2015 EEI Financial Conference November 8-11, 2015 Patrick J. Goodman Executive Vice President and Chief Financial Officer

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 the Company's 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 the Company 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 reliability and safety standards, affecting the Company’s operations or related industries; – general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including reliability and safety standards, affecting the Company'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 rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in 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 distributed generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the Company's ability to obtain long-term contracts with customers and suppliers; – performance, availability and ongoing operation of the Company's facilities, including facilities not operated by the Company, due to the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions; – a high degree of variance between actual and forecasted load or generation that could impact the Company'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 Company'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 BHE's and its subsidiaries' credit facilities; – changes in BHE's and its subsidiaries' credit ratings; – risks relating to nuclear generation; – 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; Forward-Looking Statements 2

– the impact of inflation on costs and the Company's ability to recover such costs in regulated rates; – increases in employee healthcare costs, including the implementation of the Affordable Care Act; – 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 transaction levels; – 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 Company's consolidated financial results; – the Company's ability to successfully integrate future acquired operations into its business; – the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the Company's control or by a breakdown or failure of the Company's operating assets, including storms, floods, fires, earthquakes, explosions, landslides, mining accidents, litigation, wars, terrorism, and embargoes; and – other business or investment considerations that may be disclosed from time to time in BHE's filings with the United States Securities and Exchange Commission or in other publicly disseminated written documents. Further details of the potential risks and uncertainties affecting the Company are described in BHE’s filings with the United States Securities and Exchange Commission. The Company 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 Appendix in this presentation for a reconciliation of those non-GAAP financial measures to the most directly comparable GAAP measures. Forward-Looking Statements 3

Our Strategy 4 Reinvest in our businesses • Position regulated assets to provide excellent service and competitive rates to our customers • Continue to invest in our employees and hard assets • Participate in energy markets and policy developments Internal growth • Invest in renewable generation • Invest in grid infrastructure • Modernize gas pipeline infrastructure Acquire companies • Strong strategic fit

Organizational Structure 5 2014 Berkshire Hathaway Inc. ($ billions) Revenue $ 194.7 Net Income $ 19.9 Equity $ 240.2 2014 Berkshire Hathaway Energy ($ billions) Revenue $ 17.3 Net Income $ 2.1 Equity $ 20.4 A3/BBB+/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/BBB+/A- Holding Company Aa2/A/A+(1) Regulated Electric and Gas Utility Baa2/BBB/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

Berkshire Hathaway Energy 6 • Berkshire Hathaway Energy’s integrated utilities operate in 11 states • Northern Powergrid has 3.9 million end-users, making it the third-largest distribution company in Great Britain • With our assets at PacifiCorp, NV Energy and AltaLink, we are the largest transmission owner in the Western Interconnection • Together, Northern Natural Gas and Kern River deliver approximately 8% of the natural gas consumed in the U.S. • Berkshire Hathaway Energy has 1,293 MW of solar generation in operation and under construction – 6% of the U.S. solar market • Berkshire Hathaway Energy has 6,190 MW of wind generation in operation and under construction – 8% of the U.S. wind market • Comparable companies Company Name Sept. 30, 2015 Market Cap(1) (billions) LTM June 30, 2015 Net Income(1) (billions) Duke Energy $49.5 $2.4 NextEra Energy Inc. $44.9 $2.9 Dominion Resources $41.8 $1.7 Southern Company $40.6 $2.1 Exelon Corp. $25.6 $2.3 BHE Net Income: LTM Sept. 30, 2015 $2.3 billion BHE retains more equity than any of its utility peers (1)As reported by S&P Capital IQ

Energy Assets 7 (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 Sept. 30, 2015 As of, and for the 12 months ended, Sept. 30, 2015 Assets $84 billion Revenues $17.9 billion Customers(1) 8.5 million Employees 21,000 Transmission Line 32,600 Miles Natural Gas Pipeline 16,400 Miles Generation Capacity 29,925 MW(2) Natural Gas 35% Coal 33% Renewables 30% Nuclear and Other 2%

• 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 holder of assets; its owner for life philosophy promotes stability and helps make BHE the buyer of choice in many circumstances – Tax appetite of Berkshire Hathaway has allowed us to realize significant tax benefits • No dividend requirement – Cash flow is retained in the business and used to help fund growth and strengthen our balance sheet BHE Competitive Advantage 8

9 Revenue and EBITDA Diversification • Diversified revenue sources reduce regulatory concentrations • For the 12 months ended Sept. 30, 2015, 88% of EBITDA is from investment-grade regulated subsidiaries. A significant portion of the remaining non-regulated EBITDA is from fully contracted generation assets at BHE Renewables BHE LTM Sept. 30, 2015 Energy Revenue(1): $15.6 Billion PacifiCorp 30.4% NV Energy 17.8% MidAmerican Funding 13.5% Northern Powergrid 11.6% BHE Pipeline Group 9.4% BHE Renewables 8.3% BHE Transmission 5.6% HomeServices 3.4% BHE LTM Sept. 30, 2015 EBITDA(2): $7.0 Billion Nevada 21.5% Iowa 15.4% Utah 14.8% Oregon 8.0% Wyoming 5.7% Illinois 5.0% California 4.2% Washington 2.7% Idaho 2.0% FERC 6.5% United Kingdom 7.6% Alberta 3.1% Other 3.5% (1) Excludes HomeServices and equity income, which add further diversification (2) Refer to the Appendix for the calculation of EBITDA; percentages exclude Corporate/other

• Since being acquired by Berkshire Hathaway in March 2000, BHE has realized significant growth in its assets, net income and cash flows $6.5 $37.6 $50.1 $59.2 $60.1 $0 $15 $30 $45 $60 $75 2001 2012 2013 2014 Sept. 2015 Billions $0.1 $1.5 $1.6 $2.1 $2.3 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 2001 2012 2013 2014 LTM 9/30/15 Billions $0.8 $4.3 $4.7 $5.1 $6.7 $0.0 $2.0 $4.0 $6.0 $8.0 2001 2012 2013 2014 LTM 9/30/15 Billions $1.7 $15.7 $18.7 $20.4 $22.1 $0 $5 $10 $15 $20 $25 2001 2012 2013 2014 Sept. 2015 Billions Net Income Attributable to BHE BHE Shareholders’ Equity Property, Plant and Equipment (Net) Cash Flows From Operations 10 Berkshire Hathaway Energy Financial Summary

Core Principles Six core principles are the moat Plan – Execute – Measure – Correct 11

Customer Service – Deliver Reliable and Cost-Effective Service 12 Mastio Results Interstate Pipelines 2003 2015 Kern River 10 1 Northern Natural Gas 43 2 TQS Results 2015 Top 5 Utilities on Overall Customer Satisfaction Rank Utility Very Satisfied 1 Berkshire Hathaway Energy 96.1% 2 Southern Company 95.7% 3 We Energies 89.7% 4 Oklahoma Gas and Electric 86.4% 5 Consumers Energy 85.2% Top 3 for the 12th consecutive year No. 1 for the 10th consecutive year

