The following is management's discussion and analysis of certain significant
factors that have affected the consolidated financial condition and results of
operations of the Company during the periods included herein. Explanations
include management's best estimate of the impact of weather, customer growth,
usage trends and other factors. This discussion should be read in conjunction
with the Company's historical unaudited Consolidated Financial Statements and
Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
The Company's actual results in the future could differ significantly from the
historical results.
BHE is a holding company that owns a highly diversified portfolio of locally
managed businesses principally engaged in the energy industry and is a
consolidated subsidiary of Berkshire Hathaway. As of November 3, 2022, Berkshire
Hathaway and family members and related or affiliated entities of the late Mr.
Walter Scott, Jr., a former member of BHE's Board of Directors, beneficially
owned 92% and 8%, respectively, of BHE's common stock.
Berkshire Hathaway Energy's operations are organized as eight business segments:
PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican
Energy), NV Energy (which primarily consists of Nevada Power and Sierra
Pacific), Northern Powergrid (which primarily consists of Northern Powergrid
(Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group
(which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE
Transmission (which consists of BHE Canada (which primarily consists of
AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE,
through these locally managed and operated businesses, owns four utility
companies in the U.S. serving customers in 11 states, two electricity
distribution companies in Great Britain, five interstate natural gas pipeline
companies, one of which owns a liquefied natural gas ("LNG") export, import and
storage facility, in the U.S., an electric transmission business in Canada,
interests in electric transmission businesses in the U.S., a renewable energy
business primarily investing in wind, solar, geothermal and hydroelectric
projects, the largest residential real estate brokerage firm in the U.S. and one
of the largest residential real estate brokerage franchise networks in the U.S.
The reportable segment financial information includes all necessary adjustments
and eliminations needed to conform to the Company's significant accounting
policies. The differences between the reportable segment amounts and the
consolidated amounts, described as BHE and Other, relate principally to other
entities, including MidAmerican Energy Services, LLC, corporate functions and
intersegment eliminations.
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Operating results for the third quarter and first nine months of 2022 and 2021
Overview
Operating income and (loss) earnings on common shares for the Company’s reportable segments are summarized as follows (in millions):
Third Quarter First Nine Months
2022 2021 Change 2022 2021 Change
Operating revenue:
PacifiCorp $ 1,635 $ 1,491 $ 144 10 % $ 4,246 $ 4,031 $ 215 5 %
MidAmerican Funding 1,148 966 182 19 3,050 2,726 324 12
NV Energy 1,334 1,085 249 23 2,926 2,443 483 20
Northern Powergrid 359 277 82 30 1,019 857 162 19
BHE Pipeline Group 964 785 179 23 2,855 2,584 271 10
BHE Transmission 177 185 (8) (4) 543 547 (4) (1)
BHE Renewables 302 316 (14) (4) 763 773 (10) (1)
HomeServices 1,405 1,743 (338) (19) 4,284 4,738 (454) (10)
BHE and Other 176 120 56 47 456 414 42 10
Total operating revenue $7,500 $6,968 $532
8 % $ 20,142 $ 19,113 $ 1,029 5 %
(Loss) earnings on common
shares:
PacifiCorp $ 409 $ 333 $ 76 23 % $ 622 $ 728 $ (106) (15) %
MidAmerican Funding 300 373 (73) (20) 745 728 17 2
NV Energy 270 282 (12) (4) 392 416 (24) (6)
Northern Powergrid 100 83 17 20 282 162 120 74
BHE Pipeline Group 234 144 90 63 755 627 128 20
BHE Transmission 59 65 (6) (9) 183 184 (1) (1)
BHE Renewables(1) 173 163 10 6 526 360 166 46
HomeServices 29 102 (73) (72) 134 321 (187) (58)
BHE and Other (2,424) 351 (2,775) * (1,750) 580 (2,330) *
Total (loss) earnings on
common shares $ (850) $ 1,896 $ (2,746) * $ 1,889 $ 4,106 $ (2,217) (54) %
(1) Includes tax attributes of ignored entities that are not liable to pay income taxes and whose profits are taxable directly to BHE.
* Not significant
Earnings on common shares decreased $2,746 million for the third quarter of 2022
compared to 2021. The third quarter of 2022 included a pre-tax loss of $3,259
million ($2,574 million after-tax) compared to a pre-tax gain in the third
quarter of 2021 of $296 million ($253 million after-tax) on the Company's
investment in BYD Company Limited. Excluding the impact of this item, adjusted
earnings on common shares for the third quarter of 2022 was $1,724 million, an
increase of $81 million, or 5%, compared to adjusted earnings on common shares
in the third quarter of 2021 of $1,643 million.
Earnings on common shares decreased $2,217 million for the first nine months of
2022 compared to 2021. The first nine months of 2022 included a pre-tax loss of
$1,948 million ($1,539 million after-tax) compared to a pre-tax gain in the
first nine months of 2021 of $1,126 million ($855 million after-tax) on the
Company's investment in BYD Company Limited. Excluding the impact of this item,
adjusted earnings on common shares for the first nine months of 2022 was $3,428
million, an increase of $177 million, or 5%, compared to adjusted earnings on
common shares in the first nine months of 2021 of $3,251 million.
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The decrease in earnings on common shares for the third quarter and for the first nine months of 2022 compared to 2021 is mainly explained by the following elements:
•The Utilities' earnings decreased $9 million for the third quarter and $113
million for the first nine months of 2022 compared to 2021. The decrease for the
first nine months reflected higher operations and maintenance expense, higher
depreciation and amortization expense and unfavorable investment earnings,
partially offset by higher electric utility margin and a favorable income tax
benefit from higher PTCs recognized. Electric retail customer volumes increased
1.7% for the first nine months of 2022 compared to 2021, primarily due to higher
customer usage and an increase in the average number of customers;
•Northern Powergrid's earnings increased $17 million for the third quarter and
$120 million for the first nine months of 2022 compared to 2021. The increase
for the first nine months was primarily due to a deferred income tax charge of
$109 million related to a June 2021 enacted increase in the United Kingdom
corporate income tax rate from 19% to 25% effective April 1, 2023;
•BHE Pipeline Group's earnings increased $90 million for the third quarter and
$128 million for the first nine months of 2022 compared to 2021, largely due to
higher earnings at BHE GT&S from the impacts of the EGTS general rate case,
favorable income tax adjustments and lower operations and maintenance expense.
In addition, earnings for the first nine months decreased from the effects of
higher margins on natural gas sales and higher transportation revenue in the
first quarter of 2021 at Northern Natural Gas from the February 2021 polar
vortex weather event;
•BHE Renewables' earnings increased $10 million for the third quarter and $166
million for the first nine months of 2022 compared to 2021. The increase for the
first nine months was primarily due to higher operating revenue from owned
renewable energy projects and higher earnings from tax equity investments,
mainly due to the unfavorable impacts in the first quarter of 2021 from the
February 2021 polar vortex weather event;
•HomeServices' earnings decreased $73 million for the third quarter and $187
million for the first nine months of 2022 compared to 2021, reflecting lower
earnings from mortgage services mainly from a decrease in funded volumes and
lower earnings from brokerage and settlement services largely attributable to a
decrease in closed units at existing companies; and
•BHE and Other's earnings decreased $2,775 million for the third quarter and
$2,330 million for the first nine months of 2022 compared to 2021, mainly due to
$2,827 million and $2,394 million, respectively, of unfavorable comparative
changes in the Company's investment in BYD Company Limited, partially offset by
lower federal income tax credits recognized on a consolidated basis in the third
quarter and lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to
certain subsidiaries of Berkshire Hathaway.
Reportable segment results
PacifiCorp
Operating revenue increased $144 million for the third quarter of 2022 compared
to 2021, primarily due to higher retail revenues of $117 million and higher
wholesale and other revenue of $27 million, largely from higher average
wholesale prices. Retail revenue increased primarily due to price impacts of $61
million from higher average retail rates largely due to tariff changes and $57
million from higher retail volumes. Retail customer volumes increased 3.5%,
primarily due to the favorable impact of weather and an increase in the average
number of customers, partially offset by lower customer usage.
Earnings increased $76 million for the third quarter of 2022 compared to 2021,
primarily due to higher utility margin of $67 million and a favorable income tax
benefit, partially offset by higher operations and maintenance expense of $22
million and higher depreciation and amortization expense of $5 million, mainly
from additional assets placed in-service. Utility margin increased primarily due
to higher retail rates and volumes, favorable deferred net power costs and
higher average wholesale prices, partially offset by higher purchased power and
thermal generation costs. The favorable income tax benefit was largely due to
higher PTCs recognized of $21 million and the effects of ratemaking.
Operating revenue increased $215 million for the first nine months of 2022
compared to 2021, primarily due to higher retail revenues of $143 million and
higher wholesale and other revenue of $72 million, largely from higher average
wholesale prices. Retail revenue increased primarily due to price impacts of
$104 million from higher average retail rates largely due to tariff changes and
$40 million from higher retail volumes. Retail customer volumes increased 0.8%,
primarily due to an increase in the average number of customers and the
favorable impact of weather, partially offset by lower customer usage.
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Earnings decreased $106 million for the first nine months of 2022 compared to
2021, primarily due to higher operations and maintenance expense of $160
million, an unfavorable income tax benefit, higher depreciation and amortization
expense of $25 million, mainly from additional assets placed in-service, and
unfavorable changes in the cash surrender value of corporate-owned life
insurance policies, partially offset by higher utility margin of $88 million.
Operations and maintenance expense increased mainly due to an increase in loss
accruals associated with the September 2020 wildfires, net of estimated
insurance recoveries, and higher general and plant maintenance costs, Utility
margin increased primarily due to higher retail rates and volumes, higher
average wholesale prices and favorable deferred net power costs, partially
offset by higher purchased power and thermal generation costs. The unfavorable
income tax benefit was largely due to the effects of ratemaking and lower PTCs
recognized of $6 million.
MidAmerican Funding
Operating revenue increased $182 million for the third quarter of 2022 compared
to 2021, primarily due to higher electric operating revenue of $155 million and
higher natural gas operating revenue of $29 million. Electric operating revenue
increased due to higher wholesale and other revenue of $87 million and higher
retail revenue of $68 million. Electric wholesale and other revenue increased
mainly due to higher average wholesale per-unit prices of $96 million. Electric
retail revenue increased primarily due to higher recoveries through adjustment
clauses of $47 million (fully offset in expense, primarily cost of sales) and
higher customer volumes of $17 million. Electric retail customer volumes
increased 3.1%, primarily due to higher customer usage. Natural gas operating
revenue increased due to higher purchased gas adjustment recoveries of
$34 million (fully offset in cost of sales), primarily from a higher average
per-unit cost of natural gas sold, partially offset by the impacts of certain
regulatory recovery mechanisms of $6 million.
