first nine months of 2020, as compared to the same period of 2019, primarily due to a $19 million pension and OPEB mark-to-market adjustment in the first quarter of 2020 and higher net financing costs from money pool borrowing and lending activity and debt issuances at ATSI, MAIT and FET, partially offset by lower pension and OPEB non-service costs.
Income Taxes —
Regulated Transmission’s effective tax rate was 22.9% and 20.7% for the nine months ended September 30, 2020 and 2019, respectively due to changes in the amortization of excess deferred income taxes and the absence of tax benefits in 2019.
Corporate / Other — First Nine Months of 2020 Compared with First Nine Months of 2019
Financial results at Corporate/Other resulted in a $150 million increased loss from continuing operations in the first nine months of 2020, as compared to the same period of 2019, primarily due to the $147 million pension and OPEB mark-to-market adjustment in the first quarter of 2020, higher other operating expenses and lower returns on certain equity method investments, partially offset by $10 million in tax benefits from accelerated amortization of certain investment tax credits and lower other Pension and OPEB non-service costs.
For the nine months ended September 30, 2020, FirstEnergy recorded income from discontinued operations, net of tax, of $46 million compared to a loss, net of tax, of $62 million for the nine months ended September 30, 2019. The change in discontinued operations, net of tax, was primarily due to lower settlement-related expenses with the FES Debtors, including adjustments to the estimated worthless stock deduction and Intercompany Tax Allocation Agreement, as well as the acceleration of net pension and OPEB prior service credits in 2020 and the absence of tax expense in 2019 associated with non-deductible interest.
REGULATORY ASSETS AND LIABILITIES
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy, the Utilities and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.
Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at FirstEnergy and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between FirstEnergy and regulators. Certain of these regulatory assets, totaling approximately $115 million and $111 million as of September 30, 2020 and December 31, 2019, respectively, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order, of which, $78 million and $73 million as of September 30, 2020 and December 31, 2019, respectively, are being sought for recovery in a formula rate amendment filing at ATSI that is pending before FERC. See Note 9, "Regulatory Matters" for additional information.
The following table provides information about the composition of net regulatory assets and liabilities as of September 30, 2020, and December 31, 2019, and the changes during the nine months ended September 30, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Regulatory Assets (Liabilities) by Source
|
|
September 30,
2020
|
|
December 31,
2019
|
|
Change
|
|
|
(In millions)
|
|
|
|
|
|
|
|
Customer payables for future income taxes
|
|
$
|
(2,456)
|
|
|
$
|
(2,605)
|
|
|
$
|
149
|
|
Nuclear decommissioning and spent fuel disposal costs
|
|
(185)
|
|
|
(197)
|
|
|
12
|
|
Asset removal costs
|
|
(730)
|
|
|
(756)
|
|
|
26
|
|
Deferred transmission costs
|
|
280
|
|
|
298
|
|
|
(18)
|
|
Deferred generation costs
|
|
122
|
|
|
214
|
|
|
(92)
|
|
Deferred distribution costs
|
|
232
|
|
|
155
|
|
|
77
|
|
Contract valuations
|
|
37
|
|
|
51
|
|
|
(14)
|
|
Storm-related costs
|
|
721
|
|
|
551
|
|
|
170
|
|
Uncollectible and COVID-19 related costs
|
|
62
|
|
|
3
|
|
|
59
|
|
Other
|
|
(55)
|
|
|
25
|
|
|
(80)
|
|
Net Regulatory Liabilities included on the Consolidated Balance Sheets
|
|
$
|
(1,972)
|
|
|
$
|
(2,261)
|
|
|
$
|
289
|
|
The following is a description of the regulatory assets and liabilities described above:
Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes such as tax reform. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset.
Nuclear decommissioning and spent fuel disposal costs - Reflects a regulatory liability representing amounts collected from customers and placed in external trusts including income, losses and changes in fair value thereon (as well as accretion of the related ARO) primarily for the future decommissioning of TMI-2.
Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement.
Deferred transmission costs - Primarily represents differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed. Amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.
Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain electric customer heating discounts, fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. The ENEC rate is updated annually.
Deferred distribution costs - Primarily relates to the Ohio Companies’ deferral of certain expenses resulting from distribution and reliability related expenditures, including interest (amortized through 2036), as well as the Ohio Companies’ deferrals related to the decoupling mechanism which are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.
Contract valuations - Includes the amortization of purchase accounting adjustments at PE which were recorded in connection with the AE merger representing the fair value of NUG purchased power contracts (amortized over the life of the contracts through 2030).
Storm-related costs - Relates to the recovery of storm costs, which vary by jurisdiction. Approximately $162 million and $193 million are currently being recovered through rates as of September 30, 2020 and December 31, 2019, respectively.
Uncollectible and COVID-19 related costs - Includes the deferral of prudently incurred incremental costs and certain waived late payment charges arising from COVID-19, including uncollectible expenses under new and existing riders prior to the pandemic.
The following table provides information about the composition of net regulatory assets that do not earn a current return as of September 30, 2020 and December 31, 2019, of which approximately $193 million and $228 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Assets by Source Not Earning a Current Return
|
|
September 30,
2020
|
|
December 31,
2019
|
|
Change
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Deferred transmission costs
|
|
$
|
31
|
|
|
$
|
27
|
|
|
$
|
4
|
|
|
|
Deferred generation costs
|
|
6
|
|
|
15
|
|
|
(9)
|
|
|
|
Storm-related costs
|
|
645
|
|
|
471
|
|
|
174
|
|
|
|
COVID-19 related costs
|
|
29
|
|
|
—
|
|
|
29
|
|
|
|
Other
|
|
31
|
|
|
32
|
|
|
(1)
|
|
|
|
Regulatory Assets Not Earning a Current Return
|
|
$
|
742
|
|
|
$
|
545
|
|
|
$
|
197
|
|
|
|
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest payments, dividend payments, and contributions to its pension plan.
The $2.5 billion equity issuance in 2018 strengthened FirstEnergy’s balance sheet and supported the company’s transition to a fully regulated utility company. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans.
In addition to this equity investment, FE and its distribution and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2020 and beyond, FE and its distribution and transmission subsidiaries expect to rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through the issuance of long-term debt by FE and certain of its distribution and transmission subsidiaries to, among other things, fund capital expenditures and refinance short-term and maturing long-term debt, subject to market conditions and other factors.
On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions through 2021.
With an operating territory of 65,000 square miles, the scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services.
FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.
In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as a fully regulated company, FirstEnergy is focused on maintaining balance sheet strength and flexibility. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt.
Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.
On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court. In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor of the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.
On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the FES Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in 2020.
The outbreak of COVID-19 is a global pandemic. FirstEnergy is continuously evaluating the global pandemic and taking steps to mitigate known risks. FirstEnergy is actively monitoring the continued impact COVID-19 is having on its customers’ receivable balances, which include increasing arrears balances since the pandemic has begun. FirstEnergy has incurred, and it is expected to incur for the foreseeable future, incremental uncollectible and other COVID-19 pandemic related expenses. COVID-19 related expenses consist of additional costs that FirstEnergy is incurring to protect its employees, contractors and customers, and to support social distancing requirements resulting from the COVID-19 pandemic. These costs include, but are not limited to, new or added benefits provided to employees, the purchase of additional personal protection equipment and disinfecting supplies, additional facility cleaning services, initiated programs and communications to customers on utility response, and increased technology expenses to support remote working, where possible. The full impact on FirstEnergy’s business from the COVID-19 pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of its employees, contractors and customers is its first priority. FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the continued impact the COVID-19 pandemic is having on its business, however, FirstEnergy does not currently expect disruptions in its ability to deliver service to customers or any material impact on its capital spending plan.
FirstEnergy continues to effectively manage operations during the pandemic in order to provide critical service to customers and believes it is well positioned to manage through the economic slowdown. FirstEnergy Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory, which also allows for flexibility with capital investments and measures to maintain sufficient liquidity over the next twelve months. However, the situation remains fluid and future impacts to FirstEnergy that are presently unknown or unanticipated may occur. Furthermore, the likelihood of an impact to FirstEnergy, and the severity of any impact that does occur, could increase the longer the global pandemic persists.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. In addition to the subpoenas referenced above, the OH AG, certain FE shareholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. In addition, on August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers.
