Berkshire Hathaway Energy 2015 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’s (“BHE”) and its subsidiaries’ (collectively, the “Company”) 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; – 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 and availability of the Company’s facilities, including the impacts of 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;

Forward-Looking Statements – 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; – 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 AltaLink and 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 (“SEC”) 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 SEC. 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-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.

2015 Fixed-Income Investor Conference Pat Goodman Executive Vice President and Chief Financial Officer Berkshire Hathaway Energy

Energy Assets (1) Pro forma 2014 including AltaLink (2) Includes both electric and natural gas customers and end-users worldwide. Additionally, AltaLink serves approximately 85% of Alberta, Canada’s population (3) Net MW owned in operation and under construction as of Dec. 31, 2014 Assets $82 billion Revenues(1) $17.9 billion Customers(2) 8.5 million Employees 20,900 Transmission Line 32,600 Miles Natural Gas Pipeline 16,400 Miles Generation Capacity 29,200 MW(3) Natural Gas 35% Coal 35% Renewables 28% Nuclear and Other 2%

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

• 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 allows 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

• On December 1, 2014, Berkshire Hathaway Energy acquired AltaLink for $2.7 billion • AltaLink owns and operates a regulated transmission-only business headquartered in Alberta, Canada • The acquisition of AltaLink: – Aligns well with Berkshire Hathaway Energy core principles – Allows Berkshire Hathaway Energy to continue to diversify its regulated business mix – Provides additional opportunities to deploy capital and grow • Following the close of the AltaLink Transaction in December 2014, S&P upgraded AltaLink Investments, L.P. from BBB- to BBB+, further demonstrating the benefits of Berkshire Hathaway Energy ownership – Maintained ring-fencing structure at AltaLink Investments AltaLink Transaction

Diverse Operations with Significant Scale BHE 2014 Net Income: $2.1 billion BHE retains more equity than any of its utility peers • 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 1,092 MW of solar generation in operation – 7% of the U.S. solar market • Berkshire Hathaway Energy has 4,243 MW of wind generation in operation – 6% of the U.S. wind market • Comparable companies Company Name Market Cap (billions) Dec. 31, 2014 Net Income (billions) Dec. 31, 2014(1) Duke Energy $59.1 $2.5 NextEra Energy Inc. $46.4 $2.5 Dominion Resources $44.9 $1.3 Southern Company $44.2 $2.0 Exelon Corp. $31.9 $1.6 (1) Net Income excludes income or loss from discontinued operations, net of tax

Financial Strength – Pro Forma Revenue and EBITDA Diversification BHE 2014 Pro Forma Energy Revenue(1): $15.9 Billion BHE 2014 Pro Forma EBITDA(2): $6.8 Billion (1) Excludes HomeServices and equity income, which add further diversification (2) Refer to the Appendix for the calculation of EBITDA; percentages exclude Corporate/other. Pro Forma includes AltaLink as part of BHE Transmission. Nevada 20.4% Iowa 16.4% Utah 14.6% Oregon 8.0% Wyoming 5.6% Illinois 4.7% Washington 2.7% Idaho 2.0% FERC 6.8% United Kingdom 8.1% Alberta 3.9% Philippines 0.7% Other 6.1% PacifiCorp 30.9% NV Energy 17.6% MidAmerican Funding 12.1% Northern Powergrid 12.8% BHE Pipeline Group 9.5% BHE Transmission 7.6% BHE Renewables 7.0% HomeServices 2.5% • Diversified revenue sources reduce regulatory concentrations • In 2014, 89% of pro forma EBITDA was from investment-grade regulated subsidiaries

$15.7 $18.7 $20.4 $0 $5 $10 $15 $20 $25 2012 2013 2014 Billions Berkshire Hathaway Energy Financial Summary $37.6 $50.1 $59.2 $0 $20 $40 $60 2012 2013 2014 Billions Net Income Attributable to BHE BHE Shareholders’ Equity Property, Plant and Equipment (Net) Cash Flows From Operations • BHE has realized significant growth in its assets, net income and cash flows over the past three years $4.3 $4.7 $5.1 $0.0 $2.0 $4.0 $6.0 2012 2013 2014 Billions $1.5 $1.6 $2.1 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 2012 2013 2014 Billions

Reportable Segment Information Years Ended Dec. 31 ($ millions) 2014 2013 2012 Operating Income: PacifiCorp 1,308$ 1,275$ 1,034$ MidAmerican Funding 423 357 369 NV Energy 791 (42) - Northern Powergrid 674 501 565 BHE Pipeline Group 439 446 465 BHE Transmission 16 (5) (2) BHE Renewables 314 223 93 HomeServices 125 129 62 BHE and Other (44) (49) (19) Total operating income 4,046 2,835 2,567 Interest expense - senior & subsidiary (1,633) (1,219) (1,176) Interest expense - junior subordinated debentures (78) (3) - Capitalized interest and other, net 267 228 184 Income before income tax expense and equity income (loss) 2,602 1,841 1,575 Income tax expense 589 130 148 Equity income (loss) 109 (35) 68 Net income 2,122 1,676 1,495 Net income attributable to noncontrolling interests 27 40 23 Net income attributable to BHE shareholders 2,095$ 1,636$ 1,472$

• BHE Key Credit Ratios(1) – Acquisitions have increased debt leverage in the near-term; however, operations have strengthened with increased diversification and the addition of incremental regulated cash flows • Ratings Summary (issuer or senior unsecured ratings unless noted) Credit Metrics and Financial Strength (1) Refer to the Appendix for the calculations of key ratios (2) Pro Forma 2014 column includes AltaLink related debt. 2014 column excludes AltaLink debt and BHE acquisition debt related to AltaLink acquisition. 2013 column excludes NVE debt and BHE acquisition debt related to NVE acquisition (3) Ratings are senior secured ratings (4) Issuer ratings Pro Forma 2014 2014 2013 2012 FFO Interest Coverage 4.5x 4.9x 4.5x 4.6x FFO to Adjusted Debt Excluding Acquisition Related Debt (2) 17.8% 20.5% 18.9% 19.8% Adjusted Debt to Total Capitalization 59.8 59.8 58.1 57.6 Moody’s S&P Fitch Moody’s S&P Fitch DBRS B rkshire Hathaway Energy A3 BBB+ BBB+ Kern River Funding Corp. (3) A2 A- A- PacifiCorp (3) A1 A A Northern Powergrid (Northeast) A3 A- A- Mi American Energy (3) Aa2 A A+ Northern Powergrid (Yorkshire) (4) A3 A- A- Nevada Power (3) A2 A A- AltaLink, L.P. (3) NR A- NR A Sierra Pacific Power (3) A2 A A- AltaLink Investments, L.P. NR BBB+ NR BBB Northern Natural Gas A2 A- A

