Berkshire Hathaway Energy 2017 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 storms, floods, fires, earthquakes, explosions, landslides, mining accidents, litigation, wars, terrorism, embargoes, 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 the London Interbank Offered Rate, the base interest rate for the Registrants' credit facilities; – 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 and mortgage industries and regulations that could affect brokerage and mortgage transactions; – 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; – the ability to successfully integrate future acquired operations into a Registrant's business; 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 2017 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, 2016 Assets $85 billion Revenues $17.4 billion Customers(1) 8.6 million Employees 21,000 Transmission Line 33,500 Miles Natural Gas Pipeline 16,400 Miles Generation Capacity 31,599 MW(2) Renewables 35% Natural Gas 33% Coal 30% 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 assets to manage bypass risk by providing excellent service and competitive rates to our customers • Decarbonize our operations by participating in energy policy development, transforming our businesses and assets • Advance 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 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 $1.1 billion and $1.8 billion in 2016 and 2015, 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, 2016, per S&P Capital IQ (2) As reported by company public filings Comparable Companies ($ billions) Market Cap Dec. 31, 2016(1) Net Income Dec. 31, 2016(2) NextEra Energy Inc. $55.9 $2.9 Duke Energy $54.3 $2.2 Southern Company $48.7 $2.4 Dominion Resources $48.1 $2.1 Exelon Corp. $32.8 $1.1 DISTRIBUTION Berkshire Hathaway Energy‟s integrated utilities operate in 11 states and serve approximately 4.7 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 2016 GENERATION We own approximately 31,600 MW of generation in operation and under construction, with resource diversity ranging from natural gas and coal to renewable sources RENEWABLES As of December 31, 2016, we had invested $19 billion in solar, wind, geothermal and biomass generation Berkshire Hathaway Energy 2016 Net Income: $2.5 billion

Revenue and EBITDA Diversification (1) Excludes HomeServices and equity income, which add further diversification (2) Refer to the BHE Appendix for the calculation of EBITDA; percentages exclude Corporate/other • Diversified revenue sources reduce regulatory concentrations • In 2016, approximately 88% of EBITDA was from investment-grade regulated subsidiaries BHE 2016 Energy Revenue(1): $15 Billion PacifiCorp 31% NV Energy 17% MidAmerican Funding 15% Northern Powergrid 9% BHE Pipeline Group 9% BHE Renewables 8% BHE Transmission 7% HomeServices 4% BHE 2016 EBITDA(2): $7 Billion Nevada 20% Utah 16% Iowa 16% Oregon 9% Wyoming 6% Illinois 4% California 4% Washington 2% Idaho 2% FERC 7% United Kingdom 7% Alberta 3% Other 4%

BHE Asset Profile 82% 8% 10% Renewables and Other Natural Gas Generation Coal Generation Berkshire Hathaway Energy Net Property, Plant and Equipment as of December 31, 2016 • 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 84% 2% 14% MidAmerican Energy PacifiCorp 69% 9% 22% 64% 33% 3% Nevada Power 74% 19% 7% Sierra Pacific Power

Generation Diversification 2016 BHE Power Capacity – 31,599 MW 2016 BHE Power Generation – 113 TWh Total Renewables 35% Total Renewables(1) 24% (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 30% Natural Gas 33% Nuclear and other 2% Wind 26% Solar 4% Hydro 4% Geothermal 1% Coal 46% Natural Gas 26% Nuclear and other 4% Wind 15% Solar 3% Hydro 4% Geothermal 2% Coal 58% Gas 23% Nuclear and Other 3% Wind 5% Hydro 8% Geothermal 3% Total Renewables 16% Total Renewables(1) 12% Coal 74% 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 • In August 2016, the IUB approved MidAmerican Energy‟s request to construct up to 2,000 MW of additional wind-powered generating facilities which are expected to be placed in-service in 2017 through 2019, with a cost cap of $3.6 billion • BHE Solar acquired the 110 MW Alamo 6 solar project in Texas in January 2017 for approximately $385 million, and is expected to spend approximately $218 million constructing the community solar gardens in Minnesota, which are comprised of 28 locations with a capacity of 95 MW • In 2016, PacifiCorp, MidAmerican Energy and BHE Renewables purchased $324 million of equipment that in the future will facilitate the repowering of at least 1,230 MW of wind-powered generating facilities between PacifiCorp and MidAmerican Energy, and the development of 380 MW of wind-powered generating facilities between PacifiCorp and BHE Renewables, which will qualify for production tax credits • BHE has funded to date, approximately $840 million renewable tax equity investments (1) Includes owned operating, under construction and in-development facilities. Excludes tax equity investments Owned Wind and Solar Generation Capacity (MW) (1) Regulated Unregulated MidAmerican BHE PacifiCorp Energy NVE Renewables Total 1999-2014 1,030 2,832 - 1,473 5,335 2015 - 581 15 486 1,082 2016 - 594 - 495 1,089 2017-2019 240 2,000 - 322 2,562 Total 1,270 6,007 15 2,776 10,068 Investment (billions) $3 $11 $0 $9 $23

• 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 $70 billion of liquidity, as of December 31, 2016 – BHE does not pay dividends, which allows BHE to continue to grow the business and improve credit quality – BHE retains more dollars of earnings than any other U.S. electric utility Berkshire Hathaway Ownership is Unique to the Utility Industry (1) As reported by company public filings (2) Calculated using reported shares outstanding on each respective balance sheet for the period ending December 31, 2016, per S&P Capital IQ ` ($ in millions) Net Income to Common(1) Common Dividend(1) Retained Earnings per day Common Dividend as % of Net Income December 31, 2016 Market Cap(2) Berkshire Hathaway Energy: 2016 Actual 2,542$ -$ 7.0 0% Privately Held December 31, 2016: NextEra Energy 2,912$ 1,612$ 3.6 55% 55,907 Souther Company 2,448 2,104 0.9 86% 48,717 D ke Energy 2,152 2,332 (0.5) 108% 54,334 Dominion Resources 2,123 1,727 1.1 81% 48,099 PPL C rpo ati n 1,902 1,030 2.4 54% 23,145 PG&E Corporation 1,393 921 1.3 66% 30,804 Sempra Energy 1,370 686 1.9 50% 25,175 Edison International 1,311 626 1.9 48% 23,455 Exelon Corporation 1,134 1,166 (0.1) 103% 32,794 American Electric Power 611 1,116 (1.4) 183% 30,958 Peer Median Average 1,648 1,141 1.2 74%

Low Cost Competitive Rates Company Weighted Average Retail Rate ($/kWh) Customer Service Ranking Pacific Region(1) $0.1447 Pacific Power $0.0948 Mountain Region(1) $0.0954 Rocky Mountain Power $0.0816 Nevada Power $0.0946 Sierra Pacific Power $0.0752 Midwest Region(2) $0.0967 MidAmerican Energy $0.0713 BHE Pipelines Mastio #1 BHE TQS #1 Score: 96.1% (1) Source: Edison Electric Institute (Summer 2016) (2) Source: U.S. Energy Information Administration Highest Average Rates ($/kWh) by State(1): Hawaii – $0.2395; Massachusetts – $0.1816; Connecticut – $0.1768; Rhode Island – $0.1717; New York – $0.1674 U.S. National Average(1): $0.1068 Relative to Pacific Region: Pacific Power 34% lower Relative to Mountain Region: Rocky Mountain Power 14% lower Nevada Power 1% lower Sierra Pacific Power 21% lower Relative to Midwest Region: MidAmerican Energy 26% lower

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 $59.2 $60.8 $62.5 $0.0 $15.0 $30.0 $45.0 $60.0 $75.0 2001 2014 2015 2016 Billions $0.1 $2.1 $2.4 $2.5 $0.0 $0.7 $1.4 $2.1 $2.8 2001 2014 2015 2016 Billions $0.8 $5.1 $7.0 $6.1 $0.0 $2.0 $4.0 $6.0 $8.0 2001 2014 2015 2016 Billions $1.7 $20.4 $22.4 $24.3 $0.0 $5.0 $10.0 $15.0 $20.0 $25.0 2001 2014 2015 2016 Billions Net Income Attributable to BHE BHE Shareholders’ Equity Property, Plant and Equipment (Net) Cash Flows From Operations

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 $90 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 N et I n c ome a n d C a s h Flo w s From O p e ra ti o n s ($ m il li o n s ) T ota l A s s ets & 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 2001 – 2016 CAGR Total Assets 13.6% Net Income 21.2% Cash Flows From Operations 14.0% • We have grown our assets significantly since 2001 while de-risking the business, reducing total debt(1) / total assets from 58% to 43% in 2016 and improving our credit ratings

2015 – 2016 Net Income Variance Years Ended Dec. 31 ($ millions) 2016 2015 Variance PacifiCorp 764$ 697$ 67$ 10% MidAmerican Funding 532 442 90 20% NV Energy 359 379 (20) -5% Northern Powergrid 342 422 (80) -19% BHE Pipeline Group 249 243 6 2% BHE Transmission 214 186 28 15% BHE Renewables 179 124 55 44% HomeServices 127 104 23 22% BHE and Other (224) (227) 3 1% Net income attributable to BHE 2,542$ 2,370$ 172$ 7%

Return on Equity (1) Based on 13-point average equity Net Income Divided by Average Equity(1) Entity 2016 2015 Allowed ROE PacifiCorp 10.1% 9.3% 9.8% MidAmerican Energy 11.1% 10.3% 10.9% Nevada Power 9.1% 9.6% 9.8% Sierra Pacific Power 7.7% 8.0% 9.8% Northern Natural Gas 11.2% 11.3% 12.0% Kern River 10.6% 10.7% 11.55%

• BHE Key Credit Ratios(1) – Credit ratios continue to be strong and supportive of our credit ratings • Ratings (issuer or senior unsecured ratings unless noted) Credit Metrics and Financial Strength (1) Refer to the BHE Appendix for the calculations of key ratios (2) 2014 column excludes AltaLink debt and BHE acquisition debt related to AltaLink acquisition (3) Ratings are senior secured ratings 2016 2015 2014 FFO Interest Coverage 4.3x 4.5x 4.9x FFO to Adjusted Debt Excluding Acquisition Related Debt (2) 16.0% 17.6% 20.6% Adjusted Debt to Total Capitalization 59% 59% 60% Moody’s S&P Fitch Moody’s S&P Fitch DBRS Berk hire Hathaw y Energy A3 A- BBB+ Northern Natural Gas Company A2 A A - PacifiCorp (3) A1 A+ A+ Kern River Funding Corp. (3) A2 A A- - MidAmerican Energy Company (3) Aa2 A+ A+ Northern Powergrid (Northeast) A3 A A- - Nevada Power Company (3) A2 A+ A- Northern Powergrid (Yorkshire) A3 A A - Sierra Pacific Power Company (3) A2 A+ A- AltaLink, L.P. (3) - A - A