The Board has formed a new sub-committee of our Audit committee to, together with the Board, assess FirstEnergy’s compliance program and implement potential changes, as appropriate. In addition, in his new role of Executive Director, Mr. Pappas will assist the FirstEnergy leadership team with execution of strategic initiatives, engage with FirstEnergy’s external stakeholders, and support the development of enhanced controls and governance policies and procedures. Despite the many disruptions FirstEnergy is currently facing, the leadership team remains committed and focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigation and subsequent litigation surrounding the investigation of HB 6. See also “Outlook - State Regulation - Ohio” below for details on the PUCO proceeding reviewing political and charitable spending and legislative activity in response to the investigation of HB 6. The outcome of the government investigations, PUCO proceedings, legislative activity, and any of these lawsuits is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows. FirstEnergy is considering reductions to its Regulated Distribution and Regulated Transmission capital investment plans and reductions to operating expenses, as well as changes to its planned equity issuances, to allow for flexibility should a fine be imposed as a result of the government investigation.
FirstEnergy is unable to predict the outcome of the legislative activity in response to the investigation of HB 6, however, a repeal of the decoupling provision of HB 6 is reasonably possible. As of September 30, 2020, the uncollected amount recognized as a regulatory asset on FirstEnergy’s Consolidated Balance Sheet from the decoupling mechanism was approximately $100 million. However, absent the decoupling mechanism and other provisions of HB 6, it is expected that the Ohio Companies would have collected lost distribution revenues estimated at approximately $63 million for the nine months ended September 30, 2020, for a pre-tax net impact of approximately $37 million. Furthermore, as FirstEnergy would not have financially benefited from the zero nuclear credit included in HB 6, there is no expected impact to FirstEnergy due to the repeal of that provision in HB 6. On November 2, 2020, the Ohio Companies filed their annual update to the Ohio decoupling rider with an estimated annual revenue requirement of approximately $113 million with a proposed effective date of January 1, 2021, unless otherwise ordered by the PUCO.
As of September 30, 2020, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was primarily due to accounts payable, short-term borrowings, and accrued interest, taxes, compensation and benefits. FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its current working capital needs.
Short-Term Borrowings / Revolving Credit Facilities
FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion, which are available until December 6, 2022. Under the FE credit facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sublimits for each borrower including FE and its regulated distribution subsidiaries. Under the FET credit facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sublimits for each borrower including FE's transmission subsidiaries.
Borrowings under the credit facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the credit facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.
FirstEnergy’s revolving credit facilities bear interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. To the extent these interest rates increase, interest expense will increase. If sources of capital for FirstEnergy are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity.
FirstEnergy had $300 million and $1,000 million of short-term borrowings as of September 30, 2020 and December 31, 2019, respectively. FirstEnergy’s available liquidity from external sources as of November 19, 2020, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrower(s)
|
|
Type
|
|
Maturity
|
|
Commitment
|
|
Available Liquidity
|
|
|
|
|
|
|
|
(In millions)
|
|
FirstEnergy(1)
|
|
Revolving
|
|
December 2022
|
|
$
|
2,500
|
|
|
$
|
2,246
|
|
|
|
|
|
|
|
|
|
|
|
|
FET(2)
|
|
Revolving
|
|
December 2022
|
|
1,000
|
|
|
1,000
|
|
|
|
|
|
|
Subtotal
|
|
$
|
3,500
|
|
|
$
|
3,246
|
|
|
|
|
Cash and cash equivalents(3)
|
|
—
|
|
|
286
|
|
|
|
|
|
|
Total
|
|
$
|
3,500
|
|
|
$
|
3,532
|
|
|
(1)FE and the Utilities. Available liquidity includes impact of $4 million of LOCs issued under various terms.
(2)Includes FET and the Transmission Companies.
(3)As of November 18, 2020.
The following table summarizes the borrowing sublimits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of September 30, 2020:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrower
|
|
FirstEnergy Revolving
Credit Facility
Sublimit
|
|
|
|
FET Revolving
Credit Facility
Sublimit
|
|
Regulatory and
Other Short-Term Debt Limitations
|
|
|
|
|
|
(In millions)
|
|
|
|
FE
|
|
|
$
|
2,500
|
|
|
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FET
|
|
|
—
|
|
|
|
|
|
|
1,000
|
|
|
|
—
|
|
(1)
|
|
|
OE
|
|
|
500
|
|
|
|
|
|
|
—
|
|
|
|
500
|
|
(2)
|
|
|
CEI
|
|
|
500
|
|
|
|
|
|
|
—
|
|
|
|
500
|
|
(2)
|
|
|
TE
|
|
|
300
|
|
|
|
|
|
|
—
|
|
|
|
300
|
|
(2)
|
|
|
JCP&L
|
|
|
500
|
|
|
|
|
|
|
—
|
|
|
|
500
|
|
(2)
|
|
|
ME
|
|
|
500
|
|
|
|
|
|
|
—
|
|
|
|
500
|
|
(2)
|
|
|
PN
|
|
|
300
|
|
|
|
|
|
|
—
|
|
|
|
300
|
|
(2)
|
|
|
WP
|
|
|
200
|
|
|
|
|
|
|
—
|
|
|
|
200
|
|
(2)
|
|
|
MP
|
|
|
500
|
|
|
|
|
|
|
—
|
|
|
|
500
|
|
(2)
|
|
|
PE
|
|
|
150
|
|
|
|
|
|
|
—
|
|
|
|
150
|
|
(2)
|
|
|
ATSI
|
|
|
—
|
|
|
|
|
|
|
500
|
|
|
|
500
|
|
(2)
|
|
|
Penn
|
|
|
100
|
|
|
|
|
|
|
—
|
|
|
|
100
|
|
(2)
|
|
|
TrAIL
|
|
|
—
|
|
|
|
|
|
|
400
|
|
|
|
400
|
|
(2)
|
|
|
MAIT
|
|
|
—
|
|
|
|
|
|
|
400
|
|
|
|
400
|
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)No limitations.
(2)Includes amounts which may be borrowed under the regulated companies’ money pool.
Subject to each borrower’s sublimit, $250 million of the FE credit facility and $100 million of the FET credit facility, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sublimit.
The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
As of September 30, 2020, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities.
On November 17, 2020, FE and the Utilities and FET and certain of its subsidiaries entered into amendments to the FE credit facility and the FET credit facility, respectively. The amendments provide for modifications and/or waivers of (i) certain representations and warranties and (ii) certain affirmative and negative covenants, contained therein, which allowed FirstEnergy to regain compliance with such provisions. In addition, among other things, the amendment to the FE credit facility reduces the sublimit applicable to FE to $1.5 billion, and the amendments increased certain tiers of pricing applicable to borrowings under the credit facilities.
FirstEnergy Money Pools
FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine months of 2020 was 0.87% per annum for the regulated companies’ money pool and 1.21% per annum for the unregulated companies’ money pool.