Credit Metrics Note: Credit metrics for Northern Powergrid are in GBP Regulated U.S. Utilities Pipelines and Electric Distribution 2014 2013 2012 2014 2013 2012 PacifiCorp Northern Natural Gas FFO Interest Coverage 5.2x 5.0x 4.8x FFO Interest Coverage 8.3x 7.9x 6.3x FFO to Debt 22.3% 22.1% 21.3% FFO to Debt 36.5% 33.9% 30.8% Debt to Total Capitalization 47.7% 46.9% 47.3% Debt to Total Capitalization 40.3% 39.8% 41.1% MidAmerican Energy Kern River FFO Interest Coverage 7.1x 6.9x 7.7x FFO Interest Coverage 8.2x 7.2x 7.0x FFO to Debt 25.8% 24.9% 29.2% FFO to Debt 47.5% 40.5% 39.5% Debt to Total Capitalization 49.1% 48.0% 47.3% Debt to Total Capitalization 36.3% 39.8% 41.6% Nevada Power Northern Powergrid FFO Interest Coverage 4.8x 3.5x 4.1x FFO Interest Coverage 5.3x 4.3x 4.7x FFO o Debt 22.3% 14.8% 20.2% FFO to Debt 24.2% 19.1% 21.9% Debt to Total Capitalization 55.3% 55.3% 53.3% Debt to Total Capitalization 42.9% 45.2% 47.5% Sierra Pacific Power FFO Interest Coverage 5.1x 4.9x 5.2x FFO to Debt 20.9% 20.2% 23.3% Debt to Total Capitalization 54.6% 54.2% 53.2%

Return on Equity (1) Based on 13-point average equity (2) Excludes one-time items and merger-related expenses Net Income Divided by Average Equity(1) Entity 2014 2013 Allowed ROE PacifiCorp 9.2% 9.0% 9.8% MidAmerican Energy 10.2% 9.5% 10.9% Nevada Power 8.3% (2) 7.9% (2) 9.8% Sierra Pacific Power 9.0% (2) 8.6% (2) 9.8% Northern Natural Gas 11.6% 11.6% 12.0% Kern River 10.1% 10.5% 11.55%

• Berkshire Hathaway Energy and its subsidiaries will spend approximately $14.1b over the next three years for development and maintenance capital expenditures, which includes new environmental capital expenditures, transmission, and generation project expansions, including solar, wind and natural gas plant additions Capital Expenditures and Cash Flows Free Cash Flow

• Excluding AltaLink and new renewable projects acquired in 2015, 2015-2017 capital expenditures projections have been increased by $1.1b from prior year projections, primarily due to developmental capital expenditures at NV Energy in 2017 and the Wind IX investment at MidAmerican Energy in 2015 Operational Excellence – Reinvesting in Our Business

Wind and Solar Investments • On October 10, 2014 MEC announced plans to construct an additional 162 MW of wind generation – The project is expected to be completed by the end of 2015 and cost up to $243m • In 2014 BHE Renewables acquired and began construction on the $408m Jumbo Road wind project in Texas • On February 27, 2015 BHE Renewables acquired Grande Prairie Wind, LLC and Geronimo Community Solar Gardens, LLC which will add up to 400 MW of wind and 74 MW of solar generation, respectively – The projects are expected to be complete in 2016, with estimated total capital expenditures of $794m • In early 2015, BHE committed to fund a wind project through tax equity investment of approximately $270m • Continue to look for additional wind and solar opportunities 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 - 625 15 953 1,593 Total 1,030 3,457 15 2,426 6,928 Investment (billions) $2 $6 $0 $8 $16

Coal 74.2% Gas 9.3% Nuclear and Other 4.4% Wind 1.5% Hydro 5.4% Geothermal 5.2% Coal 57.5% Gas 22.7% Nuclear and Other 3.2% Wind 5.2% Hydro 8.0% Geothermal 3.4% Generation Diversification 2014 BHE Capacity Coal 56.0% Gas 23.6% Nuclear and Other 3.2% Wind 9.9% Hydro 3.5% Solar 1.9% Geothermal 1.9% 2014 BHE Generation 2006 BHE Capacity 2006 BHE Generation Coal 35.1% Gas 35.3% Nuclear and Other 1.8% Wind 17.7% Hydro 4.4% Solar 4.4% Geothermal 1.3% Total Renewables 16.6% Total Renewables 27.8% Total Renewables(1) 12.1% Total Renewables(1) 17.2% (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.

BHE Transmission Project Location Cost Description AltaLink Alberta Assets of $5.9b Purchased for $2.7b on December 1, 2014 Owns a regulated electric transmission-only company consisting of approximately 7,800 miles of transmission lines and 300 substations in Alberta, Canada Electric Transmission Texas Texas $2.2b in current rate base, approximately $3.1b 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 Central Valley Power Connect California $157.0m 50% ownership of 230-kV transmission line assets currently in development with Pacific Gas & Electric Company TransCanyon Western Electricity Coordinating Council (including California ISO) $338.0m 50% ownership in joint venture with Bright Canyon Energy, a subsidiary of Pinnacle West Capital Corporation. Delaney-to-Colorado River 500-kV project approved by the California ISO in July 2014, competitive solicitation submitted. California ISO expected to determine successful bidder in mid- 2015.

HomeServices of America Located in 25 States HomeServices is organized in three main businesses - Brokerage - Mortgage - Franchise $28 $22 $47 $73 $83 $0 $20 $40 $60 $80 $100 2010 2011 2012 2013 2014 ($ Millions) Net Income Attributable to HomeServices

Financing Plan 2015 • Solar Star – Completed nonrecourse project financing of $325m at 3.95% in March 2015 • PacifiCorp – Anticipate a $200m-$300m 2015 debt financing • MidAmerican Energy – Anticipate a $500m-$600m 2015 debt financing primarily to fund wind capital expenditures and refinancings • Northern Powergrid – Anticipate £400m of debt financings in 2015, split between Northern Powergrid (Yorkshire) and Northern Powergrid (Northeast). In late March 2015, a £150m financing at Northern Powergrid (Yorkshire) at 2.5% was completed • AltaLink – Completed March 2015 debt issuance of C$200m 7-year notes at 2.244% to refinance existing short-term debt outstanding at AltaLink Investments, L.P. – Anticipate an additional C$800m in total debt financings for 2015 at AltaLink, L.P. • Scheduled debt maturities total $1.2b