Earnings decreased $73 million for the third quarter of 2022 compared to 2021,
primarily due to higher depreciation and amortization expense of $120 million,
an unfavorable income tax benefit, higher operations and maintenance expense of
$10 million and unfavorable changes in the cash surrender value of
corporate-owned life insurance policies, partially offset by higher electric
utility margin of $83 million. Depreciation and amortization expense increased
primarily from the impacts of certain regulatory mechanisms and additional
assets placed in-service. Electric utility margin increased primarily due to the
higher wholesale and retail revenues, partially offset by higher purchased power
costs. The unfavorable income tax benefit was largely due to the effects of
ratemaking, partially offset by higher PTCs recognized of $14 million from
higher wind- and solar-powered generation.
Operating revenue increased $324 million for the first nine months of 2022
compared to 2021, primarily due to higher electric operating revenue of
$357 million, partially offset by lower natural gas operating revenue of
$22 million and lower nonregulated operating revenue of $10 million. Electric
operating revenue increased due to higher wholesale and other revenue of
$192 million and higher retail revenue of $165 million. Electric wholesale and
other revenue increased mainly due to higher average wholesale per-unit prices
of $174 million and higher wholesale volumes of $23 million. Electric retail
revenue increased primarily due to higher recoveries through adjustment clauses
of $110 million (fully offset in expense, primarily cost of sales) and higher
customer volumes of $45 million. Electric retail customer volumes increased
4.0%, primarily due to higher customer usage. Natural gas operating revenue
decreased due to lower purchased gas adjustment recoveries of $37 million (fully
offset in cost of sales), primarily from a lower average per-unit cost of
natural gas sold, partially offset by the impacts of tax reform of $6 million,
the favorable impact of weather of $5 million and higher customer usage of $4
million.
Earnings increased $17 million for the first nine months of 2022 compared to
2021, primarily due to higher electric utility margin of $240 million, a
favorable income tax benefit and higher natural gas utility margin of
$15 million, partially offset by higher depreciation and amortization expense of
$231 million, unfavorable changes in the cash surrender value of corporate-owned
life insurance policies, higher operations and maintenance expense of $25
million, higher interest expense of $12 million and lower nonregulated utility
margin of $10 million. Electric utility margin increased primarily due to the
higher wholesale and retail revenues, partially offset by higher purchased power
costs. The favorable income tax benefit was mainly due to higher PTCs recognized
of $106 million from higher wind- and solar-powered generation, partially offset
by the effects of ratemaking. Depreciation and amortization expense increased
primarily from the impacts of certain regulatory mechanisms and additional
assets placed in-service.
NV Energy
Operating revenue increased $249 million for the third quarter of 2022 compared
to 2021, primarily due to higher electric operating revenue of $244 million from
higher fully-bundled energy rates (fully offset in cost of sales) of $243
million. Electric retail customer volumes increased 0.3%.
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Earnings decreased $12 million for the third quarter of 2022 compared to 2021,
primarily due to higher operations and maintenance expense of $11 million,
higher depreciation and amortization expense of $6 million, mainly from
additional plant placed in-service, and lower cash surrender value of
corporate-owned life insurance policies, partially offset by higher interest and
dividend income of $10 million from carrying charges on regulatory balances.
Operations and maintenance expense increased mainly due to higher plant
operations and maintenance expenses and an unfavorable change in earnings
sharing at the Nevada Utilities.
Operating revenue increased $483 million for the first nine months of 2022
compared to 2021, primarily due to higher electric operating revenue of $457
million, from higher fully-bundled energy rates (fully offset in cost of sales)
of $452 million, and higher natural gas operating revenue of $26 million from a
higher average per-unit cost of natural gas sold (fully offset in cost of
sales). Electric retail customer volumes increased 1.3%, primarily due to an
increase in the average number of customers, partially offset by the unfavorable
impact of weather.
Earnings decreased $24 million for the first nine months of 2022 compared to
2021, primarily due to higher operations and maintenance expense of $19 million,
unfavorable changes in the cash surrender value of corporate-owned life
insurance policies and higher depreciation and amortization expense of $12
million, mainly from additional plant placed in-service, partially offset by
higher interest and dividend income of $24 million from carrying charges on
regulatory balances. Operations and maintenance expense increased mainly due to
higher plant operations and maintenance expenses and an unfavorable change in
earnings sharing at the Nevada Utilities.
Northern Power Grid
Operating revenue increased $82 million for the third quarter of 2022 compared
to 2021, primarily due to higher revenue at CE Gas of $72 million from a gas
project that commenced commercial operation in March 2022 and a solar project
that commenced commercial operation in July 2022 and higher distribution revenue
of $63 million, partially offset by $60 million from the stronger U.S. dollar.
Distribution revenue increased due to the recovery of Supplier of Last Resort
payments totaling $45 million (fully offset in cost of sales) and higher tariff
rates of $28 million, partially offset by a 5.5% decline in units distributed of
$10 million.
Earnings increased $17 million for the third quarter of 2022 compared to 2021,
primarily due to the higher distribution tariff rates and improved earnings at
CE Gas of $19 million from the new gas and solar projects, partially offset by
$17 million from the stronger U.S. dollar, the decline in units distributed and
higher distribution-related operating and depreciation expenses of $6 million.
Operating revenue increased $162 million for the first nine months of 2022
compared to 2021, primarily due to higher distribution revenue of $133 million
and higher revenue at CE Gas of $122 million from the new gas and solar
projects, partially offset by $105 million from the stronger U.S. dollar.
Distribution revenue increased due to the recovery of Supplier of Last Resort
payments totaling $90 million (fully offset in cost of sales) and higher tariff
rates of $67 million, partially offset by a 4.0% decline in units distributed of
$22 million.
Earnings increased $120 million for the first nine months of 2022 compared to
2021, primarily due to a deferred income tax charge of $109 million related to a
June 2021 enacted increase in the United Kingdom corporate income tax rate from
19% to 25% effective April 1, 2023, the higher distribution tariff rates and
improved earnings at CE Gas of $28 million from the new gas and solar projects,
partially offset by higher distribution-related operating and depreciation
expenses of $33 million, including higher storm-related costs, the decline in
units distributed and $25 million from the stronger U.S. dollar.
BHE Pipeline Group
Operating revenue increased $179 million for the third quarter of 2022 compared
to 2021, primarily due to higher operating revenue of $151 million at BHE GT&S
and higher operating revenue of $27 million at Northern Natural Gas. The
increase in operating revenue at BHE GT&S was primarily due to higher
non-regulated revenue of $61 million (largely offset in cost of sales) from
favorable commodity prices, higher LNG revenue of $59 million at Cove Point,
from favorable variable revenue and additional services due to a decrease in
scheduled outage days, and an increase in regulated gas transportation and
storage services rates due to the settlement of EGTS' general rate case of $41
million, partially offset by lower gas sales of $14 million at EGTS used for
operational and system balancing activities. The increase in operating revenue
at Northern Natural gas was largely due to higher transportation revenue of $22
million from higher volumes and rates.
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Earnings increased $90 million for the third quarter of 2022 compared to 2021,
primarily due to higher earnings of $95 million at BHE GT&S largely due to the
impacts of the EGTS general rate case of $50 million, favorable income tax
adjustments, lower operations and maintenance expense of $18 million and higher
earnings at Cove Point of $15 million from the higher operating revenue.
Operating revenue increased $271 million for the first nine months of 2022
compared to 2021, primarily due to higher operating revenue of $280 million at
BHE GT&S, partially offset by lower operating revenue of $17 million at Northern
Natural Gas. The increase in operating revenue at BHE GT&S was primarily due to
higher non-regulated revenue of $130 million (largely offset in cost of sales)
from favorable commodity prices, higher LNG revenue of $97 million at Cove
Point, from favorable variable revenue and additional services due to a decrease
in scheduled outage days, and an increase in regulated gas transportation and
storage services rates due to the settlement of EGTS' general rate case of $66
million, partially offset by lower gas sales of $31 million at EGTS used for
operational and system balancing activities. The decrease in operating revenue
at Northern Natural Gas was mainly due to lower gas sales of $27 million related
to system balancing activities offset by higher transportation revenue of $19
million. The variances in gas sales and transportation revenue included
favorable impacts recognized in the first quarter of 2021 of $77 million and $49
million, respectively, from the February 2021 polar vortex weather event.
Excluding this item, gas sales increased $50 million (largely offset in cost of
sales) and transportation revenue increased $68 million due to higher volumes
and rates.
Earnings increased $128 million for the first nine months of 2022 compared to
2021, primarily due to higher earnings of $194 million at BHE GT&S, partially
offset by lower earnings of $62 million at Northern Natural Gas. Earnings at BHE
GT&S increased mainly due to the impacts of the EGTS general rate case of $81
million, favorable income tax adjustments, lower operations and maintenance and
property and other tax expense of $47 million, increased earnings at Cove Point
of $24 million from the higher operating revenue and higher margin of $22
million from non-regulated activities. Earnings at Northern Natural Gas
decreased as the higher gross margin on gas sales and higher transportation
revenue in the first quarter of 2021 from the February 2021 polar vortex weather
event were partially offset by the favorable transportation revenue in 2022 due
to higher volumes and rates.
BHE Transmission
Operating revenue decreased $8 million for the third quarter and $4 million for
the first nine months of 2022 compared to 2021, primarily due to the stronger
U.S. dollar of $6 million and $13 million, respectively, and lower revenue from
the Montana-Alberta Tie Line, partially offset by higher non-regulated revenue
from a wind-powered generating facility.
Earnings decreased $6 million for the third quarter and $1 million for the first
nine months of 2022 compared to 2021, primarily due to lower earnings from the
Montana-Alberta Tie Line, higher non-regulated interest expense and the stronger
U.S. dollar of $2 million and $3 million, respectively, partially offset by
improved equity earnings at Electric Transmission Texas, LLC and the higher
non-regulated revenue.