Long-Term Debt Capacity
FE’s and its subsidiaries’ access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of November 17, 2020:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
Corporate Credit Rating
|
|
Senior Secured
|
|
Senior Unsecured
|
|
Outlook/Watch (1)
|
Issuer
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
FE
|
|
BB+
|
|
Baa3
|
|
BBB-
|
|
—
|
|
—
|
|
—
|
|
BB+
|
|
Baa3
|
|
BBB-
|
|
CW-N
|
|
N
|
|
N
|
AGC
|
|
BB
|
|
Baa2
|
|
BBB
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
CW-N
|
|
S
|
|
N
|
ATSI
|
|
BB+
|
|
A3
|
|
BBB
|
|
—
|
|
—
|
|
—
|
|
BBB-
|
|
A3
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
CEI
|
|
BB+
|
|
Baa2
|
|
BBB
|
|
BBB+
|
|
A3
|
|
A-
|
|
BBB-
|
|
Baa2
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
FET
|
|
BB+
|
|
Baa2
|
|
BBB-
|
|
—
|
|
—
|
|
—
|
|
BB+
|
|
Baa2
|
|
BBB-
|
|
CW-N
|
|
S
|
|
N
|
JCP&L
|
|
BB+
|
|
A3
|
|
BBB
|
|
—
|
|
—
|
|
—
|
|
BBB-
|
|
A3
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
ME
|
|
BB+
|
|
A3
|
|
BBB
|
|
—
|
|
—
|
|
—
|
|
BBB-
|
|
A3
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
MAIT
|
|
BB+
|
|
A3
|
|
BBB
|
|
—
|
|
—
|
|
—
|
|
BBB-
|
|
A3
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
MP
|
|
BB+
|
|
Baa2
|
|
BBB
|
|
BBB+
|
|
A3
|
|
A-
|
|
BBB-
|
|
Baa2
|
|
—
|
|
CW-N
|
|
S
|
|
N
|
OE
|
|
BB+
|
|
A3
|
|
BBB
|
|
BBB+
|
|
A1
|
|
A-
|
|
BBB-
|
|
A3
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
PN
|
|
BB+
|
|
Baa1
|
|
BBB
|
|
—
|
|
—
|
|
—
|
|
BBB-
|
|
Baa1
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
Penn
|
|
BB+
|
|
A3
|
|
BBB
|
|
—
|
|
A1
|
|
A-
|
|
—
|
|
—
|
|
—
|
|
CW-N
|
|
S
|
|
N
|
PE
|
|
BB+
|
|
Baa2
|
|
BBB
|
|
—
|
|
—
|
|
A-
|
|
—
|
|
—
|
|
—
|
|
CW-N
|
|
S
|
|
N
|
TE
|
|
BB+
|
|
Baa1
|
|
BBB
|
|
BBB+
|
|
A2
|
|
A-
|
|
—
|
|
—
|
|
—
|
|
CW-N
|
|
S
|
|
N
|
TrAIL
|
|
BB+
|
|
A3
|
|
BBB
|
|
—
|
|
—
|
|
—
|
|
BBB-
|
|
A3
|
|
BBB+
|
|
CW-N
|
|
S
|
|
N
|
WP
|
|
BB+
|
|
A3
|
|
BBB
|
|
—
|
|
—
|
|
A-
|
|
—
|
|
—
|
|
—
|
|
CW-N
|
|
S
|
|
N
|
(1) S = Stable, P = Positive, N = Negative, CW-N = CreditWatch with Negative implications
On October 30, 2020, Fitch Ratings downgraded FE and FET’s issuer default ratings and senior unsecured ratings one notch to BBB- from BBB. Fitch also downgraded FE’s subsidiaries issuer default ratings one notch to BBB from BBB+, except for PE, MP, and AGC, whose ratings were affirmed at BBB. Senior unsecured issue ratings for the subsidiaries were downgraded one notch, where applicable, to BBB+ from A-. Senior secured issue ratings for the subsidiaries were downgraded one notch, where applicable, to A- from A. The rating outlook is negative for FE and its subsidiaries.
On October 30, 2020, S&P downgraded FE and its subsidiaries issuer credit ratings two notches to BB+ from BBB, except for AGC which was lowered to BB from BBB-. The senior unsecured issue ratings of FE and FET were changed one notch to BB+ from BBB-. The senior unsecured issue ratings of the subsidiaries, where applicable, were lowered one notch to BBB- from BBB. Additionally, the senior secured issue ratings of the subsidiaries, where applicable, were lowered one notch to BBB+ from A-. The ratings on FE and its subsidiaries remain on CreditWatch with negative implications.
The applicable undrawn and drawn margin on the FE and FET credit facilities are subject to ratings based pricing grids. The applicable fee paid on the undrawn commitments under the FE and FET credit facilities are based on FE and FET’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s. The fee paid on actual borrowings are determined based on each borrower’s senior unsecured non-credit enhanced debt ratings as determined by S&P and Moody’s.
The interest rate payable on approximately $3.85 billion in FE’s senior unsecured notes are subject to adjustments from time to time if the ratings on the notes from any one or more of S&P, Moody’s and Fitch decreases to a rating set forth in the applicable documents. Generally a one-notch downgrade by the applicable rating agency may result in a 25 bps coupon rate increase beginning at BB, Ba1, and BB+ for S&P, Moody’s and Fitch, respectively, to the extent such rating is applicable to the series of outstanding senior unsecured notes, during the next interest period, subject to an aggregate cap of 2% from issuance interest rate.
Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of September 30, 2020, FE and its subsidiaries could issue additional debt of approximately $6.6 billion, or incur a $3.5 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE credit facility.
Changes in Cash Position
As of September 30, 2020, FirstEnergy had $260 million of cash and cash equivalents and approximately $36 million of restricted cash compared to $627 million of cash and cash equivalents and approximately $52 million of restricted cash as of December 31, 2019, on the Consolidated Balance Sheets.
Cash Flows From Operating Activities
FirstEnergy's most significant sources of cash are derived from electric service provided by its distribution and transmission operating subsidiaries. Beyond the cash settlement and tax sharing payments to the FES Debtors in 2020, and pension contribution in 2019, the most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.
FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. For the nine months ended September 30, 2020 and 2019, cash flows from operating activities includes income (loss) from discontinued operations of $46 million and $(62) million, respectively.
In the first nine months of 2020, cash provided from operating activities was $851 million compared to $1,737 million in the same period of 2019. The decrease in cash provided from operating activities is primarily due to the $978 million cash settlement and tax sharing payments made to the FES Debtors upon their emergence in February 2020, an increase to accounts receivable customer balances due to the impact of COVID-19, and higher storm restoration costs, partially offset by the absence of a $500 million cash contribution to the qualified pension plan in February 2019.
Cash Flows From Financing Activities
In the first nine months of 2020, cash provided from financing activities was $937 million compared to $665 million in the same period of 2019. The following table summarizes new debt financing, redemptions, repayments, short-term borrowings and dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
Securities Issued or Redeemed / Repaid
|
|
2020
|
|
2019
|
|
|
(In millions)
|
|
|
|
|
|
New Issues
|
|
|
|
|
Unsecured notes
|
|
$
|
3,250
|
|
|
$
|
1,850
|
|
|
|
|
|
|
|
|
|
|
|
FMBs
|
|
175
|
|
|
250
|
|
|
|
|
|
|
|
|
$
|
3,425
|
|
|
$
|
2,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemptions / Repayments
|
|
|
|
|
Term loan
|
|
$
|
(750)
|
|
|
$
|
—
|
|
Unsecured notes
|
|
(250)
|
|
|
(725)
|
|
|
|
|
|
|
FMBs
|
|
(50)
|
|
|
—
|
|
|
|
|
|
|
Senior secured notes
|
|
(60)
|
|
|
(59)
|
|
|
|
$
|
(1,110)
|
|
|
$
|
(784)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term borrowings, net
|
|
$
|
(700)
|
|
|
$
|
—
|
|
|
|
|
|
|
Preferred stock dividend payments
|
|
$
|
—
|
|
|
$
|
(6)
|
|
|
|
|
|
|
Common stock dividend payments
|
|
$
|
(634)
|
|
|
$
|
(609)
|
|
On February 20, 2020, FE issued $1.75 billion in senior unsecured notes in three separate series: (i) $300 million aggregate principal amount of 2.050% Notes, Series A, due 2025, (ii) $600 million aggregate principal amount of 2.650% Notes, Series B, due 2030 and (iii) $850 million aggregate principal amount of 3.400% Notes, Series C, due 2050. Proceeds from the issuance of the notes, together with cash on hand, were used: (i) to repay the entire $750 million two-year term loan due September 2021, (ii) to make the $853 million in bankruptcy settlement payments and $125 million tax sharing agreement payment with the FES Debtors as discussed above, (iii) to repay $250 million of the $1 billion outstanding 364-day term loan due September 2020, and (iv) for working capital needs and general corporate purposes.
