Berkshire Hathaway Energy
2018 Fixed-Income Investor Conference
A Berkshire Hathaway Company
Forward-Looking Statements
This presentation contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking
statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate,"
"continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon Berkshire Hathaway Energy Company (BHE) and its
subsidiaries, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its
subsidiaries or Sierra Pacific Power Company and its subsidiaries (collectively, the Registrants), as applicable, current intentions, assumptions, expectations
and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause
actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:
– general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax
reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective
Registrant's operations or related industries;
– changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and
capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;
– the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the
respective Registrant's ability to recover costs through rates in a timely manner;
– changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation,
energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply
or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;
– performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to
the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and
operating conditions;
– the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a
breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, earthquakes, explosions, landslides, an
electromagnetic pulse, mining incidents, litigation, wars, terrorism, embargoes, and cyber security attacks, data security breaches, disruptions, or
other malicious acts;
– a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of
balancing its generation resources with its retail load obligations;
– changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a
significant impact on generating capacity and energy costs;
– the financial condition and creditworthiness of the respective Registrant's significant customers and suppliers;
– changes in business strategy or development plans;
– availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other
sources of debt financing and volatility in interest rates;
– changes in the respective Registrant's credit ratings;
– risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
Forward-Looking Statements
– hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;
– the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and
changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;
– the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
– fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
– increases in employee healthcare costs;
– the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and
other postretirement benefits expense and funding requirements;
– changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and
franchising transactions;
– the ability to successfully integrate future acquired operations into a Registrant's business;
– unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors
that could affect future facilities and infrastructure additions;
– the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
– the impact of new accounting guidance or changes in current accounting estimates and assumptions on the consolidated financial results of the
respective Registrants; and
– other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the United States Securities and
Exchange Commission (SEC) or in other publicly disseminated written documents.
Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants’ filings with the SEC. Each Registrant
undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The
foregoing factors should not be construed as exclusive.
This presentation includes certain non-Generally Accepted Accounting Principles (GAAP) financial measures as defined by the SEC’s Regulation G. Refer to
the BHE Appendix in this presentation for a reconciliation of those non-GAAP financial measures to the most directly comparable GAAP measures.
Pat Goodman
Executive Vice President and Chief Financial Officer
Berkshire Hathaway Energy
2018 Fixed-Income Investor Conference
Energy Assets
(1) Includes both electric and natural gas
customers and end-users worldwide.
Additionally, AltaLink serves
approximately 85% of Alberta, Canada’s
population
(2) Net MW owned in operation and under
construction as of December 31, 2017
Assets $90 billion
Revenues $18.6 billion
Customers(1) 8.8 million
Employees 23,000
Transmission Line 33,500
Miles
Natural Gas Pipeline 16,400
Miles
Power Capacity 31,853 MW(2)
Renewables 36%
Natural Gas 33%
Coal 29%
Nuclear and Other 2%
Berkshire Hathaway Energy
Vision
To be the best energy company in serving our customers, while delivering sustainable energy solutions
Culture
Personal responsibility to our customers
Strategy
Reinvest in our businesses
• Continue to invest in our employees and
operations, maintenance and capital
programs for property, plant and equipment
• Position our regulated businesses to meet
changing customer expectations and retain
customers (reduce bypass risk) by providing
excellent service and competitive rates
• Reduce the carbon footprint of our operations
by participating in energy policy development,
resulting in the transformation of our
businesses and assets
• Advance grid resilience, cybersecurity and
physical security programs
Invest in internal growth
• Pursue the development of a value-enhancing
energy grid and gas pipeline infrastructure
• Create customer solutions through innovative
rate design and redesign
• Grow our portfolio of renewable energy
• Develop strong grid systems, including
cybersecurity and physical resilience programs
Acquire companies
• Additive to business model
Competitive Advantage
Berkshire Hathaway Ownership
BHE Competitive Advantage
• Diversified portfolio of regulated assets
– Weather, customer, regulatory, generation, economic and catastrophic
risk diversity
• Berkshire Hathaway ownership
– Access to capital from Berkshire Hathaway allows us to take advantage
of market opportunities
– Berkshire Hathaway is a long-term owner of assets which promotes
stability and helps make BHE the buyer of choice in many circumstances
– Tax appetite of Berkshire Hathaway has allowed us to receive significant
cash tax benefits from our parent of $636 million and $1.1 billion in 2017
and 2016, respectively
• No dividend requirement
– Cash flow is retained in the business and used to help fund growth and
strengthen our balance sheet
Diversity in Our Portfolio
(1) Calculated using reported shares outstanding on each respective balance sheet for the period ending December 31, 2017, per S&P Capital IQ
(2) As reported by company public filings, including the impact of 2017 Tax Reform on earnings
Comparable Companies
($ billions)
Market Cap
Dec. 31, 2017(1)
Net Income
Dec. 31, 2017(2)
NextEra Energy Inc. $73.6 $5.4
Duke Energy $58.9 $3.1
Dominion Energy $52.3 $3.0
Southern Company $48.5 $0.8
Exelon Corp. $38.0 $3.8
DISTRIBUTION
Our integrated utilities serve approximately 4.9 million customers; Northern Powergrid has
3.9 million end-users, making it the third-largest distribution company in Great Britain
TRANSMISSION
We own significant transmission infrastructure in 15 states and the province of Alberta; with
our assets at PacifiCorp, NV Energy and AltaLink, we are the largest transmission owner in
the Western Interconnection
PIPELINES
BHE Pipeline Group transported approximately 8% of the total natural gas consumed in the
United States during 2017
GENERATION
We own 31,853 MW of power capacity in operation and under construction, with resource
diversity ranging from natural gas and coal to renewable sources
RENEWABLES
As of December 31, 2017, we had invested $21 billion in solar, wind, geothermal and
biomass generation
Berkshire Hathaway Energy
2017 Net Income: $2.9 billion(2)
Berkshire Hathaway Energy’s regulated energy businesses serve customers and end-users
across 18 western and Midwestern states in the U.S. and in the U.K. and Canada
Revenue and Net Income Diversification
(1) Excludes HomeServices and equity income, which add further diversification
(2) Percentages exclude Corporate/other
• Diversified revenue sources reduce regulatory concentrations
• In 2017, approximately 88% of adjusted net income was from investment-
grade regulated subsidiaries
BHE 2017
Energy Revenue(1): $15 Billion
Nevada
20%
Iowa
17%
Utah
15%
Oregon
8%
Wyoming
6%
Illinois
4%
California
4%
Washington
3%
Idaho
2%
FERC
6%
United
Kingdom
6%
Alberta
5%
Other
4%
PacifiCorp
27%
MidAmerican
Funding
21%
NV Energy
13%
Northern
Powergrid
9%
BHE Pipeline
Group
10%
BHE
Transmission
8%
BHE
Renewables
8%
HomeServices
4%
BHE 2017
Adjusted Net Income(2): $2.6 Billion
Environmental, Social and Governance
82%
8%
10%
Renewables and
Other
Natural Gas
Generation
Coal Generation
Net PP&E as of December 31, 2017
Berkshire Hathaway Energy
• Berkshire Hathaway Energy is growing its renewable energy portfolio and continues to de-risk its
balance sheet as it relates to carbon-based generation assets. We are leading the way to a sustainable
energy future for our customers
85%
2%
13%
MidAmerican Energy PacifiCorp
69%
9%
22%
64%
35%
1%
Nevada Power
76%
18%
6%
Sierra Pacific
• We are actively engaged in the Edison Electric Institute
Environmental, Social and Governance/Sustainability
initiative
• BHE began reporting additional information on our
website in first quarter 2018
– Quantitative portfolio, emission and resource
metrics including greenhouse gas emission rates
and methane leak rates
Generation Diversification
2017 BHE Power Capacity – 31,853 MW
2017 BHE Power Generation – 116 TWh
Total
Renewables
36%
Total
Renewables(1)
27%
(1) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply
with RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from
energy purchased
Coal
29%
Natural Gas
33%
Nuclear and
Other
2%
Wind
26%
Solar
5%
Hydro
4%
Geothermal
1%
Coal
46%
Natural Gas
24%
Nuclear and
Other
3%
Wind
17%
Solar
3%
Hydro
5%
Geothermal
2%
Coal
58%
Natural Gas
23%
Nuclear and
Other
3%
Wind
5%
Hydro
8%
Geothermal
3%
Total
Renewables
16%
Total
Renewables(1)
12%
Coal
74%
Natural Gas
9%
Nuclear and
Other
5%
Wind
2%
Hydro
5%
Geothermal
5%
2006 BHE Power Capacity – 16,386 MW
2006 BHE Power Generation – 83 TWh
Wind and Solar Investments
(1) Includes owned operating, under construction and in-development facilities. Excludes tax equity investments
• PacifiCorp and MidAmerican Energy are repowering existing wind facilities which entails the replacement of
significant components of older turbines which are expected to qualify for production tax credits. Project spend
related to the repowering of existing wind facilities is anticipated to be approximately $2.3 billion from 2016 – 2020
• PacifiCorp’s 2017 Integrated Resource Plan (IRP) includes the implementation of wind repowering, new
transmission, and the development of 1,311 MW of new wind powered facilities (1,111 MW of which will be owned)
for a total investment of approximately $3.4 billion from 2017 – 2020
• MidAmerican Energy is progressing on the construction of up to 2,000 MW of additional wind-powered generating
facilities. As of January 2018, 334 MW had been placed in-service. The project is expected to be completed and
in-service by 2020, with a cost cap of $3.6 billion
• BHE Renewables is constructing the Community Solar Gardens project in Minnesota, comprised of 28 locations
with a capacity of 98 MW, and up to 512 MW of wind generating projects, including the 212 MW Walnut Ridge
facility located in Illinois. Upon completion, the combined investment for the projects is anticipated to be
approximately $1.1 billion
Owned Wind and Solar Generation Capacity (MW)
(1)
Regulated Unregulated
MidAmerican BHE
PacifiCorp Energy NVE Renewables Total
1999-2015 1,030 3,413 15 1,959 6,417
2016 - 594 - 495 1,089
2017 - 334 - 211 545
2018-2020 1,111 1,666 - 536 3,313
Total 2,141 6,007 15 3,201 11,364
Investment (billions) $5 $11 $0 $10 $26
• Our support is explicit from our Aa2/AA rated parent
– BHE is not like any other typical utility holding company. Our balance sheet and credit strength is
supported by a strong owner with over $100 billion of liquidity, as of December 31, 2017
– BHE does not pay dividends, which allows BHE to continue to grow the business and maintain
credit quality
– BHE retains more dollars of earnings than any other U.S. electric utility
Berkshire Hathaway Ownership is
Unique to the Utility Industry
(1) As reported by company public filings
(2) Calculated using reported shares outstanding on each respective balance sheet for the period ending December 31, 2017, per S&P Capital IQ
`
($ in millions)
Net Income to
Common(1)
Adjusted
Earnings(1)
Common
Dividend(1)
Adjusted Retained
Earnings
per day
Common Dividend
as % of Adjusted
Earnings
December 31,
2017 Market
Cap(2)
Berkshire Hathaway Energy:
2017 Actual 2,870$ 2,617$ -$ 7.2 0% Privately Held
December 31, 2017:
Duke Energy 3,059$ 3,199$ 2,450$ 2.1 77% 58,877
NextEra Energy 5,378 3,165 1,845 3.6 58% 73,565
Southern Company 842 3,017 2,300 2.0 76% 48,456
E elon Corporation 3,770 2,471 1,236 3.4 50% 37,965
D minion Energy 2,999 2,289 1,931 1.0 84% 52,284
American Electric Power 1,913 1,808 1,178 1.7 65% 36,197
Public Service Enterprise 1,574 1,488 870 1.7 58% 25,983
Sempra Energy 256 1,368 755 1.7 55% 26,875
Consolidated Edison, Inc. 1,525 1,264 803 1.3 64% 24,381
Xcel Energy Inc. 1,148 1,171 721 1.2 62% 24,428
Peer Median Average 1,743 2,048 1,207 1.7 63%
$0.1
$2.4 $2.5
$2.6
$2.9
$0.0
$0.6
$1.2
$1.8
$2.4
$3.0
2001 2015 2016 2017
Berkshire Hathaway Energy
Financial Summary
• Since being acquired by Berkshire Hathaway in March 2000, BHE has realized
significant growth in its assets, net income and cash flows
$6.5
$60.8 $62.5
$65.9
$0.0
$15.0
$30.0
$45.0
$60.0
$75.0