BBB Renewables
Operating revenue decreased $14 million for the third quarter of 2022 compared
to 2021, primarily due to higher wind, geothermal and solar revenues of $37
million, from higher generation and pricing, and favorable changes in the
valuation of certain derivative contracts totaling $6 million, partially offset
by lower natural gas revenues of $45 million from lower generation and hedge
losses and lower hydro earnings of $13 million due to the transfer of the
Casecnan generating facility to the Philippine National Irrigation
Administration in December 2021.
Earnings increased $10 million for the third quarter of 2022 compared to 2021,
primarily due to higher wind earnings of $29 million and higher geothermal
earnings of $9 million, largely due to the higher operating revenue, partially
offset by lower natural gas earnings of $21 million, largely due to the lower
operating revenue and lower hydro earnings of $9 million due to the Casecnan
generating facility transfer. Wind earnings increased primarily due to higher
earnings from owned projects of $16 million, largely from the higher operating
revenue, and higher earnings from tax equity investments of $13 million, mainly
from higher production tax credits offset by unfavorable operating performance.
Operating revenue decreased $10 million for the first nine months of 2022
compared to 2021, primarily due to lower natural gas revenues of $55 million
from lower generation and hedge losses, unfavorable changes in the valuation of
certain derivative contracts totaling $51 million and lower hydro revenues of
$19 million due to the Casecnan generating facility transfer, partially offset
by higher wind, geothermal and solar revenues of $114 million from higher
generation and pricing.
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Earnings increased $166 million for the first nine months of 2022 compared to
2021, primarily due to higher wind earnings of $179 million, higher geothermal
earnings of $18 million, largely due to the higher operating revenue and lower
maintenance costs, and higher solar earnings of $13 million, mainly due to the
higher operating revenue, partially offset by lower natural gas earnings of $20
million largely due to the lower operating revenue and lower hydro earnings of
$19 million due to the Casecnan generating facility transfer. Wind earnings
increased primarily due to higher earnings from tax equity investments of $136
million, mainly as a result of the unfavorable impacts recognized in the first
quarter of 2021 from the February 2021 polar vortex weather event and higher
production tax credits offset by unfavorable operating performance, and higher
earnings from owned projects of $43 million, largely from the higher operating
revenue and favorable production tax credits offset by the unfavorable
derivative contract valuations.
HomeServices
Operating revenue decreased $338 million for the third quarter of 2022 compared
to 2021, primarily due to lower brokerage and settlement services revenue of
$252 million, from a 16% decrease in closed transaction volume, and lower
mortgage revenue of $82 million from a 39% decrease in funded volume, primarily
due to a decline in refinance activity. The decrease in brokerage volume was due
to 24% fewer closed units at existing companies offset by acquisitions and a 5%
increase in average sales price at existing companies.
Earnings decreased $73 million for the third quarter of 2022 compared to 2021,
primarily due to lower earnings from brokerage and settlement services of $49
million, largely attributable to the decrease in closed units at existing
companies, and lower earnings from mortgage services of $30 million from the
decrease in funded volume.
Operating revenue decreased $454 million for the first nine months of 2022
compared to 2021, primarily due to lower mortgage revenue of $242 million from a
36% decrease in funded volume, primarily due to a decline in refinance activity,
and lower brokerage and settlement services revenue of $212 million from a 4%
decrease in closed transaction volume. The decrease in brokerage volume was due
to 19% fewer closed units at existing companies offset by acquisitions and an 8%
increase in average sales price at existing companies.
Earnings decreased $187 million for the first nine months of 2022 compared to
2021, primarily due to lower earnings from mortgage services of $101 million,
largely from the decrease in funded volumes, and lower earnings from brokerage
and settlement services of $98 million due to the decrease in closed units at
existing companies, partially offset by favorable operating expense variances.
BHE and others
Operating revenue increased $56 million for the third quarter of 2022 compared
to 2021, primarily due to higher electric and natural gas sales revenue at
MidAmerican Energy Services, LLC, from favorable pricing, including changes in
unrealized positions on natural gas derivative contracts, and higher electric
volumes, partially offset by lower natural gas volumes.
Earnings decreased $2,775 million for the third quarter of 2022 compared to
2021, primarily due to the $2,827 million unfavorable comparative change in the
Company's investment in BYD Company Limited, lower earnings of $16 million at
MidAmerican Energy Services, LLC, mainly due to unfavorable changes in
unrealized positions on derivative contracts, higher BHE corporate interest
expense from an April 2022 debt issuance and higher corporate costs, partially
offset by $77 million of higher federal income tax credits recognized on a
consolidated basis and $18 million of lower dividends on BHE's 4.00% Perpetual
Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.
Operating revenue increased $42 million for the first nine months of 2022
compared to 2021, primarily due to higher natural gas and electric sales revenue
at MidAmerican Energy Services, LLC, from favorable natural gas pricing,
including changes in unrealized positions on derivative contracts, and higher
electric volumes, partially offset by unfavorable electric pricing and lower
natural gas volumes.
Earnings decreased $2,330 million for the first nine months of 2022 compared to
2021, primarily due to the $2,394 million unfavorable comparative change in the
Company's investment in BYD Company Limited, unfavorable changes in the cash
surrender value of corporate-owned life insurance policies and higher BHE
corporate interest expense from an April 2022 debt issuance, partially offset by
$64 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued
to certain subsidiaries of Berkshire Hathaway, lower corporate costs and higher
earnings of $29 million at MidAmerican Energy Services, LLC, mainly due to
favorable changes in unrealized positions on derivative contracts.
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Cash and capital resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity
separate and apart from BHE and its other subsidiaries. It should not be assumed
that the assets of any subsidiary will be available to satisfy BHE's obligations
or the obligations of its other subsidiaries. However, unrestricted cash or
other assets that are available for distribution may, subject to applicable law,
regulatory commitments and the terms of financing and ring-fencing arrangements
for such parties, be advanced, loaned, paid as dividends or otherwise
distributed or contributed to BHE or affiliates thereof. The Company's long-term
debt may include provisions that allow BHE or its subsidiaries to redeem such
debt in whole or in part at any time. These provisions generally include
make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial
Statements in Item 8 of the Company's Annual Report on Form 10-K for the year
ended December 31, 2021 for further discussion regarding the limitation of
distributions from BHE's subsidiaries.
As of September 30, 2022, the Company's total net liquidity was as follows (in
millions):
BHE Pipeline
MidAmerican NV Northern BHE Group and
BHE PacifiCorp Funding Energy Powergrid Canada HomeServices Other Total
Cash and cash equivalents $ 106 $ 219 $ 582 $ 123 $ 164 $ 60 $ 291 $ 232 $ 1,777
Credit facilities(1) 3,500 1,200 1,509 650 237 777 3,400 - 11,273
Less:
Short-term debt (100) - - (320) (14) (261) (746) - (1,441)
Tax-exempt bond support
and letters of credit - (218) (370) (17) - (1) - - (606)
Net credit facilities 3,400 982 1,139 313 223 515 2,654 - 9,226
Total net liquidity $ 3,506 $ 1,201 $ 1,721 $ 436 $ 387 $ 575 $ 2,945 $ 232 $ 11,003
Credit facilities:
Maturity dates 2025 2025 2023, 2025 2025 2024, 2026 2023, 2026 2023, 2026
(1)Includes $14 million drawn on a capital credit facility
Operation of the Northern Electricity Grid.
Operational activities
Net cash flows from operating activities for the nine-month periods ended
September 30, 2022 and 2021 have been $7.9 billion and $7.0 billion, respectively. The increase is mainly due to favorable tax cash flow, improved operating results and changes in working capital.
The timing of the Company’s income tax cash flows from period to period may be significantly affected by the estimated federal tax payment methods chosen and the assumptions made for each payment date.
Investing activities
Net cash flows from investing activities for the nine-month periods ended
September 30, 2022 and 2021 were $(5.5) billion and $(3.5) billion,
respectively. The change was primarily due to higher capital expenditures of
$791 million, higher other investment purchases of $628 million, including $614
million of U.S. Treasury Bills, and the July 2021 receipt of $1.3 billion due to
the termination of the Q-Pipe Purchase Agreement, partially offset by higher net
sales of marketable securities of $607 million. Refer to "Future Uses of Cash"
for a discussion of capital expenditures.
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Fundraising activities
Net cash flows from financing activities for the nine-month period ended
September 30, 2022 was $(1.6) billion. Sources of cash totaled $2.2 billion and
consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and
proceeds from BHE senior debt issuances totaling $1.0 billion. Uses of cash
totaled $3.8 billion and consisted mainly of repayments of subsidiary debt
totaling $882 million, purchases of common stock totaling $870 million,
preferred stock redemptions of $800 million, net repayments of short-term debt
totaling $540 million and distributions to noncontrolling interests of $395
million.
For discussions of recent financing and BHE shareholders' equity transactions,
refer to Notes 4 and 10 of Notes to Consolidated Financial Statements in Part I,
Item 1 of this Form 10-Q.
Net cash flows from financing activities for the nine-month period ended
September 30, 2021 was $(2.0) billion. Sources of cash consisted of proceeds
from subsidiary debt issuances totaling $2.0 billion. Uses of cash totaled $4.0
billion and consisted mainly of preferred stock redemptions of $1.5 billion,
repayments of subsidiary debt totaling $1.3 billion, repayments of BHE senior
debt totaling $450 million, distributions to noncontrolling interests of $366
million and net repayments of short-term debt totaling $316 million.
Future uses of cash
The Company has available a variety of sources of liquidity and capital
resources, both internal and external, including net cash flows from operating
activities, public and private debt offerings, the issuance of commercial paper,
the use of unsecured revolving credit facilities, the issuance of equity and
other sources. These sources are expected to provide funds required for current
operations, capital expenditures, acquisitions, investments, debt retirements
and other capital requirements. The availability and terms under which BHE and
each subsidiary has access to external financing depends on a variety of
factors, including regulatory approvals, its credit ratings, investors' judgment
of risk and conditions in the overall capital markets, including the condition
of the utility industry and project finance markets, among other items.
Capital expenditure
The Company has significant future capital requirements. Capital expenditure
needs are reviewed regularly by management and may change significantly as a
result of these reviews, which may consider, among other factors, impacts to
customer rates; changes in environmental and other rules and regulations;
outcomes of regulatory proceedings; changes in income tax laws; general business
conditions; load projections; system reliability standards; the cost and
efficiency of construction labor, equipment and materials; commodity prices; and
the cost and availability of capital.