On March 31, 2020, MAIT issued $125 million of 3.60% senior unsecured notes due 2032 and $125 million of 3.70% senior unsecured notes due 2035. Proceeds from the issuance of the notes were used: (i) to refinance existing debt, (ii) for capital expenditures, and (iii) for general corporate purposes.
On April 20, 2020, PN issued $125 million of 3.61% senior unsecured notes due 2032 and $125 million of 3.71% senior unsecured notes due 2035. Proceeds of the issuance of the notes were used: (i) to refinance indebtedness, including short-term borrowings incurred under the FirstEnergy regulated money pool to repay a portion of the $250 million aggregate principle amount of PN’s 5.20% Senior Notes due April 1, 2020, (ii) to fund capital expenditures, (iii) to fund general corporate purposes, or (iv) for any combination of the above.
On June 8, 2020, FE issued $750 million in senior unsecured notes in two separate series: (i) $300 million aggregate principal amounts of 1.600% Notes, Series A, due 2026 and (ii) $450 million aggregate principal amount of 2.250% Notes, Series B, due 2030. Proceeds from the issuance of the notes were used to repay all amounts outstanding under the 364-day term loan due September 2020.
On June 29, 2020, PE issued $75 million of 2.67% FMBs due 2032 and $100 million of 3.43% FMBs due 2051. Proceeds of the issuance of the FMBs were used to repay short-term borrowings under the FirstEnergy regulated money pool, to fund capital expenditures, and for general corporate purposes.
On July 20, 2020, CEI issued $150 million of 2.77% senior unsecured notes due 2034 and $100 million of 3.23% senior unsecured notes due 2040. Proceeds from the issuance of the notes were used to refinance existing short-term borrowings, to fund capital expenditures, and for general corporate purposes.
Cash Flows From Investing Activities
Cash used for investing activities in the first nine months of 2020 principally represented cash used for property additions. The following table summarizes investing activities for the first nine months of 2020 and 2019:
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|
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|
|
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|
|
For the Nine Months Ended September 30,
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Increase
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Cash Used for Investing Activities
|
|
2020
|
|
2019
|
|
(Decrease)
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|
|
(In millions)
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Property Additions:
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|
|
|
|
|
|
Regulated Distribution
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|
$
|
1,115
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|
|
$
|
1,037
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|
|
$
|
78
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|
Regulated Transmission
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|
817
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|
|
835
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|
|
(18)
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|
Corporate / Other
|
|
47
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|
|
40
|
|
|
7
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments
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|
18
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|
|
30
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|
|
(12)
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|
|
|
|
|
|
|
|
Asset removal costs
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|
175
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|
|
158
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|
|
17
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|
Other
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|
(1)
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|
(19)
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|
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18
|
|
|
|
$
|
2,171
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|
|
$
|
2,081
|
|
|
$
|
90
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|
|
|
|
|
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|
|
Cash used for investing activities for the first nine months of 2020 increased $90 million, compared to the same period of 2019, primarily due to higher property additions. The increase in property additions was due to an increase of $78 million at Regulated Distribution for investments to improve and modernize the electric system.
GUARANTEES AND OTHER ASSURANCES
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy and its subsidiaries could be required to make under these guarantees as of September 30, 2020, was approximately $1.7 billion, as summarized below:
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Guarantees and Other Assurances
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Maximum Exposure
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(In millions)
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FE’s Guarantees on Behalf of its Consolidated Subsidiaries
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|
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|
AE Supply asset sales(1)
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|
$
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570
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|
Deferred compensation arrangements
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|
467
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|
|
|
|
Fuel related contracts and other
|
|
4
|
|
|
|
1,041
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|
|
|
|
FE’s Guarantees on Other Assurances
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|
|
Global holding facility
|
|
114
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|
Deferred compensation arrangements
|
|
147
|
|
Surety Bonds
|
|
339
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|
LOCs and other
|
|
16
|
|
|
|
616
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|
|
|
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|
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|
|
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|
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|
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Total Guarantees and Other Assurances
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|
$
|
1,657
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|
(1)As a condition to closing AE Supply’s sale of four natural gas generating plants in December 2017, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC. In addition, as a condition to closing AE Supply’s transfer of Pleasants Power Station and as contemplated under the FES Bankruptcy settlement agreement, FE has provided two guarantees totaling $15 million for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.
Collateral and Contingent-Related Features
In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain agreements contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE’s or its subsidiaries’ credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
Certain agreements entered into by FE and its subsidiaries have margining provisions that require posting of collateral. As of September 30, 2020, $1 million of collateral has been posted by FE or its subsidiaries.
These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of September 30, 2020:
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|
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|
|
Potential Collateral Obligations
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|
|
|
|
|
Utilities and FET
|
|
FE
|
|
Total
|
|
|
|
(In millions)
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Contractual Obligations for Additional Collateral
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|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
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|
|
Upon further downgrade (1)
|
|
|
|
|
|
$
|
40
|
|
|
$
|
—
|
|
|
$
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
Surety Bonds (collateralized amount)(2)
|
|
|
|
|
|
66
|
|
|
257
|
|
|
323
|
|
Total Exposure from Contractual Obligations
|
|
|
|
|
|
$
|
106
|
|
|
$
|
257
|
|
|
$
|
363
|
|
(1)As a result of the credit rating downgrades in October 2020, as further discussed above, FirstEnergy may be required to provide $4.5 million in collateral.
(2)Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure).
Other Commitments and Contingencies
FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding’s outstanding principal balance is $114 million as of September 30, 2020. In addition to FE, Signal Peak, Global Rail,
Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility.
In connection with the facility, 69.99% of Global Holding’s direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV’s and WMB Marketing Ventures, LLC’s respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy has limited exposure to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy’s Risk Management and Risk Policy Committees are responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice.
The valuation of derivative contracts is based on observable market information. As of September 30, 2020, FirstEnergy has a net asset of $7 million in non-hedge derivative contracts that are related to FTRs at certain of the Utilities. FTRs are subject to regulatory accounting and do not impact earnings.
Equity Price Risk
As of September 30, 2020, the FirstEnergy pension plan assets were allocated approximately as follows: 21% in equity securities, 37% in fixed income securities, 7% in absolute return strategies, 9% in real estate, 5% in private equity, 4% in derivatives and 17% in cash and short-term securities. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution and pension investment performance returns to date, FirstEnergy expects no required contributions through 2021. As of September 30, 2020, FirstEnergy’s OPEB plan assets were allocated approximately 55% in equity securities, 42% in fixed income securities and 3% in cash and short-term securities. See Note 5, “Pension and Other Post-Employment Benefits,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans.
Through September 30, 2020, FirstEnergy’s pension and OPEB plan assets have gained approximately 9.2% and 5.7%, respectively, as compared to an annual expected return on plan assets of 7.5%. On February 27, 2020, FirstEnergy remeasured its plan assets, and from that date through September 30, 2020, FirstEnergy’s pension and OPEB plan assets have gained approximately 6.1% and 5.0%, respectively.
NDT funds have been established to satisfy JCP&L, ME and PN’s nuclear decommissioning obligations associated with TMI-2. As of September 30, 2020, approximately 15% of the funds were invested in fixed income securities and 85% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $135 million and $744 million for fixed income securities and short-term investments, respectively, as of September 30, 2020, excluding $2 million of net receivables, payables and accrued income. A decline in the value of JCP&L, ME and PN’s NDTs or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During the nine months ended September 30, 2020, JCP&L, ME and PN made no contributions to the NDTs.
Interest Rate Risk
FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date and the difference between expected and actual returns on the plans’ assets.
Under the approved bankruptcy settlement agreement discussed above, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans. The emergence on February 27, 2020, triggered a remeasurement of the affected pension and OPEB plans and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment of approximately $423 million in the first quarter of 2020. The pension and OPEB mark-to-market adjustment primarily reflects a 38 bps decrease in the discount rate used to measure benefit obligations from December 31, 2019, partially offset by a slightly higher than expected return on assets.