Regulated Platform Credit Metrics Note: Refer to the BHE appendix for the calculations of key ratios, excluding AltaLink, L.P. AltaLink financial information is disclosed in the Management’s Discussion and Analysis section as presented in its Canadian public financial filings Regulated U.S. Utilities Regulated Pipelines and Electric Distribution 2016 2015 2014 2016 2015 2014 PacifiCorp Northern Natural Gas FFO Interest Coverage 5.7x 5.4x 5.2x FFO Interest Coverage 9.5x 10.4x 8.3x FFO to Debt 24.1% 23.2% 22.4% FFO to Debt 41.8% 48.7% 36.6% Debt to Total Capitalization 50% 49% 48% Debt to Total Capitalization 36% 36% 40% MidAmerican Energy Northern Powergrid FFO Interest Coverage 7.8x 7.2x 7.1x FFO Interest Coverage 5.1x 5.1x 5.3x FFO to Debt 30.4% 26.6% 25.9% FFO to Debt 21.7% 21.2% 24.4% Debt to Total Capitalization 46% 48% 49% Debt to Total Capitalization 43% 44% 43% Nevada Power AltaLink, L.P. FFO Interest Coverage 4.6x 6.1x 4.6x FFO Interest Coverage 3.2x 2.6x 3.0x FFO to Debt 21.6% 29.5% 21.2% FFO to Debt 11.8% 9.6% 10.4% Debt to Total Capitalization 51% 51% 55% Debt to Total Capitalization 62% 62% 61% Sierra Pacific Power FFO Interest Coverage 5.4x 6.1x 4.9x FFO to Debt 20.7% 25.7% 19.8% Debt to Total Capitalization 51% 53% 54%

• Berkshire Hathaway Energy and its subsidiaries will spend approximately $13.6 billion from 2017 – 2019 for development and maintenance capital expenditures, which includes new generation project expansions, primarily wind, transmission and distribution, and environmental capital expenditures Capital Expenditures and Cash Flows $- $1,500 $3,000 $4,500 $6,000 $7,500 2012A 2013A 2014A 2015A 2016A 2017F 2018F 2019F 2020F 2021F $ m il li o n s BHE Cash Flows from Operations BHE Total Capital Expenditures BHE Operating Capital Expenditures Free Cash Flow 2017 – 2021: $20B 2017 – 2021: $11B

• 2017-2019 capital expenditure projections have increased by $4.6 billion from prior year projections, primarily due to the Wind XI investment at MidAmerican Energy, the development of solar energy projects at BHE Renewables, and the repowering of wind facilities at PacifiCorp and MidAmerican Energy, partially offset by lower growth capital investment at AltaLink Capital Investment Plan 850 780 985 846 1,620 896 1,691 617 1,709 409 1,649 349 457 403 386 340 376 386 591 546 520 515 420 483 384 354 256 180 344 211 334 74 83 65 86 69 366 542 252 582 231 721 4,673 3,316 4,191 2,937 4,726 3,115 $- $900 $1,800 $2,700 $3,600 $4,500 $5,400 2017 Current Plan 2017 Prior Plan 2018 Current Plan 2018 Prior Plan 2019 Current Plan 2019 Prior Plan $ M ill io n s PacifiCorp MidAmerican Funding NV Energy Northern Powergrid BHE Pipeline Group and Other BHE Renewables BHE Transmission

Financing Plan 2017 • MidAmerican Energy – In February 2017, issued $850 million of First Mortgage, green bonds comprised of two tranches: $375 million 10-year offering at 3.10% coupon, and $475 million 30- year offering at 3.95% coupon – Anticipate approximately $50 million of tax-exempt debt financing in late 2nd half of 2017 • Nevada Power and Sierra Pacific Power - Anticipate approximately $115 million of tax-exempt debt financing during 2017 • BHE Renewables – Anticipate non-recourse project financing of approximately $225 million for the Alamo 6 Solar project during the first half of 2017 • Northern Powergrid – Anticipate up to £150 million debt financing in mid-2017 for the development of smart metering services • AltaLink, L.P. – Anticipate debt financing of up to C$200 million in late-2017

Potential Tax Reform • We are not certain if tax reform will occur, and if so what it will entail • We expect any changes in law will be reflected in our regulated utilities revenue requirements. Any reduced tax rate will benefit customers, any loss of interest deductibility will be a detriment to customers, and any accelerated tax depreciation for capital will increase cash flow and decrease rate base. We believe the likely net impact is a reduction in customer rates • We believe there will be a one-time gain in the year the tax law is enacted related to the reduction of the tax rate applied to non-regulated deferred income tax liabilities. If interest is not deductible the interest cost at our parent and non-regulated subsidiaries will reduce cash flow and earnings, while accelerated tax depreciation will improve cash flow • Changes to rules on foreign income taxes may impact future dividend strategy and capitalization • We believe BHE is well positioned to adjust to changes made in tax legislation and we do not believe there will be any material credit impacts to BHE

Questions

BHE Appendix

Organizational Structure 2016 Berkshire Hathaway Inc. ($ billions) Revenue $ 223.6 Net Income $ 24.1 Equity $ 283.0 2016 Berkshire Hathaway Energy ($ billions) Revenue $ 17.4 Net Income $ 2.5 Equity $ 24.3 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 Electricity Transmission Contracted Non-utility Power Generation Northern Powergrid (Yorkshire) plc A3/A/A U.K. Regulated Electric Distribution A2/A/A-(1) 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, AltaLink L.P., and Kern River Funding Corp. are senior secured ratings

Reportable Segment Information Years Ended Dec. 31 ($ millions) 2016 2015 2014 Operating Income: PacifiCorp 1,427$ 1,344$ 1,308$ MidAmerican Funding 566 451 395 NV Energy 770 812 791 Northern Powergrid 494 593 674 BHE Pipeline Group 455 464 439 BHE Transmission 92 260 16 BHE Renewables 256 255 314 HomeServices 212 184 125 BHE and Other (21) (35) (16) Total operating income 4,251 4,328 4,046 Interest expense - senior & subsidiary (1,789) (1,800) (1,633) Interest expense - junior subordinated debentures (65) (104) (78) Capitalized interest and other, net 453 311 267 Income before income tax expense and equity income (loss) 2,850 2,735 2,602 Income tax expense 403 450 589 Equity income (loss) 123 115 109 Net income 2,570 2,400 2,122 Net income attributable to noncontrolling interests 28 30 27 Net income attributable to BHE shareholders 2,542$ 2,370$ 2,095$

Rate Base Growth $16.6 $17.2 $17.4 $17.5 $0.0 $4.0 $8.0 $12.0 $16.0 $20.0 2014A 2015A 2016A 2017F Billions $7.0 $6.8 $6.8 $6.9 $0.0 $2.0 $4.0 $6.0 $8.0 2014A 2015A 2016A 2017F Billions $6.7 $7.5 $9.0 $9.7 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 2014A 2015A 2016A 2017F Billions NV Energy MidAmerican Energy PacifiCorp BHE Pipeline Group $3.1 $3.1 $3.0 $3.1 $0.0 $1.0 $2.0 $3.0 $4.0 2014A 2015A 2016A 2017F Billions Note: Rate base represents mid-year averages

Rate Base Growth £2.6 £2.7 £2.9 £3.0 £0.0 £1.0 £2.0 £3.0 £4.0 2014A 2015A 2016A 2017F Billions $3.5 $5.3 $7.0 $7.5 $0.0 $2.0 $4.0 $6.0 $8.0 2014A 2015A 2016A 2017F AltaLink, L.P. Northern Powergrid (1) 2015 includes the addition of AltaLink, L.P., which was acquired on December 1, 2014 (2) Northern Powergrid rate base converted into USD at the June 30 USD/GBP FX rate each year including 1.7106 (2014), 1.5712 (2015), 1.3311 (2016), and 1.2500 (2017 estimate) (3) AltaLink, L.P. rate base converted into USD at the June 30 CAD/USD FX rate each year including 1.2494 (2015), 1.2924 (2016) and 1.3000 (2017 estimate) Note: Rate base represents mid-year averages Berkshire Hathaway Energy $37.8 $43.1 $45.5 $46.7 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 2014A 2015A 2016A 2017F PAC MEC Northern Powergrid BHE Pipeline Group NVE AltaLink, L.P. (1) (2) (3) Billions C$ Billions

Long-Term Debt Summary As of December 31, 2016 Consolidated Berkshire Hathaway Energy Wt. Avg. Wt. Avg. $ (millions) Coupon Life (Years) (1) Berkshire Hathaway Energy - Parent 7,818 5.14% 15.3 PacifiCorp 7,079 5.04% 12.8 MidAmerican Funding 4,592 4.61% 14.4 NV Energy 4,582 5.55% 11.2 Northern Natural Gas Company 795 4.87% 13.3 Kern River Gas Transmission Company 195 4.89% 1.0 Northern Powergrid(2) 2,379 5.37% 9.8 BHE Canada(3) 4,058 3.92% 18.3 BHE Renewables 3,674 4.93% 9.1 Total Berkshire Hathaway Energy Long-Term Debt 35,172 4.94% 13.4 Berkshire Hathaway Energy - Parent Junior Subordinated Debentures 944 3.00% 28.0 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 1,002 3.29% 28.1 Total Berkshire Hathaway Energy Long-Term Securities 36,174 4.89% 13.8 (1) Weighted average life assumes perpetual preferred stock has an average life of 30 years (2) USD to GBP exchange rate at $1.2336/pound (3) CAD to USD exchange rate at $1.3441/USD

Debt Maturities As of December 31, 2016 Long-Term Debt Maturities(1) (1) Excludes capital leases $985 $3,526 $2,078 $1,527 $790 $1,555 $2,054 $1,564 $1,169 $944 $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 $ M ill io n s PacifiCorp MidAmerican Funding NV Energy Northern Powergrid BHE Pipeline Group BHE Renewables AltaLink 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% 2009 2010 2011 2012 2013 2014 2015 2016 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) 2016 2015 Actual Percent PacifiCorp Residential 16,058 15,566 492 3.2% Commercial 16,857 17,262 (405) -2.3% Industrial and Other 21,403 21,814 (411) -1.9% Total 54,318 54,642 (324) -0.6% MidAmerican Energy Residential 6,408 6,166 242 3.9% Commercial 3,812 3,806 6 0.2% Industrial and Other 13,704 13,070 634 4.9% Total 23,924 23,042 882 3.8% Nevada Power Residential 9,394 9,246 148 1.6% Commercial 4,663 4,635 28 0.6% Industrial and Other 7,525 7,785 (260) -3.3% Total 21,582 21,666 (84) -0.4% Sierra Pacific Power Residential 2,375 2,315 60 2.6% Commercial 2,933 2,942 (9) -0.3% Industrial and Other 3,030 2,989 41 1.4% Total 8,338 8,246 92 1.1% Northern Powergrid Residential 12,839 12,718 121 1.0% Commercial 5,338 5,769 (431) -7.5% Industrial and Other 17,742 18,093 (351) -1.9% Total 35,919 36,580 (661) -1.8%