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The Company's historical and forecast capital expenditures, each of which
exclude amounts for non-cash equity AFUDC and other non-cash items, are as
follows (in millions):
Nine-Month Periods Annual
Ended September 30, Forecast
2021 2022 2022
Capital expenditures by company:
PacifiCorp $ 1,157 $ 1,481
$2,255
MidAmerican Funding 1,266 1,404
2,039
NV Energy 519 801
1,289
Northern Powergrid 564 614
791
BHE Pipeline Group 684 800 1,223
BHE Transmission 234 143 223
BHE Renewables 129 99 161
HomeServices 29 31 53
BHE and Other(1) 12 12 18
Total $ 4,594 $ 5,385 $ 8,052
Capital expenditures by type:
Wind generation $ 872 $ 583 $ 846
Electric distribution 1,217 1,316 1,814
Electric transmission 539 1,157 1,743
Natural gas transmission and storage 647 640 959
Solar generation 104 333 408
Other 1,215 1,356 2,282
Total $ 4,594 $ 5,385 $ 8,052
(1)BHE and others represent amounts primarily related to other entities, including MidAmerican Energy Services, LLCcorporate functions and intersegment eliminations.
The Company’s historical and planned capital expenditures consisted primarily of the following items:
•Wind generation includes both growth and operating expenses. Growth expenses include expenses for the following:
• Construction of wind power generation facilities in MidAmerican Energy
totaling $39 million and $275 million for the nine-month periods ended
September 30, 2022 and 2021, respectively. Total planned expenditures for the construction of additional wind facilities $74 million for the remainder of 2022.
•Repowering of wind-powered generating facilities at MidAmerican Energy totaling
$422 million and $274 million for the nine-month periods ended September 30,
2022 and 2021, respectively. Planned spending for the repowering of wind-powered
generating facilities totals $98 million for the remainder of 2022. MidAmerican
Energy expects its repowered facilities to meet Internal Revenue Service
guidelines for the re-establishment of PTCs for 10 years from the date the
facilities are placed in-service. As a result of the Inflation Reduction Act of
2022, all of the 310 MWs of current repowering projects not in-service as of
September 30, 2022, are currently expected to qualify for 100% of the PTCs
available for 10 years following each facility's return to service.
•Construction of wind-powered generating facilities at PacifiCorp totaling $5
million and $99 million for the nine-month periods ended September 30, 2022 and
2021, respectively. Construction includes 516 MWs of new wind-powered generating
facilities that were placed in-service in 2021. Planned spending for
constructing additional wind-powered generating facilities totals $22 million
for the remainder of 2022.
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•Planned acquisition and repowering of two wind-powered generating facilities by
PacifiCorp totaling $16 million and $9 million for the nine-month periods ended
September 30, 2022 and 2021, respectively. The repowered facilities are expected
to be placed in-service in 2023 and 2024. Planned spending for acquiring and
repowering generating facilities totals $8 million for the remainder of 2022.
•Repowering of wind power plants in BBB Renewables totaling $45 million for the nine-month period ended September 30, 2022.
•Electric distribution includes both growth and operating expenditures. Growth
expenditures include spending for new customer connections and enhancements to
existing customer connections. Operating expenditures include spending for
ongoing distribution systems infrastructure needed at the Utilities and Northern
Powergrid, wildfire mitigation, storm damage restoration and repairs and
investments in routine expenditures for distribution needed to serve existing
and expected demand.
•Electric transmission includes both growth and operating expenses. Growth expenses include expenses for the following:
•PacifiCorp's transmission investment primarily reflects planned costs for the
416-mile, 500-kV high-voltage transmission line between the Aeolus substation
near Medicine Bow, Wyoming and the Clover substation near Mona, Utah; the
59-mile, 230-kV high-voltage transmission line between the Windstar substation
near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV
high-voltage transmission line from the Longhorn substation near Boardman,
Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these
segments totaled $640 million and $57 million for the nine-month periods ended
September 30, 2022 and 2021, respectively. Planned spending for these Energy
Gateway Transmission segments to be placed in-service in 2024-2026 totals
$299 million for the remainder of 2022.
•Nevada Utilities' Greenlink Nevada transmission expansion program. In this
project, the company has received approval from the PUCN to build a 350-mile,
525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill
substation to the Northwest substation to the Harry Allen substation; a
235-mile, 525-kV transmission line, known as Greenlink North, connecting the new
Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV
transmission line from the new Ft. Churchill substation to the Mira Loma
substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill
substation to the Robinson Summit substations. Expenditures for the expansion
program and other growth projects totaled $91 million and $64 million for the
nine-month periods ended September 30, 2022 and 2021, respectively. Planned
spending for the expansion program estimated to be placed in-service in
2026-2028 and other growth projects totals $53 million for the remainder of
2022.
•Operating expenditures include spending for system reinforcement, upgrades and
replacements of facilities to maintain system reliability and investments in
routine expenditures for transmission needed to serve existing and expected
demand.
•Natural gas transmission and storage includes both growth and operating
expenditures. Growth expenditures include, among other items, spending for asset
modernization and the Northern Natural Gas Twin Cities Area Expansion and
Spraberry Compression projects. Operating expenditures include, among other
items, spending for pipeline integrity projects, automation and controls
upgrades, underground storage, corrosion control, unit exchanges, compressor
modifications, projects related to Pipeline and Hazardous Materials Safety
Administration natural gas storage rules and natural gas transmission, storage
and liquefied natural gas terminalling infrastructure needs to serve existing
and expected demand.
• Solar production includes growth expenses, including expenses for the following:
•Construction of solar-powered generating facilities at MidAmerican Energy
totaling 141 MWs of small- and utility-scale solar generation, all of which were
placed in-service as of September 30, 2022, with total spend of $103 million and
$97 million for the nine-month periods ended September 30, 2022 and 2021,
respectively, and planned spending of $33 million for the remainder of 2022.
•Construction of a solar-powered generating facility at Nevada Power totaling
$47 million and $7 million for the nine-month periods ended September 30, 2022
and 2021, respectively and planned spending of $42 million for the remainder of
2022. Construction includes expenditures for a 150-MW solar photovoltaic
facility with an additional 100 MWs of co-located battery storage that will be
developed in Clark County, Nevada. Commercial operation is expected by the end
of 2023.
• BHE Renewables has made installments on 785 MW of solar modules totaling $22 million for the nine-month period ended September 30, 2022.
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• Other capital expenditures include both growth and operating expenditures, including routine expenditures for generation and other infrastructure needed to meet existing and forecasted demand, natural gas distribution, technology and environmental expenditures related to emission control equipment and the management of coal combustion residues.
Material cash needs
As of September 30, 2022, there have been no material changes in cash
requirements from the information provided in Item 7 of the Company's Annual
Report on Form 10-K for the year ended December 31, 2021, other than those
disclosed in Notes 4 and 8 of the Notes to Consolidated Financial Statements in
Part I, Item 1 of this Form 10-Q.
Quad Cities Power Plant Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation
Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1,
2022), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad
Cities Station") of which MidAmerican Energy has a 25% ownership interest,
announced on June 2, 2016, its intention to shut down Quad Cities Station on
June 1, 2018. In December 2016, Illinois passed legislation creating a zero
emission standard, which went into effect June 1, 2017. The zero emission
standard requires the Illinois Power Agency to purchase ZECs and recover the
costs from certain ratepayers in Illinois, subject to certain limitations. The
proceeds from the ZECs will provide Constellation Energy additional revenue
through 2027 as an incentive for continued operation of Quad Cities Station.
MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer
Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer
price in the market is adjusted to effectively remove the revenues it receives
through a state government-provided financial support program, resulting in a
higher offer that may not clear the capacity market. Prior to December 19, 2019,
the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM
MOPR to include existing resources would require exclusion of ZEC compensation
when bidding into future capacity auctions, resulting in an increased risk of
Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly
apply the MOPR to all new and existing resources, including nuclear. This
greatly expanded the breadth and scope of the PJM's MOPR, which became effective
as of the PJM's capacity auction for the 2022-2023 planning year in May 2021.
While the FERC included some limited exemptions, no exemptions were available to
state-supported nuclear resources, such as Quad Cities Station. The FERC
provided no new mechanism for accommodating state-supported resources other than
the existing Fixed Resource Requirement ("FRR") mechanism under which an entire
utility zone would be removed from PJM's capacity auction along with sufficient
resources to support the load in such zone. In response to the FERC's order, the
PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed
tariff language reflecting the FERC's directives and a schedule for resuming
capacity auctions. On April 16, 2020, the FERC issued an order largely denying
requests for rehearing of the FERC's December 2019 order but granting a few
clarifications that required an additional PJM compliance filing, which the PJM
submitted on June 1, 2020. A number of parties, including Constellation Energy,
have filed petitions for review of the FERC's orders in this proceeding, which
remain pending before the D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for
the 2022-2023 planning year, which prevented Quad Cities Station from clearing
in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders
developed further MOPR reforms to ensure that the capacity market rules respect
and accommodate state resource preferences such as the ZEC programs. The PJM
filed related tariff revisions at the FERC on July 30, 2021, and, on September
29, 2021, the PJM's proposed MOPR reforms became effective by operation of law.
Under the new tariff provisions, the MOPR will no longer apply to Quad Cities
Station. Requests for rehearing of the FERC's notice establishing the effective
date for the PJM's proposed market reforms were filed in October 2021 and denied
by operation of law on November 4, 2021. Several parties have filed petitions
for review of the FERC's orders in this proceeding, which remain pending before
the Court of Appeals for the Third Circuit. Constellation Energy is strenuously
opposing these appeals.
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Assuming the continued effectiveness of the Illinois zero emission standard,
Constellation Energy no longer considers Quad Cities Station to be at heightened
risk for early retirement. However, to the extent the Illinois zero emission
standard does not operate as expected over its full term, Quad Cities Station
would be at heightened risk for early retirement. The FERC's December 19, 2019
order on the PJM MOPR may undermine the continued effectiveness of the Illinois
zero emission standard unless the PJM adopts further changes to the MOPR or
Illinois implements an FRR mechanism, under which Quad Cities Station would be
removed from the PJM's capacity auction.
Regulatory issues
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive
regulation. The discussion below contains material developments to those matters
disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year
ended December 31, 2021 and new regulatory matters occurring in 2022.