FirstEnergy would anticipate an after-tax mark-to-market gain (loss) in the fourth quarter of 2020 to be in the range of approximately $(330) million to $40 million assuming a discount rate of approximately 2.7% to 3.0% and a return on the pension and OPEB plans’ assets based on actual investment performance since the last remeasurement date on February 27, 2020 through September 30, 2020.
CREDIT RISK
Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirement that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. In addition, in response to the COVID-19 pandemic, FirstEnergy has increased reviews of counterparties, customers and industries that have been negatively impacted, which could affect meeting contractual obligations with FirstEnergy. FirstEnergy has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy’s overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, Pennsylvania Companies, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, it is expected that appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy’s credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements, and surveys to determine negative impacts to essential vendors as a result of the COVID-19 pandemic. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties’ credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
OUTLOOK
CARES ACT
On March 27, 2020, the President signed into law the CARES Act, an economic stimulus package in response to the COVID-19 pandemic. The CARES Act contains several corporate income tax provisions, including making remaining AMT credits immediately refundable; providing a 5-year carryback of NOLs generated in tax years 2018, 2019, and 2020, and removing the 80% taxable income limitation on utilization of those NOLs if carried back to prior tax years or utilized in tax years beginning before 2021; and temporarily liberalizing the interest deductibility rules under Section 163(j) of the Tax Act, by raising the adjusted taxable income limitation from 30% to 50% for tax years 2019 and 2020 and giving taxpayers the election of using 2019 adjusted taxable income for purposes of computing 2020 interest deductibility. FirstEnergy has approximately $18 million of refundable AMT credits that will be fully refundable through the CARES Act, however, does not expect to generate additional income tax refunds from the NOL carryback provision and expects interest to be fully deductible starting in 2020. FirstEnergy does not currently expect the other provisions of the CARES Act to have a material effect on current income tax expense or the realizability of deferred income tax assets.
On July 28, 2020, the IRS issued final regulations implementing interest expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed certain rules on the computation of interest expense and limitation amount, as well as rules relevant to status as a regulated utility business and the allocation of consolidated group interest expense between utility and non-utility businesses. After reviewing the final regulations, FirstEnergy recorded a true-up to prior years’ reserve estimates during the quarter, which did not have a material impact to FirstEnergy’s income statement.
STATE REGULATION
Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.
MARYLAND
PE operates under MDPSC approved base rates that were effective as of March 23, 2019. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE’s approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years’ programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On September 1, 2020, PE filed its proposed plan for the 2021-2023 EmPOWER Maryland program cycle. The new plan largely continues PE’s existing programs and is estimated to cost approximately $148 million over the three-year period. The MDPSC had a hearing on the proposed plan in October 2020.
On January 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019.
On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs. On September 22, 2020, PE filed its depreciation study that indicated a slight increase in depreciation, and as a result, is seeking that the difference in depreciation be deferred for future recovery in PE’s next base rate case. The MDPSC has set the matter for hearing and delegated it to a public utility law judge. On November 6, 2020, an order was issued scheduling evidentiary hearings in April 2021.
Maryland’s Governor issued an order on March 16, 2020, forbidding utilities from terminating residential service or charging late fees for non-payment for the duration of the COVID-19 pandemic. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic, including incremental uncollectible expense, incurred from the date of the Governor’s order (or earlier if the utility could show that the expenses related to suspension of service terminations). On July 8, 2020, the MDPSC issued a notice opening a public conference to collect information from utilities and other stakeholders about the impacts of the COVID-19 pandemic on the utilities and their customers. The MDPSC subsequently issued orders allowing Maryland electric and gas utilities to resume residential service terminations for non-payment on November 15, 2020, subject to various restrictions, and clarifying that utilities could resume charging late fees on October 1, 2020.
NEW JERSEY
JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. JCP&L provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.
On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.
In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to ratepayers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which
were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.
Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On May 8, 2019, the NJBPU approved a Stipulation of Settlement submitted by JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition to implement JCP&L’s infrastructure plan, JCP&L Reliability Plus. The plan provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020, to enhance the reliability and resiliency of JCP&L’s distribution system and reduce the frequency and duration of power outages. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. The NJBPU approved adjusted rates that took effect on March 1, 2020. As further discussed below, JCP&L will recover the IIP capital investments as part of its distribution base rate case.
On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase of $186.9 million on an annual basis, which represents an overall average increase in JCP&L rates of 7.8%. The filing seeks to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. JCP&L proposed a rate effective date of March 19, 2020. The NJBPU issued orders suspending JCP&L’s proposed rates until November 19, 2020. JCP&L filed updates to the requested distribution base rate in both June and July 2020, resulting in JCP&L seeking a total annual distribution base rate increase of approximately $185 million. On October 16, 2020, the parties submitted a stipulation of settlement to the administrative law judge, providing for, among other things, a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which will become effective for customers on November 1, 2021. Until the rates become effective, and starting on January 1, 2021, JCP&L will be permitted to amortize an existing regulatory liability totaling approximately $86 million to offset the base rate increase that otherwise would have occurred in this period. The parties also agreed that the actual net gain from the sale of JCP&L’s interest in the Yards Creek pumped-storage hydro generation facility in New Jersey (210 MWs), as further discussed below, shall be applied to reduce JCP&L’s existing regulatory asset for previously deferred storm costs. On October 22, 2020, the administrative law judge entered an initial decision adopting the settlement. On October 28, 2020, the NJBPU approved the settlement and ordered an upcoming management audit for JCP&L.
On April 6, 2020, JCP&L signed an asset purchase agreement with Yards Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility. Subject to terms and conditions of the agreement, the base purchase price is $155 million. Completion of the transaction is subject to several closing conditions, including approval by the NJBPU and FERC. On July 31, 2020, FERC approved the transfer of JCP&L’s interest in the hydroelectric operating license. On October 8, 2020, FERC issued an order authorizing the transfer of JCP&L’s ownership interest in the hydroelectric facilities. There can be no assurance that all closing conditions will be satisfied or that the transaction will be consummated. JCP&L currently anticipates closing of the transaction to occur in the next few months. Assets held for sale on FirstEnergy’s Consolidated Balance Sheets associated with the transaction consist of property, plant and equipment of $44 million, which is included in the regulated distribution segment. On October 28, 2020, the NJBPU approved the sale of Yards Creek.
On August 27, 2020, JCP&L filed an AMI Program with the NJBPU, which proposes the deployment of approximately 1.2 million advanced meters over a three-year period beginning on January 1, 2023, at a total cost of approximately $418 million, including the pre-deployment phase. The 3-year deployment is part of the 20 year AMI Program that is expected to cost a total of approximately $732 million and proposes a cost recovery mechanism through a separate AMI tariff rider.
On June 10, 2020, the NJBPU issued an order establishing a framework for the filing of utility-run energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act. Under the established framework, JCP&L will recover its program investments over a ten year amortization period and its operations and maintenance expenses on an annual basis, be eligible to receive lost revenues on energy savings that resulted from its programs and be eligible for incentives or subject to penalties based on its annual program performance, beginning in the fifth year of its program offerings. On September 25, 2020, JCP&L filed its energy efficiency and peak demand reduction program. JCP&L’s program consists of 11 energy efficiency and peak demand reduction programs and subprograms to be run from July 1, 2021 through June 30, 2024. The program also seeks approval of cost recovery totaling approximately $230 million as well as lost revenues associated with the energy savings resulting from the programs.
On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 through September 30, 2021, or until the Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case. On August 21, 2020, the Governor of New Jersey issued a press release announcing that the New Jersey utilities agreed to extend their voluntary moratorium preventing shutoffs to both residential and commercial customers during the COVID-19 pandemic until October 15, 2020. On October 15, 2020, the Governor issued an Executive Order prohibiting utilities from terminating service to any residential gas, electric, public and private water customer, through March 15, 2021, requiring the
reconnection of certain customers, and disallowing the charging of late payment charges or reconnection fees during the public health emergency. On October 28, 2020, the NJBPU issued an order expanding the scope of the proceeding to examine all pandemic issues, including recovery of the COVID-19 regulatory assets, by way of a generic proceeding. Comments are due by November 30, 2020.