2001 2015 2016 2017
($ billions)
$0.8
$7.0
$6.1 $6.1
$0.0
$2.0
$4.0
$6.0
$8.0
2001 2015 2016 2017
($ billions)
$1.7
$22.4 $24.3
$28.2
$0.0
$6.0
$12.0
$18.0
$24.0
$30.0
2001 2015 2016 2017
($ billions)
Net Income Attributable to BHE
BHE Shareholders’ Equity Property, Plant and Equipment (Net)
Cash Flows From Operations
($ billions) (1)
(1) Net income in 2017 of $2.9 billion includes a $516 million benefit as a result of 2017 Tax Reform, partially offset by a charge of $263 million from tender offers for
certain long-term debt completed in December 2017. Excluding the impact of one-time adjustments, 2017 adjusted net income was $2.6 billion
Berkshire Hathaway Energy
Growing the Business
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
N
et
I
n
c
ome
a
n
d
C
a
s
h
Flo
w
s
From
O
p
e
ra
ti
o
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s
($
m
il
li
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n
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)
T
ota
l
A
s
s
ets
a
n
d
T
ota
l
D
e
b
t
($
bi
ll
io
n
s
)
Total Assets Total Debt Net Income Cash Flows From Operations
(1) Total Debt excludes Junior Subordinated Debentures and BHE trust preferred securities. As of December 31, 2017, $100 million of junior subordinated
debentures remained outstanding
2001 – 2017 CAGR
Total Assets 13.1%
Net Income 20.6%
Cash Flows From Operations 13.1%
• We have grown our assets significantly since 2001 while de-risking the business, reducing
total debt(1) / total assets from 58% to 44% in 2017 and improving our credit ratings
2017 Net Income
(1) Adjusted net income of $2.617 billion removes the impact of one-time items related to the $516 million benefit as a result of 2017 Tax Reform and a
charge of $263 million from the tender offer for long-term debt at Berkshire Hathaway Energy and MidAmerican Funding
($ millions) Years Ended Dec. 31
As Reported Adjusted
(1)
As Reported
Net Income Attributable to BHE 2017 2017 2016
PacifiCorp 769$ 763$ 764$
MidAmerican Funding 574 601 532
NV Energy 346 365 359
Northern Powergrid 251 251 342
BHE Pipeline Group 277 270 249
BHE Transmission 224 224 214
BHE Renewables 864 236 179
HomeServices 149 118 127
BHE and Other (584) (211) (224)
Net income attributable to BHE 2,870$ 2,617$ 2,542$
Tax Reform Impact
Impacts of Tax Reform in 2017 Financial Statements:
• One-time gain of $516 million from 2017 Tax Reform
• Deferred tax liabilities were decreased, largely offset by an increase in regulatory liabilities
• The 2017 Tax Reform Act
– Reduces the federal corporate tax rate from 35% to 21% effective January 1, 2018
– Creates a one-time repatriation tax of foreign earnings and profits to be paid over the next
eight years
– Eliminates bonus depreciation on qualifying regulated utility assets acquired after
September 27, 2017
– Extends and modifies the additional first-year bonus depreciation for non-regulated property
• The 2017 Tax Reform Act and the related regulatory outcomes will likely result in lower revenue,
income taxes and cash flow in future years. BHE does not expect the 2017 Tax Reform Act and related
regulatory treatment to have a material adverse impact on its cash flows, subject to actual regulatory
outcomes, which will be determined based on rulings by regulatory commissions expected in 2018
($ millions) PacifiCorp
MidAmerican
Funding NV Energy
BHE Pipeline
Group
BHE
Renewables
BHE
Transmission HomeServices
BHE & Other
Corp Entities
BHE
Consolidated
Impact to Net Income 6$ (10)$ (19)$ 7$ 628$ -$ 31$ (127)$ 516$
Decrease in
eferred Tax Liability
2,361 1,822 1,115 621 703 161 31 301 7,115
Increase in
Regulatory Liability
2,358 1,845 1,134 614 - - - -
5,950
Return on Equity
(1) Based on 13-point average equity, including as reported net income and equity in 2017
(2) Effective January 1, 2018, 100% revenue sharing will be triggered each year by MidAmerican Energy’s actual returns above a threshold calculated annually
(3) Nevada Power is permitted to earn up to 9.7% before 50% revenue sharing commences
Net Income Divided by
Average Equity(1)
Entity 2017 2016
Allowed
ROE
PacifiCorp 10.3% 10.1% 9.8%
MidAmerican Energy 11.0% 11.1% 10.5%(2)
Nevada Power 9.0% 9.1% 9.4%(3)
Sierra Pacific 9.5% 7.7% 9.6%
Northern Natural Gas 11.3% 11.2% 12.0%
Kern River 10.6% 10.6% 11.55%
Credit Ratios Support Our Credit Ratings
(1) Moody’s / S&P / Fitch / DBRS. Ratings are issuer or senior unsecured ratings unless otherwise noted
(2) Refer to the Appendix for the calculations of key ratios
(3) Ratings are senior secured ratings
Unadjusted Credit Metrics
FFO Interest Coverage FFO / Debt Debt / Total Capitalization
Credit Ratings(1) Average 2017 2016 2015 Average 2017 2016 2015 2017 2016 2015
Berkshire Hathaway Energy(2) A3 / A- / BBB+ 4.4x 4.4x 4.3x 4.5x 16.4% 15.8% 16.0% 17.6% 58% 59% 59%
Regulated U.S. Utilities
PacifiCorp(2) (3) A1 / A+ / A+ 5.4x 5.3x 5.7x 5.4x 23.5% 23.1% 24.1% 23.2% 48% 50% 49%
MidAmerican Energy(2) (3) Aa2 / A+ / A+ 7.5x 7.6x 7.8x 7.2x 28.3% 28.1% 30.4% 26.6% 47% 46% 48%
Nevada Power(2) (3) A2 / A+ / A- 5.2x 4.9x 4.6x 6.1x 24.6% 22.8% 21.6% 29.5% 53% 51% 51%
Sierra Pacific(2) (3) A2 / A+ / A- 5.9x 6.1x 5.4x 6.1x 21.9% 19.2% 20.7% 25.7% 50% 51% 53%
Regulated Pipelines and Electric Distribution
Northern Natural Gas A2 / A / A 9.7x 9.3x 9.5x 10.4x 44.0% 41.5% 41.8% 48.7% 34% 36% 36%
AltaLink, L.P.(3) – / A / – / A 3.0x 3.1x 3.2x 2.6x 11.2% 12.2% 11.8% 9.6% 60% 62% 62%
Northern Powergrid Holdings Baa1 / A- / A- 4.9x 4.5x 5.1x 5.1x 20.2% 17.7% 21.7% 21.2% 43% 43% 44%
Northern Powergrid (Northeast) A3 / A / A-
Northern Powergrid (Yorkshire) A3 / A / A
• Berkshire Hathaway Energy and its subsidiaries will spend approximately $16.4 billion from
2018 – 2020 for growth and operating capital expenditures, which primarily consist of new wind
generation project expansions, repowering of existing wind facilities and transmission and
distribution capital expenditures
Capital Expenditures and Cash Flows
$-
$1,500
$3,000
$4,500
$6,000
$7,500
2013A 2014A 2015A 2016A 2017A 2018F 2019F 2020F 2021F 2022F
($
m
il
li
o
n
s
)
BHE Cash Flows from Operations BHE Total Capital Expenditures BHE Operating Capital Expenditures
Free Cash Flow
2018 – 2022: $21 Billion Free Cash
Flow above Operating Capex
2018 – 2022: $11 Billion Free
Cash Flow above Total Capex
+
Capital Investment Plan
6,443
5,682
4,279
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
2018 2019 2020
($ millio
n
s
)
PacifiCorp MidAmerican Funding NV Energy
Northern Powergrid BHE Pipeline Group BHE Renewables
BHE Transmission HomeServices and Other
Capex
by Type
Current Plan
2018-2020
Prior Plan
2018-2020 Variance
Operating $ 7,277 $ 6,125 $ 1,152
Wind Generation
(Growth)
6,073 3,716 2,357
Other Growth 1,608 1,379 229
Electric Transmission
(Growth)
1,164 609 555
Environmental 186 215 (29)
Solar Generation
(Growth)
96 30 66
Total $ 16,404 $ 12,074 $ 4,330
Capex
by Business
Current Plan
2018-2020
Prior Plan
2018-2020 Variance
PacifiCorp $ 5,114 $ 3,647 $ 1,467
MidAmerican Energy 5,004 3,816 1,188
NV Energy 1,529 1,500 29
Northern Powergrid 1,799 1,353 446
BHE Pipeline Group 1,013 680 333
BHE Renewables 1,042 267 775
BHE Transmission 756 709 47
HomeServices and
Other
147 102 45
Total $ 16,404 $ 12,074 $ 4,330
6,443
5,682
4,279
$-
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
2018 2019 2020
($ mill
io
n
s
)
Operating Wind Generation (Growth)
Other Growth Electric Transmission (Growth)
Environmental Solar Generation (Growth)
Financing Plan 2018
Completed Debt Offerings
• Berkshire Hathaway Energy
– In January 2018, issued $2.2 billion parent senior debt comprised of 4 tranches:
$450 million 3-year offering at 2.375% coupon, $400 million 5-year offering at 2.8%
coupon, $600 million 10-year offering at 3.25% coupon and $750 million 30-year
offering at 3.8% coupon. The proceeds were used to refinance short-term debt that
had been incurred, in part, related to the $1.5 billion tender offer for a portion of
Berkshire Hathaway Energy and MidAmerican Funding debt in December 2017
• MidAmerican Energy
– In February 2018, issued $700 million 30-year First Mortgage, green bonds at
3.65% coupon, the company’s second green bond offering
Anticipated Debt Offerings
Co p y
Issuances in 2018
($ millions)
Anticipated
Issue Date
Maturities in 2018
($ millions)
Nevada Power $575 First-half 2018 $823
Northern Natural Gas $525 Summer 2018 $200
PacifiCorp $650 Summer 2018 $586
MidAmerican Energy $500 Second-half 2018 $350
Northern Powergrid - Yorkshire £150 Second-half 2018
Questions
BHE Appendix
Organizational Structure
2017 Berkshire Hathaway Inc. ($ billions)
Revenue $ 242.1
Net Income $ 44.9
Equity $ 348.3
2017 Berkshire Hathaway Energy ($ billions)
Revenue $ 18.6
Net Income $ 2.9
Equity $ 28.2
A3/A-/BBB+
Aa2/AA/A+
90%
Nevada Power
Company
A2/A+/A-(1)
Regulated Electric
Utility
Sierra Pacific Power
Company
A2/A+/A-(1)
Regulated Electric
and Gas Utility
Real Estate
Brokerage, Mortgage
and Franchises
Northern Powergrid
(Northeast) Ltd.
A3/A/A-
U.K. Regulated
Electric Distribution
Regulated
Electric
Transmission
Contracted
Non-utility Power
Generation
Northern Powergrid
(Yorkshire) plc
A3/A/A
U.K. Regulated
Electric Distribution
Regulated Natural
Gas Transmission
A2/A/A
Regulated Natural
Gas Transmission
Baa1/A-/A-
Holding Company
Aa2/A+/A+(1)
Regulated Electric
and Gas Utility
Baa2/A-/BBB-
Holding Company
A1/A+/A+(1)
Regulated Electric
Utility
A/A(1)
S&P / DBRS
Alberta Canada
Regulated Transmission
(1) Ratings for PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and AltaLink L.P. are senior secured ratings
Reportable Segment Information
Years Ended Dec. 31
Adjusted As Reported
($ millions) 2017 2017 2016 2015
Operating Income:
PacifiCorp 1,462$ 1,462$ 1,427$ 1,344$
MidAmerican Funding 549 562 566 451
NV Energy 765 765 770 812
Northern Powergrid 436 436 494 593
BHE Pipeline Group 475 475 455 464
BHE Transmission 322 322 92 260
BHE Renewables 316 316 256 255
HomeServices 214 214 212 184
BHE and Other (38) (38) (21) (35)
Total operating income 4,501 4,514 4,251 4,328
Interest expense - senior & subsidiary (1,822) (1,822) (1,789) (1,800)
Interest expense - junior subordinated debentures (19) (19) (65) (104)
Capitalized interest and other, net 273 (166) 453 311
Income before income tax expense and equity income (loss) 2,933 2,507 2,850 2,735
Income tax expense (benefit) 353 (554) 403 450
Equity income (loss) 77 (151) 123 115
Net income 2,657 2,910 2,570 2,400
Net income attributable to noncontrolling interests 40 40 28 30
Net income attributable to BHE shareholders 2,617$ 2,870$ 2,542$ 2,370$
Rate Base
$14.0 $14.0 $13.9 $13.9
$0.0
$4.0
$8.0
$12.0
$16.0
2015A 2016A 2017A 2018F
($ billions)
$6.8 $6.8 $6.7 $6.8
$0.0
$2.0
$4.0
$6.0
$8.0
2015A 2016A 2017A 2018F
($ billions)
$7.5
$8.3 $8.9
$10.2
$0.0
$3.0
$6.0
$9.0
$12.0
2015A 2016A 2017A 2018F
($ billions)
NV Energy
MidAmerican Energy PacifiCorp
BHE Pipeline Group
$3.0 $3.0 $3.0 $3.1
$0.0
$1.0
$2.0
$3.0
$4.0
2015A 2016A 2017A 2018F
($ billions)
Note: Rate base represents mid-year averages
Rate Base
(1) Northern Powergrid rate base converted into USD at the June 30 USD/GBP FX rate each year including 1.57 (2015), 1.33 (2016), 1.30 (2017), and 1.40 (2018 estimate)
(2) AltaLink, L.P. rate base converted into USD at the June 30 CAD/USD FX rate each year including 1.25 (2015), 1.29 (2016), 1.30 (2017), and 1.25 (2018 estimate)
Note: Rate base represents mid-year averages
£2.7 £2.9
£3.0 £3.1
£0.0
£1.0
£2.0
£3.0
£4.0
2015A 2016A 2017A 2018F
(£ billions)
$5.3
$7.0
$7.4 $7.6
$0.0
$2.0
$4.0
$6.0
$8.0
2015A 2016A 2017A 2018F
AltaLink, L.P. Northern Powergrid
Berkshire Hathaway Energy
$39.8 $41.2 $42.2
$44.5
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
2015A 2016A 2017A 2018F
PAC MEC Northern Powergrid BHE Pipeline Group NVE AltaLink, L.P.
(1) (2)
($ billions)
(C$ billions)
Long-Term Debt Summary
as of December 31, 2017
• In January 2018, Berkshire Hathaway Energy issued $2.2 billion parent senior debt. Proceeds were used to refinance short-term
debt that had been incurred in part related to the $1.5 billion tender offer for a portion of Berkshire Hathaway Energy and
MidAmerican Funding debt in December 2017
• In February 2018, MidAmerican Energy issued $700 million 30-year First Mortgage, green bonds. Proceeds were used to finance
development of the 2,000 MW Wind XI project and repowering of some of the company’s existing wind facilities
Consolidated Berkshire Hathaway Energy
Wt. Avg. Wt. Avg.
$ (millions) Coupon Life (Years)
(1)
Berkshire Hathaway Energy - Parent 6,452 5.13% 14.7
PacifiCorp 7,025 5.12% 11.9
MidAmerican Funding 5,259 4.32% 15.7
NV Energy 4,581 5.55% 10.3
Northern Powergrid(2) 2,805 5.16% 8.5
Northern Natural Gas 796 4.87% 12.3
BHE Canada(3) 4,334 3.92% 17.3
BHE Renewables 3,594 4.74% 9.1
HomeServices 247 2.81% 3.8
Total Berkshire Hathaway Energy Long-Term Debt 35,093 4.84% 12.9
Berkshire Hathaway Energy - Parent Junior Subordinated Debentures 100 5.00% 39.5
Northern Electric Preferred Stock - Perpetual 56 8.06% 30.0
PacifiCorp Preferred Stock - Perpetual 2 6.75% 30.0
Total Berkshire Hathaway Energy Preferred Stock and Jr. Sub. Debentures 158 6.11% 36.0
Total Berkshire Hathaway Energy Long-Term Securities 35,251 4.85% 13.0
(1) Weighted average life assumes perpetual preferred stock has an average life of 30 years
(2) USD to GBP exchange rate at $1.3512/pound
(3) CAD to USD exchange rate at $1.2571/USD
Debt Maturities
as of December 31, 2017
Long-Term Debt Maturities(1)
(1) Excludes capital leases
3,410
2,082
1,650
854
1,810
2,116
1,620
1,232
987
855
$-
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
($ mill
io
n
s
)
PacifiCorp MidAmerican Funding NV Energy
Northern Powergrid BHE Pipeline Group BHE Renewables
BHE Canada HomeServices Berkshire Hathaway Energy
Jurisdictional Strength – Unemployment Rates
Source: Bloomberg, Bureau of Labor and Statistics
(1) Weighted average of Oregon, Utah and Wyoming
58.0%
60.0%
62.0%
64.0%
66.0%
68.0%
70.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
2010 2011 2012 2013 2014 2015 2016 2017
U
.S
.