PacifiCorp
Oregon
In March 2022, PacifiCorp filed a general rate case requesting an overall rate
change of $82 million, or 6.6%, to become effective January 1, 2023, that
includes cost increases associated with the implementation of PacifiCorp's
wildfire mitigation and vegetation management plans. Parties to the case filed
testimony in June 2022. PacifiCorp filed reply testimony in July 2022 supporting
an overall rate increase of $94 million but proposing that the request be capped
at PacifiCorp's original request. PacifiCorp and parties to the case settled
various aspects of the general rate case in multiple settlement stipulations. In
August 2022, the first partial stipulation was filed resolving issues related to
wildfire mitigation and vegetation management, including addressing the
associated costs increases. Also in August 2022, a second partial stipulation
was filed representing the settlement of certain revenue requirement issues
among the stipulating parties, including the extension of Oregon's recovery
period for Jim Bridger Units 1 and 2 that will be converted to natural
gas-fueled units and certain other issues. In September 2022, a third
stipulation was filed resolving most of the remaining issues in the general rate
case following the first and second partial stipulations. The stipulations
together result in a total rate increase of $49 million, or 3.9%, effective
January 1, 2023. The stipulating parties also agreed to amortize certain
deferrals totaling approximately $10 million, or 0.8 %, in the first year of
amortization, effective April 1, 2023. Further, in the third stipulation,
PacifiCorp agreed to a general rate case stay-out provision under which it
agreed not to file a general rate case with rates effective any earlier than
January 1, 2025. In September 2022, the fourth and final partial stipulation was
filed resolving technical issues related to a voluntary renewable energy tariff
that will allow non-residential customers to purchase energy from renewable
resources not currently in PacifiCorp's rates. A commission decision on the
stipulations is pending.
In May 2022, PacifiCorp filed its 2021 power cost adjustment mechanism ("PCAM"),
which is the first time since the mechanism has been in place that a rate change
has been warranted. After consideration of the mechanism's deadband, sharing
band and earnings test, PacifiCorp requested recovery of $52 million, or a 4.2%
increase, to become effective January 1, 2023. This request is incremental to
the rate change sought in the general rate case. In September 2022, a settlement
stipulation was filed agreeing to the recovery of the requested $52 million over
a four-year period beginning April 1, 2023. A commission decision on the
stipulation is pending.
In July 2022, PacifiCorp filed an application requesting approval of an
automatic adjustment clause with a balancing account to recover costs associated
with implementing PacifiCorp's wildfire protection plan in Oregon. Oregon Senate
Bill 762 provides for utilities to timely recover these costs through an
automatic adjustment clause. The filing requests a rate increase of $20 million,
or 1.6%, to recover incremental costs in 2022 and is incremental to costs
addressed in PacifiCorp's wildfire mitigation and vegetation management
mechanism through the general rate case stipulation described above. While
PacifiCorp requested an effective date of August 24, 2022, the OPUC has
suspended the filing for further review. A decision is expected in 2023.
Washington
In June 2021, PacifiCorp filed a power cost only rate case to update baseline
net power costs for 2022. PacifiCorp requested a $13 million, or 3.7%, rate
increase with an effective date of January 1, 2022. In November 2021, PacifiCorp
reached a proposed settlement with most of the parties, which includes an
agreement to adjust the PTC rate in base rates and apply a production factor and
include a net power cost update as part of the compliance filing. A hearing was
held in January 2022 and the WUTC issued an order approving the settlement in
March 2022. A compliance filing reflecting a $43 million, or 12.2%, increase was
filed in April 2022 with rates effective May 1, 2022.
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In June 2022, PacifiCorp filed its 2021 PCAM and the new tracking mechanism for
PTCs approved in the 2021 general rate case. For the 2021 PCAM, PacifiCorp is
requesting a recovery of $26 million, or a 6.5% increase. PacifiCorp proposed
that the 2021 PCAM be amortized over two years, rather than the one-year period
required under the current terms of the PCAM. For the new 2021 PTC tracker,
PacifiCorp is seeking recovery of $3 million, or an 0.8% increase. Should the
WUTC approve the proposal to extend the amortization period of the 2021 PCAM
from one to two years, the combined annual increase would be $16 million, or
4.0%, effective January 1, 2023.
California
In May 2022, PacifiCorp filed a general rate case requesting an overall rate
change of $28 million, or 25.7%, to become effective January 1, 2023. In June
2022, a proposed procedural schedule was developed that would result in a
decision in August 2023.
In August 2022, PacifiCorp filed an Energy Cost Adjustment Clause ("ECAC")
application requesting an overall rate increase of $15 million, or 13.6%,
effective January 1, 2023. Approximately $4 million of the increase, or 3.6%, is
attributed to the ECAC rate and $11 million of the increase, or 10.0%, to the
Greenhouse Gas rate.
MidAmerican Energy
South Dakota
In May 2022, MidAmerican Energy filed an application with the South Dakota Public Utilities Commission (“SDPUC”) for an increase in sound South Dakota retail natural gas prices, which would increase revenues for $7 million annually. If approved, the requested tariffs would increase retail customer bills by an average of 6.4%.
PRIME Wind
In January 2022, MidAmerican Energy filed an application with the IUB for
advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy
expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new
wind generation and up to 50 MWs of solar generation. If all of Wind PRIME
generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind
generation and nearly 200 MWs of solar generation. Wind PRIME is projected to
allow MidAmerican Energy to generate renewable energy greater than or equal to
all of its Iowa retail customers' annual energy needs. MidAmerican Energy
secured sufficient safe harbor equipment necessary to remain eligible for 100%
PTCs under current tax law. Procedural hearings with the IUB are expected to
begin in February 2023.
NV Energy (Nevada Power and Sierra Pacific)
Senate Bill 448 (“SB 448”)
SB 448 was signed into law on June 10, 2021. The legislation is intended to
accelerate transmission development, renewable energy and storage, and
accelerate transportation electrification within the state of Nevada. In
September 2021, the Nevada Utilities filed an amendment to the 2021 Joint IRP
for the approval of their Transmission Infrastructure for a Clean Energy Economy
Plan that sets forth a plan for the construction of high-voltage transmission
infrastructure, Greenlink North among others, that will be placed into service
no later than December 31, 2028, and requires the IRP to include at least one
scenario that uses sources of supply that will achieve certain reductions in
carbon dioxide emissions. In September 2021, the Nevada Utilities filed an
application for the approval of their Economic Recovery Transportation
Electrification Plan to accelerate transportation electrification in the state
of Nevada. The plan establishes requirements for the contents of the
transportation electrification investment as well as requirements for review,
cost recovery and monitoring. The plan covers an initial period beginning
January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN
issued an order granting the application and accepting the Economic Recovery
Transportation Electrification Plan with some modifications. The PUCN opened
rulemakings to address other regulations that resulted from SB 448. In February
2022, the PUCN adopted regulations regarding the Economic Development Electric
Rate Rider Program to revise the discounted electric rates to ease the economic
burden on small businesses who take advantage of the discounted rates under the
tariff. In September 2022, the PUCN adopted regulations regarding resource
planning, which incorporates a plan to accelerate transportation electrification
into the distributed resources plan pursuant to SB 448.
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ON Line Temporary Rider (“ONTR”)
In October 2021, Sierra Pacific filed an application with the PUCN for approval
of the ONTR with corresponding updates to its electric rate tariffs to authorize
recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being
accumulated as a result of the ON Line cost reallocation as well as the related
on-going reallocated revenue requirement. Sierra Pacific's application would
have, if approved by the PUCN as filed, resulted in a one-time rate increase of
$28 million to be collected over a nine-month period starting on April 1, 2022.
In March 2022, the PUCN issued an order directing Sierra Pacific to recover $14
million of the ON Line regulatory asset as a one-time rate increase collectable
over a nine-month period effective April 1, 2022, with the expected remaining
balance at December 31, 2022 to be included in rate base in the 2022 regulatory
rate review for inclusion in the rates set in that case.
Merge request
In March 2022, the Nevada Utilities filed a joint application with the PUCN for
authorization to merge Sierra Pacific with and into Nevada Power, with Nevada
Power being the surviving entity. If approved by the PUCN as filed, Nevada Power
will have two distinct electric service territories in northern and southern
Nevada each with their own rates and one natural gas service territory in the
Reno and Sparks area. In October 2022, the proceedings relating to the joint
application were postponed to November 2022. An order is expected in the first
half of 2023.
Regulatory Rate Review
In June 2022, Sierra Pacific filed a regulatory rate review with the PUCN that
requested an annual revenue increase of $88 million, or 9.7%. In addition, a
filing was made to revise depreciation rates based on a study, the results of
which are reflected in the proposed revenue requirement. In August 2022, Sierra
Pacific filed an updated certification filing that requested an annual revenue
increase of $77 million, or 8.5%. Parties to the review filed testimony and
evidence in August and September 2022. Hearings in the cost of capital and
revenue requirement phases were held in September and October 2022,
respectively. The hearings in the rate design phase are scheduled for November
2022. An order is expected by the end of 2022 and, if approved, would be
effective January 1, 2023.
Transportation Electrification Plan (“TEP”)
In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP
for the approval of a Distributed Resource Plan amendment to implement the
state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs
and schedules to implement the TEP. The 2022 TEP outlines programs, investments
and incentives to accelerate transportation electrification across Nevada. The
Nevada Utilities anticipate a budget of $348 million, which represents the
maximum cost over the depreciable life of the TEP's programs and assets, to
deploy the TEP in 2023 through 2024.
Northern Power Grid Distribution Companies
GEMA, through Ofgem, is undertaking its scheduled review of the electricity
distribution price control to put in place a new price control at the end of the
current period that ends March 2023. The new price control ("ED2") will run for
five years from April 2023 to March 2028. In December 2020 and March 2021, GEMA
published its decision on the methodology it will use to set ED2. This confirmed
that Ofgem will maintain many aspects of the current price control and that the
changes being made will generally follow the template that was set by the price
controls implemented in April 2021 for transmission and gas distribution in
Great Britain. Specific changes include new service standard incentives and
mechanisms to adjust cost allowances in specific circumstances, while others
will be discontinued, and partially updating the allowed return on equity within
the period for changes in the interest rate on government bonds.
In December 2021, Northern Powergrid published and filed its business plan with
Ofgem, setting out its detailed approach for 2023-2028 including the cost
allowances this approach would require. In June 2022, Ofgem published its draft
determinations, which included an allowed cost of equity of 4.75% plus inflation
(calculated using the United Kingdom's consumer price index including owner
occupiers' housing costs). When placed on a comparable footing, by adjusting for
differences in the assumed equity ratio and the measure of inflation used, this
working assumption is approximately two percentage points lower than the current
cost of equity for electricity distribution. Ofgem's proposals also set out cost
allowances and associated expectations. In August 2022, Northern Powergrid
formally responded to Ofgem's consultation on its draft determinations to lobby
for a better settlement. Final values from Ofgem are expected in November 2022.