Retail Electric Sales – Weather Normalized December 31 Variance (GWh) 2016 2015 Actual Percent PacifiCorp Residential 16,135 15,810 325 2.1% Commercial 16,762 17,163 (401) -2.3% Industrial and Other 21,360 21,693 (333) -1.5% Total 54,257 54,666 (409) -0.7% MidAmerican Energy Residential 6,297 6,239 58 0.9% Commercial 3,788 3,816 (28) -0.7% Industrial and Other 13,703 13,069 634 4.9% Total 23,788 23,124 664 2.9% Nevada Power Residential 9,195 8,933 262 2.9% Commercial 4,614 4,573 41 0.9% Industrial and Other 7,475 7,707 (232) -3.0% Total 21,284 21,213 71 0.3% Sierra Pacific Power Residential 2,418 2,311 107 4.6% Commercial 2,935 2,937 (2) -0.1% Industrial and Other 3,027 2,981 46 1.5% Total 8,380 8,229 151 1.8% Northern Powergrid Residential 12,937 12,894 43 0.3% Commercial 5,387 5,761 (374) -6.5% Industrial and Other 17,793 18,055 (262) -1.4% Total 36,117 36,710 (593) -1.6%

Retail Load (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 2010 2011 2012 2013 2014 2015 2016 2017F B H E T ota l Weather N orma li ze d G W h Northern Powergrid - CAGR (-1.1%) Rocky Mountain Power - CAGR 0.5% MidAmerican Energy - CAGR 1.9% Nevada Power - CAGR 0.0% Pacific Power - CAGR -0.5% Sierra Pacific Power - CAGR 1.6% BHE Total - CAGR 0.2% Weather N orma li ze d G W h

Private Generation Penetration Rate Total Electric Customers as of December 2016 Private Solar Customers as of December 2016 Private Solar Portion of Total Customers MidAmerican Energy Company Iowa 673,408 382 0.06% Illinois 85,078 18 0.02% South Dakota 4,915 0 0.00% PacifiCorp Utah 882,367 15,902 1.80% Oregon 576,914 5,228 0.91% Wyoming 140,580 241 0.17% Washington 130,206 588 0.45% Idaho 76,797 218 0.28% California 45,092 291 0.65% NV Energy Nevada 1,245,637 24,146 1.94% Total BHE Customers 3,860,994 47,014 1.22% Berkshire Hathaway Energy – Impact of Private Generation Note: Electric and Private Solar customers represent residential customers only

Consolidated Environmental Position • Owned coal-fueled capacity has declined as a percentage of BHE‟s generation portfolio from 51% in 2000, to 30% as of December 31, 2016 • Coal Combustion Residuals – managing under new regulatory requirements – PacifiCorp has 6 active surface impoundments and 4 landfills; 3 inactive surface impoundments are undergoing closure – MidAmerican Energy has 3 active surface impoundments and 4 landfills; 4 inactive surface impoundments are undergoing closure, and 2 have been closed – NV Energy operates 2 active evaporative surface impoundments and 2 landfills; all other surface impoundments are undergoing closure by removal • 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 • The U.S. Supreme Court issued a stay February 9, 2016, of the implementation of the Clean Power Plan pending the outcome of the litigation pending in the D.C. Circuit Court of Appeals and through any action taken on appeal to the U.S. Supreme Court – Oral arguments were held September 27, 2016, before ten judges in the D.C. Circuit; decision is expected in early 2017 • Paris Agreement became effective November 4, 2016, after ratification by the requisite number of parties representing 55 countries and 55% of global greenhouse gas emissions. Under the agreement, the U.S. committed to reducing greenhouse gas emissions 26-28% from 2005 levels by 2025. A party cannot withdraw until November 4, 2019, and the withdrawal would take effect one year later

Reducing Carbon Footprint • Through fuel switching and retirements, BHE‟s utilities expect to eliminate approximately 2,560 MW of coal generation through 2025 (1) Adjusted for re-rating of coal plants in 2014, 2015, and 2016, including plants still in operation and retired (2) NV Energy is divesting its interest Coal MW as of Dec. 31, 2013(1) 10,526 MW Riverside 3 – retired in 2014 (4) MW Reid Gardner 1-3 – retired in 2014 (300) MW Carbon 1 and 2 – removed from service in 2015 (172) MW Riverside 5 – converted 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 Cholla 4 – natural gas conversion or retire (395) MW Naughton 3 – natural gas conversion or retire (280) MW Navajo – interest to be divested in 2019 (255) MW North Valmy(2) – to be retired in 2025 (261) MW Coal MW as of Dec. 31, 2025 7,964 MW

Deliver Reliable and Affordable Service Mastio Results Interstate Pipelines 2003 2017 Northern Natural Gas 43 1 Kern River 10 2 TQS Results 2016 Top 5 Utilities on Overall Customer Satisfaction Rank Utility Very Satisfied 1 Berkshire Hathaway Energy 96.1% 2 Company A 95.9% 3 Company B 93.4% 4 Company C 92.3% 5 Company D 86.6% 47 Company name not available 20.0% Top 3 for the 13th consecutive year No. 1 for the 12th consecutive year

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). 2014 Debt has been restated, and is net of deferred financing costs (3) FFO to Adjusted Debt Excluding Acquisition Related Debt equals FFO divided by Adjusted Debt Excluding Acquisition Related Debt (4) Adjusted Debt to Total Capitalization equals Adjusted Debt divided by Capitalization ($ millions) FFO 2016 2015 2014 Net cash flows from operating activities 6,056$ 6,980$ 5,146$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions (144) (649) 1,170 FFO 5,912$ 6,331$ 6,316$ Adjusted Interest Interest expense 1,854$ 1,904$ 1,711$ Interest expense on subordinated debt (65) (104) (78) Adjusted Interest 1,789$ 1,800$ 1,633$ FFO Interest Coverage(1) 4.3x 4.5x 4.9x Adjusted Debt Debt(2) 37,985$ 38,946$ 39,897$ Subordinated debt (944) (2,944) (3,794) Adjusted Debt 37,041$ 36,002$ 36,103$ Acquisition Financing Debt (1,500) Acquisition Subsidiary Debt (4,007) Adjusted Debt Excluding Acquisition Related Debt 37,041$ 36,002$ 30,596$ FFO to Adjusted Debt Excluding Acquisition Related Debt(3) 16.0% 17.6% 20.6% Capitalization Berkshire Hathaway Energy shareholders‟ equity 24,327$ 22,401$ 20,442$ Adjusted debt 37,041 36,002 36,103 Subordinated debt 944 2,944 3,794 Noncontrolling interests 136 134 131 Capitalization 62,448$ 61,481$ 60,470$ Adjusted Debt to Total Capitalization(4) 59.3% 58.6% 59.7%

Berkshire Hathaway Energy Non-GAAP Financial Measures ($ millions) BHE Consolidated EBITDA Dec-16 Net income attributable to BHE shareholders $2,542 Noncontrolling interests 28 Interest expense 1,854 Capitalized interest (139) Income tax expense 403 Depreciation and amortization 2,591 EBITDA $7,279

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. 2014 Debt has been restated, and is net of deferred financing costs (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2016 2015 2014 Net cash flows from operating activities 1,568$ 1,734$ 1,570$ +/- Changes in other operating assets and liabilities 203 (74) 10 FFO 1,771$ 1,660$ 1,580$ Interest expense 380$ 379$ 379$ FFO Interest Coverage(1) 5.7x 5.4x 5.2x Debt (2) 7,349$ 7,166$ 7,039$ FFO to Debt(3) 24.1% 23.2% 22.4% Capitalization PacifiCorp shareholders‟ equity 7,390$ 7,503$ 7,756$ Debt 7,349 7,166 7,039 Capitalization 14,739$ 14,669$ 14,795$ Debt to Total Capitalization(4) 49.9% 48.9% 47.6%

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. 2014 Debt has been restated, and is net of deferred financing costs (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization FFO 2016 2015 2014 Net cash flows from operating activities 1,403$ 1,351$ 823$ +/- Changes in other operating assets and liabilities (65) (216) 235 FFO 1,338$ 1,135$ 1,058$ Interest expense 196$ 183$ 174$ FFO Interest Coverage(1) 7.8x 7.2x 7.1x Debt (2) 4,400$ 4,271$ 4,084$ FFO to Debt(3) 30.4% 26.6% 25.9% Capitalization MidAmerican Energy shareholder's equity 5,160$ 4,705$ 4,250$ Debt 4,400 4,271 4,084 Capitalization 9,560$ 8,976$ 8,334$ Debt to Total Capitalization(4) 46.0% 47.6% 49.0%

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. 2014 Debt has been restated, and is net of deferred financing costs (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization FFO 2016 2015 2014 Net cash flows from operating activities 771$ 892$ 704$ +/- Changes in other operating assets and liabilities (109) 77 46 FFO 662$ 969$ 750$ Interest expense 185$ 190$ 208$ FFO Interest Coverage(1) 4.6x 6.1x 4.6x Debt (2) 3,066$ 3,285$ 3,544$ FFO to Debt(3) 21.6% 29.5% 21.2% Capitalization Nevada Power shareholder's equity 2,972$ 3,163$ 2,888$ Debt 3,066 3,285 3,544 Capitalization 6,038$ 6,448$ 6,432$ Debt to Total Capitalization(4) 50.8% 50.9% 55.1%

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. 2014 Debt has been restated, and is net of deferred financing costs (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization FFO 2016 2015 2014 Net cash flows from operating activities 243$ 342$ 246$ +/- Changes in other operating assets and liabilities (4) (33) (10) FFO 239$ 309$ 236$ Interest expense 54$ 61$ 61$ FFO Interest Coverage(1) 5.4x 6.1x 4.9x Debt (2) 1,153$ 1,202$ 1,190$ FFO to Debt(3) 20.7% 25.7% 19.8% Capitalization Sierra Pacific Power shareholder's equity 1,108$ 1,076$ 998$ Debt 1,153 1,202 1,190 Capitalization 2,261$ 2,278$ 2,188$ Debt to Total Capitalization(4) 51.0% 52.8% 54.4%

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. 2014 Debt has been restated, and is net of deferred financing costs (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization FFO 2016 2015 2014 Net cash flows from operating activities 367$ 362$ 297$ +/- Changes in other operating assets and liabilities (35) 25 31 FFO 332$ 387$ 328$ Interest expense 39$ 41$ 45$ FFO Interest Coverage(1) 9.5x 10.4x 8.3x Debt (2) 795$ 795$ 895$ FFO to Debt(3) 41.8% 48.7% 36.6% Capitalization Northern Natural Gas shareholder‟s equity 1,409$ 1,410$ 1,330$ Debt 795 795 895 Capitalization 2,204$ 2,205$ 2,225$ Debt to Total Capitalization(4) 36.1% 36.1% 40.2%