Employee Commitment – Improve Safety Culture and Work Environment 13 Berkshire Hathaway Energy Incident Rate 0 1 2 3 4 5 6 7 8 9 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 BHE Incident Rate 1.41 2.16 Industry Median Top Decile Berkshire Hathaway Energy Businesses with Incident Rate ≤ 1.0 CalEnergy Philippines Northern Powergrid Northern Natural Gas BHE U.S. Transmission Kern River AltaLink MidAmerican Energy Company Rocky Mountain Power BHE Renewables NV Energy Pacific Power 20 years 12 years 6 years 3 years 3 years 2 years 2 years 2 years 1 year 1 year 1 year NV Energy 50% step change improvement

Environmental Respect – Invest in Renewable Energy 14 “MidAmerican Energy’s commitment to wind generation garners long-lasting benefits and makes Iowa a competitive economic force not only in the United States but also in the world.” “Iowa has attracted major tech companies, such as Google, Microsoft and Facebook, because of our low energy prices and commitment to renewable energy.” – Iowa Governor Terry E. Branstad • Committed to the American Business Act on Climate Pledge on July 27, 2015 – One of 13 major U.S. companies – and the only company from the energy sector – invited to participate in the White House event to launch the program – Build on our investment in renewable energy generation under construction and in operation as of 2014 by pledging to invest up to an additional $15 billion going forward Owned Wind and Solar Generation Capacity (MW) Regulated Unregulated MidAmerican BHE PacifiCorp Energy NVE Renewables Total 1999-2012 1,030 2,280 - 497 3,807 2013 - 44 - 324 368 2014 - 508 - 652 1,160 2015-2016 - 1,175 15 958 2,148 Total 1,030 4,007 15 2,431 7,483 Investment (billions) $2 $7 $0 $8 $17

Environmental Respect – Generation Diversity 15 Dec. 31, 2000 BHE Generation Capacity (1) Sept. 30, 2015 BHE Generation Capacity (1) (1) Net MW owned in operation and under construction Coal 33% Natural Gas 35% Nuclear and other 2% Wind 21% Hydro 4% Solar 4% Geothermal 1% Coal 51% Natural Gas 27% Nuclear and other 8% Hydro 2% Geothermal Solar, Wind 12% Total Renewables 30% Total Renewables 14% Total Generation Capacity - 29,925 MW Total Generation Capacity – 5,618 MW

Midwest Region(2) MidAmerican Energy Company $0.06724 Midwest Region $0.09408 Regulatory Integrity – Achieve Balanced Outcomes 16 Company Average Rate ($/kWh) Pacific Region(1) Pacific Power $0.0933 Nevada Power $0.1104 Pacific Region $0.1440 Mountain Region(1) Rocky Mountain Power $0.0794 Sierra Pacific Power $0.0913 Mountain Region $0.0976 Highest Average Rates ($/kWh) by State(1): Hawaii – $0.2975; Connecticut – $0.1910; Massachusetts – $0.1898; New York – $0.1820; Rhode Island – $0.1682 (1) Source: Edison Electric Institute (Summer 2015) (2) Source: U.S. Energy Information Administration

Regulatory Integrity – Distributed Generation Penetration Rate 17 Total Electric Customers as of Sept. 30, 2015 Net Metered Customers as of Sept. 30, 2015 Net Metered Portion of Total Customers South Dakota 4,793 0 0.00% California 44,831 206 0.46% Idaho 75,265 148 0.20% Illinois 84,723 17 0.02% Washington 129,117 346 0.27% Wyoming 139,819 204 0.15% Oregon 568,915 4,362 0.77% Iowa 663,822 237 0.04% Utah 861,042 5,513 0.64% Nevada 1,226,579 13,478 1.10% Total 3,798,906 24,511 0.65% Berkshire Hathaway Energy – Impact of Distributed Generation

18 0.00 0.50 1.00 1.50 2.00 2.50 3.00 K ilo w at t/U sa ge Customer Demand Utility-Provided Grid Services 23.99 hours/day utility provides all grid services Utility-Provided Power 10 hours/day utility provides 100% of power needed DG System-Provided Power 6.5 hours/day DG system provides 100% of power needed DG Generation Utility and DG System-Provided Power 7.5 hours/day both utility and DG system provides power 100% Utility-Provided Power DG Peak 12-2 PM Customer Demand Peak 6-8 PM DG customer uses grid to export excess power 100% Utility-Provided Power B as ic S er vi ce an d D em an d C ha rg e 4am 8am 12pm 4pm 8pm 12am Distributed Generation – U.S. Average

Regulatory Integrity – Distributed Generation Update 19 • Nevada – On July 31, 2015, NV Energy filed, as required by Senate Bill 374, a new proposed tariff that would apply to customer- generators applying for net energy metered service after the existing 235 megawatt cap is met. The Public Utilities Commission of Nevada will hold hearings from November 18-20, 2015, with a ruling on the final tariff due by state law by December 31, 2015 – NV Energy is proposing a three-part rate design which includes a demand charge in order to assure cost shifting does not happen between customers within the rate class • PacifiCorp – Regulatory proceedings in Utah, Oregon, and Washington are addressing the benefits and costs of solar and net metering impacts. In Utah, hearings to establish a framework to evaluate costs and benefits have been completed and an order is expected by the end of 2015 – In Wyoming, PacifiCorp currently has a $20/month residential customer charge that mitigates the impact on fixed cost recovery from net metering program participants – In Idaho, the current participation level is relatively low and PacifiCorp is evaluating its net metering tariffs for potential changes in the future – PacifiCorp is performing load research studies on residential net metering customers in order to support alternative rate structures for net metering customers including higher customer charges and/or demand charges – As a cost-based alternative to net metering, PacifiCorp is also implementing a solar subscriber program in Utah, and in Oregon, a recent community solar investigation resulted in a commission recommendation to the legislature stating that utilities should be allowed to own community solar installations and community solar should be a state-wide program open to residential customers • Iowa – The Iowa Utilities Board has an open Notice of Inquiry docket on distributed generation. The docket is intended to gather input from all stakeholders on a wide range of topics related to distributed generation including interconnection considerations, system impacts, and net metering – There have been several Board Orders requesting comments and several workshops hosted by the Board as part of the Notice of Inquiry docket. MidAmerican is participating by filing comments to each Board Order and by actively participating in the workshops. MidAmerican comments include recommendations that the Board adopt three part cost of service based rates for new distributed generation customers as the best way to ensure any DG growth occurs in an equitable manner that does not shift part of the cost of service for DG customers to non-DG customers

Operational Excellence – Improve Deployment and Operation of Assets 20 25 50 75 100 125 150 175 200 2011 2012 2013 2014 2015 Rocky Mountain Power Northern Powergrid Pacific Power NV Energy MidAmerican Energy Company AltaLink Berkshire Hathaway Energy SAIDI (minutes) Top Quartile 85 minutes Top Decile 56 minutes