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BHE Pipeline Group
BHE CG&S
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional
services, with proposed rates to be effective November 1, 2021. EGTS' previous
general rate case was settled in 1998. EGTS proposed an annual cost-of-service
of approximately $1.1 billion, and requested increases in various rates,
including general system storage rates by 85% and general system transportation
rates by 60%. In October 2021, the FERC issued an order that accepted the
November 1, 2021 effective date for certain changes in rates, while suspending
the other changes for five months following the proposed effective date, until
April 1, 2022, subject to refund. In September 2022, a settlement agreement was
filed with the FERC, resolving EGTS' general rate case for its
FERC-jurisdictional services and providing for increased service rates and
decreased depreciation rates. Under the terms of the settlement agreement, EGTS'
rates result in an increase to annual firm transportation and storage revenues
of approximately $160 million and a decrease in annual depreciation expense of
approximately $30 million, compared to the rates in effect prior to April 1,
2022. As of September 30, 2022, EGTS' provision for rate refund for April 2022
through September 2022 totaled $56 million and was included in other current
liabilities on the Consolidated Balance Sheet. FERC approval of the settlement
is expected late 2022 or early 2023.
Northern Natural Gas
In July 2022, Northern Natural Gas filed a general rate case that proposed an
overall annual cost-of-service of $1.3 billion. This is an increase of $323
million above the cost of service filed in its 2019 rate case of $1.0 billion.
Depreciation on increased rate base and an increase in depreciation and negative
salvage rates account for $115 million of the $323 million increase in the filed
cost of service. Northern Natural Gas has requested increases in various rates,
including transportation reservation rates ranging from approximately 45% in the
Field Area to 120% in the Market Area to be implemented, subject to refund, on
August 1, 2022. In July 2022, the FERC issued an order that suspended the rates
proposed for five months following the proposed effective date, until January 1,
2023, subject to refund and the outcome of hearing procedures.
BHE transmission
AltaLink
Request for general rate 2022-2023
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years
of its commitment to keep rates flat for customers at or below the 2018 level of
C$904 million for the five-year period from 2019 to 2023. The two-year
application achieves flat tariffs by continuing to transition to the
AUC-approved salvage recovery method and continuing the use of the flow-through
income tax method, with an overall year-over-year increase of approximately 2%
in 2022 and 2023 revenue requirements. The application requested the approval of
transmission tariffs of C$824 million and C$847 million for 2022 and 2023,
respectively after proposed refunds. In September 2021, AltaLink provided
responses to information requests from the AUC and filed an amended application
to reflect certain adjustments and forecast updates.
In January 2022, the AUC issued its decision with respect to AltaLink's
2022-2023 GTA. AltaLink's 2022-2023 GTA reflected its continued commitment to
provide rate stability to customers by maintaining flat tariffs and providing
additional tariff relief measures, including a proposed tariff refund of C$60
million of accumulated depreciation in each of 2022 and 2023. The AUC did not
approve AltaLink's proposed refund due to an anticipated improvement in general
economic conditions in Alberta. In March 2022, AltaLink filed a review and
variance application requesting the AUC to review and vary its decision to deny
AltaLink's proposed C$120 million refund of accumulated depreciation surplus,
given material changes in circumstances since the decision was issued in January
2022. In May 2022, the AUC issued a decision with respect to AltaLink's
application to review and vary its proposed $120 million refund of accumulated
depreciation surplus. The AUC found that a material decline in Alberta's
economic circumstances is not sufficient evidence to warrant the refund.
In July 2022, AltaLink submitted its second compliance filing application with
total 2022 and 2023 revenue requirements at C$879 million and C$883 million,
respectively. In August 2022, the AUC approved the revised revenue requirements
as filed, allowing AltaLink to fully deliver on its flat-for-five commitment to
customers.
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2023 Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the 2023 generic cost of capital proceeding.
The proceeding will be conducted in two stages. The first stage will determine
the cost of capital parameters for 2023 and the second stage will consider
returning to a formula-based approach to establish cost of capital adjustments,
commencing in 2024. In March 2022, the AUC issued its decision with respect to
the first stage of the 2023 GCOC proceeding by approving the extension of the
2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023,
recognizing lingering uncertainty and continued volatility of financial markets
due to the COVID-19 pandemic. In June 2022, the AUC initiated the second stage
to explore a formula-based approach to determine the return on equity for 2024
and future test periods.
Environmental laws and regulations
Each Registrant is subject to federal, state, local and foreign laws and
regulations regarding climate change, RPS, air and water quality, emissions
performance standards, coal combustion byproduct disposal, hazardous and solid
waste disposal, protected species and other environmental matters that have the
potential to impact each Registrant's current and future operations. In addition
to imposing continuing compliance obligations, these laws and regulations
provide regulators with the authority to levy substantial penalties for
noncompliance, including fines, injunctive relief and other sanctions. These
laws and regulations are administered by various federal, state, local and
international agencies. Each Registrant believes it is in material compliance
with all applicable laws and regulations, although many are subject to
interpretation that may ultimately be resolved by the courts. The discussion
below contains material developments to those matters disclosed in Item 1 of
each Registrant's Annual Report on Form 10-K for the year ended December 31,
2021, and new environmental matters occurring in 2022.
Climate change
Affordable Clean Energy Rule
In June 2014, the EPA released proposed regulations to address greenhouse gas
emissions from existing fossil-fueled generating facilities, referred to as the
Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal
calculated state-specific emission rate targets to be achieved based on the
"best system of emission reduction." In August 2015, the final Clean Power Plan
was released, which established the best system of emission reduction as
including: (a) heat rate improvements; (b) increased utilization of existing
combined-cycle natural gas-fueled generating facilities; and (c) increased
deployment of new and incremental non-carbon generation placed in-service after
2012. The Clean Power Plan was stayed by the United States Supreme Court in
February 2016 while litigation proceeded. On June 19, 2019, the EPA repealed the
Clean Power Plan and issued the Affordable Clean Energy rule. In the Affordable
Clean Energy rule, the EPA determined that the best system of emission reduction
for existing coal-fueled generating facilities is limited to actions that can be
taken at a point source facility, specifically heat rate improvements, and
identified a set of candidate technologies and measures that could improve heat
rates. Measures taken to meet the standards of performance must be achieved at
the source itself. The Affordable Clean Energy rule was challenged by
environmental and health groups in the D.C. Circuit. On January 19, 2021, the
D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA,
finding that the rule "rested critically on a mistaken reading of the Clean Air
Act" that limited the best system of emission reduction to actions taken at a
facility. In October 2021, the United States Supreme Court agreed to hear an
appeal of that decision. Arguments in the case were held February 28, 2022, and
on June 30, 2022, the United States Supreme Court issued its decision regarding
the scope of the EPA's authority to regulate greenhouse gas emissions under the
Clean Air Act. The United States Supreme Court held that the "generation
shifting" approach in the Clean Power Plan exceeded the powers granted to the
EPA by Congress, although the court did not address whether the EPA may only
adopt measures applied at the individual source as it did in the Affordable
Clean Energy rule. A key area where the EPA went astray was using the Clean
Power Plan to give states the option to promulgate regulations that would
encourage "generation shifting," or moving away from higher-polluting power
sources like coal to lower-polluting sources like natural gas or renewables. The
United States Supreme Court found that type of regulation, which would impact
larger economic forces beyond the fence lines of individual generating
facilities, is not permitted under Section 111(d) of the Clean Air Act. The
United States Supreme Court reversed the D.C. Circuit's vacatur of the
Affordable Clean Energy rule and remanded the case for further proceedings. The
ruling has no immediate impact on the Registrants, as there is no Section 111(d)
rule currently in effect. The Biden administration plans to propose by March
2023 its own rule to replace the Clean Power Plan and Affordable Clean Energy
rule.
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Clean Air Act Regulations
The Clean Air Act is a federal law administered by the EPA that provides a
framework for protecting and improving the nation's air quality and controlling
sources of air emissions. The implementation of new standards is generally
outlined in SIPs, which are a collection of regulations, programs and policies
to be followed. SIPs vary by state and are subject to public hearings and EPA
approval. Some states may adopt additional or more stringent requirements than
those implemented by the EPA. The major Clean Air Act programs most directly
affecting the Registrants' operations are described below.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six
principal pollutants, consisting of carbon monoxide, lead, NOx, particulate
matter, ozone and SO2, considered harmful to public health and the environment.
Areas that achieve the standards, as determined by ambient air quality
monitoring, are characterized as being in attainment, while those that fail to
meet the standards are designated as being nonattainment areas. Generally,
sources of emissions in a nonattainment area that are determined to contribute
to the nonattainment are required to reduce emissions. Currently, with the
exceptions described in the following paragraphs, air quality monitoring data
indicates that all counties where the relevant Registrant's major emission
sources are located are in attainment of the current NAAQS.
On June 4, 2018, the EPA published final ozone designations for much of the U.S.
Relevant to the Registrants, these designations include classifying Yuma County,
Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch
Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with
the 2015 ozone standard. These areas were required to meet the 2015 standard
three years from the August 3, 2018, effective date. All other areas relevant to
the Registrants were designated attainment/unclassifiable with this same action.
However, on January 29, 2021, the D.C. Circuit vacated several provisions of the
2018 implementing rules for the 2015 ozone standards for contravening the Clean
Air Act. The EPA and environmental groups finalized a consent decree in January
2022 that sets deadlines for the agency to approve or disapprove the "good
neighbor" provisions of interstate ozone plans of dozens of states. Relevant to
the Registrants, the EPA must, by April 30, 2022, propose to approve or
disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan,
Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On
February 22, 2022, the EPA published a series of proposed decisions to
disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the
Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New
York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's
SIP after re-analyzing the state's data. The EPA must finalize the proposed
rules by December 15, 2022. In addition, the EPA must, by December 15, 2022,
approve or disapprove the interstate plans of Arizona, California, Nevada and
Wyoming. On April 15, 2022, the EPA issued its final rule approving Iowa's SIP
as meeting the good neighbor provisions for the 2015 ozone standard. On May 24,
2022, the EPA disapproved the Utah and Wyoming interstate ozone SIPs. Until the
EPA takes final action consistent with this decree, additional impacts to the
relevant Registrants cannot be determined.