L
a
b
o
r
P
ar
ti
cipat
io
n
U
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mp
lo
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ment
R
ate
s
Iowa Nevada Alberta U.K. PAC Territory U.S. Labor Participation
(1)
Retail Electric Sales – Actual
December 31 Variance
(GWh) 2017 2016 Actual Percent Exact Amount
PacifiCorp
Residential 16,625 16,058 567 3.5%
Commercial 17,726 16,857 869 5.2%
Industrial and Other 20,899 21,403 (504) -2.4%
Total 55,250 54,318 932 1.7%
MidAmerican Energy
Residential 6,207 6,408 (201) -3.1%
Commercial 3,761 3,812 (51) -1.3%
Industrial and Other 14,524 13,704 820 6.0%
Total 24,492 23,924 568 2.4%
Nevada Power
Residential 9,501 9,394 107 1.1%
Commercial 4,656 4,663 (7) -0.2%
Industrial and Other 6,413 7,525 (1,112) -14.8%
Distribution Only Service 1,830 662 1,168 NM
Total 22,400 22,244 156 0.7%
Sierra Pacific
Residential 2,492 2,375 117 4.9%
Commercial 2,954 2,933 21 0.7%
Industrial and Other 3,192 3,030 162 5.3%
Distribution Only Service 1,394 1,360 34 2.5%
Total 10,032 9,698 334 3.4%
Northern Powergrid
Residential 12,634 12,839 (205) -1.6%
Commercial 4,340 5,338 (998) -18.7%
Industrial and Other 18,316 17,742 574 3.2%
Total 35,290 35,919 (629) -1.8%
Retail Electric Sales – Weather Normalized
December 31 Variance
(GWh) 2017 2016 Actual Percent Exact Amount
PacifiCorp
Residential 16,130 16,135 (5) 0.0%
Commercial 17,508 16,762 746 4.5%
Industrial and Other 20,885 21,360 (475) -2.2%
Total 54,523 54,257 266 0.5%
MidAmerican Energy
Residential 6,235 6,297 (62) -1.0%
Commercial 3,797 3,788 9 0.2%
Industrial and Other 14,523 13,703 820 6.0%
Total 24,555 23,788 767 3.2%
Nevada Power
Residential 9,331 9,195 136 1.5%
Commercial 4,603 4,614 (11) -0.2%
Industrial and Other 6,343 7,475 (1,132) -15.1%
Distribution Only Service 1,795 659 1,136 NM
Total 22,072 21,943 129 0.6%
Sierra Pacific
Residential 2,403 2,418 (15) -0.6%
Commercial 2,940 2,935 5 0.2%
Industrial and Other 3,179 3,027 152 5.0%
Distribution Only Service 1,395 1,360 35 2.6%
Total 9,917 9,740 177 1.8%
Northern Powergrid
Residential 12,760 12,811 (51) -0.4%
Commercial 4,388 5,351 (963) -18.0%
Industrial and Other 18,341 17,795 546 3.1%
Total 35,489 35,957 (468) -1.3%
Retail Electric Sales – Weather Normalized
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
140,000
145,000
150,000
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
2011 2012 2013 2014 2015 2016 2017 2018F
B
H
E
T
ota
l
Weather
N
orma
li
ze
d
G
W
h
Northern Powergrid - CAGR (1.2%) Rocky Mountain Power - CAGR (0.1%)
MidAmerican Energy - CAGR 1.9% Nevada Power - CAGR 0.7%
Pacific Power - CAGR (0.1%) Sierra Pacific - CAGR 2.3%
BHE Total - CAGR 0.2%
Weather
N
orma
li
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d
G
W
h
Private Generation Penetration Rate
Private Generation
Customers as of
December 2017
Total Electric
Customers as of
December 2017
Private Generation
Portion of
Total Customers
MidAmerican Energy Company
Iowa 569 684,934 0.08%
Illinois 28 85,338 0.03%
South Dakota 0 5,003 0.00%
PacifiCorp
Utah 27,638 903,790 3.06%
Oregon 6,084 583,436 1.04%
Wyoming 276 140,968 0.20%
Washington 847 131,052 0.65%
Idaho 357 78,387 0.46%
California 377 45,143 0.84%
NV Energy
Nevada 26,727 1,272,512 2.10%
Total BHE Customers 62,903 3,930,563 1.60%
Berkshire Hathaway Energy – Impact of Private Generation
Consolidated Environmental Position
• We have significantly reduced our carbon footprint
– Since 2000, we have added approximately 10 GW of wind and solar powered assets to our
power capacity portfolio which are in operation or under construction as of December 31, 2017
– Owned coal-fueled capacity has declined as a percentage of BHE’s power capacity portfolio
from 51% in 2000 to 29%, as of December 31, 2017
• Steam Electric Effluent Limitation Guidelines
– For BHE’s operating companies, impacted waste streams are limited to bottom ash or fly ash
transport water, combustion residual leachate and non-metal cleaning wastes
– With minor exceptions, most new requirements are addressed by compliance with the coal
combustion residuals rule
– EPA issued a final rule September 18, 2017, extending certain compliance dates for flue gas
desulfurization wastewater and bottom ash transport water limits from November 2018 to
November 2020
• Coal Combustion Residuals (CCR) – managing under current regulatory requirements;
however, EPA is reconsidering portions of the final rule that may influence closure actions
– PacifiCorp has 6 active surface impoundments and 4 active landfills; 3 inactive surface
impoundments are undergoing closure
– MidAmerican Energy operates 2 active surface impoundments and 4 active landfills. In addition,
MidAmerican Energy has 6 inactive surface impoundments; 5 have been closed, and 1 is
continuing closure activities
– NV Energy operates 2 active evaporative surface impoundments and 2 active landfills; all other
surface impoundments are undergoing closure by removal
• MidAmerican Energy Company, NV Energy and PacifiCorp posted the
results of their groundwater detection monitoring on March 1, 2018, in
advance of the required posting under the CCR rule
• The ash ponds operated by the BHE companies are structurally sound and
do not pose a risk to public safety
• The majority of the groundwater monitoring results are consistent with
naturally occurring substances, do not exceed standards for action and do
not threaten drinking water or human health; however, some testing results
require additional assessment or action
• The companies are working with their states and other agencies to evaluate
the groundwater results to identify and take actions that meet or exceed all
applicable requirements and are consistent with our environmental respect
principles. This may include action to close ash ponds and implement
alternative disposal methods
Coal Combustion Residuals
Reducing Carbon Footprint
• Through fuel switching and retirements, BHE’s utilities expect to eliminate approximately
2,645 MW of coal generation through 2025
Coal MW as of Dec. 31, 2013(1) 10,529 MW
Riverside 3 – retired in 2014 (4) MW
Reid Gardner 1-3 – retired in 2014 (300) MW
Carbon 1 and 2 – retired in 2015 (172) MW
Riverside 5 – conversion to natural gas in 2015 (124) MW
Walter Scott 1 and 2 – retired in 2015 (124) MW
Neal 1 and 2 – retired in 2016 (390) MW
Reid Gardner 4 – retired in 2017 (257) MW
Naughton 3 – natural gas conversion or retire (280) MW
Navajo – interest to be divested in 2019 (255) MW
Cholla 4 – natural gas conversion or retire (395) MW
Craig 1 – natural gas conversion or retire (83) MW
North Valmy – to be retired in 2025 (261) MW
Coal MW as of Dec. 31, 2025 7,884 MW
(1) Adjusted for re-rating of coal plants between December 31, 2013, and December 31, 2017, including plants still in operation and retired
Berkshire Hathaway Energy
Non-GAAP Financial Measures
($ millions)
Net Income
adjusted Tax Reform
Debt Tender
Offer Premium
Net Income
as reported
PacifiCorp 763$ 6$ -$ 769$
MidAmerican Funding 601 (10) (17) 574
NV Energy 365 (19) - 346
Northern Powergrid 251 - - 251
BHE Pipeline Group 270 7 - 277
BHE Transmission 224 - - 224
BHE Renewables 236 628 - 864
HomeServices 118 31 - 149
BHE and Other (211) (127) (246) (584)
Net Income 2,617 516 (263) 2,870
Operating Revenue 18,614 - - 18,614
Total Operating Costs and Expenses 14,113 (13) - 14,100
Operating Income 4,501 13 - 4,514
Interest Expense - Senior & Subsidiary (1,822) - - (1,822)
Interest Expense - Junior Subordinated Debentures (19) - - (19)
Capitalized interest and other, net 273 - (439) (166)
Income Tax (Benefit) Expense 353 (731) (176) (554)
Equity (Loss) Income 77 (228) - (151)
Net Income Attributable to Noncontrolling Interests 40 - - 40
Net Income 2,617$ 516$ (263)$ 2,870$
Berkshire Hathaway Energy
Non-GAAP Financial Measures
(1) FFO Interest Coverage equals the sum of FFO and Adjusted Interest divided by Adjusted Interest
(2) Debt includes short-term debt, Berkshire Hathaway Energy senior debt, Berkshire Hathaway Energy subordinated debt and subsidiary debt (including current maturities)
(3) FFO to Adjusted Debt equals FFO divided by Adjusted Debt
(4) Adjusted Debt to Total Capitalization equals Adjusted Debt divided by Capitalization
($ millions)
FFO 2017 2016 2015
Net cash flows from operating activities 6,066$ 6,056$ 6,980$
+/- Changes in other operating assets and liabilities 177 (144) (649)
FFO 6,243$ 5,912$ 6,331$
Adjusted Interest
Interest expense 1,841$ 1,854$ 1,904$
Interest expense on subordinated debt (19) (65) (104)
Adjusted Interest 1,822$ 1,789$ 1,800$
FFO Interest Coverage(1) 4.4x 4.3x 4.5x
Adjusted Debt
Debt(2) 39,681$ 37,985$ 38,946$
Subordinated debt (100) (944) (2,944)
Adjusted Debt 39,581$ 37,041$ 36,002$
FFO to Adjusted Debt(3) 15.8% 16.0% 17.6%
Capitalization
Berkshire Hathaway Energy shareholders’ equity 28,176$ 24,327$ 22,401$
Adjusted debt 39,581 37,041 36,002
Subordinated debt 100 944 2,944
Noncontrolling interests 132 136 134
Capitalization 67,989$ 62,448$ 61,481$
Adjusted Debt to Total Capitalization(4) 58.2% 59.3% 58.6%
PacifiCorp
Non-GAAP Financial Measures
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
($ millions)
FFO 2017 2016 2015
Net cash flows from operating activities 1,575$ 1,568$ 1,734$
+/- Changes in other operating assets and liabilities 66 203 (74)
FFO 1,641$ 1,771$ 1,660$
Interest expense 381$ 380$ 379$
FFO Interest Coverage(1) 5.3x 5.7x 5.4x
Debt (2) 7,105$ 7,349$ 7,166$
FFO to Debt(3) 23.1% 24.1% 23.2%
Capitalization
PacifiCorp shareholders’ equity 7,555$ 7,390$ 7,503$
Debt 7,105 7,349 7,166
Capitalization 14,660$ 14,739$ 14,669$
Debt to Total Capitalization(4) 48.5% 49.9% 48.9%
MidAmerican Energy
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2017 2016 2015
Net cash flows from operating activities 1,396$ 1,403$ 1,351$
+/- Changes in other operating assets and liabilities 19 (65) (216)
FFO 1,415$ 1,338$ 1,135$
Interest expense 214$ 196$ 183$
FFO Interest Coverage(1) 7.6x 7.8x 7.2x
Debt (2) 5,042$ 4,400$ 4,271$
FFO to Debt(3) 28.1% 30.4% 26.6%
Capitalization
MidAmerican Energy shareholder's equity 5,764$ 5,160$ 4,705$
Debt 5,042 4,400 4,271
Capitalization 10,806$ 9,560$ 8,976$
Debt to Total Capitalization(4) 46.7% 46.0% 47.6%
Nevada Power
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2017 2016 2015
Net cash flows from operating activities 667$ 771$ 892$
+/- Changes in other operating assets and liabilities 35 (109) 77
FFO 702$ 662$ 969$
Interest expense 179$ 185$ 190$
FFO Interest Coverage(1) 4.9x 4.6x 6.1x
Debt (2) 3,075$ 3,066$ 3,285$
FFO to Debt(3) 22.8% 21.6% 29.5%
Capitalization
Nevada Power shareholder's equity 2,678$ 2,972$ 3,163$
Debt 3,075 3,066 3,285
Capitalization 5,753$ 6,038$ 6,448$
Debt to Total Capitalization(4) 53.5% 50.8% 50.9%
Sierra Pacific
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2017 2016 2015
Net cash flows from operating activities 182$ 243$ 342$
+/- Changes in other operating assets and liabilities 39 (4) (33)
FFO 221$ 239$ 309$
Interest expense 43$ 54$ 61$
FFO Interest Coverage(1) 6.1x 5.4x 6.1x
Debt (2) 1,154$ 1,153$ 1,202$
FFO to Debt(3) 19.2% 20.7% 25.7%
Capitalization
Sierra Pacific Power shareholder's equity 1,172$ 1,108$ 1,076$
Debt 1,154 1,153 1,202
Capitalization 2,326$ 2,261$ 2,278$
Debt to Total Capitalization(4) 49.6% 51.0% 52.8%
Northern Natural Gas
Non-GAAP Financial Measures
($ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2017 2016 2015
Net cash flows from operating activities 260$ 367$ 362$
+/- Changes in other operating assets and liabilities 70 (35) 25
FFO 330$ 332$ 387$
Interest expense 40$ 39$ 41$
FFO Interest Coverage(1) 9.3x 9.5x 10.4x
Debt (2) 796$ 795$ 795$
FFO to Debt(3) 41.5% 41.8% 48.7%
Capitalization
Northern Natural Gas shareholder’s equity 1,580$ 1,409$ 1,410$
Debt 796 795 795
Capitalization 2,376$ 2,204$ 2,205$
Debt to Total Capitalization(4) 33.5% 36.1% 36.1%
Northern Powergrid
Non-GAAP Financial Measures
(£ millions)
(1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest
(2) Debt includes short-term debt and current maturities
(3) FFO to Debt equals FFO divided by Debt
(4) Debt to Total Capitalization equals Debt divided by Capitalization
FFO 2017 2016 2015
Net cash flows from operating activities 338£ 382£ 345£
+/- Changes in other operating assets and liabilities 26 31 48
FFO 364£ 413£ 393£
Interest expense 103£ 100£ 95£
FFO Interest Coverage(1) 4.5x 5.1x 5.1x
Debt (2) 2,059£ 1,906£ 1,858£
FFO to Debt(3) 17.7% 21.7% 21.2%
Capitalization
Northern Powergrid shareholders’ equity 2,721£ 2,491£ 2,297£
Debt 2,059 1,906 1,858
Noncontrolling interests 35 36 36
Capitalization 4,815£ 4,433£ 4,191£
Debt to Total Capitalization(4) 42.8% 43.0% 44.3%
Cindy Crane Stefan Bird
President and CEO
Pacific Power
President and CEO
Rocky Mountain Power
2018 Fixed-Income Investor Conference
PacifiCorp Retail Sales
2017 compared to 2016 up 0.5%
• Commercial sales up 4.5%
• Residential sales unchanged
• Industrial sales down 0.1%
2018 forecast vs. 2017 down 1.3%
• Industrial sales – lower due to changes
in large customers’ operating projections
• Commercial sales – relatively flat, but
lower due to energy efficiency programs
• Residential sales – lower due to use per
customer reductions that more than
offset growth in new customers
Annual Growth Rate
2012 = 0.1%
2013 = 0.3%
2014 = 1.2%
2015 = (0.9%)
2016 = (0.7%)
2017 = 0.5%
2018 = (1.3%)
2019 = (0.2%)
0
7
14
21
28
35
42
49
56
63
2012 2013 2014 2015 2016 2017 2018F 2019F
T
W
h
PacifiCorp Electric Retail Sales
Weather Normalized
Annual Growth Rate
2013 = 0.3%
2014 = 1.2%
2015 = (0.9%)
2016 = (0.7%)
2017 = 0.5%
2018 = (1.3%)
2019 = (0.2%)
PacifiCorp Capital Expenditures
2018-2020 forecast vs. prior plan up $1,467 million
• $1,215 million higher growth capital expenditures include safe harbor
wind investments to deliver cost-effective fleet repowering and
greenfield wind opportunities in-service in 2019-2020, as well as a
new transmission line. The growth projects are anticipated to yield net
savings to customers
• Operating capital expenditures relatively flat
($ millions)
2018-2020
Current
Plan
Prior
Plan
Growth $ 3,139 $ 1,924
Operating 1,975 1,723
Total $ 5,114 $ 3,647
$660 $569 $496 $530
$821
$624
$256 $334
$273
$682
$1,279
$1,178
-
500
1,000
1,500
2,000
2,500
2015 2016 2017 2018F 2019F 2020F
Operating Growth
($
m
il
li
ons
)
Energy Vision 2020 Overview
Includes:
• Repowering of 999 MW of existing wind facilities; 12
projects; approximately $1.1 billion
• 1,111 MW of new owned wind facilities; four projects;
approximately $1.5 billion. An additional 200 MW of wind
procured through PPA
• 140-mile, 500 kV segment of Gateway West transmission;
approximately $700 million
• 230 kV transmission network upgrades required for wind
interconnection: approximately $100 million
(1) Includes approximately $300 million for assumed vendor supplied financing transaction associated with one of the four new wind projects (200 MW) assumed to be paid in 2020
New Wind Facilities
Repowered Wind Facilities
New Transmission Line
Energy Vision 2020 is an investment of
approximately $3.4 billion(1) to expand the amount
of wind power serving customers by 2020
Wind Project Location
In-Service
Date
Capacity
(MW)
Number of
Turbines
Description
TB Flats I & II
Carbon & Albany
Counties, WY
Nov. 15, 2020 500 134
PacifiCorp Self-Build with EPC Agreement;
Invenergy Development Transfer Agreement;
Vestas 2.0 MW to 4.2 MW WTGs
Cedar Springs
Converse County,
WY
Dec. 31, 2020 400 160
NextEra development;
50 percent Build Transfer Agreement to PacifiCorp /
50 percent PPA; GE 2.3 MW to 2.5 MW WTGs
Ekola Flats
Carbon County,
WY
Nov. 15, 2020 250 64
PacifiCorp Self-Build with EPC Agreement;
Invenergy Development Transfer Agreement;
GE and Vestas 2.3 MW to 4.2 MW WTGs
Uinta Uinta County, WY Oct. 31, 2020 161 47
Invenergy development;
Invenergy Build-Transfer Agreement to PacifiCorp
GE 2.3 MW to 3.8 MW WTGs
Total 1,311
New Wind and Transmission Facilities
Transmission Projects
1) New 140-mile, 500 kV Aeolus-to-Bridger/Anticline line; including new Aeolus and Anticline substations
2) New 5-mile, 345 kV Anticline-to-Jim Bridger line; including modifications at Jim Bridger substation
3) New voltage control device at Latham substation
4) New 16-mile, 230 kV line from Shirley Basin to proposed Aeolus substation, with substation modifications (TB Flats I & II)
5) Reconstruction of 16-mile, 230 kV Shirley Basin-Freezeout-Aeolus line, with substation modifications (Cedar Springs)
6) Reconstruction of 15-mile, 230 kV Freezeout-Standpipe-Aeolus line, with substation modifications (Cedar Springs)
7) New 7-mile, 230 kV line to replace the Ben Lomond-Naughton circuit, and new 230 kV three breaker ring bus (Uinta)
Aeolus-to-Bridger/Anticline line; approximately $680 million 230 kV network upgrades; approximately $110 million
Project Name Location
In-Service
Date
Current Net
Capacity
(MW)
Project
Generation
Increase (%)
Wyoming Projects
Glenrock I Glenrock, WY 11/1/2019 99.0 21.7%
Glenrock III Glenrock, WY 11/1/2019 39.0 20.7%
Rolling Hills Glenrock, WY 10/1/2019 99.0 17.4%
Seven Mile Hill I Medicine Bow, WY 11/1/2019 99.0 23.0%
Seven Mile Hill II Medicine Bow, WY 11/1/2019 19.5 22.8%
High Plains McFadden, WY 10/1/2019 99.0 24.9%
McFadden Ridge McFadden, WY 11/1/2019 28.5 25.3%
Dunlap I Medicine Bow, WY 11/1/2019 111.0 22.5%
594.0 22.2%
Washington Projects
Marengo I Dayton, WA 11/1/2019 140.4 35.5%
Marengo II Dayton, WA 11/1/2019 70.2 39.4%
Goodnoe Hills Goldendale, WA 10/1/2019 94.0 28.4%
304.6 34.3%
Oregon Project
Leaning Juniper Arlington, OR 10/1/2019 100.5 27.0%
Total 999.1 25.7%
Wind Repowering
Price-Policy Scenario Wind Repowering New Wind and Transmission
Medium Gas, Medium CO2 $273 million $167 million
Customer Benefits and Remaining Milestones
Present-Value Customer Benefit of Energy Vision 2020 Projects
(2017-2050)
Key Milestones Date
Complete 2017R Wind Request for Proposals (RFP) evaluation and determination of final shortlist Complete
Obtain 2017R Wind RFP final shortlist acknowledgement from Oregon (Utah to be included in regulatory pre-approval) March 30, 2018
Obtain regulatory pre-approvals for new wind and transmission resources (Idaho, Utah and Wyoming) June 15, 2018
Obtain regulatory pre-approvals for repowering (Utah and Wyoming; Idaho already received via settlement) June 15, 2018
Issue EPC limited notice-to-proceed for new wind resources (surveys, design and procurement prep) June 15, 2018
Issue EPC limited notice-to-proceed for transmission line December 31, 2018
Acquire all required rights of way and easements for transmission line March 31, 2019
Issue EPC full notice-to-proceed for new wind and transmission line contracts April 1, 2019
Complete 2019 repowering projects March to December 2019
Complete 2020 repowering projects June to December 2020
Begin delivery of wind turbine generators (new wind projects) May 5, 2020
New wind and transmission in-service December 31, 2020
0 5,000 10,000 15,000 20,000 25,000
GWh
Wyoming
2018F
2017
Rocky Mountain Power Retail Sales
2018 forecast sales compared to 2017 down 1.2%
• Industrial sales – lower due to changes in large customers’
operating projections
• Commercial sales – higher due to economic growth,
partially offset by energy efficiency programs
• Residential sales – lower due to decline in use-per-
customer, partially offset by new customer growth
0
8
16
24
32
40
2012 2013 2014 2015 2016 2017 2018F 2019F
T
W
h
Rocky Mountain Power
Electric Retail Sales
Weather Normalized
2012 = 0.4%
2013 = 0.5%
2014 = 1.2%
2015 = (1.0%)
2016 = (1.3%)
2017 = 0.6%
2018 = (1.2%)
2019 = (0.3%)
Annual Growth Rate
427 GWh (-1.8%)
10 GWh (0.3%)
28 GWh (-0.3%)
0 5,000 10,000 15,000 20,000 25,000
GWh
Idaho
2018F
2017
0 5,000 10,000 15,000 20,000 25,000
GWh
Utah
2018F
2017
Rocky Mountain Power
Regulatory Update
Utah (authorized ROE 9.8%)
• Last general rate case filed in 2014 and no general rate case in the near future; Rocky Mountain Power made
a customer pledge to not increase base rates prior to 2021
• Energy Balancing Account filing to refund $6.5 million in excess deferred net power costs, reduced rates 0.7%
effective May 1, 2017
• The Utah Public Utilities Commission (UPSC) issued a deferred accounting order on February 28, 2018,
requiring PacifiCorp to defer the impacts of 2017 Tax Reform beginning January 1, 2018. A procedural
schedule has been set targeting a rate reduction effective May 1, 2018
Wyoming (authorized ROE 9.5%)
• Last general rate case filed in 2015 and no general rate case in the near future; Rocky Mountain Power made
a customer pledge to not increase base rates prior to 2021
• Energy Cost Adjustment Mechanism filing to refund $5.4 million in excess deferred net power costs, reduced
rates 2.3%, effective January 1, 2018
• The Wyoming Public Service Commission directed all utilities to defer 2017 Tax Reform impacts beginning
January 1, 2018. Wyoming has directed utilities to provide an assessment of the impacts from 2017 Tax
Reform and proposed tax rate reduction plans by March 30, 2018
Idaho (authorized ROE 9.9%)
• Last general rate case filed in 2011 and no general rate case in the near future
• Energy Cost Adjustment Mechanism filing to recover $7.5 million in deferred net power costs with offset to
depreciation deferral, reduced rates 1.0%, effective June 1, 2017
• The Idaho Utilities Commission ordered all utilities to defer 2017 Tax Reform impacts beginning January 1,
2018 and directed utilities to file a report quantifying the impacts and rate reduction by March 30, 2018, based
upon a 2017 test period
Utah Private Generation Update
• In November 2016, PacifiCorp filed applications in Utah to address cost shifting due to
private generation (PG)
• A settlement was reached with parties and was approved by the UPSC on September 29, 2017,
ending the existing net metering program November 15, 2017, and transitioning to a new
program with a separate compensation rate for exported power
• Existing PG customers on net metering (pre-November 15) will be grandfathered and continue to
receive the full retail rate (about 10.60 ¢/kWh for residential customers) on that program until
January 1, 2036
• A transition program for new PG customers began December 1, 2017, for a limited number of
customers, with a fixed export rate until January 1, 2033
− New residential PG customers will receive a credit of 9.2 ¢/kWh through 2032 for excess
energy. Total new residential customers eligible for the credit rate will be capped at 170 MW
− New PG rates for commercial customers are 92.5% of current average commercial energy
rates through 2032 for excess energy. Commercial customer participation is capped at
70 MW
− The program values imports (rates paid to the utility) and exports (rates paid by the utility for
excess power sent to the grid) on a 15-minute basis
• A new proceeding has been initiated at the UPSC to determine the export credit for new PG
customers after the transition program
Rocky Mountain Power
Utah Net Metering
• Net metering interconnections will continue to grow in 2018 as interconnections are completed for applications
received prior to November 15, 2017. A total of 3,554 eligible applications have not completed the
interconnection process
• Transition program has received applications to reserve 3.6 MW of total 240 MW (70 MW commercial,
170 MW residential) available since December 1, 2017, program initiation. Transition program applications are
significantly down compared to prior year net metering applications
Applications Received January February March YTD Totals
2017 (Net Metering) 603 917 829 2,349
2018 (Transition Program) 86 245 230 561
1,548 2,222
3,572
6,690
16,689
27,823
29,420
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
2012 2013 2014 2015 2016 2017 2018
YTD
Utah Net Metering
Cummulative Interconnections
Residential Non-Residential Total
(1) 2018 YTD as of March 15, 2018
(1)
Solar Development Opportunities
• Rocky Mountain Power sponsored legislation in Utah called the sustainable transportation and
energy plan (STEP), which was voted into law in spring 2016. A provision of STEP created a
renewable energy tariff (RET) for customers desiring more renewable energy than PacifiCorp’s
standard generation portfolio
• Rocky Mountain Power also sponsored legislation in Utah to enable it to own solar plant without
having to normalize the investment tax credit (ITC), which passed the Utah legislature and is
pending the Governor’s signature
• As such, there exists significant opportunities for Rocky Mountain Power to own solar plants for
customers that utilize the RET
Customer Size (MW) In-Service Date
Salt Lake City – municipal 70 2020
Salt Lake City – community 1,250 2032
Park City/Summit County – municipal 5 2022 – 2025
Park City/Summit County – community 250 2032
Moab – municipal 1 2024
Moab – community 20 2032
New Large C&I to Utah 800 2020 – 2025
Stefan Bird
President & CEO
Pacific Power
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000
GWh
Oregon
2018F
2017
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000
GWh
Washington
2018F
2017
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000
GWh
California
2018F
2017
Pacific Power Retail Sales
0
5
10
15
20
2012 2013 2014 2015 2016 2017 2018F 2019F
T
W
h
Pacific Power
Electric Retail Sales
Weather Normalized
2012 = (0.4)%
2013 = 0.0%
2014 = 1.3%
2015 = (0.5%)
2016 = 0.4%
2017 = 0.2%
2018 = (1.5%)
2019 = 0.1%
Annual Growth Rate
2018 forecast sales compared to 2017 down 1.5%
• Industrial sales – lower due to the loss of a large industrial
customer
• Commercial sales – lower due to efficiency programs offset by
economic growth and expansion of data centers
• Residential sales – lower due to decline in use-per-customer
from energy efficiency
169 GWh (-1.3%)
4 GWh (-0.5%)
97 GWh (-2.3%)
Oregon (authorized ROE 9.8%)
• Pacific Power made a customer pledge to not increase base rates prior to 2021; the last general rate case was
filed in 2013
• Transition Adjustment Mechanism rate increase of $2.0 million or 0.2% for changes in forecast net power costs
and production tax credits, effective January 1, 2018
• The Public Utility Commission of Oregon has indicated support to defer 2017 Tax Reform impacts; the
Commission will hold workshops to discuss utilities’ proposed deferrals and amortization methodologies and to
determine next steps
Washington (authorized ROE 9.5%)
• No general rate case in the near future; the last rate case with a two-year rate plan was filed in 2015
• Washington’s decoupling mechanism measures company annualized earnings and provides for rate adjustments
based on an earnings test. The 2017 result showed the company over earned and will surcredit approximately
$2.5 million to customers
• The Washington Utilities and Transportation Commission has indicated support to defer 2017 Tax Reform
impacts, and has scheduled a meeting in late April to discuss
California (authorized ROE 10.6%)
• Next general rate case will be filed using a 2019 test period; the last general rate case was filed in 2009
• Energy Cost Adjustment Clause and Greenhouse Gas Allowance Costs and Revenues Application rate reduction
of $0.2 million (3.8%), for changes in forecast net power costs and greenhouse gas costs effective January 1,
2018
• Beginning April 1, 2018, PacifiCorp is authorized to recover $3.2 million over approximately a two-year period for
amounts recorded in its Catastrophic Events Memorandum Account
• The California Public Utilities Commission has indicated support to defer 2017 Tax Reform impacts, and a
memorandum account was established beginning January 1, 2018
Pacific Power Regulatory Update
• Senate Bill 1547 was signed into law March 8, 2016
– Increases renewable portfolio standard to 27% by 2025, 35% by 2030, 45% by
2035, 50% by 2040
• With Energy Vision 2020 resources, Pacific Power’s compliance position is sufficient
through 2036
– Removes coal from Oregon rates by January 1, 2030
– Incorporates production tax credits in annual power cost mechanism
– Establishes community solar program
• Community solar rulemaking completed in 2017, implementation underway, with
program administrator to be selected by mid-2018
– Authorizes utilities to invest in electric vehicle charging
• Electric utility transportation electrification proposals were approved in early
March 2018
– Maintains level playing field for service territory acquisitions by requiring acquirer
to meet renewable portfolio standard requirements and pay for any stranded
costs
Oregon Clean Electricity
and Coal Transition Plan Update
Advanced Metering Infrastructure Projects
Scope Benefits
• $122 million capital investment
• Oregon
o 590,000 smart meters
o In-service January 2018 – December 2019