Questions

Scott Thon President and CEO AltaLink 2015 Fixed-Income Investor Conference

AltaLink Service Territory ALBERTA, CANADA Calgary Edmonton • Transmission-only company • Serve 85% of Alberta’s population • Service area covers ~82,000 square miles • ~7,800 miles of transmission lines • ~300 substations • Cost of Service Framework Other Key Highlights • No volume or commodity price risk • AESO determines transmission need • Consistently ranked in top quartile for reliability, safety and cost efficiency • Experienced management team with proven track record • AltaLink, L.P. credit rating stable at A- (S&P) AltaLink – Transmission Business

-4.1% 4.5% 5.7% 4.5% 3.8% 3.5% 1.9% 3.1% 2.8% -6.0% -4.0% -2.0% 0.0% 2.0% 4.0% 6.0% $0 $50 $100 $150 $200 $250 $300 2009 2010 2011 2012 2013 2014F 2015F 2016F 2017F 3,679 3,733 3,790 3,889 4,007 4,122 4,210 4,285 2009 2010 2011 2012 2013 2014 2015F 2016F Alberta – A Decade of Growth Overview of Alberta Economy Real GDP (C$b in 2002 $’s) GDP, by Sector Population (000s) • Canada’s third largest economy, with 18% of Canadian real GDP • Canada’s fourth largest province, with 11% of population • One of North America’s fastest growing economies • Unemployment rate among lowest in North America • Alberta is rated AAA by Moody’s, S&P and DBRS Source: Statistics Canada, Government of Alberta Source: Government of Alberta – Highlights of the Alberta Economy 2015 Source: EDC Associates Ltd. (First Quarter 2015) (Data as of 2013) Energy, 23% Finance & Real Estate, 14% Construction, 11% Business & Commercial Services, 11% Retail & Wholesale, 9% Manufacturing, 7% Transportation & Utilities, 6% Health, 5% Other, 14% G D P R e a l G D P G ro w th ( y /y ) Source: EDC Associates Ltd. (First Quarter 2015) Forecast Actual Forecast Actual CAGR (2009-2016): 1.9%

Alberta’s Competitive Power Market Supports Growth Overview of Alberta Power Market • The Alberta Power Pool (wholesale market) was established in 1996 and is Canada’s only truly deregulated spot power market – The AESO is responsible for the operation of the wholesale electricity market – Alberta is an energy-only market – there are no capacity payments made to generators – 9,000MW added since deregulation • Coal sets the market price 56% of the time, while gas sets the price 42% of the time in 2012 – Imports represented only 4.7% of Alberta’s internal energy load in 2012 Installed Generation Capacity, by Fuel Average Price (C$/MWh) with On-Off-Peak Range Maximum Hourly Load (MW) Source: Market Surveillance Administrator, Alberta Utilities Commission, Alberta Electric System Operator, The Conference Board of Canada Source: Alberta Electric System Operator – AESO Current Supply Demand Report (February 26, 2015) Source: Alberta Electric System Operator – 2014 Annual Market Statistics Total Capacity: 16,159 MW Wind, 9% Other, 3% Coal, 39% Gas, 43% Hydro, 6% P o w e r P ri c e (C $ /M W h ) CAGR (2003-2014): 2.0% 8,786 9,236 9,580 9,661 9,701 9,806 10,236 10,196 10,226 10,609 11,139 11,169 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $0 $20 $40 $60 $80 $100 $120 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 54.59 70.36 80.79 66.95 89.95 47.81 50.88 76.22 64.32 80.19 49.42 Source: Alberta Electric System Operator – 2014 Annual Market Statistics

• 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 • Nearly all capital spending is directed by the AESO, who is responsible for system planning 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

Cost of Service Tariffs Predictable Earnings and Cash Flows • Transmission tariffs include: – Opportunity to earn an authorized return – Recovery of prudent capital costs – Recovery of forecast operating expenses, interest costs and deemed income taxes Return on Common Equity Return on Debt Income Taxes Depreciation (Return of Capital) Operating Expenses Debt Common Equity Regulated Rate Base Regulated Tariff Common Equity Rate of Return Embedded Cost of Debt • Forecast risk is partially mitigated by deferral and reserve accounts – Direct Assign Capital deferral account – Long-term Debt deferral account – Property Tax deferral account – Annual Structure payments – Self Insurance reserve – Hearing Cost reserve

Financial Strength • Strong financial growth correlated with rate base investment R a te Bas e (C $ M ) N e t Inc o me b ef o re ta x (C $ M ) 0 50 100 150 200 250 0 1,000 2,000 3,000 4,000 5,000 6,000 Rate Base CWIP in Rate Base CWIP ALP Net Income (1) (1) Net Income based on IFRS

0.5 0.7 1.0 1.8 2.0 1.5 1.1 0.0 0.5 1.0 1.5 2.0 2010A 2011A 2012A 2013A 2014A 2015F 2016F Growth Maintenance 1.6 2.0 2.6 3.7 5.2 6.6 7.3 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 2010A 2011A 2012A 2013A 2014A 2015F 2016F Rate Base Construction Work in Progress Forecast Financial Strength Strong Growth in Regulatory Capital M id -Y e a r Reg u lat o ry Capi ta l (in b ill io n s o f C$ ) G ro s s Capi tal E xpe n d it u re s (in b ill io n s o f C$) 2015F and 2016F based on AltaLink’s 2015-16 GTA Filing Actual Actual Forecast C$2.9b to be added to rate base in 2015

2015-2016 GTA Filed Large Increases Due to Capital Investment 2015 Highlights • C$2.9b moves from CWIP into Rate Base – Increasing tariff for property tax, insurance, interest, depreciation, salvage and equity returns • Additions subject to mid-year rule • Revenue requirement forecast of C$810.5m (22.5% increase) 2016 Highlights • Full year impact of 2015 additions • Further C$0.8b moves into rate base • Revenue requirement forecast of C$1,001.6m (23.6% increase) Rate mitigation measures • AltaLink has offered to end CWIP in rate base • Stronger credit metrics in 2016 and beyond Source: Government of Alberta – Talk About Transmission (September 2010) Allocation of Transmission Costs in Alberta (Data as of 2010) Source: AESO 2014 ISO Tariff Application Farm 4% Industrial 61% Commercial 19% Residential 16% (Data as of 2013) 7.3 5.1 5.1 3.4 3.7 1.9 4.8 2.3 0 5 10 15 20 Residential Small Industrial Large Industrial Administration Distribution Transmission Generation Breakdown of Average Electricity Bill E le c tr ic it y B ill B re a k d o w n (¢ / K W h 17.8 8.8 7.0 Average monthly residential bill is C$106.60 System Growth & Maintenance System Support Operating Costs 2015 2016