Financial Strength – Strong Credit Profile 21 • BHE key credit ratios(1) – Credit ratios continue to be strong and supportive of our credit rating inclusive of our most recent NVE and AltaLink acquisitions which further diversifies our business risk • Ratings (issuer or senior unsecured ratings unless noted) (1) Refer to the Appendix for the calculations of key ratios (2) 2014 calculation excludes AltaLink debt and BHE acquisition debt related to AltaLink acquisition. 2013 calculation excludes NVE debt and BHE acquisition debt related to NVE acquisition (3) Ratings are senior secured ratings LTM 9/30/15 2014 2013 FFO Interest Coverage 4.8x 4.9x 4.5x FFO to Adjusted Debt Excluding Acquisition Related Debt(2) 18.7% 20.5% 18.9% Adjusted Debt to Total Capitalization 58.6% 59.8% 58.1% Total Assets ($ billions) $83.8 $82.3 $70.0 Moody’s S&P Fitch Moody’s S&P Fitch DBRS Berkshire Hathaway Energy A3 BBB+ BBB+ Kern River Funding Corp.(3) A2 A- A- - PacifiCorp(3) A1 A A Northern Powergrid (Northeast) A3 A- A- - MidAmerican Energy Company(3) Aa2 A A+ Northern Powergrid (Yorkshire) A3 A- A - Nevada Power Company(3) A2 A A- AltaLink L.P.(3) - A- - A Sierra Pacific Power(3) A2 A A- Northern Natural Gas Company A2 A- A

Financial Strength – Credit Metrics 22 Note: Refer to the 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 LTM 9/30/15 2014 2013 LTM 9/30/15 2014 2013 PacifiCorp Northern Natural Gas FFO Interest Coverage 5.1x 5.2x 5.0x FFO Interest Coverage 8.7x 8.3x 7.9x FFO to Debt 21.5% 22.3% 22.1% FFO to Debt 41.3% 36.5% 33.9% Debt to Total Capitalization 49.4% 47.7% 46.9% Debt to Total Capitalization 35.8% 40.3% 39.8% MidAmerican Energy Kern River FFO Interest Coverage 8.2x 7.1x 6.9x FFO Interest Coverage 9.4x 8.2x 7.2x FFO to Debt 31.2% 25.8% 24.9% FFO to Debt 55.4% 47.5% 40.5% Debt to Total Capitalization 46.4% 49.1% 48.0% Debt to Total Capitalization 34.2% 36.3% 39.8% Nevada Power Company Northern Powergrid FFO Interest Coverage 5.9x 4.8x 3.5x FFO Interest Coverage 5.2x 5.3x 4.3x FFO to Debt 28.7% 22.3% 14.8% FFO to Debt 22.5% 24.2% 19.1% Debt to Total Capitalization 51.3% 55.3% 55.3% Debt to Total Capitalization 43.6% 42.9% 45.2% Sierra Pacific Power Company AltaLink, L.P. FFO Interest Coverage 6.5x 5.1x 4.9x FFO Interest Coverage 2.6x 3.0x 3.3x FFO to Debt 27.6% 20.9% 20.2% FFO to Debt 9.6% 10.5% 10.9% Debt to Total Capitalization 53.3% 54.6% 54.2% Debt to Total Capitalization 62.8% 61.1% 60.2%

• Our businesses continue to perform well Financial Information ($ millions) 23 LTM Years Ended Net Income Attributable to BHE 9/30/2015 12/31/2014 12/31/2013 PacifiCorp 672$ 700$ 681$ MidAmerican Funding 515 409 340 NV Energy 377 354 (43) Northern Powergrid 378 412 335 BHE Pipeline Group 232 230 237 BHE Transmission 159 56 33 BHE Renewables 130 121 (20) HomeServices 119 83 73 BHE and Other (282) (270) - Net income attributable to BHE 2,300$ 2,095$ 1,636$

2015 Projected Capital Expenditures - $5.8 Billion 24 Capital Expenditures by Business ($m) Capital Expenditures by Type ($m) PacifiCorp $919 NV Energy $567 MidAmerican Funding $1,445 Northern Powergrid $693 BHE Pipeline Group $255 BHE Renewables $1,015 BHE Transmission $889 HomeServices and Other $31 Solar Generation $793 Wind Generation $1,030 Environmental $153 Other Development Projects $68 Electric Transmission $931 Electric Distribution and Other Operating $2,839

(1) Net MW owned in operation as of Sept. 30, 2015 (2) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities • Headquartered in Portland, Oregon • 5,700 employees • 1.8 million electric customers in six western states • 10,904 MW of owned generation capacity(1) • Owned generating capacity by fuel type: 9/30/15 3/31/06 – Coal 54% 72% – Natural gas 25% 13% – Hydro(2) 11% 14% – Wind, geothermal and other(2) 10% 1% PacifiCorp 25

PacifiCorp – Business Update 26 • Higher retail prices approved by regulators, primarily to recover capital investments and higher energy costs – Wyoming 2014 general rate case approved rate increase of $20 million, or 3%, effective January 2015 – Utah 2014 general rate case Step 2 increase of $19 million, or 1%, implemented in September 2015 – Multi-party settlement approved in Utah Energy Balancing Account filing to recover $30 million of deferred net power costs over a 12-month period beginning in November 2015 • Energy cost adjustment mechanisms exist in all six states, with the approval of a power cost adjustment mechanism in Washington in May 2015 • Utah mine disposition transaction approved and determined to be in the public interest by the commissions in Utah, Oregon, Idaho and Wyoming • Actual retail load for the nine months ended September 30, 2015 was 40,937 gigawatt-hours, a 1.5% decrease versus the first nine months of 2014, due to lower retail customer usage, partially offset by an increase in residential and commercial customers • 170-mile 345-kV Sigurd-to-Red Butte transmission line was placed in-service in May 2015 • PacifiCorp and the California ISO are exploring the feasibility, costs and benefits of PacifiCorp joining a regional ISO as a participating transmission owner if the California ISO becomes a regional ISO by modifying its governance structure and expanding its balancing authority area – If PacifiCorp decides to join the regional ISO, it would extend PacifiCorp’s current participation in the real- time market through the regional energy imbalance market to participation in the day-ahead energy market operated by the California ISO in addition to unified planning and operation of PacifiCorp’s transmission network

MidAmerican Energy 27 • Headquartered in Des Moines, Iowa • 3,500 employees • 1.4 million electric and natural gas customers in four Midwestern states • 9,005 MW(1) of owned generation capacity • Owned generating capacity by fuel type: 9/30/15(1) 12/31/00 – Coal 34% 70% – Natural gas 15% 19% – Wind(2) 45% 0% – Nuclear and other 6% 11% (1) Net MW owned in operation and under construction as of Sept. 30, 2015 (2) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities SOUTH DAKOTA NEBRASKA KANSAS MISSOURI ILLINOIS WISCONSIN MINNESOTA IOWA MidAmerican Energy Service Territory Major Generating Facilities Wind Projects Wind Projects Under Construction