Separately, on March 28, 2022, the EPA proposed determinations as to whether
certain areas have achieved levels of ground-level ozone pollution that meet the
2008 and 2015 ozone NAAQS. Relevant to the Registrants, the Southern Wasatch
Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone
standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch
Front in Utah are proposed to have not met the 2015 ozone, will be reclassified
as Moderate Non-Attainment, and will have until August 3, 2024 to meet the
standard. Until the EPA takes final action on the proposal and the affected
states submit any required SIPs, the relevant Registrants cannot determine the
impacts of the proposed rule.
Interstate Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and
SO2, precursors of ozone and particulate matter, from down-wind sources in the
eastern U.S., including Iowa, to reduce emissions by implementing a plan based
on a market-based cap-and-trade system, emissions reductions, or both. After
numerous appeals, the CSAPR was promulgated to address interstate transport of
SO2 and NOx emissions in 27 eastern and Midwestern states.
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The first phase of the rule was implemented January 1, 2015. In November 2015,
the EPA released a proposed rule that would further reduce NOx emissions in
2017. The final "CSAPR Update Rule" was published in the Federal Register in
October 2016 and required additional reductions in NOx emissions beginning in
May 2017. On December 6, 2018, the EPA finalized a rule to close out the CSAPR,
having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully
addressed Clean Air Act interstate transport obligations of 20 eastern states.
The EPA determined that 2023 is an appropriate future analytic year to evaluate
remaining good neighbor obligations and that there will be no remaining
nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in
the eastern U.S. in that year. Accordingly, the 20 CSAPR Update-affected states
would not contribute significantly to nonattainment in, or interfere with
maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the
CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit.
The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind
states to continue to significantly contribute to downwind air quality problems
beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy
that did not fully address interstate ozone transport, and remanded the CSAPR
Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019,
finding that because the CSAPR Close-Out Rule relied on the same faulty
reasoning as the CSAPR Update Rule, the CSAPR Close-Out Rule must be vacated. On
October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from
generating facilities in 12 states in the CSAPR trading program in response to
the D.C. Circuit's decision to vacate the CSAPR Update Rule. The rule is
intended to fully resolve 21 upwind states' remaining good neighbor obligations
under the 2008 ozone NAAQS. Additional emissions reductions are required at
generating facilities in 12 states, including Illinois; the EPA predicts that
emissions from the remaining nine states, including Iowa and Texas, will not
significantly contribute to downwind states' ability to attain or maintain the
ozone standard. The EPA accepted comment on the proposal through December 15,
2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update Rule largely
as proposed. Significant new compliance obligations are not anticipated as a
result of the rule. In June 2021, a new lawsuit was filed that challenges the
Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court.
Until litigation is exhausted, the relevant Registrants cannot determine whether
additional action may be required.
In March 2022, the EPA released its Good Neighbor Rule, which contains proposed
revisions to the CSAPR framework and is intended to address ozone transport for
the 2015 ozone NAAQS. The rule focuses on reductions of NOx, precursors to ozone
formation and covers 26 states. Relevant to the Registrants, four states are
included in the cross-state program for the first time - California, Nevada,
Utah and Wyoming. Iowa is not included in the proposal. In a separate but
related action in February 2022, the EPA proposed to approve the good neighbor
provisions of Iowa's SIP addressing ozone transport and the 2015 ozone standard.
The EPA proposes to retain emissions allowance trading for generating
facilities. Beginning in 2023, emissions budgets would be set at the level of
reductions achievable through immediately available measures such as
consistently operating existing emissions controls. Starting in 2026, emissions
budgets would be set at levels achievable by the installation of SCR controls at
certain generating facilities. The proposal also includes additional industries
beyond the power sector for the first time, with a focus on the top NOx emitting
stationary source categories. These include natural gas pipeline compressor
stations, pulp and paper mills, cement production, iron and steel boilers and
furnaces, glass furnaces, chemical manufacturing and petroleum and coal product
manufacturing. These sources will not have access to trading and will instead be
subject to rate-based limits that are assigned for each source category. The EPA
accepted comments on the proposal through June 21, 2022. Until the EPA takes
final action consistent with this decree, impacts to the relevant Registrants
cannot be determined.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and
implement plans to improve visibility in designated federally protected areas
("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in
Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra
Pacific's fossil-fueled generating facilities are subject to the Clean Air
Visibility Rules. In accordance with the federal requirements, states are
required to submit SIPs that address emissions from sources subject to BART
requirements and demonstrate progress towards achieving natural visibility
requirements in Class I areas by 2064.
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The state of Utah issued a regional haze SIP requiring the installation of SO2,
NOx and particulate matter controls on Hunter Units 1 and 2 and Huntington
Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah
regional haze SIP and disapproved the NOx and particulate matter portions.
Subsequently, the Utah Division of Air Quality completed an alternative BART
analysis for Hunter Units 1 and 2 and Huntington Units 1 and 2. In January 2016,
the EPA published two alternative proposals to either approve the Utah SIP as
written or reject the Utah SIP relating to NOx controls and require the
installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and
2 within five years. The EPA's final action on the Utah regional haze SIP was
effective August 4, 2016. The EPA approved in part and disapproved in part the
Utah regional haze SIP and issued a FIP requiring the installation of SCR
equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years
of the effective date of the rule. PacifiCorp and other parties filed requests
with the EPA to reconsider and stay that decision, as well as filed motions for
stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth
Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA
issued a letter indicating it would reconsider its FIP decision. In light of the
EPA's grant of reconsideration and the EPA's position in the litigation, the
Tenth Circuit held the litigation in abeyance and imposed a stay of the
compliance obligations of the FIP for the number of days the stay is in effect
while the EPA conducts its reconsideration process. To support the
reconsideration, PacifiCorp undertook additional air quality modeling using the
Comprehensive Air Quality Model with Extensions dispersion model. On January 14,
2019, the state of Utah submitted a SIP revision to the EPA, which includes the
updated modeling information and additional analysis. On June 24, 2019, the Utah
Air Quality Board unanimously voted to approve the Utah regional haze
SIP revision, which incorporates a BART alternative into Utah's regional haze
SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon generating
facility enforceable under the SIP and removes the requirement to install SCR
equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah
Division of Air Quality submitted the SIP revision to the EPA for approval at
the end of 2019. In January 2020, the EPA published its proposed approval of the
Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon
generating facility federally enforceable and adopts as BART the existing NOx
controls and emission limits on the Hunter and Huntington generating facilities.
The proposed approval withdraws the FIP requirements to install SCR equipment on
Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final
rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With
the approval, the EPA also finalized its withdrawal of the FIP requirements for
the Hunter and Huntington generating facilities. The Utah Regional Haze SIP
Alternative took effect December 28, 2020. As a result of these actions, the
Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On
January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra
Club and Utah Physicians for a Healthy Environment filed a petition for review
of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and
the state of Utah moved to intervene in the litigation. After review of the rule
by the Biden administration, the EPA determined it would defend the rule, and
briefing has been completed. A date for oral arguments has not been scheduled.
The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for
the regional haze second planning period on June 6, 2022. The SIP sets
mass-based NOx emissions limits and rate-based SO2 limits for PacifiCorp's
Hunter and Huntington generating facilities to ensure reasonable visibility
progress for the second planning period.
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The state of Wyoming issued two regional haze SIPs requiring the installation of
SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled
generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012
and the EPA's approval was upheld on appeal by the Tenth Circuit in
October 2014. In addition, the EPA initially proposed in June 2012 to disapprove
portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA
withdrew its initial proposed actions on the NOx and particulate matter SIP and
the proposed FIP, published a re-proposed rule in June 2013, and finalized its
determination in January 2014, which aligns more closely with the SIP proposed
by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the
state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and
2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger
Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston
Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for
Dave Johnston Unit 3, where it required the installation of SCR controls by 2019
or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston
Unit 3 by 2027, its currently approved depreciable life. The EPA also
disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak
coal-fueled generating facility, requiring the installation of SCR controls
within five years (i.e., by 2019). The EPA action became final on March 3, 2014.
PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014.
The state of Wyoming also filed an appeal of the EPA's final action, as did the
Powder River Basin Resource Council, National Parks Conservation Association and
Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March
2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit
in the appeal. The EPA, U.S. Department of Justice, state of Wyoming and
PacifiCorp executed a settlement agreement December 16, 2020, removing the
requirement to install SCR in lieu of monthly and annual NOx emissions limits.
The settlement agreement was subject to a comment period which ended July 6,
2021. The EPA did not give final approval to the settlement agreement and
parties were unable to reach an agreement through mediation. The abatement on
litigation was lifted September 28, 2022, and opening briefs are due October 28,
2022. PacifiCorp objects to the EPA's FIP requiring SCR on the Wyodak Unit. That
requirement in the agency's plan remains stayed by the court. PacifiCorp has
also intervened on behalf of the EPA against claims that Units 1 and 2 at the
Naughton generating facility should have been subject to a SCR requirement. On
February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit
application and reasonable progress determination for Jim Bridger Units 1 and 2,
seeking a rescission of the December 2017 permit requiring the installation of
SCR, to be replaced with a permit imposing plant-wide emission limits to achieve
better modeled visibility, fewer overall environmental impacts and lower costs
of compliance. In May 2020, the Wyoming Air Quality Division issued a permit
approving PacifiCorp's monthly and annual NOx and SO2 emission limits on the
four Jim Bridger units and submitted a regional haze SIP revision to the EPA.
The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable
progress reassessment application and incorporates PacifiCorp's proposed
emission limits in lieu of the requirement to install SCR systems on Jim Bridger
Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency
suspension order under Section 110(g) of the Clean Air Act, allowing the
operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA
and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA
proposed to reject the SIP revisions. The EPA took comment on the proposal
through February 17, 2022. On February 14, 2022, the First Judicial District
Court for the State of Wyoming entered a consent decree reached between the
state of Wyoming and PacifiCorp under Sections 201 and 209(a) of the Wyoming
Environmental Quality Act, resolving claims of threatened violations of the
Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality
Standards and Regulations at the Jim Bridger facility. No penalties were imposed
under the consent decree. Consistent with the terms and conditions of the
consent decree and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must
convert both units to natural gas and begin meeting emissions limits consistent
with that conversion by January 1, 2024. In addition, PacifiCorp must propose an
RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and
4. Wyoming issued its proposed implementation plan for second planning period
reasonable progress on February 18, 2022 and accepted comments through March 23,
2022. The EPA and PacifiCorp executed an administrative order on consent June 9,
2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze
rule. The federal order contains the same emission and operating limits as the
Wyoming consent decree and adds federal approval of the compliance pathway
outlined in the state consent decree, including revision of the SIP to include
conversion of Jim Bridger Units 1 and 2 to natural gas. The order includes a
one-year deadline to complete the SIP revision. The proposed SIP revision
reflecting these agreements is currently being evaluated under parallel
processes by the state of Wyoming and the EPA. The Wyoming Department of
Environmental Quality submitted the Jim Bridger Units 1 and 2 proposed SIP
revision to federal land managers for a 60-day consultation on June 7, 2022.