• California
o 47,000 smart meters
o In-service December 2018
• Further deployments being assessed
• Project cost savings fully offset
investment/operating cost
• Customers gain access to near real-time
consumption data and information to
proactively manage their monthly usage
• Improved outage detection and response
• Improved connect/disconnect service
• Improved system monitoring for real-time
operations and distribution system planning
Energy Imbalance Market
Benefits November 2014 – December 2017
Balancing Area Authority Total ($ millions)
CAISO $79.2
PacifiCorp $113.8
NV Energy $40.6
Arizona Public Service $40.5
Puget Sound Energy $11.4
Portland General Electric $2.8
Total $288.4
• The energy imbalance market is in its fourth
year with cumulative benefits totaling
$288 million through December 2017
• PacifiCorp’s customers have benefited by $114
million since November 2014, and NV Energy,
which joined a year later, has realized customer
benefits of $41 million. Berkshire Hathaway
Energy customer benefits total $155 million
PacifiCorp Appendix
PacifiCorp Overview
• Six-state service territory
‒ Utah – Oregon
‒ Idaho – Washington
‒ Wyoming – California
• 5,500 employees
• 1.9 million electricity customers
• 141,000 square miles of service
territory
• 16,500 transmission line miles
• 10,887 MW(1) owned power
capacity
(1) Net MW owned in operation as of December 31, 2017
PacifiCorp Retail Sales
2017 Retail Sales by Class (GWh) 2017 Retail Sales by State (GWh)
2017 Retail Electric Revenue: $4.9 billion
Residential
30%
Commercial
32%
Industrial,
Irrigation
and Other
38%
Utah
44%
Oregon
24%
Wyoming
17%
Washington
8%
Idaho
6%
California
1%
PacifiCorp Power Capacity and Asset Profile
Power generating fleet increase primarily
attributed to:
• 1,654 MW Natural Gas – Lake Side 1 &
2 and Chehalis
• 998 MW Wind – 594 MW Eastside and
404 MW Westside
• (172) MW Coal – retired Carbon plant
Asset Profile
69%
9%
22%
Renewables and
Other
Natural Gas
Generation
Coal Generation
Net Property, Plant and Equipment as of December 31, 2017
March 31, 2006
Power Capacity – 8,470 MW (1)
December 31, 2017
Power Capacity – 10,887 MW (1)
(1) Net MW owned in operation
Coal
72%
Natural
Gas
13%
Hydro and
Other
15%
Coal
54%
Natural
Gas
25%
Hydro
11%
Wind and
Other
10%
PacifiCorp
Environmental Position
Arizona
• Re-assessed Regional Haze State Implementation Plan (SIP) for Cholla approved by EPA effective April 26, 2017; allowing
Cholla Unit 4 to avoid the installation of selective catalytic reduction (SCR) and remain coal-fueled through April 2025
Colorado
• Colorado Air Quality Board approved alternate Regional Haze SIP compliance strategy for Craig Unit 1 on December 15, 2016;
incorporating year-end 2025 shutdown in lieu of SCR installation. SIP amendment documentation submitted to EPA on May 27,
2017, with review and approval expected to carry through 2018
Utah
• EPA has commenced reconsideration of Regional Haze Federal Implementation Plan (FIP) requiring SCR on Hunter Units 1 and
2 and Huntington Units 1 and 2 by August 4, 2021. The 10th Circuit Court granted a day-for-day stay of the compliance deadline
and placed the FIP litigation in abatement September 11, 2017
Wyoming
• EPA’s Regional Haze FIP for the Wyodak plant, requiring the installation of SCR within five years (i.e., by 2019), was granted a
day-for-day stay by the 10th Circuit Court in September 2014. Multiparty litigation of the FIP is currently being held in abatement
pending ongoing settlement of one of the parties
• EPA approved the Regional Haze SIP requiring installation of SCR on Jim Bridger Units 1 and 2 in 2021 and 2022. PacifiCorp is
assessing compliance alternatives in its IRP proceedings that avoid the installation of SCR while delivering intended Regional
Haze outcomes
• Naughton Unit 3 will be removed from coal-fueled service by January 30, 2019, in lieu of SCR and baghouse retrofits prescribed
by the approved Regional Haze SIP. Amended Regional Haze SIP submitted to EPA for review and approval in November 2017.
PacifiCorp is assessing natural gas conversion options in its IRP proceedings
Environmental Expenditures
• Forecast(1) environmental expenditures include $19 million in 2018, $16 million in 2019 and $21 million in 2020
(1) Environmental expenditures forecast includes PacifiCorp’s share of minority-owned Craig, Cholla, Colstrip and Hayden plants. Amounts include debt AFUDC and escalation
but exclude non-cash equity AFUDC
PacifiCorp Major Transmission Projects
• Wallula-to-McNary
– Planned in-service November 2018
• Gateway West
– BLM record of decision on 8 of 10 segments
November 2013
– Remaining two segments across Idaho record
of decision expected March 2018
• Aeolus-to-Jim Bridger/Anticline
– Segment D2 of Gateway West
– Planned in-service 2020
• Gateway South
– BLM record of decision December 2016
• Boardman-to-Hemingway
– BLM record of decision December 2017
– Oregon Energy Facility Siting Council permit
target date August 2020
• Segments In-Service
– Populus-to-Terminal November 2010
– Mona-to-Oquirrh May 2013
– Sigurd-to-Red Butte May 2015
Over $6 billion total investment planned; $1.6 billion placed in-service
Adam Wright
President and CEO
MidAmerican Energy Company
2018 Fixed-Income Investor Conference
Electric Retail Sales
• Economic and Load Data
– Service territory has experienced strong electric load growth
– Forecast loads for 2018 and 2019 reflect a continuation, but slight
moderation of this trend, particularly for the industrial class due to
announced data center and biotechnology expansions within MidAmerican
Energy’s service territory
– Data centers attracted to relatively low, stable electric rates and
MidAmerican Energy’s wind portfolio
0
5
10
15
20
25
30
2012 2013 2014 2015 2016 2017 2018F 2019F
T
W
h
MidAmerican Energy Electric Retail Sales
Weather Normalized
Annual Growth Rates:
2013 = 1.7%
2014 = 2.6%
2015 = 1.8%
2016 = 2.9%
2017 = 3.2%
2018 = 0.7%
2019 = 1.0%
Capital Investment Plan
• First 334 MW of Wind XI project completed on time and within the
regulatory cost cap in fourth quarter 2017
• Construction continues on the remainder of the 2,000 MW, $3.6 billion
Wind XI project
– 715 MW (2018), 951 MW (2019)
• Wind repowering efforts continuing for oldest 1.5 MW GE turbines
– 272 turbines (2017), 192 turbines (2018), 139 turbines (2019),
102 turbines (2020)
– Evaluating older Siemens turbines in fleet
• Operating capital varies with timing of major power generation planned
outages and system requirements
$339 $430 $488
$653
$404 $352
$1,107
$1,206
$1,285
$1,743
$1,307
$545
-
500
1,000
1,500
2,000
2,500
2015 2016 2017 2018F 2019F 2020F
($
m
il
li
ons
)
Operating Growth
($ millions)
2018-2020
Current
Plan
Prior
Plan
Operating $ 1,409 $ 958
Growth 3,595 2,857
Total $ 5,004 $ 3,815
Build Renewable Energy
Green
Advantage
Percent(2)
MW
Installed
Capacity
Cumulative
Investment
($ billions)
2012 Actual 3% 2,285 $3.7
2013 Actual 6% 2,329 $3.8
2014 Actual 28% 2,832 $4.6
2015 Actual 38% 3,448 $5.8
2016 Actual 47% 4,048 $7.0
2017 Actual 51% 4,387 $7.7
2018 Plan 64% 5,114 $9.1
2019 Plan 79% 6,065 $10.9
2020 Plan 95% 6,065 $11.4
MidAmerican Energy’s
Iowa Wind Generation(1)
MidAmerican Energy Participates in the
Midcontinent Independent System Operator
(1) Includes investment in repowered facilities
(2) Represents the portion of Iowa retail sales supplied by renewable energy
as certified by the Iowa Utilities Board
All or some of the renewable attributes associated with the generation have
been or may in the future be: (a) sold to third parties, or (b) used to comply
with future regulatory requirements
The size of MISO’s non-renewable installed capacity enables
MidAmerican to continue developing wind generation while
maintaining satisfactory reliability. Non-renewable sources
account for 86% of MISO capacity
Forecast 2019 Iowa Electric Net Plant
including Wind XI
• 57% of Iowa electric net plant subject to
rate-making principles
• 11.5% weighted average return on equity
• 32 years weighted average remaining life
Rate Status
Annual Growth Rates:
2010 = 4.2%
2011 = 1.2%
2012 = 0.6%
2013 = 1.7%
2014 = 6.7%
2015 = 3.4%
Subject to Rate Principles
Subject to General Rate Order
$8,093
57%
$6,022
43%
• No expected need for electric base rate increase through
2029, subject to the outcome of 2017 Tax Reform regulatory
proceedings
• All state jurisdictions have energy and transmission cost rider
recovery mechanisms; Iowa and South Dakota riders include
PTCs from over half of wind projects currently in-service
• Rate base reductions via Iowa revenue sharing and other
arrangements mitigate the need for future base rate increases
• Iowa revenue sharing for 2018 and beyond reduces rate base
for 100% of pre-tax income on ROEs exceeding a weighted
average value calculated annually; based on current forecast,
trigger would be 10.5% for 2018
• Proceedings initiated in all states to provide customers the
benefit of lower income tax expense resulting from 2017 Tax
Reform legislation
– In Iowa, MidAmerican Energy’s largest jurisdiction,
proposal is to provide customers with the benefits of tax
reform by lowering rates for the change in tax expense
and continuing to reduce rate base for the excess
deferred taxes
– Proposal in Iowa balances current customer benefits
with the objective of eliminating or minimizing future
base rate increases
Electric rates among the lowest in the Midwest region and the United States
MidAmerican Energy Appendix
MidAmerican Energy Company Overview
SOUTH DAKOTA
NEBRASKA
KANSAS MISSOURI
ILLINOIS
WISCONSIN
MINNESOTA
IOWA
MidAmerican Energy
Service Territory
Major Generating Facilities
Wind Projects
• Headquartered in Des Moines, Iowa
• 3,300 employees
• 1.6 million electric and natural gas customers
in four Midwestern states
• 10,608 MW(1) of owned capacity
• Owned capacity by fuel type:
12/31/17(1) 12/31/00
– Coal 26% 70%
– Natural gas 13% 19%
– Wind(2) 57% 0%
– Nuclear and other 4% 11%
(1) Net MW owned in operation and under construction as of December 31, 2017
(2) All or some of the renewable energy attributes associated with generation from
these generating facilities may be: (a) used in future years to comply with
renewable portfolio standards or other regulatory requirements or (b) sold to third
parties in the form of renewable energy credits or other environmental
commodities
MidAmerican Energy
2017 Retail Electric Sales by Class (GWh)
2017 Retail Electric Revenue: $1.8 billion
Residential
25%
Commercial
15%
Industrial
53%
Other
7%
• Private generation activities in Iowa
– Iowa Utilities Board approved MidAmerican Energy’s net metering tariff
in 2017 as part of a three to five year pilot project
• Size cap on system equal to customer’s “load”
• Annual payout of excess energy: 50% paid to customer; 50% paid to
low-income heating assistance program
• Payout at avoided cost
– Inquiry concluded: Avoided costs set at locational marginal price
• MidAmerican Energy’s approach to private generation
in Iowa
– Focused on keeping costs low for all customers
– Avoid inter-class cross-subsidization through proper rate design
– Considering how to add solar generation options for customers
– Considering how to add energy storage to the system
Private Generation in Iowa
MidAmerican Energy
Environmental Position
• MidAmerican Energy has 2,718 MW(1) of
coal-fueled power capacity
• Projected environmental capital spend(2)
– $129 million from 2018-2020
(1) Net owned capacity as of December 31, 2017
(2) Environmental capital expenditures forecast excludes equity AFUDC
(3) Net MW owned in operation and under construction
Asset Profile
85%
2%
13%
Renewables
and Other
Natural Gas
Generation
Coal
Generation
Net Property, Plant and Equipment as of December 31, 2017
December 31, 2000
Power Capacity – 4,086 MW (3)
December 31, 2017
Power Capacity – 10,608 MW (3)
Coal
26%
Natural Gas
13%
Nuclear and
other
4%
Wind
57%
Coal
70%
Natural
Gas
19%
Nuclear
and Other
11%
Paul Caudill
CEO
NV Energy
2018 Fixed-Income Investor Conference
NV Energy Electric Retail Sales
System Load Comparison 2017 versus 2016
Nevada Power
• Commercial (including distribution only service)
down 0.2% due to more aggressive energy
efficiency programs
• Residential up 1.5% due to customer growth
• Industrial (including distribution only service) up
0.1%. Retail and convention space increases
almost offset by energy efficiency programs
Sierra Pacific
• Industrial up 4.3% primarily led by manufacturing
• Residential down 0.6% primarily due to the net
metering billing change from 2016 to 2017
• Large mining down 1.1% due to low metal prices
Load Forecast For 2018 and 2019
Nevada Power
• Retail, convention center, small hotel and
residential customer growth drives load growth in
2018 and 2019
Sierra Pacific
• Increasing data center and manufacturing loads
will help drive non-residential load growth
Annual Growth Rate
2013 = 1.4%
2014 = (0.4%)
2015 = 3.5%
2016 = 2.2%
2017 = 1.8%
2018 = 4.1%
2019 = 2.8%
Annual Growth Rate
2013 = 0.0%
2014 = 0.1%
2015 = 1.9%
2016 = 1.5%
2017 = 0.6%
2018 = 0.3%
2019 = 1.1%
Capital Investment Plan
• Capital investment for 2018-2020 increased
$29.0 million from prior plan primarily due to
additional electric delivery projects related to
grid resilience and reliability, the acceleration of
a 35 MW solar project and new business, offset
by the removal of natural gas acquisitions
($ millions)
2018-2020
Current
Plan
Prior
Plan
Operating $ 1,097 $ 1,010
Growth $ 432 $ 490
Total $ 1,529 $ 1,500
$522 $528
$364 $385 $379 $333
$49
$1
$93
$139
$178
$115
-
100
200
300
400
500
600
2015 2016 2017 2018F 2019F 2020F
($
m
il
li
ons
)
Operating Growth
• Regulatory Rates Review
– The Public Utilities Commission of Nevada (PUCN) issued an order for Nevada Power on
December 29, 2017, that included a 9.4% return on equity and requires sharing 50% of all
revenue earned in excess of 9.7%; included rate reductions of $26 million, consisting of
reductions in both fixed and volumetric charges to
Nevada Power’s customers
– Nevada Power and Sierra Pacific filed advice letters February 14, 2018, requesting approval of a
tax rate reduction rider reducing electric rates for all customers of $59 million and $25 million,
respectively; reflects 2017 Tax Reform, including the corporate federal income tax rate
modification from 35% to 21% and the PUCN issued an order supporting the filing