Top Quartile Performance Industry Leader in Operational Performance Safety A ll Inju ri e s P e r 200,00 0 H our s C o st E ff ic ie n cy O & M C o st s / G ro ss F ix e d A ss e ts ( % ) R e lia b ili ty Inte rr up ti on s P e r D e liv e ry P o in t R e lia b ili ty H our s o f Inte rr up ti o n P e r D e liv e ry P o in t 0.00 0.50 1.00 1.50 2.00 2006 2007 2008 2009 2010 2011 2012 2013 2014 AltaLink CEA 0.00 1.00 2.00 3.00 2006 2007 2008 2009 2010 2011 2012 2013 2014 0.00 0.50 1.00 1.50 2.00 2006 2007 2008 2009 2010 2011 2012 2013 2014 0.00 1.00 2.00 3.00 4.00 2006 2007 2008 2009 2010 2011 2012 2013 2014F

Source: 2015-16 General Tariff Application Effective Management of Assets AltaLink Breakers by Number of Units and Age AltaLink Transformers by Number of Units and Age • Asset profile is distributed in age • Targeted maintenance investments support reliability • Operational readiness and integration process ensures proactive integration of new assets and technology AltaLink Transmission Lines by Km and Age Source: 2015-16 General Tariff Application Source: 2015-16 General Tariff Application 0 200 400 600 800 1,000 1,200 1,400 1,600 0-9 10-19 20-29 30-39 40-49 50-59 60-70 >70 0 50 100 150 200 250 300 350 400 1-10 11-20 21-30 31-40 41-50 51-60 60+ 0 20 40 60 80 100 120 0 -10 0-10 21-30 31-40 41-50 51-60 61-70 71-80 81-90

Unique Culture is Our Strength Top Decile in Employee Engagement • Top decile employee engagement  95% employee survey participation  83% engagement score • AltaLink employs over 800 people  60% of employees are unionized Named one of Canada’s top 10 most admired corporate cultures in 2014 • Recognizes organizations for having a culture that helps them enhance performance and sustain a competitive advantage • Winning organizations outpaced the S&P/TSX three- year annual growth rate by more than 600%

Leader in Sustainability Recognized as Sustainable Electricity Company AltaLink achievements • Avian protection plan • Oil and power pole recycling programs • Environmental assessments for projects • Leading practices in external engagement and construction • Comprehensive environmental management system based on ISO 14001 • Strong community engagement • Comprehensive employee programs First transmission company in Canada to achieve CEA Sustainable Company designation

Key Investment Highlights • Regulated under cost of service framework • No volume or commodity price risk • Limited counterparty risk (AESO and regulated utilities) • Fixed monthly revenue payments from AESO (AA- rating S&P) Predictable and Stable Cash Flows • Well-established and transparent regulatory structure (lower risk than U.S.) • Credit relief measures approved by AUC to support credit ratings • Cost of service framework comparable to U.S. regulators Supportive Regulatory Environment • Consistently ranked in top quartile for reliability, safety and cost efficiency • Named one of Canada’s 10 most admired corporate cultures in 2014 • Received top safety and sustainability designations from Canadian Electricity Association Strong Operational Performance • Strong financial results as reflected in 19.6% compounded annual growth rate for EBITDA from 2010 to 2014 • Growth driven by electricity demand, congestion relief and enabling Alberta’s energy-only market • Key projects have obtained all major approvals and are already under construction • All 2014 transmission projects completed within or better than cost estimates and schedule Significant Growth • Experienced management team with proven track record Experienced Management Team • AltaLink, L.P. credit rating stable at A / A- (DBRS / S&P) • AltaLink Investments, L.P. upgraded two notches by S&P to BBB+ • Significant increase in operating cash flow as CWIP projects enter rate base Financial Strength and Performance

Questions

2015 Fixed-Income Investor Conference Cindy Crane Stefan Bird Pat Reiten President and CEO PacifiCorp Transmission President and CEO Pacific Power President and CEO Rocky Mountain Power

PacifiCorp Overview • Six-state service territory ‒ Utah – Oregon ‒ Idaho – Washington ‒ Wyoming – California • 5,900 employees • 1.8 million electricity customers • 143,000 square miles of service territory • 16,400 transmission line miles • 11,136 MW(1) owned generation capacity ‒ Coal 55% ‒ Natural gas 25% ‒ Hydro (2) 10% ‒ Wind, geothermal and other (2) 10% (1) Net MW owned in operation as of December 31, 2014 (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

Generating Capacity by Fuel Type March 31, 2006 December 31, 2014 8,470 MW (1) 11,136 MW (1) (1) Net owned capacity (MW) Generating fleet increase primarily attributed to the addition of: • 1,654 MW Natural Gas - Lake Side 1 & 2 and Chehalis • 997 MW Wind - 594 MW Eastside and 404 MW Westside Coal 72.1% Natural Gas 13.3% Hydro 13.7% Wind 0.4% Geothermal and Other 0.5% Coal 55.3% Natural Gas 24.8% Hydro 10.3% Wind 9.2% Geothermal and Other 0.4%

• PacifiCorp’s net income trend continues to grow. The 2012 decline was primarily due to charges for the USA Power litigation and certain fire and other damage claims • Efforts to minimize customer rate increases while maintaining systems reliability, safety and customer service have resulted in generally flat operations and maintenance expenditures PacifiCorp Financial Overview $566 $555 $537 $682 $698 - 100 200 300 400 500 600 700 800 2010 2011 2012 2013 2014 PacifiCorp Net Income ($ millions) $1,103 $1,077 $1,114 $1,057 - 200 400 600 800 1,000 1,200 2011 2012 2013 2014 PacifiCorp O&M Expense ($ millions) (1) (1) Excludes $165m of charges related to the USA Power litigation and certain fire and other damage claims

PacifiCorp Financial Overview • Operating capital varies with plant overhauls and system requirements • Development capital decreases with completion of major projects: – Wind generation installed 2008-2010 – Lake Side 2 placed in-service 2014 (construction 2011-2014) – Environmental controls for SO2, NOx, particulates and mercury (2008-2017) – Hydroelectric - Lewis River fish passage and Soda Springs (2011-2014) – Energy Gateway transmission segments (construction 2008-2015) include Populus-to-Terminal (2010), Mona-to-Oquirrh (2013), Sigurd-to-Red Butte (May 2015) ($ Millions) 2015-2017 Current Plan Prior Plan Operating $ 1,927 $ 1,935 Development 600 848 Total $ 2,527 $ 2,783 $943 $1,334 $750 $592 $601 $502 $463 $279 $142 $179 $846 $994 $857 $914 $745 $563 $603 $686 $631 $610 - 500 1,000 1,500 2,000 2,500 2008 2009 2010 2011 2012 2013 2014 2015F 2016F 2017F PacifiCorp Capital Expenditures Development Operating ($ millions)