Wyoming held a public hearing for the Bridger gas conversion SIP revision on
September 14, 2022, and accepted public comments on the plan through September
20, 2022. For the second round of regional haze planning, Wyoming determined
that no controls will be necessary on any Wyoming resources to make reasonable
progress.
In February 2022, NV Energy received 30-day notice letters from the Nevada
Division of Environmental Protection regarding the reopening and revision of the
Valmy and Tracy Generating Station's Title V air quality operating permits to
add federally enforceable retirement dates of December 31, 2028 for Valmy Units
1 and 2 and December 31, 2031 for Tracy Unit 4. The enforceable retirement dates
will implement Nevada's SIP for the regional haze second planning period. The
revised permits were received in March and April 2022. The Nevada Division of
Environmental Protection accepted public comment on its SIP through July 25,
2022.
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Nevada, Utah and Wyoming each submitted regional haze SIPs for second planning
period to the EPA in August 2022. The EPA has 18 months to approve or disapprove
all or parts of the states' plans. On August 25, 2022, the EPA promulgated a
finding of failure to submit a SIP for the regional haze second planning period
for 15 states, including Iowa. The finding establishes a two-year deadline for
the agency to promulgate FIPs to address the requirements, unless prior to
promulgating a FIP, the state submits, and the agency approves, a SIP meeting
the requirements. The finding says the agency intends to continue to work with
states in developing approvable SIP submittals in a timely manner. The Iowa
Department of Natural Resources continues to work with the EPA on development of
its SIP. Iowa anticipates submitting a final plan to the EPA in spring 2023.
Critical accounting estimates
Certain accounting measurements require management to make estimates and
judgments concerning transactions that will be settled several years in the
future. Amounts recognized on the Consolidated Financial Statements based on
such estimates involve numerous assumptions subject to varying and potentially
significant degrees of judgment and uncertainty and will likely change in the
future as additional information becomes available. Estimates are used for, but
not limited to, the accounting for the effects of certain types of regulation,
impairment of goodwill and long-lived assets, pension and other postretirement
benefits, income taxes and revenue recognition - unbilled revenue. For
additional discussion of the Company's critical accounting estimates, see Item 7
of the Company's Annual Report on Form 10-K for the year ended December 31,
2021. There have been no significant changes in the Company's assumptions
regarding critical accounting estimates since December 31, 2021.
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PacifiCorp and its subsidiaries
Consolidated Financial Section
51
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PART I
Item 1. Financial Statements
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Aging farmers, dying farmland
December 6, 2021
Montana Loans
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Roberta T. Mainor
Credit to Farmers
The expansion of the farm or ranch involves an investment in capital, and is especially challenging for those who are only beginning their journey in business. We have designed loan programs for farmers that are younger than of 35 or who have more than ten years of experience. They are comparable to our loan options that have modified the criteria for approval of credit in order to accommodate this need in the following manner. This program will allow you to get the money you require like this, while also aiding you to improve your financial position.
“At present, the production of eggs is the thing I’m most interested in and also something my grandfather was interested in. About 90 percent of eggs that are produced in the United States [are produced by the 60 farms that are owned by the company” Spencer explained.
Montana along with Montana and the United States of America are not the only countries that are experiencing a shift towards industrialization. As America shifts away from farms that were owned by families and towards growth, corporations are have a greater say in and control of the agricultural sector, using central processing facilities as well as manufacturing cheap products to satisfy the needs of the consumer. Shipping is available throughout in the United States and internationally A increase in the number of farms controlled by companies according to USDA statistics, occurred between 2012 and 2017. The increase was around 10 percent between 2012 and 2017. The amount of farms that are owned and operated by private individuals or households has declined by about the same amount during the same time.
Spencer is a real person in this sense. “I’m not certain if there’s any issue with this. This is just how things are at the moment “he explained. “There always is food to be found. Which do you believe it could be? Are you more a fan of family-owned farms to corporate farms? The agricultural sector will be increasingly controlled by corporate. Since a long time the big firms have attempted to consolidate their control over their businesses in operations and industries.”
The evolution of the American agriculture system however it has its own set of consequences. Small farms and ranches make important economic contributions to local economies, investing money into the local economy selling their products to communities, as well as also creating jobs for the local community. Rural communities are harmed when the longevity is at risk as well as when the employment opportunities available for the agricultural sector are cut down.
“Isn’t it the case that when you purchase something from Walmart there’s no transaction cost and there is no investment in our economy? The location is Walmart’s headquarters “The Community Food & Agriculture Coalition (CFAC) is an organization based in Missoula which works to create regional and local food infrastructure According to Bonnie Buckingham, executive director of the group. It’s feasible in the western part of Montana. “Community and value” is created in the sense that people are connected with their local communities through food, purchasing products from farmers, or by participating in events that bring people together. For producers, these kinds of events help strengthen bonds between the participants in the community.
The smaller farms also are green, as they tend to not use an excessive amount of toxic pesticides and will be more likely to aid in the protection of the species diversity in the agricultural and ecological realm as well as other advantages. They also have a higher ethical standard from an animal’s point viewpoint than most people. Spencer is a great example. He feeds his chickens a 100 100% vegetarian diet and keeps in cages which he claims is the most humane approach.
It is possible that farms like Spencer’s could be destroyed completely due to development, which will result in irreparable erosion of soil. Only a small amount of Montana’s topsoil could be utilized for agriculture however, only in small amounts. As per the CFAC the CFAC, just 8 percent of the land of Missoula County, for example has soils suitable for the production of agricultural crops. It would take about 1000 years to make three centimeters of topsoil out of the soil developed over the course of many thousands of years.
The majority of the soil is in the lower part of Missoula Valley, which happens to be the exact location that developers are currently eyeing to develop. If the soil isn’t properly prepared for paver and paving, it will not be able to carry out vital ecological functions like food production or water retention. It is also able to absorb carbon dioxide, which is a vital service to the ecosystem, and becomes more important as policymakers try to slow the progression of global warming.
“It is possible that the soil could be lost forever should we not safeguard it today. This kind of soil might be located in a field that can be grazed with horses, or just left to grow grass. It could be possible to obtain viable productive, productive, as well as productive soils near term which can be protected similar way as described in this article “Buckingham stated. If there’s a structure or industry located on it, or the land is dispersed and divided, we will never be able cultivate food on the soil.
In the course of addressing certain issues that confront the state, non-profit organizations and officials from government have come up with inventive ways to broaden its activities and engage more people.We’ll be in the process of ending our current state of things if we don’t safeguard it in its current shape.
One example of this could be Trust Montana. Trust Montana is a non-profit entity committed to the preservation of the agricultural land across the state. The organization was previously focused around the protection of low-cost housing However, in May 2020, the organization partnered along with other organisations, such as the Agrarian Trust and the Vilicus Training Institute in order to create the Montana Agrarian Commons, which is currently at its third year in operation. To stop the development of land that is not agricultural communities will be granted conservation easements that permit the parcel of land to remain an estate of trust to be used by the community, and it will be let to new farmers at a reasonable cost. Agrarian Commons is a program which can offer a unique selling opportunity for farmers and ranchers who have retired who wish to see their land be managed and developed with respect for the environment.
“Agrarian commons are designed to protect land for agriculture use in perpetuity to benefit of the future generations. Farmers also have leases for long-term tenure of their land “King-Ries explained. “And we’re seeking ways to assist farmers in earning cash and creating equity in a way similar to the way owners or landowners achieve this without the property getting sold for market value , and without the property becoming a commodity in its own.”
CFAC has adopted a unique approach to establishing a website named Farm Link Montana, which is designed to aid those who are new to farming, retiring and those who want to sell their farm land. The website, according to Mary Ellis, the new Farm Programs Coordinator of the coalition’s Beginning Farmers and Ranchers Program is an “kind match service.” She described it as such.”The retired farmer may be able collaborate with them to help them move gradually to larger areas or make a deal to sign a lease or a partnership together for a specific duration and for a limited time period,’ Ellis explained. So, I’m hoping to make it easier for farmers looking to get started. ”
According to Ellis the range of matches is from two to five games every year go over the normal investigation phase in the procedure. Even though that it is an insignificant amount, “in our program, we believe it is an impressive achievement when compared to other aspects to be taken into consideration,” she explained.
“This item has been tested on the field. Farmer-approved. The program offers grants of between $5,000 and $5,000 to farms in order to aid new farmers at the beginning stages the process of establishing their farms. A collaboration with Kiva which is a non-profit organisation which provides loans to those who make the difference in their community, allows the organization to provide small loans to farms and other agriculture-related enterprises.
Zach Brown of the Gallatin County Commission has been working with the Gallatin County Commission to aid farmers who are just beginning in their careers as farmers and face financial challenges. This legislation, dubbed the Montana Farmer Student Loan Assistance Program legislation that he wrote was approved by the year of 2019. The new farmers and ranchers could get up to 50 percent of their student loan payments through this scheme, managed through the State Department of Agriculture. Individuals who decide to work in the field could discover that the debt is an enormous obstacle to their dreams.
“Essentially the thing it’s doing is creating a process by which a prospective farmer or rancher could submit an application to government officials for loans aid program.” writes the book’s author. Brown has shared his ideas. Therefore that when they return to their ranches or farms they aid in the payment of students’ loans
MORGAN ROSE was one of the first organizations to be granted assistance with the repayment of loans from The Ministry of Agriculture’s Repayment Assistance Program. Dillon, Montana, is the home of Rose who is a fourth generation Montana breeder birthed and raised in the tiny town of only a few hundred people located in the southwest region of the state. It has the estimated number of people residing there at 5,000. “There isn’t any moment that I was contemplating pursuing a job in any other field than the field of production agriculture,” she said emphatically.