• Energy Supply Plan Update
– Nevada Power and Sierra Pacific filed energy supply plan updates September 1, 2017, with the
PUCN. Filing included a proposal to undertake a laddering strategy for acquiring energy, similar
to approach taken for acquiring physical gas. Strategy would mitigate risk associated with
increasingly tight capacity market during certain peak summer periods
– The PUCN approved plans for Sierra Pacific on October 25, 2017, and Nevada Power on
November 8, 2017
• Deferred Energy Accounting Adjustment Filings
– On March 1, 2018, deferred energy accounting adjustment filings were made with the PUCN to
review recovery of fuel and purchased power expenses incurred in 2017 and reset public policy
program charges
– Filing requested no change to fuel and purchase power rate, with slight reduction in public policy
program charges of $4.0 million
NV Energy Regulatory Update
• Energy Choice Initiative Investigatory Docket
– Nevada Governor’s Committee on Energy Choice petitioned the PUCN to open docket identifying
timeline, programs and statutes requiring revision and analyzing wholesale/retail market
structures for implementation of a deregulation constitutional amendment
– NV Energy indicated if the constitutional amendment passes then Nevada Power and Sierra
Pacific will not be electric energy providers and indicated initial costs to customers of $5-$7 billion
– Investigatory docket workshops held January 9-30, 2018; final report estimated April 2018
• Nevada Legislative Energy Committee
– Nevada Legislative Energy Committee met January 10, 2018, with chairman stating there would
be five meetings during the interim. Proponents of Question 3 gave a presentation on what they
believe the constitutional amendment actually does, with numerous questions from committee
members raising concerns. Audience included environmental groups, AARP© and lobbyists with
energy and environmental clients
• Petition for Declaratory Order
– As a key component to double renewable energy production by 2023, NV Energy filed a petition
for declaratory order requesting a finding that for renewable generating facilities owned by
NV Energy, the PUCN has the authority to establish a reasonable rate by reference to market-
based pricing rather than traditional rate-of-return analysis
– After reaching an agreement with stakeholders at the hearing February 27, 2018, the chairman
was complimentary and indicated he would prepare a draft order for commission consideration
NV Energy Regulatory Update
Nevada Deregulation Constitutional Amendment
Update
Considerations
Manageable
Debt
Maturities
• Recent deleveraging strengthened both utilities’ equity ratios and financing flexibility
• Bondable property exceeds outstanding debt, and is expected (excluding generation) to be sufficient to support
transmission and distribution leverage, minimizing risk that debt is called because of insufficient property basis
• 2018-2019 debt maturities may be refinanced with shorter tenures to maximize recapitalization options and ‘call’ flexibility
and minimize potential make whole premiums, if necessary
2022 2021 2020 2019 2018 2017 2016 2023
NPC GRC Filing SPPC GRC Filing
Voter Approval
NPC GRC Filing SPPC GRC Filing
Committee on Energy
Choice
Nevada Vote (Constitutional
Amendment and Governor
election)
Energy Choice
Report to Governor
Legislature’s Deadline To Adopt
Deregulation Legislation
Legislative Session Legislative Session Legislative Session Legislative
Session
NPC GRC Filing
PUCN Report due to Governor’s
Committee on Energy Choice
Adequate
Liquidity
• $650 million revolver capacity available
• $125 million of issuance capacity under tax exempts
• Effective SEC shelf registrations
• Strong cash generation
Capital
Reductions
• Legislature could enact deregulation anytime during
the 2018–2023 period if constitutional amendment
passes in November 2018
• Increased transmission and distribution spending
and additional recovery of generation investments
prior to the possible implementation of deregulation
mitigates debt reductions
• Both utilities will work with regulators to minimize
transition costs and stranded asset if constitutional
amendment passes
Consistent with the deregulation constitutional amendment ballot language, the following
may be assumed:
• Power generation and energy supply will be established as a competitive service; will
require utilities to divest of existing power plants, power purchase agreements and
gas transportation contracts
– NV Energy will be out of the power generation side of the business in order to
prohibit the grant of monopolies for the supply of electricity
• Transmission and distribution service will remain a regulated rate of return service
due to the cost of duplicating investments
– Consistent with what has been done in other fully competitive retail jurisdictions
– Legislature need not provide for transmission and distribution deregulation to
establish the competitive retail market
• Default or provider of last resort service will not be provided by regulated utilities in
order to prevent the grant of an exclusive monopoly
– NV Energy will not provide default or provider of last resort services
• Jobs for NV Energy colleagues will remain a primary focus of decision makers
Fundamental Assumptions
Coalition to Defeat Question 3
• Coalition to Defeat Question 3, a bipartisan coalition to defeat the
deregulation constitutional amendment, announced February 3, 2018
• Founding members include large and small businesses, elected
officials, rural electric associations, IBEW, AFLCIO, and various
community representatives
• NV Energy joined the Coalition to Defeat Question 3 to make sure all
Nevadans have the facts about this very complicated issue that has
the potential to dismantle an electric system that has, and will
continue to provide low costs, increased clean energy production,
great customer service and industry-leading reliability
• Ongoing efforts to increase membership in coalition and awareness of
costs, risks and uncertainty of Question 3, a constitutional
amendment that would drastically change Nevada’s electricity system
• NOon3.com, Facebook and Twitter launched
Net Energy Metering Update
• Net metering capacity installed as of December 31, 2017 was 238 MW
• In June 2017, the Nevada Legislature passed Assembly Bill 405 that established revised
net metering rules and provisions on how to credit excess energy that is fed back to the
grid for systems less than 25 kW
– Non-Time of Use Tariffs – The PUCN completed its regulatory proceedings and
approved non-time of use private generation tariffs at the end of 2017
– Time of Use Tariffs – NV Energy negotiated a resolution with interested
stakeholders, resulting in approval of four optional time of use schedules, one of
which contains demand charges; agreement provides for stakeholders to work
collaboratively to enroll a specified number of customers in each schedule
– Status of New Private Generation Customers – Generation is netted monthly of
received and delivered energy. Excess energy is credited at the following rates
(excluding public program costs):
• 1st 80 MW – 95% of retail rate
o 20.3 MW of applications as of March 1
• 2nd 80 MW – 88% of retail rate
• 3rd 80 MW – 81% of retail rate
• Excess of previous 240 MW – 75% of retail rate
Major Customer Applications to Utilize
Alternate Provider
Applicant
Peak Load
(MW)
Impact Fee
($ millions)
Status
MGM Resorts International* (south) 174 $82.2
Transition completed October 2016;
$16 million reduction credit to the impact fee
ordered by the PUCN
Wynn Las Vegas* (south) 31 $15.3
Transition completed October 2016; hearing
held on impact fee reduction consideration
with post-hearing briefs February 23, 2017.
No decision announced
Switch Ltd. (south) 87 $27.0 Transition completed June 2017
Switch Ltd. (north) 2 $0.0 Transition completed June 2017
Caesars Enterprise Services LLC*
(south)
87 $44.0
Application approved March 2017; transition
for final location occurred March 1, 2018
Caesars Enterprise Services LLC
(north)
10 $3.5
Application approved March 2017; transition
completed January 1, 2018
Peppermill Resorts (north) 9 $3.3
Order authorizing transition issued
August 21, 2017; meter installation
completed; anticipate April 1, 2018, transition
Total 400 $175.3
*Ongoing non-bypassable charges apply
NV Energy Appendix
NV Energy Overview
• Headquartered in Las Vegas, Nevada, with territory
throughout Nevada
• 2,400 employees
• 1.27 million electric and 165,000 gas customers
• Service to 90% of Nevada population, along with
tourist population in excess of 43 million
• 6,011 MW(1) of owned power generation
(91% natural gas, 9% coal/renewable/other)
• Provides electric services to
Las Vegas and surrounding
areas
• 928,334 electric customers
• 4,639 MW of owned power
capacity
• Provides electric and gas
services to Reno and northern
Nevada
• 344,311 electric customers and
165,317 gas customers
• 1,372 MW of owned power
capacity
Nevada Power Sierra Pacific
(1) Net MW owned in operation as of December 31, 2017
NV Energy
2017 Retail Electric Sales by Class (GWh)
Residential
42%
Commercial
21%
Industrial
28%
Distribution-
Only Service
8%
Other
1%
Nevada Power
Total 2017 Retail Electric Revenue:
$2.2 billion
Total 2017 Retail Electric Revenue:
$0.7 billion
Residential
25%
Commercial
29%
Industrial
32%
Distribution-
Only Service
14%
Other
0%
Sierra Pacific
NV Energy
Environmental Position
• NV Energy is reducing use of coal-fueled
generation
– 2019 elimination of Navajo interest (255 MW)
– 2025 retirement of North Valmy (261 MW)
• Decommissioning expenditures of $75.9m in
2018-2020 associated with coal retirements
• Forecast(1) environmental expenditures include
$3 million in 2018, $6 million in 2019 and
$4 million in 2020
Nevada Power Asset Profile
64%
35%
1%
Renewables and Other Natural Gas Generation
Coal Generation
Net Property, Plant and Equipment as of December 31, 2017
Sierra Pacific Asset Profile
76%
18%
6%
Renewables and Other Natural Gas Generation
Coal Generation
Net Property, Plant and Equipment as of December 31, 2017
December 31, 2017
Power Capacity – 6,011 MW (2)
Coal and
Other
9%
Natural Gas
91%
(1) Environmental capital expenditures forecast excludes equity AFUDC
(2) Net MW owned in operation and under construction
• Nevada Senate Bill 123 passed in 2013, for an emissions reduction and capacity replacement
plan for coal-fired electric generating plants:
– Reid Gardner Generating Station, 557 MW coal plant
• Reid Gardner Unit 4 (final unit) ceased operation March 11, 2017
• Pond solids removal was completed; above and below ground demolition contract fully executed,
with pre-construction meeting held February 8, 2018
– Navajo Generating Station, 2,250 MW coal plant
• Six owners: NV Energy (11.3%), Salt River Project (operator), Arizona Public Service, Tucson
Electric, Los Angeles Department of Water and Power, and U.S. Bureau of Reclamation
• Full execution of extension lease was achieved December 1, 2017, through December 22, 2019
• NV Energy impact minimal, as 2019 shutdown eliminates operating expense, allows for recovery of
costs necessary to retire and remediate and eliminates minimum dispatch provision
– North Valmy Generating Station, 522 MW coal plant
• Idaho Public Utilities Commission approved Idaho Power Company’s stipulation to retire North
Valmy Generating Station, co-owned by NV Energy, with a targeted shutdown of Unit 1 in 2019 and
Unit 2 in 2025
• Nonbinding term sheet signed December 27, 2017, provides basis of potential terms to be
incorporated into a definitive agreement in 2018. Draft definitive agreement provided to Idaho
Power Company on February 21, 2018, with their review underway
• NV Energy filed lifespan analysis process plan February 16, 2018, to address current operation and
future retirement of the North Valmy Generating Station
Reduction of Coal-Fueled Generating Stations
Net Energy Metering Update
0
5,000
10,000
15,000
20,000
25,000
30,000
2012 2013 2014 2015 2016 2017 2018
YTD
NV Energy Private Generation
Cumulative Interconnections
Residential Non-Residential
15,155
8,914
23,584
79,726
53,360
19,265
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2012 2013 2014 2015 2016 2017
KW
NV Energy Distributed power
capacity Added by Year
Sierra Pacific
Nevada Power
NV Energy
• The charts illustrate the amount of kW added by year for Nevada Power and
Sierra Pacific and the cumulative number of interconnections broken out by
residential and commercial
Mark Hewett
President and CEO
BHE Pipeline Group
2018 Fixed-Income Investor Conference
Shipper Contract Updates
(2) Based on binding shipper commitments for recontracting and total
system design capacity of 2.2 million Dth per day
Kern River – Transportation
Contract Maturities (2)
(1) Based on maximum daily quantities of market area entitlement in
decatherms as of December 31, 2017
• In 2017, completed approximately 2.3 Bcf/day in contract
renewals with a 15% increase in rates, which provides
additional $24 million in annual revenue
• Market Area Transportation weighted average remaining
contract term of over eight years
• 75% of 2017 storage revenue resulted from long-term
contracts, with an average remaining contract life of
approximately seven years
• Long-term contracts with creditworthy counterparties – top
10 customer groups (65% of 2017 revenue) have a
weighted average credit rating of BBB+/A3
• For Period One capacity expiring in 2016/2017/2018, 72%
elected to extend their contracts at Period Two rates, with
503,923 Dth per day electing 10-year contracts and 656,923 Dth
per day electing 15-year contracts
• 65% of capacity is committed to contracts that expire after 2020
• Weighted average remaining contract term of ten years
• Weighted average shipper rating of BBB/Baa2
• Shippers that do not meet credit standards are required to post
collateral
2018-2019
16%
2020-2021
9%
2022-2023
28%
2024-2029
21%
2030+
26%
Northern Natural Gas – Market Area
Transportation Contract Maturities (1)
2018-2019
10%
2020-2021
5%
2025-2028
27%
2031
31%
2032-2033
5%
Uncontracted
22%
• Northern’s top 3 shippers (CenterPoint, Xcel and MidAmerican Energy) have a
weighted average remaining contract life of approximately 12 years