Retail Sales 2014 Retail Sales by Class (GWh) 2014 Retail Sales by State (GWh) Residential 28% Commercial 31% Industrial & Irrigation 40% Other 1% California 1% Oregon 24% Washington 8% Idaho 6% Utah 44% Wyoming 17% Total 2014 Retail Revenue: $4.7b

Employee Commitment Safety Culture and Work Environment PacifiCorp Recordable Incidents 2012: 101 incidents 2013: 66 incidents 2014: 68 incidents OSHA Recordable Rate 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 2006 2007 2008 2009 2010 2011 2012 2013 2014 Berkshire Hathaway Energy PacifiCorp

2015 Fixed-Income Investor Conference Rocky Mountain Power

Load Growth Rocky Mountain Power 3,420 3,440 3,460 3,480 3,500 GWh Idaho 2015 Forecast 2014 24,150 24,200 24,250 24,300 24,350 24,400 GWh Utah 2015 Forecast 2014 9,400 9,500 9,600 9,700 9,800 9,900 GWh Wyoming 2015 Forecast 2014 142 GWh (0.6%) 291 GWh (3.0%) Weather Normalized 40 GWh (-1.1%) 32 33 34 35 36 37 38 39 2009 2010 2011 2012 2013 2014 2015 Fcst 2016 Fcst T W h Rocky Mountain Power Retail Loads Weather Normalized Annual Growth Rate 2010 = 4.2% 2011 = 2.5% 2012 = 0.4% 2013 = 0.5% 2014 = 1.2% 2015 = 1.1% 2016 = 1.9% • 2014 load growth primarily attributed to industrial expansion and data center growth • Modest growth in 2015 and 2016 due to the continuing economic recovery partially offset by energy efficiencies

Regulatory Accomplishments Strategy • Improve or implement power cost recovery mechanisms to enhance recovery of variable costs of energy production not reflected in base rates • Manage capital expenditures in line with depreciation expense levels to reduce impact to customers rates • Seek separate tariff riders where feasible for major capital projects • Manage operations and maintenance expenses at or below levels reflected in rates • Work with stakeholders to develop balanced outcomes that provide rate predictability to customers and cost recovery for the company Utah • Two-year rate plan in place through September 1, 2016 Wyoming • General rate case order received December 2014 for rates effective January 2015 • General rate case filed March 2, 2015, for rates effective January 1, 2016, includes replacement of current energy cost adjustment mechanism expiring December 31, 2015 Idaho • Two-year rate plan in place through December 31, 2015

Rocky Mountain Power Customer Generation State Residential Customers Non- Residential Customers Total DG Customers Residential Size (kW) Non- residential Size (kW) Total Generation (kW) ID 110 23 133 483 357 840 UT 3,353 394 3,747 14,535 15,108 29,643 WY 149 45 194 542 392 934 Total 3,612 462 4,074 15,560 15,857 31,417 • Net metering customer participation grew by 50% in 2014. This represents 0.47% of customers • Growth is due to declining costs of solar, including tax credits and solar incentive programs • Net metering docket in process in Utah to address costs/benefits and rate structure redesign 2,503 5,022 5,425 16,958 - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 2011 2012 2013 2014 G e n e ratio n Ca p ac it y Rocky Mountain Power Net Metering kW Added by Year Residential Non-residential Total RMP 383 480 713 1,389 - 200 400 600 800 1,000 1,200 1,400 1,600 2011 2012 2013 2014 C u st o m e r G e n e rat o rs Rocky Mountain Power Net Metering New Customers by Year Residential Non-residential Total RMP

• Modify tariff to prevent subsidization of distributed generation ‒ Ongoing net metering docket with Utah Public Service Commission to set framework for future net metering tariff ‒ Implement a rate design to recover fixed costs independent of usage • Offer customers renewable energy options ‒ Current programs o Blue Sky o Utah Solar Incentive Program o Service from Renewable Energy Facilities ‒ New programs in development o Utah Subscriber Solar for residential and small commercial o Industrial renewables program • Work with stakeholders to research new distributed generation ‒ Net zero communities ‒ Electric vehicle charging Distributed Generation Strategy

Utah Typical Residential Summer Demand with 4 kWDC Solar DG System with 4 k DG S st 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 K il o w at t Customer Demand 4am 8am 12pm 4pm 8pm 12am 100% Utility-Provided Power DG Peak 12-2 PM Customer Demand Peak 5-7 PM DG customer uses grid to export excess power 100% Utility-Provided Power Utility-Provided Power Utility-Provided Grid Services 23.99 hours/day utility provides all grid services 8 hours/day utility provides 100% of power needed DG System-Provided Power 8 hours/day DG system provides 100% of power needed DG Generation Utility and DG System-Provided Power 8 hours/day both utility and DG system provides power

Operational Excellence Natural Gas-Fueled Equivalent Availability Coal-Fueled Equivalent Availability • 2014 coal-fueled equivalent availability exceeded industry top decile benchmark by 1.1% • 2014 natural gas-fueled equivalent availability exceeded industry top decile benchmark by 2.4% 75 80 85 90 95 100 2006 2007 2008 2009 2010 2011 2012 2013 2014 E q u iv a le n t A v a ila b ili ty % Actual Industry Benchmark Top Decile 80 85 90 95 100 2006 2007 2008 2009 2010 2011 2012 2013 2014 E q u iv a le n t A v a ila b ili ty % Actual Industry Benchmark Top Decile

0.0 0.5 1.0 1.5 2.0 2.5 0 20 40 60 80 100 120 140 160 180 200 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Plan S A IFI E v e n ts S A ID I Minu te s SAIDI-T SAIDI-D SAIFI-T SAIFI-D Operational Excellence Rocky Mountain Power Reliability History Excluding Major Events

• Regional Haze Rules • Mercury and Air Toxics Standard • Clean Air Act §111(d) Rule Making • National Ambient Air Quality Standards • Clean Water Act §316(b) Cooling Water Intake Rule • Coal Combustion Residuals Rule • Steam Electric Power Generating Effluent Guidelines Key Environmental Regulations

• By April 2015, 5,981 MW(1) of owned coal-fueled generation – 97% will be controlled by scrubbers (Regional Haze, MATS, and NAAQS) – 59% will be controlled by baghouses (Regional Haze, MATS, and NAAQS) – 100% will meet mercury emissions requirements (MATS) – Carbon Units 1 and 2 (172 MW) planned to be retired mid-April 2015 • Regional Haze compliance projects under construction – Installation of selective catalytic reduction systems on Jim Bridger Units 3 and 4 (collectively 702 MW PacifiCorp share; 2015 and 2016 in-service dates) – Installation of selective catalytic reduction systems on Hayden Units 1 and 2 (collectively 78 MW PacifiCorp share; 2015 and 2016 in-service dates) – Installation of selective catalytic reduction system on Craig Unit 2 (83 MW PacifiCorp share; 2017 in-service date) • Proposed Regional Haze alternative coal-to-natural gas conversions – Naughton Unit 3 by June 2018 – Cholla Unit 4 by April 2025 Coal-Fueled Environmental Compliance Position (1)Reflects Carbon plant retirement