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. 2014 Debt has been restated, and is net of deferred financing costs (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization FFO 2016 2015 2014 Net cash flows from operating activities 382£ 345£ 336£ +/- Changes in other operating assets and liabilities 31 48 54 FFO 413£ 393£ 390£ Interest expense 100£ 95£ 91£ FFO Interest Coverage(1) 5.1x 5.1x 5.3x Debt (2) 1,906£ 1,858£ 1,601£ FFO to Debt(3) 21.7% 21.2% 24.4% Capitalization Northern Powergrid shareholders‟ equity 2,491£ 2,297£ 2,108£ Debt 1,906 1,858 1,601 Noncontrolling interests 36 36 37 Capitalization 4,433£ 4,191£ 3,746£ Debt to Total Capitalization(4) 43.0% 44.3% 42.7%

Bill Fehrman President and CEO MidAmerican Energy Company 2017 Fixed-Income Investor Conference

Customer Load • Economic and Load Data – Service territory has experienced moderate economic growth – Forecast loads for 2017 and 2018 reflect a continuation 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 2011 2012 2013 2014 2015 2016 2017F 2018F T W h MidAmerican Energy Retail Load Weather-Normalized Annual Growth Rates: 2012 = 0.6% 2013 = 1.7% 2014 = 2.6% 2015 = 1.8% 2016 = 2.9% 2017 = 2.5% 2018 = 1.3%

Forecast 2019 Iowa electric net plant including Wind XI • 67% of Iowa electric net plant subject to rate-making principles • 11.5% weighted average return on equity • 33 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 $8,186 67% $4,019 33% • No expected need for electric rate base increase through 2029 • 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 2017 reduces rate base for 80% of pre-tax income on ROEs exceeding 11% • 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 10.6% for 2018 • Managing capital and O&M spending to minimize the need for gas base rate relief Electric rates among the lowest in the Midwest region and the United States

• Wind repowering efforts planned for oldest 1.5 MW GE turbines in fleet – 173 turbines (2017), 110 turbines (2018) – Continued evaluation of remaining 423 GE turbines in fleet • Operating capital varies with timing of major power generation planned outages and system requirements Capital Investment Plan • 551 MW Wind X project completed on time and under $888 million regulatory cap in fourth quarter 2016 • Approval received for and construction initiated on 2,000 MW, $3.6 billion Wind XI project – 338 MW (2017), 680 MW (2018), 982 MW (2019) $538 $339 $507 $534 $391 $274 $989 $1,109 $1,130 $1,157 $1,318 $1,375 - 200 400 600 800 1,000 1,200 1,400 1,600 2014 2015 2016 2017F 2018F 2019F $ M il li on s Operating Development ($ millions) 2017-2019 Current Plan Prior Plan Operating $ 1,199 $ 972 Development 3,850 403 Total $ 5,049 $ 1,375

Wind Repowering • Equipment was purchased in 2016 sufficient to repower up to 1,059 MW / 706 GE turbines by 2020, which will qualify for production tax credits • Plan reflects 424.5 MW (283 turbines) and $494 million total repowering investment in-service 2017/2018 • Yields net savings for customers • Minimal environmental impact and permitting • Depending on the tower height and length of blades that can be installed during repowering (82.5 meters or 87 meters), repowering will increase annual production by between 19% and 26% Illustration of 87m blade change: New technology installed with longer rotors, upgraded gearboxes and controls on top of existing towers and foundations

Build Renewable Energy Percent of Iowa Retail Sales MW Installed Capacity Cumulative Investment ($ billions) 2012 Actual 34% 2,285 $3.7 2013 Actual 38% 2,329 $3.8 2014 Actual 39% 2,832 $4.6 2015 Actual 47% 3,448 $5.8 2016 Actual 55% 4,048 $7.0 2017 Plan 63% 4,386 $7.8 2018 Plan 66% 5,066 $8.7 2019 Plan 76% 6,048 $10.2 2020 Plan 89% 6,048 $10.2 MidAmerican Energy’s Iowa Wind Generation MidAmerican Energy Participates in the Midcontinent Independent System Operator 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

• In 2015 and 2016, Exelon publicly reported it would retire Quad Cities Nuclear Station by May 2018, prior to the 2032 expiration of its operating license – MidAmerican worked with Exelon on a legislative solution to keep the plant open – Future Energy Jobs bill signed into law in Illinois in December 2016 • Provides Exelon annual subsidies through 2027, ensuring continued operation of plant • No incremental cost to MidAmerican customers; no incremental benefit to MidAmerican • MISO MVP transmission projects nearly complete, with $445 million of the $520 million total costs spent through December 31, 2016 Other Developments

MidAmerican Energy Appendix

MidAmerican Energy Company Overview • Headquartered in Des Moines, Iowa • 3,300 employees • 1.5 million electric and natural gas customers in four Midwestern states • 10,595 MW(1) of owned power capacity (1) Net MW owned in operation and under construction as of Dec. 31, 2016 SOUTH DAKOTA NEBRASKA KANSAS MISSOURI ILLINOIS WISCONSIN MINNESOTA IOWA MidAmerican Energy Service Territory Major Generating Facilities Wind Projects Wind XI sites TBD

Rate Base Growth Note: Rate base represents mid-year averages $6.7 $7.5 $9.0 $0 $100 $200 $300 $400 $500 $600 $700 $800 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 2014A 2015A 2016A O & M ($ m il li o n s ) Rate Base ($ b il li o n s )

MidAmerican Energy 2016 Retail Electric Sales by Class (GWh) 2016 Retail Electric Revenue: $1.7 billion Residential 27% Commercial 16% Industrial 50% Other 7%

• Private generation activities in Iowa – Iowa Utilities Board approved MidAmerican‟s net metering tariff as part of a three 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 on avoided costs: proposal to set it 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 Environmental Position • Effective with the retirement of Neal Units 1 and 2 in April 2016, MidAmerican Energy has 2,708 MW(1) of coal-fueled generation capacity remaining • Projected environmental capital spend(2) – $193 million from 2017-2019 (1) Net owned capacity as of December 31, 2016 (2) Environmental capital expenditures forecast excludes equity AFUDC (3) Net MW owned in operation and under construction Asset Profile 84% 2% 14% Renewables and Other Natural Gas Generation Coal Generation Net Property, Plant and Equipment as of December 31, 2016 December 31, 2000 Power Capacity – 4,086 MW (3) December 31, 2016 Power Capacity – 10,595 MW (3) Coal 26% Natural Gas 13% Nuclear and other 4% Wind 57% Coal 70% Natural Gas 19% Nuclear and Other 11%

• Recoveries for transmission service in MISO for MidAmerican Energy- owned regional transmission assets were based on 12.38% return on equity prior to September 28, 2016 • Two FERC complaint dockets seek to lower base ROE to 9.15% and 8.67% for periods beginning November 2013 and March 2015, respectively • FERC decision in the first complaint effective September 28, 2016 ordered 10.32% ROE (before incentive adders) • ROE refunds in first case expected to be fully processed by May 2017 • Preliminary decision by administrative law judge in second complaint recommending 9.70% ROE (before incentive adders) pending before the FERC Commissioners • Immaterial refund reserve established for the period from November 2013 through May 2016 consistent with 15 month refund obligations • Final decision in the second case expected mid-2017 MISO ROE Proceedings

Stefan Bird Cindy Crane President and CEO Rocky Mountain Power President and CEO Pacific Power 2017 Fixed-Income Investor Conference

PacifiCorp Retail Sales 2016 compared to 2015 down 0.7% • Industrial sales down 2.5% • Commercial sales down 2.3% • Residential sales up 2.1% 2017 forecast vs. 2016 down 0.5% • Industrial sales - higher due to modest extraction industry growth • Commercial sales - higher due to economic growth partially offset by efficiencies • Residential sales - lower due to use per customer reductions more than offset growth in new customers 0 7 14 21 28 35 42 49 56 63 2011 2012 2013 2014 2015 2016 2017F 2018F T W h PacifiCorp Retail Sales (weather-normalized) Annual Growth Rate 2012 = 0.1% 2013 = 0.3% 2014 = 1.2% 2015 = (0.9%) 2016 = (0.7%) 2017 = (0.5%) 2018 = (0.3%)

PacifiCorp Capital Expenditures ($ millions) 2017-2019 Current Plan Prior Plan Operating $ 1,648 $ 1,790 Development 1,807 732 Total $ 3,455 $ 2,522 $603 $660 $569 $564 $501 $583 $463 $256 $334 $286 $484 $1,037 - 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2014 2015 2016 2017F 2018F 2019F $ M il li on s Operating Development 2017-2019 forecast vs. prior plan up $933 million • $1,075 million higher development capital expenditures leverage safe harbor investments to deliver cost-effective fleet repowering and greenfield wind opportunities in-service by 2020. Yields net savings to customers - 240 MW additional wind (2020) - 805 MW repowered wind (2019/2020) • $142 million lower operating capital expenditures, primarily in thermal generation due to new operating environment

Wind Repowering & New Development New technology installed with longer rotors, upgraded gearboxes and controls on top of existing towers and foundations Illustration of 87m blade change: • New wind development of 240 MW with an anticipated cost of $377.2 million is expected to be completed by 2020 • Wind repowering - Equipment was purchased in 2016 sufficient to repower the entire 1,030 MW wind fleet by 2020, which will qualify for production tax credits - Plan reflects 805 MW and $916.5 million total repowering investment by 2020 - Yields net savings for customers - Minimal environmental impact and permitting

Energy Imbalance Market • $142.6 million aggregate EIM footprint customer benefits realized November 2014 to December 2016 – $76.4 million benefits to PacifiCorp customers • Optimizes generation and transmission to serve customer demand across the entire EIM footprint in a 5-minute market • Low cost renewable energy imports from California are increasingly displacing fossil generation in low load periods; fossil plants provide low cost flexible ramp service • Benefits grow as market expands – Fall 2017 Portland General Electric – Spring 2018 Idaho Power Company – Spring 2019 Seattle City Light – Spring 2019 BANC/SMUD

Advanced Metering Infrastructure Projects Scope Benefits • $146.4 million investment • Oregon o 590,000 smart meters o In-service Jan 2018 – Dec 2019 • Idaho o 79,000 smart meters o In-service Dec 2019 • 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

0 5 10 15 20 2011 2012 2013 2014 2015 2016 2017F 2018F T W h Pacific Power Retail Sales Weather Normalized 2012 = (0.4)% 2013 = 0.0% 2014 = 1.3% 2015 = (0.5%) 2016 = 0.4% 2017 = (3.5%) 2018 = (0.5%) Annual Growth Rate Pacific Power Retail Sales 497 GWh (-3.8%) 115 GWh (-2.8%) 7 GWh (-0.9%) 2017 forecast sales compared to 2016 down 3.5% • Industrial sales – lower due to loss of large industrial customer • Commercial sales – slight decline, due in part to efficiency in equipment and lighting partially offset by economic growth and expansion of data centers • Residential sales – lower due to decline in use-per-customer, partially offset by new customer growth