The recent credit rating actions taken on October 28, 2020, by S&P and Fitch triggered a requirement from various NJBPU orders that JCP&L file a mitigation plan, which was filed on November 5, 2020, to demonstrate that JCP&L has sufficient liquidity to meet its BGS obligations. On November 18, 2020, the NJBPU scheduled a public hearing on the mitigation plan for December 11, 2020.
OHIO
The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045; and (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. ESP IV further provided for the Ohio Companies to collect through the DMR $132.5 million annually for three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that the DMR is lawful, and remanded the matter to the PUCO with instructions to remove the DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an order directing the Ohio Companies to cease further collection through the DMR, credit back to customers a refund of the DMR funds collected since July 2, 2019, and remove the DMR from ESP IV. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of the DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. The Ohio Companies are contesting this appeal but are unable to predict the outcome of this matter. The SCOH heard the argument on this matter on May 12, 2020.
On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities and ending current energy efficiency program mandates on December 31, 2020, provided that statewide energy efficiency mandates are achieved as determined by the PUCO. On February 26, 2020, the PUCO ordered that a wind-down of statutorily required energy efficiency programs shall commence on September 30, 2020, and the programs shall terminate on December 31, 2020, and that the Ohio Companies’ existing portfolio plans are extended through 2020 without changes.
On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. Various Ohio House and Senate Bills were introduced in the third quarter of 2020 to, among other things, repeal HB 6, the legislation that established support for nuclear energy supply in Ohio, provided for a decoupling mechanism for Ohio electric utilities, and provided for the ending of current energy efficiency program mandates. FirstEnergy is unable to predict the outcome of the legislative activity in response to the investigation of HB 6, however, a repeal of the decoupling provision of HB 6 is reasonably possible. As of September 30, 2020, the uncollected amount recognized as a regulatory asset on FirstEnergy’s Consolidated Balance Sheet from the decoupling mechanism was approximately $100 million. However, absent the decoupling mechanism and other provisions of HB 6, it is expected that the Ohio Companies would have collected lost distribution revenues estimated at approximately $63 million for the nine months ended September 30, 2020, for a pre-tax net impact of approximately $37 million. Furthermore, as FirstEnergy would not have financially benefited from the zero nuclear credit included in HB 6, there is no expected impact to FirstEnergy due to the repeal of that provision in HB 6. On November 2, 2020, the Ohio Companies filed their annual update to the Ohio decoupling rider with an estimated annual revenue requirement of approximately $113 million with a proposed effective date of January 1, 2021, unless otherwise ordered by the PUCO.
On July 17, 2019, the PUCO approved, with no material modifications, a settlement agreement that provides for the implementation of the Ohio Companies’ first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act to
flow back to customers. The settlement had broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties.
In March 2020, the PUCO issued entries directing utilities to review their service disconnection and restoration policies and suspend, for the duration of the COVID-19 pandemic, otherwise applicable requirements that may impose a service continuity hardship or service restoration hardship on customers. The Ohio Companies are utilizing their existing approved cost recovery mechanisms where applicable to address the financial impacts of these directives. On July 31, 2020, the Ohio Companies filed with the PUCO their transition plan and requests for waivers to allow for the safe resumption of normal business operations, including service disconnections for non-payment, on or after September 15, 2020. On September 23, 2020, the PUCO approved the Ohio Companies’ transition plan, including approval of the resumption of service disconnections for non-payment, which the Ohio Companies began on October 5, 2020.
On July 29, 2020, the PUCO consolidated the Ohio Companies’ Applications for determination of the existence of significantly excessive earnings, or SEET, under ESP IV for calendar years 2018 and 2019, which had been previously filed on July 15, 2019, and May 15, 2020, respectively, and set a procedural schedule with evidentiary hearings scheduled for October 29, 2020. The calculations included in the Ohio Companies’ SEET filings for calendar years 2018 and 2019 demonstrate that the Ohio Companies did not have significantly excessive earnings, however, FirstEnergy and the Ohio Companies are unable to predict the PUCO’s ultimate determination of the applications. On August 3, 2020, the OCC filed an interlocutory appeal asking the PUCO to stay the SEET proceeding until the SCOH determines whether DMR should be excluded from the SEET, as further discussed above. Furthermore, on July 29, 2020, Ohio House Bill 740 was introduced, which would repeal legislation passed last year that permitted the Ohio Companies to file their SEET results on a consolidated basis instead of on an individual company basis. On September 4, 2020, the PUCO opened its quadrennial review of ESP IV, consolidated it with the Ohio Companies’ 2018 and 2019 SEET Applications, and set a procedural schedule for the consolidated matters. On October 29, 2020, the PUCO issued an entry extending the deadline for the Ohio Companies to file quadrennial review of ESP IV testimony to March 1, 2021, with the evidentiary hearings to commence no sooner than May 3, 2021.
On September 8, 2020, the OCC filed motions in the Ohio Companies’ Corporate Separation Audit and Rider DMR Audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. The Ohio Companies’ filed a response in opposition to the OCC’s motions on September 23, 2020.
On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by ratepayers. The Ohio Companies filed a response on September 30, 2020, stating that any political and charitable spending in support of HB 6 or the subsequent referendum were not included in rates or charges paid for by its customers. Several parties requested that the PUCO broaden the scope of the review of political and charitable spending.
In connection with an on-going audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ Corporate Separation Plan. The additional audit is for the period from November 2016 through October 2020, and the PUCO intends to select an auditor by December 2, 2020, with a final audit report to be filed in April 2021.
See “Outlook - Other Legal Proceedings” below for additional details on the government investigation and subsequent litigation surrounding the investigation of HB 6.
PENNSYLVANIA
The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 was separately tracked and its treatment will be addressed in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn.
Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the
PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. On June 18, 2020, the PPUC entered a Final Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026. The Final Implementation Order set demand reduction targets, relative to 2007 to 2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWH for ME, 3.0% MWH for PN, 2.7% MWH for Penn, and 2.4% MWH for WP. Phase IV plans must be filed by November 30, 2020.
Pennsylvania EDCs may file with the PPUC for approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On August 30, 2019, the Pennsylvania Companies filed Petitions for approval of new LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On January 16, 2020, the PPUC approved the LTIIPs without modification. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016. On August 30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. On March 12, 2020, an order was entered approving a settlement by all parties to that case which provides for a temporary increase in the recoverability cap from 5% to 7.5%, to expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program.
Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates, which decision was appealed by the Pennsylvania OCA to the Pennsylvania Commonwealth Court. The Commonwealth Court reversed the PPUC’s decision and remanded the matter to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On April 7, 2020, the Pennsylvania Supreme Court issued an order granting Petitions for Allowance of Appeal by both the PPUC and the Pennsylvania Companies of the Commonwealth Court’s Opinion and Order. Briefs and Reply Briefs of the parties were filed, and oral argument before the Supreme Court was held on October 21, 2020. An adverse ruling by the Pennsylvania Supreme Court is not expected to result in a material impact to FirstEnergy.
The PPUC issued an order on March 13, 2020, forbidding utilities from terminating service for non-payment for the duration of the COVID-19 pandemic. On May 13, 2020, the PPUC issued a Secretarial letter directing utilities to track all prudently incurred incremental costs arising from the COVID-19 pandemic, and to create a regulatory asset for future recovery of incremental uncollectibles incurred as a result of the COVID-19 pandemic and termination moratorium. On October 13, 2020, the PPUC entered an order lifting the service termination moratorium effective November 9, 2020 subject to certain additional notification, payment procedures and exceptions, and permits the Pennsylvania Companies to create a regulatory asset for all incremental expenses associated with their compliance with the order. Customers with income levels at 300% of federal poverty income guidelines and below are not subject to termination through March 31, 2021 as long as they apply for assistance programs and payment arrangements. Utilities may create a regulatory asset for all incremental expenses associated with their compliance with the order. On October 27, 2020, several stakeholders filed a joint petition for clarification of the order. Answers to the joint petition for clarification were due on November 6, 2020.