MidAmerican Energy – Business Update 28 • Final rates associated with an Iowa electric rate increase filed May 17, 2013, were implemented July 31, 2014, resulting in a phased-in increase to base rates of $135 million at annualized amounts of $45 million (3.6%) effective August 2013, $45 million effective January 2015, and $45 million effective January 2016; and adjustment clauses for retail energy, including the pre-tax value of federal production tax credits, and Midcontinent Independent System Operator (MISO) transmission costs • All electric and gas jurisdictions presently have adjustment clauses to recover actual fuel costs currently, and the Iowa and South Dakota electric clauses include the pre-tax value of federal production tax credits • MidAmerican Energy continues to rank high in customer satisfaction as evidenced by its No. 1 rank in overall customer satisfaction in the Midwest Region-Large Segment in three J.D. Power studies (Residential Electric, Residential Natural Gas, and Business Electric), and earning its second-highest overall customer satisfaction score in company history in the TQS Key Accounts study • Customer growth and improved industrial sales helped offset mild winter weather, resulting in an increase in actual retail electric sales to 17,588 gigawatt-hours for the nine months ended September 30, 2015, a 1.9% increase over the same period for 2014 • Currently completing construction of the 1,051 MW (nominal ratings) Wind VIII and 161 MW (nominal ratings) Wind IX wind-powered generation facilities in Iowa. As of September 30, 2015, MidAmerican Energy has placed in-service 852 MW and expects to place the remaining 360 MW into service by the end of 2015 within the $2.14 billion cost cap established by the Iowa Utilities Board (IUB) • Currently constructing transmission lines in Iowa and Illinois that are anticipated to go into service in 2015- 2018, with an estimated cost of $541 million; projects have been designated as Multi-Value Projects by MISO • Wind X Project – In August 2015, the IUB approved rate-making principles related to the construction of up to 552 MW of additional wind-powered generating facilities expected to be placed in-service by the end of 2016 with a cost cap of $889 million

NV Energy 29 • Headquartered in Las Vegas, Nevada • 2,500 employees • 1.2 million electricity and 0.2 million gas customers • Provides service to approximately 90% of Nevada population, along with tourist population of 41 million annually • Owned generating capacity by fuel type: 9/30/15 12/31/13 – Coal and Other 13% 18% – Natural gas 87% 82% NV Energy Electric Service Territory CALIFORNIA ARIZONA UTAH NEVADA NV Energy Gas Service Territory Coal Plants Natural Gas Plants Energy Recovery Plant • Provides electric services to Las Vegas and surrounding areas • 4,767 megawatts of owned generation(1) • Provides electric and gas services to Reno and northern Nevada • 1,372 megawatts of owned generation(1) (1) Net MW owned in operation and under construction as of Sept. 30, 2015 Nevada Power Sierra Pacific Power

NV Energy – Business Update 30 • Nevada Power filed its triennial integrated resource plan with the Public Utilities Commission of Nevada in July 2015. Key elements include purchase agreement for 25% interest in the Silverhawk Generating Station, subscription solar proposal and One Nevada transmission line cost allocation. Hearings concluded October 29, 2015. A decision is expected December 2015 • Nevada Power filed an amendment to the 2014 Emissions Reduction and Capacity Replacement Plan for approval of two 100-megawatt power purchase agreements with renewable energy facilities. Approval of purchase agreements was provided September 2015 • NV Energy filed cost-of-service study and proposed net metering plan in August 2015 to establish separate classes and adopt a rate design for net metered solar customers. Discovery continues in the proceeding, and preparations continue for the hearing scheduled to begin November 18, 2015 • The Public Utilities Commission of Nevada unanimously granted approval October 12, 2015, of the customer satisfaction improvement plan. A key part of the plan was a favorable customer service metrics report, indicating customer satisfaction was trending upward. Parties supported closing the docket which fulfills the obligations of Commitment 20 of the Merger stipulation • NV Energy achieved record marks in the JD Power residential and commercial customer surveys, as well as the TQS survey of large industrial and commercial customers • Nellis Solar Array II 15-megawatt photovoltaic project supplied megawatts to the grid in October 2015 • Financially binding energy imbalance market operations scheduled for November 1, 2015 has been postponed pending Federal Energy Regulatory Commission approval • Three large commercial customers, Wynn Resorts, Las Vegas Sands, and MGM Resorts International, filed applications with the Public Utilities Commission of Nevada in June 2015 for approval to purchase energy from an alternative provider under Nevada Revised Statute 704B. NV Energy participated in hearings October 15-22, 2015, and decisions are expected before December 14, 2015 • By statute, Sierra Pacific and Nevada Power must file general rate applications every three years. Sierra Pacific and Nevada Power are scheduled to file no later than June 6, 2016 and June 5, 2017, respectively

Leeds Edinburgh Middlesbrough Newcastle Upon Tyne Sheffield York Northeast Yorkshire • 3.9 million end-users in northern England • Approximately 58,000 miles of distribution lines • Approximately 68% of 2015 distribution revenue from residential and commercial customers through September 30, 2015 • Distribution revenue (£ millions): • Successfully closed out DPCR5 (five-year price control period ended March 2015) by delivering asset-related outputs, outperforming cost allowances and achieving a nominal rate of return of 15%, followed by a strong start to ED1 (eight-year price control commenced April 2015) • In March 2015, Northern Powergrid was the only electricity distributor to appeal Ofgem’s ED1 price control decision. In September 2015, the appeal authority allowed part of the appeal, awarding an additional £31m in expenditure allowances Nine Months Ended 9/30/15 9/30/14 Residential 257 254 Commercial 88 92 Industrial 154 163 Other 5 9 Total 504 518 Northern Powergrid 31

• 14,700 miles of natural gas pipeline • 5.7 Bcf per day of market area design capacity, plus 1.7 Bcf per day field area capacity • More than 73 Bcf firm service and operational storage cycle capacity • 91% of transportation and storage revenue through September 30, 2015, is based on demand charges • Increased the integrity and reliability of the pipeline while managing operating costs and staffing • Ranked No. 1 among 16 mega-pipelines and No. 2 among 41 interstate pipelines in 2015 Mastio & Company survey for customer satisfaction • Excellent performance this past winter – 2014-2015 heating season 9% colder than normal compared to 24% colder than normal for 2013-2014 heating season. February 2015 was 29% colder than normal – Set new average monthly throughput record in February 2015 of 4.083 Bcf/day – Set new Market Area peak daily delivery records in the months of February and March 2015 of 4.891 Bcf and 4.477 Bcf, respectively – Pipeline system operated dependably and safely. No lost- time safety-related incidents despite harsh winter conditions Northern Natural Gas 32 MINNESOTA WISCONSIN IOWA SOUTH DAKOTA NEBRASKA KANSAS OKLAHOMA TEXAS

• 1,700 miles of natural gas pipeline • Design capacity of 2.2 million Dth per day of natural gas • 95% of revenue through September 30, 2015 is based on demand charges • Kern River delivered nearly 22%(1) of California’s demand for natural gas • Ranked No. 1 among 41 interstate pipelines in 2015 Mastio & Company survey for customer satisfaction • Existing shippers chose to extend service with Kern River for approximately 97% of the 801,971 Dth/day of capacity that was due to expire September 30, 2016. The shippers chose to extend the capacity, which represents approximately 36% of Kern River’s total firm capacity for terms of 10 or 15 years beginning October 1, 2016, for a weighted average life of 13.8 years Kern River 33 CALIFORNIA NEVADA ARIZONA UTAH WYOMING (1) 2015 California Gas Report