Oregon (authorized ROE 9.8%) • No general rate case in the near future; last general rate case filed in 2013 • Transition Adjustment Mechanism rate increase of $11.7 million or 0.9% for changes in forecast net power costs and production tax credits, effective January 1, 2017 Washington (authorized ROE 9.5%) • Approved two-year rate plan with rate increase of 1.7%, effective October 2016; second step increase of 2.3% effective September 2017 – Incorporates accelerated coal depreciation and new decoupling mechanism – Earliest next case could become effective is mid-2018 California (authorized ROE 10.6%) • Next general rate case deferred until January 1, 2019, effective date; last general rate case filed in 2009 • Energy Cost Adjustment Clause and Greenhouse Gas and Revenues Application rate reduction of $4.9 million (3.8%), for changes in forecast net power costs and greenhouse gas costs and revenues, effective January 1, 2017 • Post Test Year Adjustment Mechanism for inflation-based cost increases of $1.5 million (1.2%), effective January 1, 2017 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 • Pacific Power compliance position is sufficient until 2028 – 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 currently underway will result in implementation rules by July 2017 – Authorizes utilities to invest in electric vehicle charging • Electric utility transportation electrification proposals are under review by the Commission with resolution expected in late 2017 or early 2018 – Maintains level playing field for service territory acquisitions by requiring acquirer to meet RPS requirements and pay for any stranded costs Oregon Clean Electricity and Coal Transition Plan Update

Cindy Crane President & CEO Rocky Mountain Power

Rocky Mountain Power Retail Sales 269 GWh (1.1%) 88 GWh (1.0%) 16 GWh (-0.5%) 2017 forecast sales compared to 2016 up 0.9% • Industrial sales – higher due to improved economic conditions and market pricing • 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 2011 2012 2013 2014 2015 2016 2017F 2018F T W h Rocky Mountain Power Retail Sales Weather Normalized 2012 = 0.4% 2013 = 0.5% 2014 = 1.2% 2015 = (1.0%) 2016 = (1.3%) 2017 = 0.9% 2018 = (0.1%) Annual Growth Rate

Rocky Mountain Power Regulatory Update Utah (authorized ROE 9.8%) • No general rate case in near future; last general rate case filed in 2014 • Energy Balancing Account filing to recover $15.0 million in deferred net power costs, reduced rates 0.8% effective November 1, 2016 Wyoming (authorized ROE 9.5%) • No general rate case in near future; last general rate case filed in 2015 • Energy Cost Adjustment Mechanism filing to recover $12.2 million in deferred net power costs, reduced rates 0.5% effective November 1, 2016 Idaho (authorized ROE 9.9%) • No general rate case in near future; last general rate case filed in 2011 • Energy Cost Adjustment Mechanism filing to recover $16.7 million in deferred net power costs, reduced rates 0.7% effective April 1, 2016 • Filing to adjust net power costs in base rates reduced by $1.0 million (0.4%) effective January 1, 2017

Utah Sustainable Transportation and Energy Plan • Senate Bill 115 signed into law March 30, 2016 • Phase I approved: – Capitalization and amortization of demand side management costs and creation of the coal plant risk mitigation fund – Net power cost true-up changed to 100% – Renewable Energy Tariff – Funding budget of $50.0 million from 2017 through 2021, surcharge rates replace discontinued Utah Solar Incentive Program – Projects approved: • NOx clean coal technology programs ($1.4 million) • Solar and Energy Storage Program ($5.0 million) • Gadsby Curtailment Program ($0.5 million) • Phase II pending: (approval by July 1, 2017) – Electric Vehicle Program ($10.0 million) • Commercial Charger Incentives • Residential Time of Use Tariff

• Utah customers are pursuing clean energy goals Renewable Development Projects • In addition to wind development, PacifiCorp is pursuing solar projects in response to customer demand for renewables – Focused on company-owned properties to mitigate development costs and risks – >50 MW sites for potential of ~440 MW new solar development to capture Investment Tax Credit for benefit of customers 100% communitywide renewable by 2032 Reduce emissions 15% in 15 years 100% communitywide renewable by 2032 Carbon neutral by 2050

Rocky Mountain Power Utah Net Metering • Phase I completed in 2015 – Adopted framework for assessing net metering costs and benefits – Limited to quantifiable costs/benefits • Company filed in November 2016 to initiate second phase of docket to implement framework – Close current net metering tariff to new service – Implement transitional tariff – Establish new residential schedule with a 3-part rate design for new private customer generators • Negotiations underway with parties to determine if resolution of issues can be achieved; litigation schedule established with hearings in August 2017 1,548 2,222 3,572 6,690 16,689 18,137 - 5,000 10,000 15,000 20,000 2012 2013 2014 2015 2016 2017 YTD Utah Net Metering Cumulative Interconnections Residential Non-Residential Total

PacifiCorp Appendix

PacifiCorp Overview • Six-state service territory ‒ Utah – Oregon ‒ Idaho – Washington ‒ Wyoming – California • 5,600 employees • 1.8 million electricity customers • 143,000 square miles of service territory • 16,500 transmission line miles • 10,894 MW(1) owned power capacity (1) Net MW owned in operation as of December 31, 2016

Rate Base Growth Note: Rate base represents mid-year averages $16.6 $17.2 $17.4 $0 $200 $400 $600 $800 $1,000 $1,200 $0.0 $4.0 $8.0 $12.0 $16.0 $20.0 2014A 2015A 2016A O & M ($ m il li o n s ) Rate Base ($ b il li o n s )

PacifiCorp Retail Sales 2016 Retail Sales by Class (GWh) 2016 Retail Sales by State (GWh) 2016 Retail Electric Revenue: $4.9 billion Residential 30% Commercial 31% Industrial & Irrigation 38% Other 1% California 1% Oregon 24% Washington 7% Idaho 7% Utah 44% Wyoming 17%

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, 2016 Coal 55% Gas 25% Hydro 10% Wind and Other 10% Coal 72% Gas 13% Hydro and Other 15% March 31, 2006 Power Capacity – 8,470 MW (1) December 31, 2016 Power Capacity – 10,894 MW (1) (1) Net MW owned in operation and under construction

PacifiCorp Environmental Position Arizona • EPA issued the pre-publication version of its approval of Arizona‟s amended Regional Haze state implementation plan (SIP) on January 13, 2017, allowing Cholla Unit 4 to remain coal-fueled through April 2025 with the commitment to cease coal-fueled operation at that time, and avoiding the retrofit of selective catalytic reduction (SCR) Colorado • PacifiCorp and the owners of Craig Unit 1 have agreed with state and federal agencies and environmental groups to amend the Colorado Regional Haze SIP to allow Unit 1 to retire by December 31, 2025, or convert to natural gas under certain schedule requirements in lieu of installation of SCR. State of Colorado approval of the alternative is expected during the 2017 state legislative session. EPA review and approval will follow thereafter Utah • EPA published its final action on the updated Utah Regional Haze SIP in the Federal Register on July 5, 2016, requiring SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2 by August 4, 2021. PacifiCorp has filed a request for reconsideration and request for administrative stay with EPA, and subsequently filed petitions for judicial review and stay with the 10th Circuit Court. A court order on the stay request is expected by April 2017 Wyoming • Effective March 3, 2014, EPA issued a federal implementation plan (FIP) for the Wyodak plant, requiring the installation of SCR within five years (i.e., by 2019). The 10th Circuit Court issued a day-for-day stay on the Wyodak requirement in September 2014. The Court‟s decision on the appeals will not likely occur until late-2017, at the earliest • PacifiCorp continues to assess compliance options for the 280 MW Naughton Unit 3, including conversion to natural gas or accelerated retirement in lieu of SCR and baghouse retrofits prescribed by the Wyoming Regional Haze SIP(1) Environmental Expenditures • Forecast(2) environmental expenditures include $58 million in 2016, $32 million in 2017, $21 million in 2018 and $14 million in 2019 (1) The state of Wyoming is currently finalizing a Naughton Unit 3 permit amendment that will provide the option for natural gas conversion to occur up to one year following EPA’s approval of the Wyoming Regional Haze state implementation plan requirements for Naughton Unit 3. The state’s amended p lan is yet to be submitted to EPA for review and approval (2) 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 – Permitting near complete, in-service 2018 • Gateway West – BLM record of decision on 8 of 10 segments November 2013 – Remaining two segments across Idaho record of decision issued January 2017 • Gateway South – BLM record of decision December 2016 • Boardman-to-Hemingway – BLM record of decision expected second quarter 2017 • Segments In-Service – Populus-to-Terminal November 2010 – Mona-to-Oquirrh May 2013 – Sigurd-to-Red Butte May 2015 Over $6 billion total cost planned; $1.6 billion placed in-service

Paul Caudill President & CEO NV Energy 2017 Fixed-Income Investor Conference

0 2 4 6 8 10 2011 2012 2013 2014 2015 2016 2017F 2018F T W h Sierra Pacific Power Co. Energy Retail Load (Weather-Normalized) 0 6 12 18 24 2011 2012 2013 2014 2015 2016 2017F 2018F T W h Nevada Power Co. Energy Retail Load (Weather-Normalized) NV Energy Customer Load System Load Comparison 2016 versus 2015 Nevada Power Company • Commercial up 0.9% led by retail expansion • Residential up 1.0% due to customer growth(1) • Industrial down 3.1% due to customer migration to distribution only service (MGM Resorts International, Wynn Las Vegas) Sierra Pacific Power Company • Industrial up 1.6% primarily led by manufacturing • Residential up 2.6% based on customer growth(1) • Large mining down 0.2% due to low metal prices Load Forecast For 2017 and 2018 Nevada Power Company • Customer migration to distribution-only service reduces load in 2017, while retail and manufacturing loads help drive non-residential load growth in 2018 Sierra Pacific Power Company • Increasing data center and manufacturing loads will help drive non-residential load growth Annual Growth Rate 2012 = 3.3% 2013 = 2.2% 2014 = 0.4% 2015 = 1.7% 2016 = 1.8% 2017 = 0.4% 2018 = 3.8% Annual Growth Rate 2012 = 0.8% 2013 = 0.1% 2014 = (0.8%) 2015 = 1.7% 2016 = 0.3% 2017 = (3.1%) 2018 = 1.4% (1) Does not reflect the impact of billing changes for private generation

Capital Investment Plan • Capital investment for 2017-2019 increased $89.0 million from prior plan primarily due to additional electric delivery new business and transmission system reinforcement projects $388 $522 $528 $302 $295 $310 $170 $49 $1 $155 $91 $66 - 100 200 300 400 500 600 2014 2015 2016 2017F 2018F 2019F $ M il li on s Operating Development ($ millions) 2017-2019 Current Plan Prior Plan Operating $ 907 $ 981 Development 312 149 Total $ 1,219 $ 1,130