• The final rule was released December 19, 2014, and will become effective 180 days after it is published in the federal register. • As defined by the final rule, PacifiCorp operates 18 surface impoundments and seven landfills that contain coal combustion residuals. • PacifiCorp is assessing its ability to eliminate several of the impoundments and landfills from regulation by either closing or cleaning them prior to the effective date of the rule. • Plant studies, site inspections, and budget reviews are underway to ensure that the facilities meet the rule requirements and that operating budgets are aligned with final rule compliance requirements and deadlines. Coal Combustion Residual Rule

Project Regional Haze Rules MATS CCR Effluent Limitations Clean Water Act NOx Controls (e.g. Selective Catalytic Reduction) $770m Mercury Controls $5m Coal Combustion Residuals Compliance (including asset retirement obligations) $323m Effluent Limitation Guidelines $68m Clean Water Act §316(b) Compliance $3m Environmental Capital Cost of Coal Plant Compliance Note: Including AFUDC and escalation Total 2015-2024 Environmental Capital for Coal Plants: $1.2b (2015-2017: $298m)

Clean Air Act §111(d) Rule Making • Stated goal to achieve 30% reduction in CO2 emissions from 2005 levels by 2030 • Establishes state-by-state emission reduction requirements • Initial compliance steps required by 2020 • Interim targets applied between 2020 and 2029 • Final target by 2030 • Final rule expected summer 2015 • State compliance plans 2016 - 2018 Building Block 1 6% heat rate improvement at coal-fueled units Building Block 2 Re-dispatch NGCC units to 70%, displacing coal generation Building Block 3 Increase deployment of zero-emitting resources based on regional targets Building Block 4 Increase end-use energy efficiency of 1.5% of load; 10.7% average cumulative increase

Deer Creek Mine Closure • PacifiCorp closure of Deer Creek mine – Deteriorating quality of remaining coal reserves – Escalating cost of employee benefits for the mine's union (UMWA) employees – Follows unsuccessful 18-month attempt to sell operation – Best outcome for our customers • Long-term replacement supply agreement for Huntington plant with a third-party • Transaction on target for regulatory approval by May 31, 2015 • Underground mining concluded in January 2015 • Final mine closure underway

2015 Fixed-Income Investor Conference Stefan Bird President and CEO Pacific Power

Load Growth Pacific Power Weather Normalized 12,800 12,900 13,000 13,100 13,200 GWh Oregon 2015 Forecast 2014 3,950 4,000 4,050 4,100 4,150 GWh Washington 2015 Forecast 2014 762 764 766 768 770 GWh California 2015 Forecast 2014 170 GWh (1.3%) 79 GWh (-1.9%) 4 GWh (0.5%) 17.0 17.1 17.2 17.3 17.4 17.5 17.6 17.7 17.8 17.9 18.0 2009 2010 2011 2012 2013 2014 2015 Fcst 2016 Fcst T W h Pacific Power Retail Loads Weather Normalized Annual Growth Rate 2010 = -0.7% 2011 = -0.7% 2012 = -0.4% 2013 = 0.0% 2014 = 1.3% 2015 = 0.5% 2016 = 0.1% • 2014 load growth primarily attributed to agricultural-related businesses • Modest growth in 2015 and relatively flat in 2016 due to anticipated customer growth partially offset by energy efficiencies

Strategy • Improve or implement power cost recovery mechanisms to enhance recovery of variable costs of energy production not reflected in base rates • Manage capital expenditures in line with depreciation expense levels to reduce impact to customers rates • Seek separate tariff riders where feasible for major capital projects • Manage operations and maintenance expenses at or below levels reflected in rates • Work with stakeholders to develop balanced outcomes that provide rate predictability to customers and cost recovery for the company Oregon • No general rate cases filed in 2014 or 2015. Implemented separate tariff rider for Lake Side 2 in June 2014 • Opened docket for new mechanism to track variable costs of renewable resources Washington • 2014 general rate case order issued March 25, 2015 • Appeal of final order in the 2013 general rate case is pending California • No general rate case filed since 2009. Next case will be filed no sooner than November 2015 Regulatory Accomplishments

Pacific Power Customer Generation State Residential Customers Non- Residential Customers Total DG Customers Residential Size (kW) Non- residential Size (kW) Total Generation (kW) CA 149 31 180 1,090 1,854 2,944 OR 3,334 644 3,978 14,065 21,531 35,595 WA 210 43 253 1,279 704 1,984 Total 3,693 718 4,411 16,434 24,089 40,523 • Net metering customer participation grew by 18% in 2014. This represents 0.57% of customers • Growth is due to declining costs of solar, tax credits and solar incentive programs • The Oregon commission is opening a docket to evaluate the value of solar 662 874 669 681 - 100 200 300 400 500 600 700 800 900 1,000 2011 2012 2013 2014 C u st o m e r G e n e rat o rs Pacific Power Net Metering New Customers by Year Residential Non-residential Total Pacific Power 5,998 7,456 10,206 8,912 - 2,000 4,000 6,000 8,000 10,000 12,000 2011 2012 2013 2014 G e n e ratio n Ca p ac it y Pacific Power Net Metering kW Added by Year Residential Non-residential Total Pacific Power

• Modify tariff to prevent subsidization of distributed generation ‒ Oregon Commission docket on value of solar opens April 9, 2015 ‒ Ongoing net metering dockets with the California Commission to establish a future net metering tariff ‒ Implement a rate design to recover fixed costs independent of usage • Offer customers renewable energy options ‒ Current programs o Blue Sky o Oregon Solar Incentive Programs o California Solar Incentive Program ‒ New programs in development o Potential Subscriber Solar for residential and small commercial o Expand Blue Sky renewable energy purchase offerings • Work with stakeholders to research new distributed generation ‒ Industrial voluntary renewable program ‒ Electric vehicle charging programs Distributed Generation Strategy

Oregon Typical Residential Summer Demand with 4 kWDC Solar DG System 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 K il o w at t Customer Demand 4am 8am 12pm 4pm 8pm 12am 100% Utility-Provided Power DG Peak 1-3 PM Customer Demand Peak 6-8 PM DG customer uses grid to export excess power 100% Utility-Provided Power Utility-Provided Power Utility-Provided Grid Services 23.99 hours/day utility provides all grid services 9 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 8.5 hours/day both utility and DG system provides power