WEST VIRGINIA
MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operate under rates approved by the WVPSC effective February 2015. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP’s and PE’s ENEC rate is updated annually.
On March 13, 2020, the WVPSC urged all utilities to suspend utility service terminations except where necessary as a matter of safety or where requested by the customer. On May 15, 2020, the WVPSC issued an order to authorize MP and PE to record a deferral of additional, extraordinary costs directly related to complying with the various COVID-19 government shut-down orders and operational precautions, including impacts on uncollectible expense and cash flow related to temporary discontinuance of service terminations for non-payment and any credits to minimum demand charges associated with business customers adversely impacted by shut-downs or temporary closures related to the pandemic. MP and PE resumed disconnection activity for commercial and industrial customers on September 15, 2020, and for residential customers on November 4, 2020.
On August 28, 2020, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $55 million beginning January 1, 2021, representing a 4% decrease in rates compared to those in effect on August 28, 2020. The decrease in the ENEC rates is net of recovering approximately $10.5 million in previously deferred, incremental uncollectible and other related costs resulting from the COVID-19 pandemic. A hearing is set to begin on December 2, 2020, and an order is expected in December 2020.
Also on August 28, 2020, MP and PE filed with the WVPSC for recovery of costs associated with modernization and improvement program for their coal-fired boilers. The proposed annual revenue increase for these environmental compliance projects is $5 million beginning January 1, 2021. A hearing is set to begin on December 2, 2020.
FERC REGULATORY MATTERS
Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.
FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although in the case of the Utilities major wholesale purchases remain subject to review and regulation by the relevant state commissions.
Federally enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to six regional entities, including RFC. All of the facilities that FirstEnergy operates are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.
FirstEnergy believes that it is in material compliance with all currently effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy’s part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows.
ATSI Transmission Formula Rate
On May 1, 2020, ATSI filed amendments to its formula rate to recover regulatory assets for certain costs that ATSI incurred as a result of its 2011 move from MISO to PJM, certain costs allocated to ATSI by FERC for transmission projects that were constructed by other MISO transmission owners, certain income tax-related adjustments, including, but not limited to impacts from the Tax Act discussed further below, and certain costs for transmission-related vegetation management programs. The amount on FirstEnergy’s Consolidated Balance Sheet for these regulatory assets was approximately $76 million and $73 million, as of September 30, 2020 and December 31, 2019, respectively. Per prior FERC orders, ATSI included a “cost-benefit study” to support recovery of ATSI’s costs to move to PJM, and the MISO transmission project costs that were allocated to ATSI. Certain intervenors filed protests of the formula rate amendments on May 29, 2020, and ATSI filed a reply on June 15, 2020. On June 30, 2020, FERC issued an initial order accepting the tariff amendments subject to refund, suspending the effective date for five months to be effective December 1, 2020, and setting the matter for hearing and settlement proceedings. ATSI is engaged in settlement negotiations with the other parties.
FERC Actions on Tax Act
On March 15, 2018, FERC initiated proceedings on the question of how to address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 21, 2019, FERC issued a final rule (Order No. 864). Order No. 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Per FERC directives, ATSI submitted its compliance filing on May 1, 2020. MAIT submitted its compliance filing on June 1, 2020. Certain intervenors filed protests of the compliance filings, to which ATSI and MAIT responded. On October 28, 2020, FERC Staff requested additional information about ATSI’s proposed rate base adjustment mechanism. ATSI has 30 days to respond in writing to FERC Staff’s request. On May 15, 2020, TrAIL submitted its compliance filing and on June 1, 2020, PATH submitted its required compliance filing. These compliance filings each remain pending before FERC. MP, WP and PE (as holders of a “stated” transmission rate) are addressing these requirements in the transmission formula rates amendments that were filed on October 29, 2020. JCP&L is addressing these requirements as part of its pending transmission formula rate case.
Transmission ROE Methodology
FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will rely on three financial models - discounted cash flow, capital-asset pricing, and expected earnings - to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the replacement ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. Certain parties, including the Utilities, sought rehearing of FERC’s decision in the MISO utilities proceeding and, on May 21, 2020, FERC issued Opinion No. 569-A that changed FERC’s ROE methodology. Under this methodology FERC established an ROE that is based on three financial models – discounted cash flow, capital-asset pricing, and risk premium – to calculate a composite zone of reasonableness. FERC noted that utilities could, in utility-specific proceedings, ask to have the expected earnings methodology included in calculating the utility’s authorized ROE. FERC also noted that, going forward, it will divide that zone into three equal parts, to be used for high risk, normal risk, and low risk utilities. A given utility will be assigned to one of these three parts of the zone of reasonableness, and its ROE will be set at the median or midpoint of the other utilities that are in the applicable third of the zone. FirstEnergy filed a request for rehearing, which FERC denied on July 22, 2020. FirstEnergy also initiated appellate proceedings of FERC’s Opinion Nos. 569 and 569-A, as did a number of other parties. These proceedings are pending before the United States Court of Appeals for the District of Columbia Circuit. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis.
On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. Initial comments were submitted July 1, 2020, and reply comments were filed on July 16, 2020. FirstEnergy participated through EEI and through a consortium of PJM Transmission Owners. This proceeding is pending before FERC.
JCP&L Transmission Formula Rate
On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L and the parties to the FERC proceeding are engaged in settlement negotiations.
Allegheny Power Zone Transmission Formula Rate Filings
On October 29, 2020, MP, PE and WP filed tariff amendments with FERC to convert their existing stated transmission rate to a forward-looking formula transmission rate, effective January 1, 2021. In addition, on October 30, 2020, KATCo filed a proposed new tariff to establish a forward-looking formula rate, and requested that the new rate become effective January 1, 2021. In its filing, KATCo explained that while it currently owns no transmission assets, it may build new transmission facilities in the Allegheny zone, and that it may seek required state and federal authorizations to acquire transmission assets from PE and WP by January 1, 2022. These transmission rate filings are pending before FERC. FirstEnergy intends to include KATCo in the Regulated Transmission reportable segment.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.
Clean Air Act
FirstEnergy complies with SO2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.
CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy’s operations, cash flows and financial condition.
In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO2, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of September 30, 2020, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.
In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.
Climate Change
There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.
At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO2 emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO2 emissions by approximately 62 percent. In September 2016, the U.S. joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.
In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for GHG under the Clean Air Act” concluding that concentrations of several key GHGs constitutes an “endangerment” and may be regulated as “air pollutants” under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO2 emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy’s facilities. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility’s cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.
On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations were to phase-in as permits are renewed on a five-year cycle from 2018 to 2023. However, on April 13, 2017, EPA granted a Petition for Reconsideration and on September 18, 2017, EPA postponed certain compliance deadlines for two years. On August 31, 2020, EPA issued a final rule revising the effluent limits for discharges from wet scrubber systems, retaining the zero-discharge standard for ash transport water, (with some limited discharge allowances), and extending the deadline for compliance to December 31, 2025 for both. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. Depending on the outcome of appeals, how final rules are ultimately implemented and the compliance options MP elects to take with the new rules, the compliance with these standards, which could include capital expenditures at Ft. Martin and Harrison power stations, may be substantial and changes to MP’s operations at those power stations may also result.
On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. The EPA has proposed a penalty of $900,000 to settle alleged past boron exceedances at the Mingo and Springdale landfills. Negotiations are continuing and WP is unable to predict the outcome of this matter.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.
In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment. On December 2, 2019, the EPA published a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria. On July 29, 2020, the EPA published a final rule revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria.
FE or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on FirstEnergy’s Consolidated Balance Sheets as of September 30, 2020, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities
of approximately $104 million have been accrued through September 30, 2020. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
United States v. Larry Householder, et al.
On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. No contingency has been reflected in FirstEnergy’s consolidated financial statements as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
Legal Proceedings Relating to United States v. Larry Householder, et al.
In addition to the subpoenas referenced above under “—United States v. Larry Householder, et. al.”, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder.