NV Energy Regulatory Update Nevada Power Company • 2016 Integrated Resource Plan Amendment – December 2016, Public Utilities Commission of Nevada: • Approved proposed 100 MW power purchase agreement with Techren Solar LLC • Authorized early retirement of 257 MW Reid Gardner Station Unit 4, utilizing must-run status through March 11, 2017, to burn existing coal stockpile • 2017 Deferred Energy Accounting Adjustment – March 2017, filing submitted to Public Utilities Commission of Nevada – Resets public policy rates for energy efficiency and renewable energy programs • 2017 Regulatory Rate Review – Preparations underway for triennial rate review proceeding before the Public Utilities Commission of Nevada; filing will be made by June 5, 2017 – Focus on no increase in revenue requirement, will likely result in adjustments to individual customer class rates

NV Energy Regulatory Update Sierra Pacific Power Company • 2016 Integrated Resource Plan – December 2016, Public Utilities Commission of Nevada order: • Approved energy efficiency programs, two transmission investments, energy supply plan • Denied acquisition of South Point Energy Center due to energy choice initiative uncertainty • NV Energy filed a petition for reconsideration – February 2017, Public Utilities Commission of Nevada continued to deny acquisition of South Point Energy Center; asset purchase agreement terminated • 2016 Regulatory Rate Review – December 2016, Public Utilities Commission of Nevada approved overall customer rate reduction; reestablished six additional megawatts of private generation at full retail rate – January 2017, petition for reconsideration filed addressing private generation six megawatts – February 2017, Public Utilities Commission of Nevada issued order granting itself an open- ended period of time to take action on private generation petition for reconsideration • 2017 Deferred Energy Accounting Adjustment – March 2017, gas and electric filings submitted to Public Utilities Commission of Nevada – Resets public policy rates for energy efficiency and renewable energy programs

Energy Imbalance Market Progress • Provides efficient method for balancing supply and demand through automated dispatch by a market operator (California ISO) • Pre-energy imbalance market NV Energy balanced supply and demand using internal resources • Post-energy imbalance market balancing occurs regionally with more diverse resource portfolio, including integration of renewable energy (solar and wind) • NV Energy entered the market December 2015 • Captured $13.5 million of transactional benefits from energy purchases and sales since entering the EIM • Benefit range presented to Public Utilities Commission of Nevada of $6.0 million to $9.5 million in 2017

Net Energy Metering Update 0 5,000 10,000 15,000 20,000 25,000 2012 2013 2014 2015 2016 2017 YTD NV Energy Private Generation Cumulative Interconnections Residential Non-Residential In 2016, Private Generation customers represented approximately 2% of NVE’s total electric customers • September 2016, NV Energy and stakeholders including members of private generation industry entered into stipulation to grandfather 32,000 private solar generation customers; Public Utilities Commission of Nevada accepted stipulation • December 2016, Public Utilities Commission of Nevada recognized in Sierra Pacific Power regulatory rate review: – Existence of cost shift from private generation customers – Rate utility pays for excess energy from private generation should reflect energy market – Private generation customers previously viewed as separate customer class for establishing rates • March 2017, NV Energy and stakeholders filed petition with Public Utilities Commission of Nevada to extend period for eligible customers to opt-in to grandfathered rates until July 1, 2017

Major Customer Applications to Utilize Alternate Energy Provider Inactive Applicant Peak Load (MW) Impact Fee Status Las Vegas Sands Corporation 29 $23.97m Application approved 2015; compliance items not satisfied Peppermill Resorts 10 Undetermined Application withdrawn Approved Applicant Peak Load (MW)(1) Impact Fee Status MGM Resorts International (south)(2) 174 $82.2m Transition completed October 2016 Wynn Las Vegas(2) (south) 20 $15.3m Transition completed October 2016 Switch, Ltd. (south) 34 $27.0m Amended application approved December 2016 Transition estimated June 1, 2017 Switch, Ltd. (north) Under construction $0.00 Amended application approved December 2016 Transition estimated June 1, 2017 Caesars Enterprise Services, LLC(2) (south) 87 $44.0m Application approved March 2017; estimated transition of September 1, 2017 Caesars Enterprise Services, LLC (north) 10 $3.5m Application approved March 2017; estimated transition of September 1, 2017 Total 325 $172.0m (1) Peak load on July 28, 2016 of 7,966 MW (6,124 at Nevada Power and 1,842 at Sierra Pacific Power) (2) On-going non-bypassable charges apply

Energy Choice Initiative Background • Energy Choice Initiative was a ballot initiative that amends the Nevada State Constitution “to open Nevada‟s energy markets and give consumers the option to purchase renewable energy and lower overall energy costs” • Initiative sponsored by Nevadans for Affordable, Clean Energy Choices Political Action Committee – Primary sponsors are Las Vegas Sands Corporation and Switch Ltd. • Initiative was placed on November 2016 general ballot as Question 3 – “Shall Article 1 of the Nevada Constitution be amended to require the Legislature to provide by law for the establishment of an open, competitive retail electric energy market that prohibits the granting of monopolies and exclusive franchises for the generation of electricity?” • In the November 2016 general election, the initiative was approved by 72% of voters • Initiative will appear on the November 2018 ballot, and must pass again with a majority vote in order for the Nevada State Constitution to be amended • If initiative passes in November 2018, the legislature will be required by Nevada State Constitution to provide implementing laws by July 1, 2023

Energy Choice Initiative Executive Order Issued February 9, 2017 • Nevada Governor Sandoval issued executive order establishing the Governor‟s Committee on Energy Choice • Purpose is to review, evaluate and develop written plans for the full implementation of energy choice by 2023, provided the initiative again passes by a vote of the people in 2018 • Appointed Nevada lieutenant governor as chair to 22-member committee, comprised of: – Attorney general of the state of Nevada – Two members each of the Nevada State Senate and the Nevada State Assembly – Consumer advocate of the Bureau of Consumer Protection – Appointment of remaining 15 members from NV Energy, rural/municipal co-op utility, large consumers of electricity, small to mid-sized businesses, Nevada Resort Association, mining, organized labor, senior citizen organizations, renewable energy industries, homebuilders and conservation organizations – Non-voting committee members include a member of Public Utilities Commission of Nevada, Nevada Governor‟s Office of Energy and Office of Economic Development • Report of recommendations due to Nevada governor no later than July 1, 2018, in advance of second vote in 2018 general election

Simple Framework to a Complex Transition Regulated and efficient competitive market July 2023 Level playing field for all retail providers Customer protections MARKET POLICY 564 jobs/$91.9 million payroll $3.2 billion owned generation assets $4.2 billion energy contract obligations (NPV 2020-2046) NO STRANDED ASSETS Wholesale market structure Retail market structure State regulatory functions Default and provider of last resort services Transmission and distribution services Energy policies and programs COMPLEXITY, RISKS & COST Resource adequacy Renewable and economic development Energy efficiency ENERGY POLICY No structural winners and losers No increase in prices paid over current model Reliable service CUSTOMERS NV Energy Respects Public Policy Transition Plan 2018 • Market Structure • Competitive Services • Regulatory Framework • Restructuring and Transition Costs

Fundamental Assumptions Consistent with the Energy Choice Initiative 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, and any affiliates, 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 in the transition

NV Energy Appendix

NV Energy Today • Headquartered in Las Vegas, Nevada, with major operations in Reno, Nevada, area • 2,466 employees • 1.25 million electric and 162,000 gas customers • Service to 90% of Nevada population, along with tourist population in excess of 45 million • 6,138 megawatts of owned power generation • Provides electric services to Las Vegas and surrounding areas • 910,000 electric customers • 4,766 megawatts of owned power generation capacity(1) • Provides electric and gas services to Reno and northern Nevada • 340,000 electric customers and 162,000 gas customers • 1,372 megawatts of owned power generation capacity(1) Nevada Power Company Sierra Pacific Power Company (1) Net summer peak megawatts owned in operation as of December 31, 2016

Rate Base Growth Note: Rate base represents mid-year averages $7.0 $6.8 $6.8 $0 $100 $200 $300 $400 $500 $600 $0.0 $2.0 $4.0 $6.0 $8.0 2014A 2015A 2016A O & M ($ m il li o n s ) Rate Base ($ b il li o n s )

NV Energy 2016 Retail Electric Sales by Class (GWh) Residential 43% Commercial 22% Industrial 34% Other 1% Nevada Power Total 2016 Retail Electric Revenue: $2.0 billion Total 2016 Retail Electric Revenue: $0.7 billion Residential 29% Commercial 35% Industrial 36% Sierra Pacific Power

Customer Retention Price and Service Improvements • Nevada Power average monthly residential bill lower today than in 2007 – Based on average usage of 1,141 kilowatt-hours – $140.77 January 2017 versus $141.91 October 2007 – 2017 mandatory general rate review objective would be no change or reduction in the revenue requirement, similar to 2014 • Sierra Pacific Power average monthly residential bill lower today than in 2007 – Based on average usage of 743 kilowatt-hours – $76.98 January 2017 versus $98.50 July 2007 – 2016 general rate case settlement resulted in $2.9m reduction to the electric revenue requirement • In 2016, NV Energy received its best TQS Inc. survey score ever of 93.5% for large commercial and industrial customers, a 1.6% improvement from 2015 and 5.4% increase from 2014

NV Energy Environmental Position • NV Energy is reducing use of coal-fueled generation – 2017 retirement of Reid Gardner Unit 4 (257 MW) – 2019 elimination of Navajo interest (255 MW) – 2025 retirement of North Valmy (261 MW) • Forecast(1) environmental expenditures include $4 million in 2017, $5 million in 2018 and $7 million in 2019 Nevada Power Asset Profile 64% 33% 3% Renewables and Other Natural Gas Generation Coal Generation Net Property, Plant and Equipment as of December 31, 2016 Sierra Pacific Power Asset Profile 74% 19% 7% Renewables and Other Natural Gas Generation Coal Generation Net Property, Plant and Equipment as of December 31, 2016 December 31, 2016 Power Capacity – 6,138 MW (2) Coal and Other 13% Natural Gas 87% (1) Environmental capital expenditures forecast excludes equity AFUDC (2) Net MW owned in operation and under construction

• Navajo Generating Station is a 2,250 megawatt coal-fired facility in-service in 1974 near Page, Arizona, on the Navajo Nation American Indian Reservation • Six owners: NV Energy, Salt River Project (operator), Arizona Public Service, Tucson Electric, Los Angeles Department of Water and Power, and U.S. Bureau of Reclamation • NV Energy‟s ownership level (11.3% or 255 megawatts of the facility) resulted in the following amounts for 2016: – Operations and maintenance expense of $19.7 million – Capital expense of $5.8 million – Year-end undepreciated value of the plant of $57.1 million • February 2017, owners communicated lease will not be extended beyond expiration of December 22, 2019, for plant, water, coal and transmission • Discussion is underway between Salt River Project and the Navajo Nation to draft agreements necessary to operate through December 22, 2019 • If agreement is not reached by July 1, 2017, owners will begin decommissioning, demolition and remediation of the plant as required by the existing lease end date • March 2017, stakeholder meeting held in Washington D.C. to discuss long-term options for continued plant operation; follow-up meeting scheduled April 12, 2017 Navajo Generating Station