Customer Service Targeting Top Decile Performance 2014 J.D. Power Residential J.D. Power Business Market Strategies Residential Market Strategies Business TQS Large Industrial & Commercial PacifiCorp 2nd Quartile Top Quartile Top Decile Top Decile Top Decile Pacific Power 2nd Quartile 2nd Quartile Top Decile Top Quartile Top Decile Rocky Mountain Power 2nd Quartile Top Quartile Top Decile Top Decile Top Decile Customer Satisfaction Scores by Customer Segment Continuous Improvement • Improved customer outage communications for planned outages • Proactively communicate reliability improvements to customers • Deliver community and customer safety programs • Employees have customer service goal and training requirement • Improved quality/consistency of call menus and automated call handling 2015 Customer Service Plans  Deliver on the basics  Engage customers  Provide additional product and service options

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 0 20 40 60 80 100 120 140 160 180 200 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Plan S A IFI E v e n ts S A IDI M inute s SAIDI-T SAIDI-D SAIFI-T SAIFI-D Operational Excellence Pacific Power Reliability History Excluding Major Events

2015 Fixed-Income Investor Conference Pat Reiten President and CEO PacifiCorp Transmission

Major Transmission Capital Program • Sigurd-to-Red Butte – Construction started May 2013 – Expected in-service May 2015 • Wallula-to-McNary – Permitting continues in 2015 – Expected in-service 2017 • Gateway West – BLM record of decision on 8 of 10 segments November 2013 – Remaining two segments across Idaho expected late 2016, following supplemental environmental impact analysis • Gateway South – BLM record of decision expected year-end 2015 • Segments In-Service – Populus-to-Terminal November 2010 – Mona-to-Oquirrh May 2013 Over $6 billion total cost planned; $1.3 billion placed in-service

Energy Imbalance Market • Automatically optimizes load and generation across six-state footprint every five minutes – Efficient dispatch, renewable resource integration, improved situational awareness – $21m - $129m projected joint annual benefits – California ISO first quarterly report estimates joint benefits of $6m created in first two months ($4.7m to PacifiCorp customers) • Executed on schedule and within budget – February 2013, PacifiCorp – California ISO memorandum of understanding – November 1, 2014, full market go-live – $20m PacifiCorp startup investment – $3m annual operating expense • Benefits expected to grow with expanded participation bringing additional diversity and transfer capability – NV Energy and Puget Sound Energy are scheduled to join Fall 2015 and Fall 2016, respectively

Questions

2015 Fixed-Income Investor Conference Paul Caudill President & CEO NV Energy

NV Energy Overview • Provides electric services to Las Vegas and surrounding areas • 4,752 MW of owned generation in operation as of Dec. 31, 2014 • Provides electric and gas services to Reno and Northern Nevada • 1,372 MW of owned generation in operation as of Dec. 31, 2014 • Serves approximately 1.2 million electric and 0.2 million gas customers • 2,500 employees, two unions, representing 1,250 employees • Summer peaking utility driven by loads in Las Vegas • Generation resource mix heavily dependent on natural gas • Provides service to 90% of Nevada’s population, along with tourist population of 40 million Nevada Power Electric Service Territory CALIFORNIA ARIZONA UTAH NEVADA Sierra Pacific Power Service Territory Coal Plants Natural Gas Plants Energy Recovery Plant

27 28 29 30 2010 2011 2012 2013 2014 2015F 2016F TW h NV Energy Retail Load Weather-Normalized Economic Outlook and Load Growth 2014 compared to 2013 • Mining load up 6.5%, but industrial load down 0.4% due to continued retrenchment in the tourism industry • Commercial loads up 0.8% led by retail expansion • Residential loads decreased 1.3% (weather normalized) due to energy efficiency programs Forecast for 2015 and 2016 • Mining, retail and manufacturing loads increase, contributing to non-residential load growth • Slow residential growth as energy efficiency gains partially offset the addition of new customers Key Drivers • No income tax and low business tax rates contribute to economic growth • Unemployment has fallen substantially and is expected to continue to decline • Several large retail developments, a large manufacturing plant addition, as well as mine expansions, will drive growth in 2015 and 2016 • Over the last five years, NV Energy has achieved an average of 237 GWh of annual electricity savings through customer participation in energy efficiency programs, at a cost of approximately $0.02 per kWh 2011 = 0.8% 2012 = 0.8% 2013 = 1.6% 2014 = 0.7% 2015 = -0.5% 2016 = 1.6% Annual Growth Rate

ON Line One Nevada Line Transmission Project • 231-mile 500-kV line interconnects northern and southern transmission systems • Cost at December 31, 2014: $534.7m (excludes AFUDC) • Joint project: 25% NV Energy, 75% Great Basin Transmission ‒ NV Energy’s ownership portion: $133.7m (excludes AFUDC) • Placed in-service December 31, 2013 • Consolidated balancing area reviewed and certified by NERC in January 2014 • Optimizes generating resource economic dispatch and renewable energy delivery from northern Nevada to Las Vegas load center ‒ 2014 joint dispatch savings of $12m

• Filed May 2, 2014 • Certification filing proposed revenue requirement increase of $38.0m • Prior to deadline for filing rebuttal testimony, company engaged Nevada commission staff and consumer advocate in settlement discussions – In addition to consumer advocate, 11 intervenors • Case was settled and order issued October 15, 2014 – Zero percent revenue requirement increase; the smallest in over a decade • Stipulation agreement ensured a return of and return on more than $915m of plant in-service added since 2011 general rate case 2014 Nevada Power General Rate Case

2014 Nevada Power Emissions Reduction Capacity Replacement Filing Filing Order Generation resource plan filed with Nevada commission May 1, 2014 Filing included schedule for retirement of 812 MW of coal generation and 550-MW capacity replacement plan Accepted requirement plan, providing path to recover unamortized balance of plants, and estimated decommissioning and remediation costs of $561m Also included plan for three, 100-MW renewable energy solicitations Authorized by Commission Requested approval of 15-MW Nellis Air Force Base Solar Array II Commission approved construction of project, providing a path for recovery of estimated $54m investment Requested approval of 200-MW Moapa Solar Project Commission modified proposal and authorized 54-MW (planning capacity) and 35-MW (nameplate) of renewable generation, providing opportunity of additional estimated investment of $150m to $315m, depending on nature of resource additions