AltaLink, L.P. 34 • AltaLink is a transmission-only service provider of transmission service at 69 kilovolts and higher – Supplies electricity to approximately 85% of Alberta’s population • AltaLink owns approximately 7,800 miles of lines and 300 substations within the transmission system in Alberta – No volume or commodity exposure – Strong, stable regulatory environment – Revenue from AA- rated Alberta Electric System Operator (AESO) • Mid-year 2015 rate base and CWIP per the most recent regulatory update was C$6.4b

AltaLink Regulatory Update 35 2015-2016 General Tariff Application (GTA) • On November 18, 2014, the 2015-2016 GTA was filed with the Alberta Utilities Commission (AUC) • An amendment to the GTA was filed on June 1, 2015, which included C$555M of proposed rate relief during 2015-2017 and a request for higher equity thickness to solidify the capital structure • AltaLink filed an update to the GTA on October 16, 2015, which reduced capital expenditures by C$0.5b in 2015 and C$0.4b in 2016 • The oral hearing has been scheduled for December 8-18, 2015 2012-2013 Direct Assign Capital Deferral Account • AltaLink is seeking approval for approximately C$1.7b of direct assign capital projects which entered service in 2012-2013. The hearing is scheduled for November 9-20, 2015 Other Regulatory • On March 23, 2015, the AUC issued Decision 2191-D01-2015 regarding cost of capital matters applicable to all electricity and natural gas utilities under its jurisdiction. In its decision, which was retroactively applied to January 1, 2013, the AUC decreased the generic rate of return on common equity to 8.30% (from 8.75%) and decreased the deemed common equity to 36% (from 37%) applicable to AltaLink. On April 2, 2015, the AUC issued a letter to all interested parties setting out its intent to commence a new Generic Cost of Capital (GCOC) proceeding in 2015 for application to 2016 and potentially beyond • On November 26, 2013, the AUC issued Decision 2013-417, in which it determined that certain losses or gains related to asset dispositions are to be borne by the shareholders. In June 2015, the Alberta Court of Appeal heard the appeal of Decision 2013-417 and Decision 2011-474 (2011 GCOC Decision). The Court in a decision rendered September 18, 2015 dismissed both appeals. AltaLink is currently assessing its options for addressing the risk associated with extraordinary retirements

BHE Renewables 36 (1) Based on net owned capacity of 3,877 MW in operation and under construction as of Sept. 30, 2015 (2) Separate PPA’s exist with Missouri Joint Municipal Electric Commission (20 MW), Kansas Power Pool (25 MW), City of Independence, Missouri (20 MW), with the remaining (7 MW) still in negotiation (3) 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 2039 BHE Solar Geothermal Natural Gas BHE Wind BHE Hydro CalEnergy Philippines Solar 33% Wind 30% Geothermal 9% Hydro 3% Natural Gas 25% Portfolio Composition (1) 2015-2017 5% 2018-2027 26% 2028+ 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 1,426 1,278 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 (2) 72 72 1,153 1,153 GEOTHERMAL Imperial Valley CA 1982-2000 (3) (3) 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 4,096 3,877

BHE Renewables Update 37 Solar • Topaz – Commissioned and commercial operations declared October 2014, delivering 550 MW – Completed three months ahead of schedule with availability above 99% since COD • Solar Star I & II – Commissioned and commercial operations declared July 2015, delivering 586 MW – Completed four months ahead of schedule with availability above 99% since COD Wind • Jumbo Road – Achieved project completion in March 2015, with commercial operation under its PPA April 2015 • Grande Prairie Wind – 400 MW project acquired in February 2015 – Construction mobilization in August 2015, with estimated commercial operation in fourth quarter 2016 • Marshall Wind – 72 MW project acquired in September 2015, with estimated commercial operation to be achieved during the first half of 2016 Tax Equity • Executed agreements to provide tax equity of approximately $650m – Tax equity sized to earn a preferred return through a targeted flip date, generally over a 10-year period Geothermal • Imperial Valley projects have 328 MW out of 338 MW with long-term contracts that expire between 2016 to 2026. Upon expiration, 244 MW out of 338 MW have been re-contracted with maturities between 2028-2039. 42 MW out of the remaining 94 MW are currently being marketed

• Northern Powergrid – Anticipate up to a £300 million European Investment Bank debt financing in fourth quarter 2015 and first quarter 2016, split between Northern Powergrid Yorkshire and Northern Powergrid Northeast • Nevada Power Company – In 2016, $210 million of debt is maturing in the first quarter. Financing plan will be determined in early 2016 as to what amount, if any, will be refinanced • Sierra Pacific Power Company – In 2016, $450 million of debt is maturing in the second quarter. Financing plan will be determined in early 2016 as to what amount, if any, will be refinanced • AltaLink, L.P. – Anticipates a C$450 million to C$550 million debt financing mid-2016 Near-Term Financing Plan 38

BHE U.S. Transmission Development Opportunities 39 Project Location Cost Description Electric Transmission Texas Texas $2.2b in current rate base, approximately $3.0b in total investment planned 50% ownership in joint venture with subsidiary of American Electric Power. Various projects throughout Texas Prairie Wind Transmission Kansas $161.5m 25% ownership in joint venture with Westar Energy and subsidiary of American Electric Power. The 345- kV project is complete and energized Gates to Gregg California $168.6m 50% ownership of 230-kV transmission line assets currently in development with Pacific Gas & Electric TransCanyon Arizona & California Various Projects Pursued 50% ownership in joint venture with subsidiary of Pinnacle West Capital Corporation MPT Heartland Development Southwest Power Pool Various Projects Pursued 50% ownership in joint venture with Westar Energy Midwest Power Midcontinent Transmission Development Midcontinent ISO South Various Projects Pursued 50% ownership in joint venture with Westar Energy

Appendix 40

Clean Power Plan – Final Rule 41 Issue Final Timing Start in 2022 32% reduction from 2005 levels in 2030 Building Block 1 – Coal Plant Heat Rate Improvements Eastern Interconnect 4.3% Western Interconnect 2.1% Texas/ERCOT 2.3% Building Block 2 – Re-Dispatch of Natural Gas Combined Cycle (NGCC) Units 75% capacity factor for existing and new NGCC based on summer capacity with glide path from 2022 to 2030 Building Block 3 – Expand New Non-Carbon Resources Excluded existing nuclear in Best System of Emission Reduction (BSER) Pre-2013 renewables not included in BSER calculation and not eligible to offset emissions rate Building Block 4 – Energy Efficiency Not included in BSER but can be used for compliance

Final Clean Power Plan 42 • More aggressive renewable generation deployment in the determination of best system of emission reduction • Compliance tools changed – Only post-2012 renewable generation can generate emission-reduction credits in a rate-based program – Removed existing nuclear component so only incremental nuclear (new and uprates) can be utilized – New natural gas combined cycle cannot be used to average down an emission rate – In a mass-based program, the state must address new units based on concerns of “leakage”