• Nevada Senate Bill 123, passed in 2013, already required NV Energy to eliminate its interest in the Navajo Generating Plant by December 31, 2019 – As part of the 2013 law, NV Energy was required to file a plan with the Public Utilities Commission of Nevada to reduce coal-fired generation under the emissions reduction and capacity replacement plan – NV Energy filed the plan in 2014, and approved by Public Utilities Commission of Nevada • Emissions reduction and capacity reduction plan allows for recovery of costs necessary to decommission, demolish and remediate the Navajo Generating Station site, as well as the undepreciated value of the plant at the time of retirement or elimination • Impact to NV Energy is minimal, as an early shutdown in 2017, would eliminate operating and maintenance expense related to operating Navajo Generating Station, allow for recovery of costs necessary to retire and remediate the plant and would eliminate a minimum dispatch provision, which would enable additional economic purchasing of energy for customers Navajo Generating Station

Bill Fehrman President and CEO BHE Renewables 2017 Fixed-Income Investor Conference

BHE Renewables 2016 Update Solar • Community Solar Gardens – 66 MW community solar gardens project acquired in January 2016 and is 91.1% subscribed – 32 MW community solar gardens project acquired in 2015, started commercial operation as of February 1, 2017, and is 100% subscribed • Alamo 6 – 110 MW project acquired in January 2017, with commercial operation achieved in March 2017 • Solar Star 1 – Had two unplanned outages in 2016. There are now four spare transformers on site • Topaz and Agua Caliente – Both projects had high availability and generation above budget for 2016

BHE Renewables 2016 Update Wind • Marshall Wind – 72 MW project acquired in September 2015, commercial operation under its PPAs started in May 2016 • Grande Prairie Wind – 400 MW project completed in November 2016, commercial operation under its PPA started in December 2016 • Pinyon Pines, Jumbo Road and Bishop Hill – All projects had high availability and near budgeted generation despite lower than expected wind resource • Tax Equity – Funded renewable tax equity investments, including $170 million in 2015, $584 million in 2016, and $85 million in 2017

Renewables Opportunities • BHE Renewables is pursuing a diversified strategy for growth, including: – Continuing to pursue direct ownership of utility-scale wind and solar assets with long-term offtake agreements – Tax equity investment opportunities for hedged or contracted utility-scale wind projects • Kingfisher, South Plains II, Shannon, Mariah and New Creek have all been funded • Chapman Ranch is secured under a definitive agreement – Wind repowering is currently not economical at BHE Renewables as our turbines are relatively new, still within the PTC period and have already implemented the new technology (i.e. increased tower heights and rotor diameters) – BHE Renewables has initiated the process to establish an interconnection agreement for a 50 MW battery storage facility at the Solar Star site, which can be bid into the California energy storage market

BHE Renewables Appendix

BHE Renewables Overview (1) Based on net owned capacity of 4,082 MW in operation and under construction as of January 31, 2017 (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) 83% 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 2016 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 36% Wind 28% Geothermal 8% Hydro 4% Natural Gas 24% Portfolio Composition (1) 2017-2019 24% 2020-2029 7% 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 Generation Mix Alamo 6 TX 2017 2042 CPS 110 110 Community Solar Gardens MN 2016-2017 (2) (2) 95 95 1,631 1,483 WIND Pinyon Pines I & II CA 2012 2035 SCE 300 300 Jumbo Road TX 2015 2033 Austin Energy 300 300 Bishop Hill II IL 2012 2032 Ameren 81 81 Grande Prairie NE 2016 2037 OPPD 400 400 Marshall Wind KS 2016 2036 (3) 72 72 1,153 1,153 GEOTHERMAL Imperial Valley CA 1982-2000 (4) (4) 338 338 HYDROELECTRIC Casecnan Phil. 2001 2021 NIA 150 128 Wailuku HI 1993 2023 Hawaii Electric 10 10 160 138 NATURAL GAS Cordova IL 2001 2019 Exelon Generation 512 512 Power Resources TX 1988 2018 EDF Trading 212 212 Saranac NY 1994 2017 TransAlta Energy Mktg 245 196 Yuma AZ 1994 2024 SDG&E 50 50 1,019 970 Total Owned and Under Construction 4,301 4,082

BHE Renewables – Net Income ($ millions) Years Ended Dec. 31 2016 2015 2014 Net Income: Topaz 56 54 45 Solar Star 6 20 5 Agua Caliente 15 12 17 Bishop Hill 13 16 11 Pinyon Pines 13 1 12 Jumbo Road 10 4 1 Grande Prairie 8 1 - Marshall 3 - - MidAmerican Wind Tax Equity 37 4 - BHE Geothermal (17) (18) 1 Wailuku Hydro 2 3 - CalEnergy Philippines 47 42 39 Parent and Other (14) (15) (10) BHE Renewables Combined Net Income 179 124 121

Current Tax Legislation – Industry Impact • 2015 Omnibus spending bill extended and phased out tax credits for wind and solar • Wind PTC/ITC • 2016 – 100% • 2017 – 80% • 2018 – 60% • 2019 – 40% – Retains “start of construction” language – Developers will have the option to claim a 30% ITC instead of the PTC during the same period and with the same phase down rate • Solar ITC • 2016-2019 – 30% • 2020 – 26% • 2021 – 22% – Projects beginning construction in these years must be placed in-service by December 31, 2023 to qualify. The ITC will revert to its permanent 10% level if projects are not completed before January 1, 2024, or for projects that begin construction after 2021 • 50% bonus depreciation extended for five years, now expiring January 1, 2020 – Ramps down to 40% and 30%, respectively, in the final two years

Mark Hewett President and CEO BHE Pipeline Group 2017 Fixed-Income Investor Conference

Shipper Contract Updates 2017-2018 28% 2019-2020 38% 2021-2022 8% 2023-2028 22% 2029+ 4% NNG – Market Area Transportation Contract Maturities (1) (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 Dec. 31, 2016 • In 2016, completed approximately 1.2 Bcf/day in contract renewals with a 2% increase in rates, which provides additional $1.3 million in annual revenue • Market Area Transportation weighted average remaining contract term of five years • 74% of 2016 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 have a weighted average credit rating of BBB+/A3 • For Period One capacity expiring in 2016/2017, 94% elected to extend their contracts at Period Two rates, with 220,923 Dth per day electing 10-year contracts and 617,923 Dth per day electing 15-year contracts • 55% of capacity is committed to contracts that expire after 2019 • Weighted average remaining contract term of eight years • Weighted average shipper rating of BBB+/Baa1 • Shippers that do not meet credit standards are required to post collateral 2017 5% 2018-2019 36% 2020-2021 5% 2025-2028 16% 2031 31% 2032-2033 3% Uncontracted 4%

Kern River Gas Transmission Rate Proposal • On December 1, 2016, Kern River filed a proposal to establish an alternate set of Period Two rates for its customers – Uncontested settlement with all shippers either supporting or not opposing – FERC approved January 27, 2017 – Additional Period Two option for 25-year term compared with current options of 10 or 15 years – Applies to customers who are currently in Period Two, committed to Period Two or eligible for Period Two in the future – Customers may continue with existing Period Two rates or choose the Alternate Period Two rates – Alternate Period Two rates are specific to each respective customer group • Initial contract term of 10 or 15 years with the option to extend to 25 years – Book depreciation rates adjusted to extend the depreciable life of transmission assets to 2056 – Outstanding debt to be redeemed April 13, 2017 • 100% equity capitalization is reflected in Period Two rates • Benefits – Increases the likelihood of customers re-contracting capacity expiring in 2018 • Alternate Period Two rates approximately $0.02 - $0.07 per Dth lower than current Period Two rates • Alternate Period Two rates correlate better with the forward spread – Provides a third option to customers considering Period Two service – Extends rate base

$177 $149 $140 $153 $164 $149 $68 $70 $44 $137 $24 $145 - 50 100 150 200 250 300 350 2014 2015 2016 2017F 2018F 2019F $ M il li on s Northern Natural Gas Capital Expenditures Operating Development Capital Investment Plan $16 $29 $42 $41 $28 $15 $2 $1 - 10 20 30 40 50 2014 2015 2016 2017F 2018F 2019F $ M il li on s Kern River Gas Capital Expenditures Operating Development ($ millions) 2017-2019 Current Plan Prior Plan Operating $ 466 $ 351 Development 306 212 Total $ 772 $ 563 ($ millions) 2017-2019 Current Plan Prior Plan Operating $ 84 $ 79 Development - - Total $ 84 $ 79

Focus on Customer Satisfaction – Northern Natural Gas ranked #1 and Kern River ranked #2 out of 36 interstate pipelines in Mastio & Company‟s 2017 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 12 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 – Kern River - Directly connected to end-use markets in Nevada and California Competitive Pricing – Both pipelines have demonstrated over 10 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 - Interest coverage of 9.5x in 2016 reflects significant improvement in financial stability since the company was acquired by BHE in 2002 when the metric was 3.1x – Kern River - 100% equity capitalization consistent with tariff design Competitive Advantages

BHE Pipeline Group Appendix

• 900 employees • 14,700-mile interstate natural gas transmission pipeline system • Market Area design capacity of 5.8 Bcf/day plus 1.7 Bcf/day Field Area delivery capacity to the Market Area • Five natural gas storage facilities, with a total firm capacity of more than 79 Bcf and more than 2.0 Bcf of peak day delivery capability • Access to five major traditional supply regions and direct access to two non- traditional (tight sands and shale) supply regions • Annual average deliveries of 1,005 Bcf over the prior three years – 1,031 Bcf in 2016 Northern Natural Gas Overview

• 2016 Field Area Expansion – Total capital expenditures of approximately $28 million, serving a customer in Permian Basin – Incremental entitlement of 142,000 Dth/day – Annual demand revenues of $10 million, with contract terms up to 12 years • 2017-19 Market Area Expansions – 2017 Projects – total capital expenditures of approximately $70 million, primarily serving LDCs • Incremental entitlement of 87,937 Dth/day • Annual demand revenues of $8 million, with contract terms from 4 to 10 years – 2018-19 Projects – total capital expenditures of approximately $86 million, primarily serving LDCs and a power plant • Incremental entitlement of 89,892 Dth/day • Pending regulatory approval with annual demand revenues of $15 million, with contract terms of 21 to 25 years • Future Field Area Expansion – Total capital expenditures of approximately $37 million, serving power plant expansion – Incremental entitlement of 210,000 Dth/day – 2017 in-service with annual demand revenues of $10 million, with contract term of 13 years Northern Natural Gas Expansion Projects

Kern River Gas Transmission Overview • Headquartered in Salt Lake City, Utah • 150 employees • 1,700-mile interstate natural gas transmission pipeline system • Delivers natural gas from Rocky Mountain basins to markets in Utah, Nevada and California • Design capacity: 2.2 million Dth per day of natural gas • Over 90% of capacity contracted under long-term contracts CALIFORNIA UTAH WYOMING ARIZONA NEVADA