•Gendrich v. Anderson, et al. and Sloan v. Anderson, et al. (Common Pleas Court, Summit County, OH); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain FE directors and officers, alleging, among other things, breaches of fiduciary duty.
•Smith v. FirstEnergy Corp. et al., Buldas v. FirstEnergy Corp. et al., and Hudock and Cameo Countertops, Inc. v. FirstEnergy Corp. et al. (Federal District Court, S.D. Ohio); on July 27, 2020, July 31, 2020, and August 5, 2020, respectively, purported customers of FirstEnergy filed putative class action lawsuits against FE and FESC, as well as certain current and former FirstEnergy officers, alleging civil Racketeer Influenced and Corrupt Organizations Act violations and related state law claims. These actions have been consolidated.
•Owens v. FirstEnergy Corp. et al. and Frand v. FirstEnergy Corp. et al. (Federal District Court, S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits against FE and certain FE officers, purportedly on behalf of all purchasers of FE common stock from February 21, 2017 through July 21, 2020, asserting claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, alleging misrepresentations or omissions by FirstEnergy concerning its business and results of operations.
•Emmons v. FirstEnergy Corp. et al. (Common Pleas Court, Cuyahoga County, OH); on August 4, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE, FESC, OE, TE and CEI, along with FES, alleging several causes of action, including negligence and/or gross negligence, breach of contract, unjust enrichment, and unfair or deceptive consumer acts or practices. On October 1, 2020, plaintiffs filed a First Amended Complaint, adding as a plaintiff a purported customer of FirstEnergy and alleging a civil violation of the Ohio Corrupt Activity Act and civil conspiracy against FE, FESC and FES.
•Miller v. Anderson, et al. (Federal District Court, N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Beck v. Anderson et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al; Behar v. Anderson, et al. (U.S. District Court, S.D. Ohio); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Securities Exchange Act of 1934.
•State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. (Common Pleas Court, Franklin County, OH); on September 23, 2020, the OH AG filed a complaint against several parties including FE and FESC, alleging, one cause of action, a civil violation of the Ohio Corrupt Activity Act in connection with the passage of HB 6. The OH AG sought a preliminary injunction to prevent each of the defendants, including FE and FESC, through the end of 2020, from: (i) contributing to any groups whose purpose is to keep or modify HB 6; (ii) making any public statements for or against any repeal or modification legislation concerning HB 6; (iii) lobbying, consulting, or advising on these matters; or (iv) contributing to any Ohio legislative candidates. The court denied the OH AG’s request for preliminary injunctive relief on October 2, 2020.
•City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH); on October 27, 2020, the Cities of Cincinnati and Columbus filed a complaint against several parties including FE, alleging a civil violation of the Ohio Corrupt Activity Act and seeking to enjoin the collection of the zero nuclear credit included in HB 6.
•Mitchell v. FirstEnergy Corp. et al. (Common Pleas Court, Fairfield County, OH); on October 6, 2020, an unsuccessful candidate for the Ohio legislature filed an amended complaint adding FirstEnergy Corp. to a previously filed Ohio Corrupt Activity Act civil lawsuit against now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. The amended complaint sought an amount in excess of $875,000, plus
treble damages and other relief. On November 2, 2020, the plaintiff moved to voluntarily dismiss the claims without prejudice.
The plaintiffs in each of the above cases, seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). In addition, on August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers. The outcome of any of these lawsuits and investigations are uncertain and could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows. No contingency has been reflected in FirstEnergy’s consolidated financial statements as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.
Internal Investigation Relating to United States v. Larry Householder, et al.
As previously disclosed, a committee of independent members of the Board of Directors is directing an internal investigation related to ongoing government investigations. In connection with FirstEnergy’s internal investigation, such committee determined on October 29, 2020, to terminate FirstEnergy’s Chief Executive Officer, Charles E. Jones, together with two other executives: Dennis M. Chack, Senior Vice President of Product Development, Marketing, and Branding; and Michael J. Dowling, Senior Vice President of External Affairs. Each of these terminated executives violated certain FirstEnergy policies and its code of conduct. These executives were terminated as of October 29, 2020. Such former members of senior management did not maintain and promote a control environment with an appropriate tone of compliance in certain areas of FirstEnergy’s business, nor sufficiently promote, monitor or enforce adherence to certain FirstEnergy policies and its code of conduct. Furthermore, certain former members of senior management did not reasonably ensure that relevant information was communicated within our organization and not withheld from our independent directors, our Audit Committee, and our independent auditor. Among the matters considered with respect to the determination by the committee of independent members of the Board of Directors that certain former members of senior management violated certain FirstEnergy policies and its code of conduct related to a payment of approximately $4 million made in early 2019 in connection with the termination of a purported consulting agreement, as amended, which had been in place since 2013. The counterparty to such agreement was an entity associated with an individual who subsequently was appointed to a full-time role as an Ohio government official directly involved in regulating the Ohio Companies, including with respect to distribution rates. At this time, it has not been determined if the payments were for the purposes represented within the consulting agreement. Immediately following these terminations, the independent members of its Board appointed Mr. Steven E. Strah to the position of Acting Chief Executive Officer and Mr. Christopher D. Pappas, a current member of the Board, to the temporary position of Executive Director, each effective as of October 29, 2020. Mr. Donald T. Misheff will continue to serve as Non-Executive Chairman of the Board. Additionally, on November 8, 2020, Robert Reffner, Senior Vice President and Chief Legal Officer, and Ebony Yeboah-Amankwah, Vice President, General Counsel, and Chief Ethics Officer, were separated from FirstEnergy due to inaction and conduct that the Board determined was influenced by the improper tone at the top. The matter is a subject of the ongoing internal investigation as it relates to the government investigations.
Nuclear Plant Matters
Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of September 30, 2020, JCP&L, ME and PN had in total approximately $881 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs.
On October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of September 30, 2020. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. On October 28, 2020, Rate Counsel submitted comments recommending that the NJBPU only approve the sale of TMI-2 on the condition that any liability for TMI-2 be absorbed by the joint owners and that JCP&L should agree to not seek to recover any such costs from its utility customers. On November 2, 2020, JCP&L submitted reply comments accepting Rate Counsel’s condition. JCP&L is awaiting a NJBPU order. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. On August 10, 2020, JCP&L, ME, PN, GPUN, TMI-2 Solutions, LLC, and the PA DEP reached a settlement agreement regarding the decommissioning of TMI-2. The settlement agreement provides for increased and detailed oversight by the PA DEP over the decommissioning work, expenditures, and environmental impacts of the dismantlement of TMI-2 by TMI-2 Solutions, LLC. In addition, the PA DEP withdrew its objection to the TMI-2 transfer in the NRC proceedings. Both the NRC and NJBPU proceedings are ongoing. Assets and liabilities held for sale on FirstEnergy’s Consolidated Balance Sheet associated with the transaction consist of asset retirement obligations of $718 million, NDTs of $881 million as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment.
FES Bankruptcy
On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court and emerged on February 27, 2020. See Note 3, “Discontinued Operations,” for additional discussion.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 9, “Regulatory Matters.”
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows.
NEW ACCOUNTING PRONOUNCEMENTS
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (Issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. Prior to adoption, FirstEnergy analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities. The adoption of this standard upon January 1, 2020 did not have a material impact to FirstEnergy’s financial statements and required additional disclosures in these Notes to the Consolidated Financial Statements. Please see above for additional information on FirstEnergy’s allowance for uncollectible customer receivables.
ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 allows implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. FirstEnergy adopted this standard as of January 1, 2020, with no material impact to its financial statements.
ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. FirstEnergy’s $3.5 billion Revolving Credit Facility bears interest at fluctuating interest rates based on LIBOR and contains provisions (requiring an amendment) in the event that LIBOR can no longer be used. As of September 30, 2020, FirstEnergy has not utilized any of the expedients discussed within this ASU.
Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.
ASU 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. FirstEnergy continues to evaluate the new guidance, but currently does not expect a material impact upon adopting this standard.