Rates and Reductions 43 States with Company Generation Final Rule 2012 Emission Rate (lb/MWh) Final Rule 2030 Goal (lb/MWh) Washington 1,565 983 Oregon 1,089 871 California 954 828 Nevada 1,102 855 Arizona 1,551 1,031 Colorado 1,904 1,174 Iowa 2,195 1,283 Utah 1,790 1,175 Wyoming 2,314 1,299 Montana 2,481 1,305

• Changes to the 2012 baseline (i.e., removal of the renewable and nuclear generation) and not allowing pre-2013 renewables to be used for direct compliance make some of the targets more challenging • Impacts of the changes cannot be fully determined until the states develop their implementation plans • Key decisions for states that will impact costs and compliance – Rate or mass-based program – Distribution of allowances among affected electric generating units (and whether they are allocated or auctioned) – Whether intra- or interstate trading is adopted by the state, how broad the trading program is and whether the trading market is sufficiently liquid • Several states are currently litigating the final rule Compliance may be challenging but is achievable Clean Power Plan 111(d) Implications 44

Environmental Update 45 • Primary emissions reduction drivers: MidAmerican Energy PacifiCorp NV Energy Cross-State Air Pollution Rule Yes No No Scrubbers and baghouses installed Mercury and Air Toxics Standards Yes Yes Yes Mercury controls and monitors installed; four units to retire; one to gas only generation Mercury controls and monitors installed where needed to achieve compliance Mercury controls and monitors installed where needed to achieve compliance Regional Haze No Yes Partial In addition to current Selective Catalytic Reduction (SCR) obligations at Craig, Hayden and Jim Bridger, SCR required by EPA at Wyodak (under appeal and stayed) and Cholla 4 (alternatives under discussion); Utah revised plan currently before EPA for consideration with final decision regarding approval by March 2016, pursuant to a proposed consent decree NOx controls at affected gas- fueled units required by 1/1/15 State Law No No Yes SB 123 requires elimination of 800 MW of coal-fueled generation and addition of renewables

Environmental Respect – Reducing Coal Fleet Coal MW as of Dec. 31, 2013(1) 10,522 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 – switched to gas only in 2015 (124) MW Walter Scott 1 and 2 – retired in 2015 (124) MW Reid Gardner 4 (257) MW Neal 1 and 2 (401) MW Cholla 4 gas conversion (395) MW Naughton 3 gas conversion (280) MW Navajo(2) (255) MW Coal MW as of Dec. 31, 2025 8,210 MW • Through fuel switching and retirements, BHE’s utilities expect to eliminate approximately 2,300 MW of coal generation through 2025 46 (1) Adjusted for re-rating of coal plants in 2014 and 2015, including plants still in operation and retired (2) NV Energy is divesting its interest

• Of BHE’s nearly 9,798 MW(1) of owned coal-fueled generation: – 98% has low-NOx burners and/or over-fire air for nitrogen oxides controls – 93% has scrubbers for sulfur dioxide control – 100% is compliant with Mercury and Air Toxics Standards – 64% has baghouses for particulate matter control • To ensure timely compliance, BHE continues to review proposed regulations and legislation and analyze associated current impacts of environmental requirements on the coal-fueled fleet Consolidated Environmental Position 47 (1) Net owned capacity as of Sept. 30, 2015

• Of PacifiCorp’s 5,931 MW(1) of owned coal-fueled generation: – 97% has nitrogen oxides controls with low-NOx burners and over-fire air systems – 97% has scrubbers for sulfur dioxide control – 59% has baghouses for particulate matter control – All coal-fueled generation meets the mercury emissions requirements of the Mercury and Air Toxics Standards • Following completion of plans to retire or convert to natural gas the remaining 280 MW of Naughton Unit 3 coal-fueled unit by year-end 2018(2), 96% of coal-fueled generation will be controlled by scrubbers, 62% will be controlled by baghouses, and 15% will be controlled by selective catalytic reduction for control of nitrogen oxides (in addition to low-NOx burners) – Carbon Units 1 and 2 (172 MW) were removed from service in April 2015 to comply with the Mercury and Air Toxics Standards • Environmental capital expenditures forecast(3) ($ millions): 2015 2016 2017 2018 $127 $60 $28 $35 PacifiCorp Environmental Position (1) Net owned capacity as of Sept. 30, 2015 (2) Natural gas conversion of Naughton Unit 3 is currently permitted by the State of Wyoming to occur by June 2018. Final EPA approval is pending. (3) Environmental capital expenditures forecast includes PacifiCorp’s share of minority-owned Craig, Colstrip and Hayden plants, excluding equity AFUDC 48

MidAmerican Energy Environmental Position 49 • Of MidAmerican Energy’s 3,094(1) MW of owned coal-fueled generation: – Riverside Unit 3 (4 MW) retired in 2014, Riverside Unit 5 (124 MW) ceased burning coal in 2015 and operates solely on natural gas, Walter Scott, Jr. Energy Center Units 1 and 2 (124 MW) retired in 2015, and Neal Energy Center Units 1 and 2 (401 MW) will retire in 2016 – The units that will continue to operate are well-controlled, with 100% of the generation having nitrogen oxides controls • Low-NOx burners and/or over-fire air on all units • One selective catalytic reduction system on Walter Scott, Jr. Energy Center Unit 4 • Two selective non-catalytic reduction systems on Neal Energy Center Unit 3 and Unit 4 – 100% of generation has scrubbers and baghouses for sulfur dioxide control – 100% of generation has activated carbon injection for mercury control • Environmental capital expenditures forecast(2) ($ millions): 2015 2016 2017 2018 $23 $19 $103 $74 (1) Net owned capacity as of Sept. 30, 2015 (2) Environmental capital expenditures forecast excludes equity AFUDC

NV Energy Environmental Position 50 • NV Energy is reducing its dependency on coal-fueled generation – 300 MW Reid Gardner Units 1-3 retired at end of 2014 – 257 MW Reid Gardner Unit 4 to be retired at end of 2017 – 255 MW ownership of Navajo Units 1-3 ends at end of 2019 • Customers currently benefitting from 1,186 megawatts (nameplate) of utility-scale renewable energy resources – 20 geothermal projects – 10 solar projects – 4 biomass/methane projects – 5 small hydro projects and Hoover Dam – 1 waste heat recovery project – 1 wind project

Other Regulations and Impacts 51 • Coal Combustion Residuals – PacifiCorp operates 9 surface impoundments and 4 landfills – MidAmerican Energy owns or operates 7 surface impoundments and 4 landfills – NV Energy operates 10 evaporative surface impoundments and 2 landfills • Effluent Limitation Guidelines – For BHE operating companies, impacted waste streams are limited to bottom ash transport water, fly ash transport water, combustion residual leachate and non-metal cleaning wastes – With minor exceptions, most of the new requirements are addressed by compliance with the coal combustion residuals rule • Revised Ozone Standards – Unit retirements and installation of NOx controls are expected to assist in achieving attainment – Revision from 75 ppb to 70 ppb is not expected to result in significant impacts on BHE operating companies