• In 2017, Northern successfully completed a long-term contract renewal with
CenterPoint Energy
– Renewed 1.1 Bcf/day of winter entitlement
– Contracted extended until October 2034
– Includes growth election for 72,000 Dth/day starting in 2019
• In 2017, Northern successfully completed a long-term contract renewal with
MidAmerican Energy
– Renewed approximately 566,000 Dth/day of winter entitlement
– Contract extended for 5 years
• In 2016, Northern successfully completed a long-term contract renewal with Xcel
Energy
– Renewed approximately 785,000 Dth/day of winter entitlement
– Contract extended until October 2027
• Northern’s top 10 shippers have a weighted average remaining contract life of
approximately 10 years
Northern Natural Gas
Re-Contracting Efforts
$149 $140
$186
$253
$131
$220
$70
$44
$79
$147
$184
-
50
100
150
200
250
300
350
400
450
2015 2016 2017 2018F 2019F 2020F
($
m
il
li
ons
)
Northern Natural Gas Capital Expenditures
Operating Growth
Capital Investment Plan
$29
$42
$22
$35
$29
$14
$1
-
10
20
30
40
50
2015 2016 2017 2018F 2019F 2020F
($
m
il
li
ons
)
Kern River Capital Expenditures
Operating Growth
($ millions)
2018-2020
Current
Plan
Prior
Plan
Operating $ 604 $ 452
Growth 331 170
Total $ 935 $ 622
($ millions)
2018-2020
Current
Plan
Prior
Plan
Operating $ 78 $ 58
Growth - -
Total $ 77 $ 58
Focus on Customer Satisfaction
– Northern Natural Gas ranked #1 and Kern River ranked #2 out of 37 interstate pipelines in Mastio & Company’s
2018 survey; Northern Natural Gas also ranked #1 among mega-pipelines in customer satisfaction and Kern River
ranked #1 among regional pipelines in customer satisfaction
– BHE Pipeline Group has been ranked #1 for 13 consecutive years
Location
– Northern Natural Gas – Reticulated system - economically unfeasible to replicate
– Northern Natural Gas – Optionality with Field Area - tremendous advantage for customers and pipeline to capture
opportunities
• Proximity to Permian Basin provided for opportunity to capture increased volumes
– Kern River – Directly connected to end-use markets in Nevada and California
Competitive Pricing
– Both pipelines have demonstrated over 14 years of rate stability with no Section 4 regulatory rate review since 2004
by actively managing and growing our business and solving business issues
– Northern Natural Gas – Prices are competitive with other pipelines which minimizes level of discounting needed in
competitive markets
– Kern River – Period Two rates are the lowest delivered cost interstate pipeline options to southern California
– Long-term contracts with stable markets for both pipelines
Operational Excellence
– Northern Natural Gas – Long history of commitment to system reliability and operational excellence
– Kern River – State of the art transmission system
Financial Strength and Stability
– Northern Natural Gas – Credit metric have continued to be strong
– Kern River – 100% equity capitalization consistent with tariff design
– On March 15, 2018, the FERC issued a notice of proposed rulemaking which would require a one-time informational
filing demonstrating the impact of tax reform on returns using 2017 data. The proposed rulemaking provides four
options for pipelines to submit a voluntary filing to address tax reform in rates. We anticipate there will be no required
adjustments to rates for Northern Natural Gas or Kern River
Competitive Advantages
BHE Pipeline Group Appendix
Northern Natural Gas
Overview
MINNESOTA
WISCONSIN
IOWA
SOUTH DAKOTA
NEBRASKA
KANSAS
OKLAHOMA
TEXAS
• 14,700 miles of natural gas pipeline
• 5.9 Bcf per day of market area design
capacity; 1.7 Bcf per day field area capacity
to demarcation and 1.3 Bcf per day of
Permian area capacity
• More than 79 Bcf firm service and
operational storage cycle capacity
• 90% of transportation and storage revenue
in 2017 is based on demand charges
− Market area transportation contracts
have a weighted average contract term
of 8 years
− Storage contracts have a weighted
average contract term of 7 years
• Increased the integrity and reliability of the
pipeline
• Ranked No. 1 among 16 mega-pipelines and
No. 1 among 37 interstate pipelines in 2018
Mastio & Company customer satisfaction
survey
Permian Area
• Field area revenue becoming less dependent on fluctuating Demarc business
• Permian Basin revenue increased by 250% from 2012 to 2017
− Increased demand through Permian expansion projects – including growth to power plants
• Continued growth from 2017 due to ramped up volumes from additional Permian
expansions
Northern Natural Gas
Field Area Transportation
$40 $40
$72
$49
$23
$36
$19 $23
$28
$35
$40
$50
$-
$10
$20
$30
$40
$50
$60
$70
$80
2012 2013 2014 2015 2016 2017
Field Area Transportation Mix
Demarc Permian & Other
($ millions)
• 2017 Market Area Expansions
– Total capital expenditures of approximately $70 million, primarily serving LDCs
– Incremental entitlement of 88,000 Dth/day
– Annual demand revenues of $8 million, with contract terms from 4 to 10 years
• 2017 Field Area Expansion
– Total capital expenditures of approximately $37 million, serving a power plant expansion in
Permian Basin
– Incremental entitlement of 210,000 Dth/day (volumes ramp up between 2017 and 2020)
– Annual demand revenues of $11 million, with contract term of 13 years
• 2018-19 Expansions
– 2018-19 Market Area Projects – total capital expenditures of approximately $315 million,
primarily serving LDCs and two power plants
• Incremental entitlement of approximately 234,000 Dth/day
• Annual demand revenues of $41 million, with contract terms of 8 to 25 years
– 2018 Field Area Projects – total capital expenditures of approximately $28 million, serving
commercial processing plant supply
• Incremental entitlement of approximately 200,000 Dth/day
• Annual demand revenues of $8 million, with contract term of 5 years
Northern Natural Gas
Expansion Projects
Kern River Gas Transmission
Overview
• 1,700-mile interstate natural gas
transmission pipeline system
• Design capacity of 2.2 million Dth
per day of natural gas
• 94% of revenue through
December 31, 2017, is based on
demand charges
‒ Contracted capacity has a
weighted average contract
term of 10 years
• Ranked No. 2 among 37 interstate
pipelines in 2018 Mastio &
Company customer satisfaction
survey
CALIFORNIA
NEVADA
ARIZONA
UTAH
WYOMING
Kern River Gas Transmission
Strong Demand for Services
Daily Average Scheduled Volume
2017 Deliveries by State
(1) Based on the 2017 California Gas Report
(2) Based on Kern River’s average scheduled volumes to Nevada and
Southwest Gas Transmission Company’s system capacity served by
El Paso Natural Gas Company, LLC, or Transwestern Pipeline
Company, LLC.
• Received 27% of Rockies natural gas
supply in 2017
• Delivered approximately 26%(1) of
California’s demand for natural gas in
2016
• Delivered more than 81%(2) of
southern Nevada’s natural gas
• During 2017, scheduled throughput
averaged 105% of design capacity
Lowest-Cost Option to Southern California
Rockies
$1.9050
Rockies
$1.9050 Permian
$1.7200
Permian
$1.7200
San Juan
$1.7350 AECO
$1.5258
Rockies
$1.9050
Rockies
$1.9050
$0.1742 $0.2018 $0.5700 $0.4514 $0.4514
$0.2117
$0.3929
$1.1370
$0.3002
$0.1798
$0.4498
$0.4498
$0.4498
$2.1123 $2.1621
$2.3535
$2.2434 $2.2588
$2.5770
$3.0104
$3.5199
$0
$1
$2
$3
$4
Kern River
Alt P2 Rate
Orig Sys 15-yr
Kern River
Alt P2 Rate
2003 Exp 15-yr
Transwestern El Paso El Paso PG&E
GTN
TCPL
PG&E
GTN
NWP
PG&E
Ruby
$/D
th
Gas Price Fuel and Commodity Transportation Demand Rate
Source: Platts M2M Modeled Natural Gas Curves, 120-Month Daily Assessments Dated January 30, 2018; Fuel costs assumes Platts Gas
Daily Dated February 5, 2018.
Richard Weech
President and CEO
BHE Renewables
2018 Fixed-Income Investor Conference
BHE Renewables Overview
(1) Based on net owned capacity of 4,647 MW in operation and under construction as of March 2018
(2) Forecast approximately 100 off-takers for the purchase of all the energy produced by the solar portfolio for a period up to 25 years
(3) Separate PPAs exist with Missouri Joint Municipal Electric Commission (20 MW), Kansas Power Pool (25 MW), City of Independence, Missouri (20 MW) and Kansas Municipal Energy Agency (7 MW)
(4) 69% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under long-term power purchase agreements expiring in 2019
through 2026. Certain long-term power purchase agreement renewals for 244 MW have been entered into with other parties at fixed prices that expire from 2028-2039, of which 202 MW mature in 2039
BHE Solar
Geothermal
Natural Gas
BHE Wind
BHE Hydro
CalEnergy Philippines
Solar
33%
Wind
36%
Geothermal
7%
Hydro
3%
Natural Gas
21%
Portfolio Composition (1)
2018-2019
21%
2020-2029
10%
2030+
69%
Contract Maturities (1)
Location Installed
PPA
Expiration
Power
Purchaser
Net or
Contract
Capacity
(MW)
Net
Owned
Capacity
(MW)
SOLAR
Solar Star I & II CA 2013-2015 2035 SCE 586 586
Topaz CA 2013-2014 2040 PG&E 550 550
Agua Caliente AZ 2012-2013 2039 PG&E 290 142
Alamo 6 TX 2017 2042 CPS 110 110
Community Solar Gardens MN 2016-2017 (2) (2) 98 98
Pearl TX 2017 2042 CPS 50 50
1,684 1,536
WIND
Grande Prairie NE 2016 2037 OPPD 400 400
Pinyon Pines I & II CA 2012 2035 SCE 300 300
Jumbo Road TX 2015 2033 AE 300 300
Walnut Ridge IL 2018 2028 USGSA 212 212
Bishop Hill II IL 2012 2032 Ameren 81 81
Marshall Wind KS 2016 2036 (3) 72 72
Growth Project 300 300
1,665 1,665
GEOTHERMAL
Imperial Valley CA 1982-2000 (4) (4) 338 338
HYDROELECTRIC
Casecnan Phil. 2001 2021 NIA 150 128
Wailuku HI 1993 2023 HELCO 10 10
160 138
NATURAL GAS
Cordova IL 2001 2019 EGC 512 512
Power Resources TX 1988 2018 EDF 212 212
Saranac NY 1994 2019 TEMUS 245 196
Yuma AZ 1994 2024 SDG&E 50 50
1,019 970
Total Owned and Under Construction 4,866 4,647
BHE Renewables
Material Net Income Growth ($m)
$121 $124
$179
$864
$(200)
$-
$200
$400
$600
$800
$1,000
$(200)
$-
$200
$400
$600
$800
$1,000
2014 2015 2016 2017
Solar Wind Geothermal and Gas Hydro Parent and Other 2017 Tax Reform Impact Total Renewables
• Additional new growth investments and improved operations continue to drive net
income growth
• 2017 Tax Reform benefits of $628 million recorded in 2017
$236
BHE Renewables
2017 Solar Growth Activities
Additional Solar Capacity
• Alamo 6
– 110 MW project acquired in January 2017, with commercial operation achieved
in March 2017
– Availability and generation above expectations for 2017
• Pearl
– 50 MW project acquired in August 2017, with commercial operation achieved in
October 2017. Availability and generation above expectations for 2017
• Community Solar Gardens
– 32 MW community solar gardens development opportunity acquired in 2015,
started commercial operation as of February 1, 2017, and is 100% subscribed
– 66 MW community solar gardens development opportunity acquired in
January 2016 and is 100% subscribed
• 48 MW achieved commercial operation to date
• 18 MW will achieve commercial operation by June 2018
Additional Wind Capacity
• Walnut Ridge
– 212 MW project acquired in 2015 with construction beginning in 2017
– Commercial operation anticipated in December 2018
Additional Tax Equity Investments
• Willow Springs
– 250 MW project located in Texas
– $116 million investment
– Commercial operation achieved in November 2017
• Flat Top
– 200 MW project located in Texas
– $175 million investment
– Commercial operation anticipated in March 2018
• Rattlesnake
– 160 MW project located in Texas
– $90 million investment
– Commercial operation anticipated in April 2018
BHE Renewables
2017 Wind Growth Activities
To date, Berkshire
Hathaway Energy has
funded tax equity
investments of
$1.157 billion and has
committed to fund an
additional $570 million
BHE Renewables
Improved Operational Performance
2016
Capacity
Factor
2017
Capacity
Factor
2016
MWh
Generated
2017
MWh
Generated
Generation
Change
Wind 36.3% 36.2% 2,444,800 3,653,800 49.5%
Solar 27.5% 29.8% 3,077,300 3,621,000 17.7%
Geothermal 75.9% 82.4% 2,248,400 2,439,500 8.5%
Hydro 32.6% 38.4% 394,000 464,400 17.9%
Gas Plants 3.6% 2.4% 308,700 207,500 (32.8%)
Total 27.7% 29.7% 8,473,200 10,386,200 22.6%
Fleet Operational Metrics (owned share)
BHE Renewables
Energy Storage Initiatives
Pilot Project
• A 60 kW/548 kWh solar plus energy storage pilot project at Solar Star in California
– Partnered with First Solar
– Lithium ion battery technology
– Scheduled for completion in April 2018
– Small investment, but will provide significant value through operating experience
Universal Scale Project
• BES 1 & 2, two 24 MW energy storage projects powered by solar to be located
adjacent to Solar Star in California
– Projects in permitting and design stage
Scott Thon
President and CEO
AltaLink
2018 Fixed-Income Investor Conference
• AltaLink, L.P. 2017 net income of C$336.7 million is C$29.2 million higher than 2016
• Continue to Maintain Top Quartile Operational Performance
– Consistently better than peers’ reliability and safety performance as reported by the
Canadian Electricity Association
• 2017-2018 Negotiated Settlement
– First negotiated settlement in AltaLink’s history. Result of goodwill created after the
2015-2016 GTA customer rate relief of C$600 million
– Filing of the negotiated settlement took place February 8, 2017, which included
C$58 million of additional savings for customers and a potential C$130.3 million refund
related to a depreciation surplus
– Final decision was received August 30, 2017, with the AUC approving additional customer
tariff relief of C$50 million, which includes a depreciation surplus refund of C$31.4 million
• Customer Rate Relief and Flat Tariff Commitment
– C$50 million customer savings for 2017-2018 Negotiated Settlement, which brings total
customer rate relief for the period 2015-2018 to C$650 million
– 5-year commitment to keeping customer rates flat starting in 2019
• Rate Base is levelling at C$7.6 billion
– Annual capital expenditures in a range of C$300 - C$500 million over the next 10 years
Strong 2017 Business Results
C$650 million of Customer Rate Relief Approved
• Total customer rate relief of C$650 million includes C$600 million relief for
2015-2016 GTA and C$50 million for 2017-2018 Negotiated Settlement
• Allows the company to build rate base and maintain long-term earnings upside yet
allowing customers with near-term rate relief
2015-2016 GTA and 2017-2018 Negotiated Settlement
Approved Customer Rate Relief: 2015-2018 impact