Kern River Gas Transmission Strong Demand for Services Daily Average Scheduled Volume 2016 Deliveries by State (1) Based on the 2016 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 29% of Rockies natural gas supply in 2016 • Delivered approximately 20%(1) of California‟s demand for natural gas in 2015 • Delivered more than 82%(2) of southern Nevada‟s natural gas • During 2016, scheduled throughput averaged 110% of design capacity 0 500 1,000 1,500 2,000 2,500 3,000 2008 2009 2010 2011 2012 2013 2014 2015 2016 D th in m ill io n s Scheduled Design California 69% Nevada 27% Utah 4%

Lowest-Cost Option to Southern California

Scott Thon President and CEO AltaLink 2017 Fixed-Income Investor Conference

AltaLink Regulatory Update 2015-2016 General Tariff Application (GTA) − The Alberta Utilities Commission (AUC) approved 98% of requested operating expenses − Tariff relief of C$600 million (2015-2018) approved 2012-2013 Direct Assign Capital Deferral Account (DACDA) − AUC approved C$1.862 billion of the total C$1.977 billion of capital projects − C$109 million deferred to a future DACDA − Minor disallowances, anticipate 100% recoverability from third parties 2016 Generic Cost of Capital Decision (GCOC) − ROE was set at 8.3% for 2016 and 8.5% for 2017 (8.3% for 2013-2015) − Equity thickness of 37% for 2016 and 2017 (36% for 2013-2015) − AUC continues to support „A‟ category credit ratings 2017-2018 GTA − Traditionally AUC did not allow GTA negotiated settlement − In December 2016, the AUC approved the request to enter into a negotiated settlement process with intervenors − Successfully reached a negotiated settlement in principle on January 27, 2017 − Filing of the negotiated settlement took place on February 8, 2017, which includes C$58 million of additional savings for customers and C$130.3 million related to a depreciation surplus refund − Intervenor requests & responses completed in March 2017

2015-2016 GTA • The AUC approved C$600 million of customer rate relief in its decision • Reduces business risk by mitigating customer rate concerns • Rate relief coming at an optimal time given macroeconomic environment • Stepping up for customers with win-win solutions • Received significant support from customers, particularly industrials C$600 million of Customer Rate Relief Approved Approved Customer Rate Relief: 2015-2018 impact * 2017 and 2018 exclude approximately C$157 million of incremental proposed rate relief related to depreciation and salvage and an additional C$58 million related to a negotiated settlement 2015 2016 2017 2018 Discontinuation of CWIP-in-rate base 69 13 4 2 Refund of previously collected CWIP-in-rate base 123 142 - - Change from future income tax to flow through - 68 89 90 Total rate relief 192 223 93 92 Cumulative relief 192 415 508 600 Reported Net income 209 306 Normalized Net income 237 290 Customer Rate Relief (C$ millions)

Rate Base Investment Largely Complete CWIP balance negligible in 2016 (C$ billions) Forecast based on 2017-18 GTA, February 2017 2.5 3.5 5.3 7.0 1.2 1.8 1.3 0.2 3.7 5.3 6.6 7.2 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 2013A 2014A 2015A 2016A Mid-year Rate Base Mid-year CWIP AltaLink Capital Expenditures Normalizing 0.1 0.2 0.2 0.2 0.3 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 2017F 2018F Operating Development

73,000 74,000 75,000 76,000 77,000 78,000 79,000 80,000 81,000 2012A 2013A 2014A 2015A 2016A 4.5 5.0 5.5 6.0 6.5 7.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 N o v -1 3 J a n -1 4 Ma r- 1 4 Ma y -1 4 J u l- 1 4 S e p -1 4 N o v -1 4 J a n -1 5 Ma r- 1 5 Ma y -1 5 J u l- 1 5 S e p -1 5 N o v -1 5 J a n -1 6 Ma r- 1 6 Ma y -1 6 J u l- 1 6 S e p -1 6 N o v -1 6 (C$ billions) International exports (left) Manufacturing shipments (right) Alberta Economy Slows but Stabilizing late in 2016 Alberta • In 2016, Alberta was Canada‟s third largest economy and fourth most populated province • After falling for most of the first half of 2016, activity in the province began to improve in the latter half of the year • In December 2016, Alberta‟s unemployment rate was 8.1% versus the Canadian average of 7.0%. Alberta‟s labor market is improving with job gains in four of the last five months • The value of Alberta‟s exports have increased alongside oil production growth and higher oil prices AltaLink • Economy has caused delays in oil and gas grid connections; those delays are offset by renewable energy connection requests • After strong growth, load is leveling • AltaLink is not exposed to volume or price risk • AltaLink is focused on addressing customer cost concerns Source: Alberta Electric System Operator Source: Statistics Canada Business output rebounds from recession lows Alberta Electricity Demand (GWh) +0.4% +3.2% +2.5% -0.9% 64.3 80.2 49.4 33.3 18.3 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 2012A 2013A 2014A 2015A 2016A Average Pool Prices ($/MWh) (C$ billions)

Alberta’s Climate Leadership Plan • Alberta government introduced its Climate Leadership Plan (CLP) in November 2015 • Coal generation fully transitioning out of Alberta by 2030 − By 2030, one-third of Alberta‟s coal generating capacity is expected to be replaced by renewable energy; two-thirds will be replaced by natural gas − An economy-wide carbon tax was implemented January 1, 2017, to encourage energy efficiency and cover the cost of transitioning to renewables • A RFP for new renewable energy capacity is expected in Q2/Q3 2017 • First 400 MW of renewables to be in-service by 2019 • AltaLink transmission system ready to enable CLP Gas 70% Hydroelectric 4% Wind 24% Other 2% 2030 Alberta Generation Mix Coal 39% Gas 45% Hydroelectric 5% Wind 9% Other 2% 2016 Alberta Generation Mix

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 8,150 miles of transmission lines and 309 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 2016 rate base and CWIP was C$7.2 billion

• 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 Users (Distribution Companies, Direct Connects, Generators) Regulator Approves regulated transmission tariff TFO provides transmission service AESO provides open transmission access Users pay transmission tariff to AESO AESO pays approved revenue requirement Regulatory Framework Supports Predictable Revenue

Phil Jones President and CEO Northern Powergrid Holdings Company 2017 Fixed-Income Investor Conference

Regulatory Price Control Overview • Our performance in ED1 continues to improve – Solid start to the first two years of the ED1 period, with costs and outputs on target – Fastest improvements achieved in overall customer satisfaction during the year – Best ever year on network performance helped by automated switching and intelligent fuses – Lower debt rates are a value-creation opportunity; £450 million issued in the first two years of ED1 at a blended average rate of 2.49% • The regime continues to be stable and the RIIO model is widely viewed as a success – Revenues reduce and RAV grows as regulatory asset life transitions to 45 years – Efficient delivery of network outputs is crucial – Incentives remain central on cost efficiency and output delivery – Inflation protection continues to apply – Strong credit ratings compare well with the rest of the sector 1 – Plus RPI inflation 2 – ED1 indexed, figure stated for 2016-2017 3 – Total activity costs 4 – 2012-2013 prices (£ millions) - US GAAP 2016 2015 Revenues 735 746 Operating income 314 389 Capex 404 470 RAV 2,993 2,844 Interest cover 3.5x 4.1x Debt to RAV 62% 62% Regulatory parameters ED1 DPCR5 Allowed equity returns 1 6.0% 6.7% Allowed cost of debt 1,2 2.4% 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

Capital Investment Plan • Operating capital delivers our ED1 output commitments • The smart meter rental business has grown significantly from the prior plan with total plan capex increasing by £183 million, CAGR from 2014 to 2017 is 63% £377 £388 £329 £348 £331 £325 £35 £53 £98 £125 £86 £11 - 100 200 300 400 500 2014 2015 2016 2017F 2018F 2019F £ M il li on s Operating Development (£ millions) 2017-2019 Current Plan Prior Plan Operating £ 1,004 £ 1,025 Development 222 5 Total £ 1,226 £ 1,030

U.K. and European Economic Outlook Source: IMF, World Economic Outlook • Our assessment of Brexit is unchanged – the fundamentals of our business are not directly affected – Sustainability objectives are largely independent of EU – UK regulatory framework is at the leading edge of EU – Strategic interests in energy co-operation seem to promote the status quo • Currency fall has affected our contribution to BHE • The low inflation we faced a year ago has ended – Some foreign sourced input prices have increased – Offset by price control inflation protection • Driving growth across the country has moved up the domestic policy agenda – The productivity gap between London and the regions is a growing concern – Brexit is driving a move to more targeted, government- led industrial strategy 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 95 100 105 110 115 120 125 GD P (2 00 5 = 1 00 ) UK Euro area USA UK Euro area USAJan 2017: Jan 2016: Source: IMF, World Economic Outlook Minimal impact on UK growth so far… … but felt acutely on exchange rate

• Our existing network continues to provide development opportunities – Our ED1 business plan includes £83 million to enhance communications and controls – Distribution network operators are expected to transition to flexible distribution system operators to cope with increased diversity in supply and demand • Smart meters are providing organic growth, whereas in the oil and gas sector low commodity prices have diminished opportunities – Our smart meter rental business continues to deliver results, growth in 2016 exceeded projections. We now have over three million new smart meters contracted for a total investment of £480 million – Low oil and gas prices have restricted CE Resources‟ exploration and development activity • Equity funds have dominated recent deals, driving up prices – National Grid sold 61% of their gas distribution business to a Macquarie-led consortium valuing the business at £13.8 billion (US$17.4 billion) at 1.59 times RAV – Infracapital sold Calvin Capital to KKR so curtailing the auction process early – 50.4% stake in a 99% lease of Ausgrid sold to an Australian consortium at A$16.2 billion (a RAV premium of 41%) after higher Chinese bids were rejected on security grounds 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 60,000 miles of distribution lines • Approximately 67% of 2016 distribution revenue from residential and commercial customers through December 31, 2016 • Distribution revenue (£ millions): • Strong start to the ED1 period (eight-year price control started April 2015) with total expenditure for the 2015/2016 regulatory year at 97.1% of allowances and outputs 14.3% ahead of target. Groundwork now laid for delivering commitments effectively over the eight-year period • In 2016, a step-change is being achieved in overall customer satisfaction, from an average ranking of 5th in 2015 to an average ranking of 3rd in 2016 Twelve Months Ended 12/31/16 12/31/15 Residential 334 345 Commercial 109 117 Industrial 209 203 Other 9 9 Total 661 674

Greg Abel Chairman, President and CEO Berkshire Hathaway Energy 2017 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 assets to manage bypass risk by providing excellent service and competitive rates to our customers • Decarbonize our operations by participating in energy policy development, transforming our businesses and assets • Advance 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 cybersecurity and physical resilience programs Acquire companies • Additive to business model Competitive Advantage Berkshire Hathaway Ownership

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