Retail Electric Sales – Weather Normalized 52 Year-to-Date September 30 Variance (GWh) 2015 2014 Actual Percent PacifiCorp Residential 11,564 11,607 (43) -0.4% Commercial 12,853 12,765 88 0.7% Industrial and Other 16,512 17,129 (617) -3.6% Total 40,929 41,501 (572) -1.4% MidAmerican Energy Residential 4,824 4,928 (104) -2.1% Commercial 2,904 3,114 (210) -6.8% Industrial and Other 9,812 9,138 674 7.4% Total 17,539 17,180 360 2.1% Nevada Power Residential 7,406 7,315 91 1.2% Commercial 3,519 3,457 62 1.8% Industrial and Other 5,885 5,861 24 0.4% Total 16,810 16,633 177 1.1% Sierra Pacific Power Residential 1,736 1,735 1 0.0% Commercial 2,241 2,262 (21) -0.9% Industrial and Other 2,224 2,149 75 3.5% Total 6,200 6,146 54 0.9% Northern Powergrid Residential 9,303 9,292 10 0.1% Commercial 4,261 4,331 (70) -1.6% Industrial and Other 13,545 13,636 (91) -0.7% Total 27,108 27,259 (151) -0.6%

Retail Electric Sales – Actual 53 Year-to-Date September 30 Variance (GWh) 2015 2014 Actual Percent PacifiCorp Residential 11,409 11,545 (136) -1.2% Commercial 12,924 12,846 78 0.6% Industrial and Other 16,604 17,185 (581) -3.4% Total 40,937 41,576 (639) -1.5% MidAmerican Energy Residential 4,862 4,993 (131) -2.6% Commercial 2,914 3,135 (221) -7.0% Industrial and Other 9,812 9,138 674 7.4% Total 17,588 17,266 322 1.9% Nevada Power Residential 7,586 7,436 150 2.0% Commercial 3,560 3,474 86 2.5% Industrial and Other 5,943 5,898 45 0.8% Total 17,089 16,808 281 1.7% Sierra Pacific Power Residential 1,734 1,746 (12) -0.7% Commercial 2,244 2,268 (24) -1.1% Industrial and Other 2,231 2,157 74 3.4% Total 6,208 6,171 37 0.6% Northern Powergrid Residential 9,289 9,142 147 1.6% Commercial 4,245 4,286 (40) -0.9% Industrial and Other 13,545 13,636 (91) -0.7% Total 27,080 27,064 15 0.1%

Financial Information 54 ($ millions) LTM Years Ended Operating Revenue 9/30/2015 12/31/2014 12/31/2013 PacifiCorp 5,225$ 5,252$ 5,147$ MidAmerican Funding 3,562 3,762 3,413 NV Energy 3,355 3,241 (20) Northern Powergrid 1,188 1,283 1,025 BHE Pipeline Group 1,014 1,078 952 BHE Transmission 490 62 - BHE Renewables 748 623 355 HomeServices 2,476 2,144 1,809 BHE and Other (120) (119) (46) Total operating revenue 17,938$ 17,326$ 12,635$

Financial Information 55 ($ millions) LTM Years Ended Depreciation and Amortization 9/30/2015 12/31/2014 12/31/2013 PacifiCorp 774$ 745$ 692$ MidAmerican Funding 392 351 403 NV Energy 403 379 - Northern Powergrid 196 198 180 BHE Pipeline Group 201 196 190 BHE Transmission 160 13 - BHE Renewables 212 152 71 HomeServices 26 29 33 BHE and Other (4) (6) (9) Total depreciation and amortization 2,360$ 2,057$ 1,560$

Financial Information 56 ($ millions) LTM Years Ended Operating Income 9/30/2015 12/31/2014 12/31/2013 PacifiCorp 1,291$ 1,308$ 1,275$ MidAmerican Funding 498 423 357 NV Energy 806 791 (42) Northern Powergrid 609 674 501 BHE Pipeline Group 443 439 446 BHE Transmission 190 16 (5) BHE Renewables 287 314 223 HomeServices 185 125 129 BHE and Other (15) (44) (49) Total operating income 4,294$ 4,046$ 2,835$

Financial Information 57 ($ millions) LTM Years Ended Interest Expense 9/30/2015 12/31/2014 12/31/2013 PacifiCorp 382$ 386$ 390$ MidAmerican Funding 200 197 174 NV Energy 267 283 - Northern Powergrid 145 151 141 BHE Pipeline Group 70 76 80 BHE Transmission 124 14 - BHE Renewables 191 175 138 HomeServices 4 4 3 BHE and Other 485 425 296 Total interest expense 1,868$ 1,711$ 1,222$

(1) Excludes amounts for non-cash equity allowances for funds used during construction and other non-cash items Financial Information 58 ($ millions) LTM Years Ended Capital Expenditures(1) 9/30/2015 12/31/2014 12/31/2013 PacifiCorp 929$ 1,066$ 1,065$ MidAmerican Funding 1,439 1,527 1,027 NV Energy 661 558 - Northern Powergrid 731 675 675 BHE Pipeline Group 250 257 177 BHE Transmission 957 222 - BHE Renewables 1,753 2,221 1,329 HomeServices 13 17 21 BHE and Other 13 12 13 Total capital expenditures 6,746$ 6,555$ 4,307$

Financial Information 59 ($ millions) Total Assets 9/30/2015 12/31/2014 12/31/2013 PacifiCorp 23,534$ 23,466$ 22,885$ MidAmerican Funding 16,099 15,368 13,992 NV Energy 14,756 14,454 14,233 Northern Powergrid 7,282 7,076 6,874 BHE Pipeline Group 4,914 4,968 4,908 BHE Transmission 7,682 7,992 465 BHE Renewables 5,867 6,123 3,875 HomeServices 1,806 1,629 1,381 BHE and Other 1,819 1,228 1,387 Total assets 83,759$ 82,304$ 70,000$

• As of Sept. 30, 2015, approximately 89% of total debt was fixed-rate debt • As of Sept. 30, 2015, long-term adjusted debt had a weighted average life of approximately 14 years and a weighted average interest rate of approximately 5.0% Capitalization 60 ($ millions) BHE Debt to Capitalization Comparison 9/30/2015 12/31/2014 Short-term debt 940$ 1,445$ Current portion of long-term debt 1,574 1,232 BHE senior debt 7,860 7,860 Subsidiary debt 25,617 25,763 Total adjusted debt(1) 35,991 36,300 BHE junior subordinated debentures 3,194 3,794 Noncontrolling interests 136 131 BHE shareholders' equity 22,052 20,442 Total capitalization 61,373$ 60,667$ Adjusted debt/capitalization 58.6% 59.8% (1) Debt includes short-term debt, Berkshire Hathaway Energy senior debt, and subsidiary debt (including current maturities), but excludes Berkshire Hathaway Energy subordinated debt