2015 2016 2017 2018
Discontinuation of CWIP-in-rate base 69 13 4 2
Refund of pr viously collected CWIP-in-rate base 123 142 - -
Change from future income tax to flow through - 68 89 90
Reduction in operating costs - - 8 8
Reduction in capital spending - - - 1
Increase in revenue offsets - - 1 1
Depreciation surplus refund - - 15 16
Total rate relief 192 223 117 118
Cumulative relief 192 415 532 650
Customer Rate Relief (C$ millions)
AltaLink Regulatory Update
2014-2015 Direct Assign Capital Deferral Account (DACDA)
• The 2014-2015 DACDA application, which was filed on December 8, 2017, seeks approval
for C$3.8 billion of capital projects, C$0.9 billion of which relates to 2014 and C$2.9 billion
to 2015
• AltaLink is also seeking recovery of approximately C$48 million of canceled project
expenses
• Hearing is expected in second/third quarter of 2018, with a decision expected in
fourth quarter of 2018
2018-2020 Generic Cost of Capital (GCOC)
• First company evidence for the 2018-2020 GCOC process was filed on October 31, 2017
– Recommending equity thickness of 40% and ROE range of 9% to 10.75%
• Expert evidence filed by intervenors January 12, 2018
• Hearing ended on March 23, 2018, with a decision expected in third quarter of 2018
2019-2021 General Tariff Application (GTA)
• GTA will include a 5-year commitment (2019-2023) to keep customer rates flat
• AltaLink met with customers November 6, 2017 and launched the 5-year flat tariff
commitment
• Filing and hearing of the GTA are expected in second quarter of 2018 and fourth quarter of
2018, respectively, with a decision expected in first quarter of 2019
Regulatory Capital Investment Plan
Forward Capital Investment Normalizing
Rate Base Levelling at C$7.6 billion
(C$ billions)
Forecast based on 2017-2018 Negotiated Settlement, November, 2017
AltaLink Gross Capital Expenditures
2.5
3.5
5.3
7.0
7.4 7.6
1.2
1.8
1.3
0.2
0.1
0.1
3.7
5.3
6.6
7.2
7.5
7.7
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
2013A 2014A 2015A 2016A 2017A 2018F
Mid-year Rate Base Mid-year CWIP
0.1 0.2 0.2 0.2 0.2 0.2
1.7
1.9
0.9
0.6
0.3
0.1
$0.0
$0.5
$1.0
$1.5
$2.0
2013A 2014A 2015A 2016A 2017A 2018F
Operating Growth
Source: Alberta Electric System Operator
• Details regarding Alberta’s Climate Leadership Plan continue to take shape
• Coal generation fully transitioning out of Alberta by 2030
– Closure of existing coal plants starting to accelerate
• An economy-wide carbon tax implemented January 1, 2017, to encourage energy efficiency
and cover the cost of transitioning to renewables
– Starting January 1, 2018, the carbon levy doubled to C$30 per ton of CO2 emissions
based on “best of gas” emission standard
• Government targeting 5,000 MW of renewables (wind, solar, hydro) by 2030. REP1 auction -
approximately 600 MW of wind awarded at record low price for Canada in December 2017
• REP2 and REP3 auctions announced February 5, 2018
– REP2: 300 MW, indigenous component (parameters to be announced later)
– REP3: 400 MW, same criteria as REP1
• Proposed timeline for REP2 and 3
• BHE Canada will be participating in the REP2 and REP3 auctions
Alberta Climate Leadership Plan Update
Alberta Economic Outlook
Economic Recovery Underway, but Challenges Linger
Alberta
• In 2017, Alberta was Canada’s third largest economy and fourth most populated province
• Alberta’s economy led all provinces in 2017, with estimated real GDP growth of 4.5%
versus national average of 3.0%. Growth is expected to moderate to about 2.8% in 2018
• In December 2017, the Province’s unemployment rate fell to 6.9%. Comparatively, the
national average unemployment rate was 5.7%. Alberta’s labor market continues to
recover, with about 20,000 jobs created in the fourth quarter of 2017
• Alberta‘s crude oil production continues to advance, reaching a new high of over
1.8 million barrels a day in November 2017. However, oil pricing is negatively impacted by
pipeline bottlenecks with the light-heavy differential widening in recent months
AltaLink
• No major system upgrades expected in the near-term. Renewables investments will
leverage existing transmission infrastructure
• After strong growth, load is levelling
• AltaLink is not exposed to volume or price risk
• AltaLink continues to be focused on reducing customer cost Source: Statistics Canada and Alberta Treasury Board & Finance
Alberta Real GDP Growth
3.9%
5.7%
6.2%
-3.7% -3.7%
4.5%
-5.0%
-3.0%
-1.0%
1.0%
3.0%
5.0%
7.0%
2012A 2013A 2014A 2015A 2016A 2017E
Source: Alberta Electric System Operator
Alberta Electricity Demand (GWh) Average Pool Prices (C$/MWh)
80.2
49.4
33.3
18.3
22.2
43.0
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
2013A 2014A 2015A 2016A 2017A 2018F
74,000
75,000
76,000
77,000
78,000
79,000
80,000
81,000
82,000
83,000
2013A 2014A 2015A 20 6 2017A
+3.2%
+0.4% -0.9%
+3.8
AltaLink Appendix
AltaLink, L.P.
• AltaLink is an owner and operator of
regulated electricity transmission
facilities in the Province of Alberta
– Supplies electricity to approximately
85% of Alberta’s population
• AltaLink owns approximately 8,080 miles
of transmission lines and 312
substations within the Province of
Alberta
– No volume or commodity exposure
– Supportive regulatory environment
– Revenue from AA- rated Alberta
Electric System Operator (AESO)
• Mid-year 2018 forecast rate base of
C$7.6 billion and CWIP of C$90 million
Financial Strength
Forward Capital Investment Normalizing
• AltaLink receives approved tariff from
AESO in equal monthly installments
– No exposure to variability in
electricity prices
– No electricity volume risk
• Tariffs based on cost-of-service
regulatory model under a forward test
year basis
• The AESO, who is responsible for
system planning, directs substantially
all of AltaLink’s capital spending
Regulatory Framework Supports
Predictable Revenue
Phil Jones
President and CEO
Northern Powergrid Holdings Company
2018 Fixed-Income Investor Conference
Regulatory and Political Overview
• ED1 performance continues to improve
– Costs and outputs: on target
– Customer satisfaction: 6 percentage points
improvement from prior year
– Network performance: 3 consecutive years of
best-ever performance
– Revenues reduce and RAV grows as
regulatory asset life transitions to 45 years
– Inflation protection continues to apply
• Northern Powergrid is one of the companies
with a clear slate in Ofgem’s DPCR5 close-out
process
• Ofgem’s RIIO2 Framework Consultation signals
a commitment to the fundamental regulatory
model, with some downward pressure on
allowed equity returns from 2023 onwards
• Ofgem’s decision on a Mid-Period Review is
expected in Spring 2018
(1) – Plus RPI inflation
(2) – ED1 indexed, figure stated for 2017-2018
(3) – Total activity costs
(4) – 2012-2013 prices
(£ millions) – U.S. GAAP 2017 2016
Revenues 737 735
Operating Income
339 363
Capex
488 404
RAV
3,132 2,989
Interest Coverage 3.3x 3.5x
Debt to RAV 60% 62%
Regulatory Parameters ED1 DPCR5
Allowed Equity Returns
(1)
6.0% 6.7%
Allowed Cost of Debt
(1),(2)
2.3% 3.6%
Annual Totex
(3)
vs DPCR5 95% 100%
Average Annual RAV
(4)
Growth
1.2% 3.7%
Regulatory Asset Life 20-45
years
20
years
• The rate of return across the energy industry is attracting political attention
– Political concern has been heightened by some ill-informed comparisons between
profit margins of capital intensive network companies and asset-light suppliers
– Ofgem’s CEO has come out strongly in terms of highlighting this distinction, though
returns on gas and transmission networks are at the high end of Ofgem’s expected
range
– Ofgem has encouraged voluntary reductions by companies with ‘excess’ returns
– So far, this has not affected electricity distributors, but Ofgem has signalled lower
allowed returns for all network companies in RIIO2
– In contrast to these concerns is a backdrop of significant value delivered to
customers, record investment and lower network prices
• The leadership of the main government opposition (Labour Party) is advocating a
return to a pro-nationalization agenda
– There is no specific proposal – and the language used continues to be vague
– Significant costs of implementation for minimal customer savings mean the policy is
not popular, even within much of the Labour Party
– No imminent prospect of a change in government
Regulatory and Political Overview
95
100
105
110
115
120
125
130
GD
P
(2
00
5 =
1
00
)
UK Euro area USA
UK Euro area USA
1
1.2
1.4
1.6
1.8
2
2.2
Ex
ch
an
ge
r
at
e
($
/£
)
Spot rate Average, 10 years to present
U.K. and European Economic Outlook
Source: Pacific Exchange Rate Service
• As brighter prospects emerge for Europe, Brexit
still weighs on expectations for the U.K.
• Our assessment of Brexit is unchanged – the
fundamentals of our business are not directly
affected by the outcome of negotiations
• Currency fluctuations are having less impact on
our BHE contribution
– The pound has strengthened in first quarter
of 2018
– This reflects a more favorable assessment of
the likelihood of a deal on Brexit
Jan 2018:
Jan 2017:
Source: IMF, World Economic Outlook
U.K. growth is not expected to pick up…
… but exchange rate showing green shoots
Capital Investment Plan
• Operating capital delivers our ED1 output commitments
• The smart meter rental business has grown significantly from the prior plan with total
capital expenditures increasing by £150 million, CAGR from 2014 to 2018 is 71%
£388
£329 £316 £342
£364 £336
£53
£98 £134
£158 £80
£5
-
100
200
300
400
500
600
2015 2016 2017 2018F 2019F 2020F
(£
m
il
li
ons
)
Operating Growth
(£ millions)
2018-2020
Current
Plan
Prior
Plan
Operating £ 1,042 £ 985
Growth 243 97
Total £ 1,285 £ 1,082
• Our existing network continues to provide development opportunities
– The low-carbon agenda continues to signal a need for more investment in networks
– Distribution network operators are expected to transition to distribution system
operators to cope with increased diversity in supply and demand
• Smart meter rental continues to grow – 2017 exceeded forecast
– Over 1.7 million smart meter units have been deployed to date and we have total
contracted volumes of 3.6 million meters with an investment value of £530 million
• Higher oil and gas prices have improved the outlook for the Baltic Gas
Project (49% owned by Northern Powergrid) – Final Investment Decision is
likely by the end of 2018
• Transaction prices have remained high as corporate activity reshapes energy
markets:
– SSE exit U.K. domestic retail business into a joint venture with Innogy’s Npower
– E.ON sold their remaining 46.65% stake in Uniper to Fortum for $4.5 billion
– Shell is moving into renewable electricity, including vehicle charging services
Growth Opportunities in the U.K.
Northern Powergrid Appendix
Northern Powergrid
Leeds
Edinburgh
Middlesbrough
Newcastle Upon Tyne
Sheffield
York
Northeast
Yorkshire
• 3.9 million end-users in northern
England
• Approximately 61,000 miles of
distribution lines
• Approximately 63% of 2017 distribution
revenue from residential and
commercial customers through
December 31, 2017
• Distribution revenue (£ millions):
12 Months Ending
Customer Type 12/31/2017 12/31/2016
Residential 315 335
Commercial 95 109
Industrial 230 208
Other 9 9
Total 649 661
U.K. Political Opposition – Nationalization
• In 1995, the U.K. labour party abandoned its
policy of nationalization
– This move ended a 75+ year commitment
– It was widely seen as helping labour win power in
1997
• Labour’s 2017 manifesto reopened debate
– Gradual nationalization was proposed
– Includes water and energy networks
• Labour remains in opposition with no immediate
prospect of forming a government
• Policies do not appear to be popular
– There would be a significant cost involved. The water
sector alone is estimated at £90 billion, 5% of the
national debt(1)
– We believe that the plan would deliver little financial
gain for customers. Our business plan anticipates
keeping prices flat until 2030
Flat charges for the next decade
(1) – Social Market Foundation research, 2018
0.0
100.0
200.0
300.0
400.0
500.0
600.0
700.0
800.0
Previous RAV Totex Pass through & tax
The chart shows the make up of Allowed
Revenue between 2014 – 2030, which
determine the prices charged to customers.
• Ofgem estimates that the average domestic
customer in Great Britain will pay £83 per
annum in 2018-19 for electricity distribution
costs(1)
• Our average customer will pay £81.50, which
compares favorably to other DNOs
• Our prices are approximately 10% lower than
in 2015 and will continue at this level for the
remainder of ED1 price control
• Actual customer bills are sensitive to the
geographic region in U.K., consumption
volumes and timing differences in recouping
asset investments via Distribution Use Of
System charges in customer bills
Comparison of Customer Rates
(1) Nominal terms, Source: Ofgem Annual Report 2016-17
£76
£78
£80
£82
£84
£86
£88
£90
£92
15-16 16-17 17-18 18-19
Average Northern Powergrid
Customer Charges (2015-2018)
£0
£20
£40
£60
£80
£100
£120
UKPN ENW NPg WPD Scottish
Power
SSE
Typical Domestic Customer Charges (2018-19)
Bill Fehrman
President and CEO
Berkshire Hathaway Energy
2018 Fixed-Income Investor Conference
Berkshire Hathaway Energy
Vision
To be the best energy company in serving our customers, while delivering sustainable energy solutions
Culture
Personal responsibility to our customers
Strategy
Reinvest in our businesses
• Continue to invest in our employees and
operations, maintenance and capital
programs for property, plant and equipment
• Position our regulated businesses to meet
changing customer expectations and retain
customers (reduce bypass risk) by providing
excellent service and competitive rates
• Reduce the carbon footprint of our operations
by participating in energy policy development,
resulting in the transformation of our
businesses and assets
• Advance grid resilience, cybersecurity and
physical security programs
Invest in internal growth
• Pursue the development of a value-enhancing
energy grid and gas pipeline infrastructure
• Create customer solutions through innovative
rate design and redesign
• Grow our portfolio of renewable energy
• Develop strong grid systems, including
cybersecurity and physical resilience programs
Acquire companies
• Additive to business model
Competitive Advantage
Berkshire Hathaway Ownership
Questions
