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 $100 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 N et I n c ome a n d C a s h Flo w s From O p e ra ti o n s ($ m il li o n s ) 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 n e mp lo y 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 ze 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

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