Non-GAAP Financial Measures Berkshire Hathaway Energy 61 ($ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 6,715$ 5,146$ 4,669$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 5 1,170 (449) FFO 6,720$ 6,316$ 4,220$ Adjusted Interest Interest expense 1,868$ 1,711$ 1,222$ Interest expense on subordinated debt (103) (78) (3) Adjusted Interest 1,765$ 1,633$ 1,219$ FFO Interest Coverage(1) 4.8x 4.9x 4.5x Adjusted Debt Debt(2) 39,185$ 40,094$ 32,244$ Subordinated debt (3,194) (3,794) (2,594) Adjusted Debt 35,991$ 36,300$ 29,650$ Acquisition Financing Debt (1,500) (2,000) Acquisition Subsidiary Debt (4,007) (5,296) Adjusted Debt Excluding Acquisition Related Debt 30,793$ 22,354$ FFO to Adjusted Debt Excluding Acquisition Related Debt(3) 18.7% 20.5% 18.9% Capitalization Total BHE shareholders’ equity 22,052$ 20,442$ 18,711$ Adjusted debt 35,991 36,300 29,650 Subordinated debt 3,194 3,794 2,594 Noncontrolling interests 136 131 105 Capitalization 61,373$ 60,667$ 51,060$ Adjusted Debt to Total Capitalization(4) 58.6% 59.8% 58.1% (1) FFO Interest Coverage equals the sum of FFO and Adjusted Interest divided by Adjusted Interest (2) Debt includes short-term debt, Berkshire Hathaway Energy senior debt, Berkshire Hathaway Energy subordinated debt and subsidiary debt (including current maturities) (3) 2014 calculation excludes AltaLink debt and BHE acquisition debt related to AltaLink acquisition. 2013 calculation excludes NVE debt and BHE acquisition debt related to NVE acquisition (4) Adjusted Debt to Total Capitalization equals Adjusted Debt divided by Capitalization

Non-GAAP Financial Measures PacifiCorp 62 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 1,724$ 1,570$ 1,553$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions (181) 10 (34) FFO 1,543$ 1,580$ 1,519$ Interest expense 377$ 379$ 379$ FFO Interest Coverage(1) 5.1x 5.2x 5.0x Debt (2) 7,187$ 7,073$ 6,877$ FFO to Debt(3) 21.5% 22.3% 22.1% Capitalization PacifiCorp shareholders’ equity 7,356$ 7,756$ 7,787$ Debt 7,187 7,073 6,877 Capitalization 14,543$ 14,829$ 14,664$ Debt to Total Capitalization(4) 49.4% 47.7% 46.9%

Non-GAAP Financial Measures MidAmerican Energy 63 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 1,290$ 823$ 735$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions (20) 235 151 FFO 1,270$ 1,058$ 886$ Interest expense 177$ 174$ 151$ FFO Interest Coverage(1) 8.2x 7.1x 6.9x Debt (2) 4,066$ 4,106$ 3,552$ FFO to Debt(3) 31.2% 25.8% 24.9% Capitalization MidAmerican Energy shareholders’ equity 4,702$ 4,250$ 3,845$ Debt 4,066 4,106 3,552 Capitalization 8,768$ 8,356$ 7,397$ Debt to Total Capitalization(4) 46.4% 49.1% 48.0%

Non-GAAP Financial Measures Nevada Power Company 64 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 875$ 704$ 548$ +/- Changes in other operating assets and liabilities net of effects from acquisitions 76 95 (19) FFO 951$ 799$ 529$ Interest expense 195$ 208$ 215$ FFO Interest Coverage(1) 5.9x 4.8x 3.5x Debt (2) 3,316$ 3,576$ 3,577$ FFO to Debt(3) 28.7% 22.3% 14.8% Capitalization Nevada Power shareholder's equity 3,145$ 2,888$ 2,890$ Debt 3,316 3,576 3,577 Capitalization 6,461$ 6,464$ 6,467$ Debt to Total Capitalization(4) 51.3% 55.3% 55.3%

Non-GAAP Financial Measures Sierra Pacific Power Company 65 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 356$ 246$ 226$ +/- Changes in other operating assets and liabilities net of effects from acquisitions (22) 5 16 FFO 334$ 251$ 242$ Interest expense 61$ 61$ 62$ FFO Interest Coverage(1) 6.5x 5.1x 4.9x Debt (2) 1,211$ 1,200$ 1,200$ FFO to Debt(3) 27.6% 20.9% 20.2% Capitalization Sierra Pacific Power shareholder's equity 1,059$ 998$ 1,016$ Debt 1,211 1,200 1,200 Capitalization 2,270$ 2,198$ 2,216$ Debt to Total Capitalization(4) 53.3% 54.6% 54.2%

Non-GAAP Financial Measures Northern Natural Gas 66 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 321$ 297$ 264$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 10 31 41 FFO 331$ 328$ 305$ Interest expense 43$ 45$ 44$ FFO Interest Coverage(1) 8.7x 8.3x 7.9x Debt (2) 799$ 899$ 899$ FFO to Debt(3) 41.3% 36.5% 33.9% Capitalization Northern Natural Gas shareholder’s equity 1,434$ 1,330$ 1,360$ Debt 799 899 899 Capitalization 2,233$ 2,229$ 2,259$ Debt to Total Capitalization(4) 35.8% 40.3% 39.8%

Non-GAAP Financial Measures Kern River 67 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 222$ 214$ 220$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 1 8 2 FFO 223$ 222$ 222$ Interest expense 27$ 31$ 36$ FFO Interest Coverage(1) 9.4x 8.2x 7.2x Debt (2) 403$ 467$ 548$ FFO to Debt(3) 55.4% 47.5% 40.5% Capitalization Partners’ capital 777$ 818$ 829$ Debt 403 467 548 Capitalization 1,180$ 1,285$ 1,377$ Debt to Total Capitalization(4) 34.2% 36.3% 39.8%

Non-GAAP Financial Measures Northern Powergrid 68 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization (£ millions) LTM FFO 9/30/2015 2014 2013 Net cash flows from operating activities 345£ 336£ 321£ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 51 54 (27) FFO 396£ 390£ 294£ Interest expense 93£ 91£ 90£ FFO Interest Coverage(1) 5.2x 5.3x 4.3x Debt (2) 1,757£ 1,613£ 1,540£ FFO to Debt(3) 22.5% 24.2% 19.1% Capitalization Northern Powergrid shareholders’ equity 2,236£ 2,108£ 1,831£ Debt 1,757 1,613 1,540 Noncontrolling interests 37 37 34 Capitalization 4,030£ 3,758£ 3,405£ Debt to Total Capitalization(4) 43.6% 42.9% 45.2%

Non-GAAP Financial Measures EBITDA 69 ($ millions) BHE Consolidated EBITDA LTM 9-30-2015 Net income attributable to BHE shareholders 2,300 Noncontrolling interests 29 Interest expense 1,868 Capitalized interest (87) Income tax expense 532 Depreciation and amortization 2,360 EBITDA 7,002

SIERRA PACIFIC POWER CO 8-K