• May 31, 2013, company filed an application to merge two operating entities • Request to withdraw application was filed March 14, 2014, due to a number of changes – Interim joint dispatch agreement approved by Federal Energy Regulatory Commission – Senate Bill 123 passed subsequent to May 2013 filing – One Nevada Transmission Line placed in-service December 31, 2013 • Through the March 2, 2015 filing, we are pursuing a permanent joint dispatch agreement – Plan to maintain current legal and regulatory structure Nevada Power and Sierra Pacific Merger Filing

• NV Energy will not file electric or gas general rate case in 2015 – Sierra Pacific scheduled to file in 2016 for rates effective January 1, 2017 – Nevada Power scheduled to file in 2017 for rates effective January 1, 2018 • Annual deferred energy accounting adjustment filed February 27, 2015 – Nevada commission will review results of joint dispatch • State filing made March 2, 2015, to secure authorization for permanent joint dispatch of generation fleets • Triennial filing of Nevada Power integrated resource plan July 1, 2015 – Ensure company has ability to meet future load with reasonable and predictable rates – Meet federal greenhouse gas compliance requirements • Achieve successful outcome with distributed generation strategy – 120-day biennial state legislature began in February 2015 2015 Regulatory Integrity Outlook

Customer Generation • In 2014 net metering customer participation grew year-over-year by 164%, reaching just over 2,000 customers or 73 megawatts. This equates to 1% of total generation • Net metering docket in process to address cost of service to distributed generation customers and potentially change rate structure • Approaching the Nevada net metering cap of 3% (calculated based on peak load) State Total Customers Residential Customers Non- residential Customers Residential Size (kW) Non- residential Size (kW) Total Generation (kW) NV 5,334 4,526 808 5.39 65.67 84,661

• Existing Utility Managed Programs – SolarGenerations o Net metering cap of 3% of peak demand, or approximately 220 megawatts o $255.3m in rebate funding provided by the 2009 Legislature with goal of leading to the installation of 250 megawatts of solar, 73 megawatts installed to date o Will likely reach the 3% cap in mid-2016 o Rebates given on DG sizes up to 500 kilowatts – $40.0m for wind/hydro distributed generation • Existing Renewable Energy Alternatives – Green rider at Sierra Pacific and Nevada Power – Green rider allows customized options for larger customers – Apple data center transaction provides 100% renewable energy through a 19 megawatt renewable resource dedicated to the customer Current Distributed Generation Status

• With biannual legislature currently in session, strategy is to: – Confirm Nevada Commission has statutory authority to set separate rates for partial requirement residential and commercial customers who choose to net meter and/or install rooftop solar – Support current open commission docket related to cost to serve partial requirements customers, to include appropriate prices to pay for net metered system production – With the decline in solar panel costs, lobby to hold the subsidized net metering cap at current 3% of peak demand – The 2015 integrated resource plan filing promotes community solar as a less expensive alternative to rooftop solar, and one that allows all customers the opportunity to participate Distributed Generation Strategy

Nevada Typical Residential Summer Demand with 5 kWDC Solar DG System 0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 K il o w at t Customer Demand 4am 8am 12pm 4pm 8pm 12am DG Peak 11 AM-1 PM Customer Demand Peak 3-5 PM Utility-Provided Power Utility-Provided Grid Services Utility-Provided Power 24 hours/day utility provides all grid services 15 hours/day utility provides power while DG system provides some power 8 hours/day utility provides 100% of power needed DG System-Provided Power 15 hours/day DG system provides some of the power needed DG Generation 100% Utility-Provided Power 100% Utility-Provided Power

Operational Capital Management • Capital investment from 2015-2017 increased $494 million from prior plan primarily due to the following investments at Nevada Power: ($ Millions) 2015-2017 Current Plan Prior Plan Variance Operating $ 1,128 $ 1,159 $ (31) Development 925 400 525 Total $ 2,053 $ 1,559 $ 494 ‒ $400m investment in 570 megawatt combined cycle gas turbine in 2017 ‒ $210m investment in 100 megawatt photovoltaic plant in 2017 ‒ $160m reduction due to timing of the construction spend on a 597 megawatt combined cycle gas turbine to be placed in- service in 2020 $1,485 $827 $577 $522 $414 $370 $558 $578 $477 $999 - 200 400 600 800 1,000 1,200 1,400 1,600 2008 2009 2010 2011 2012 2013 2014 2015F 2016F 2017F NV Energy Capital Expenditures Capital Expenditures ($ Millions)

Energy Imbalance Market • Plan announced in November 2013 to join California ISO Energy Imbalance Market • Nevada Commission unanimously approved in August 2014 • Targeting October 1, 2015, in-service date • Benefits – Reduced costs through automated dispatch of least-cost resources over a larger and more diverse pool of resources and load – Enhanced reliability through increased visibility, situational awareness and automated outage response – Improved renewable energy integration due to load and resource diversity across a larger geographic footprint – The estimated annual net benefit to NV Energy customers is $1.6m-$5.1m in 2017 and $3.6m-$8.1m in 2022

89 81 57 66 56 25 0 10 20 30 40 50 60 70 80 90 100 2009 2010 2011 2012 2013 2014 YTD Actual Preventable Vehicle Accidents PVAs • Recordable incident rate at 0.74 • 25 preventable vehicle accidents 2014 – Employee Commitment and Safety 81 81 75 65 37 18 0 1 2 3 0 10 20 30 40 50 60 70 80 90 100 2009 2010 2011 2012 2013 2014 YTD Actual OSHA Recordables OSHA Recordables Incident Rate

Questions

2015 Fixed-Income Investor Conference Bill Fehrman President and CEO MidAmerican Energy Company

• Headquartered in Des Moines, Iowa • 3,600 employees • 1.4 million electric and natural gas customers in four Midwestern states • 11,000 square miles of service territory • 8,563 MW(1) owned generation capacity • Generating capacity by fuel type(1) – Wind(2) 41% – Coal 39% – Natural Gas and Other 15% – Nuclear and Hydroelectric 5% (1) Net MW owned in operation and under construction as of December 31, 2014 (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 Company Overview

• Economic and Load Data – Service territory has experienced moderate economic growth – Forecast loads for 2015 and 2016 reflect strong growth rates, particularly for the industrial class due to announced data center expansions within the MidAmerican Energy service territory – Data centers attracted to relatively low, stable electric rates and the MidAmerican Energy wind portfolio Business Update 0 5 10 15 20 25 30 2009 2010 2011 2012 2013 2014 2015F 2016F T W h MidAmerican Energy Retail Load Weather-Normalized Annual Growth Rates: 2010 = 4.2% 2011 = 1.2% 2012 = 0.6% 2013 = 1.7% 2014 = 2.6% 2015 = 8.1% 2016 = 5.3%

• Iowa electric – Filed May 2013 – Approved by the Iowa Utilities Board July 2014 – Interim rates effective August 2013 – Base rate increase, new energy and transmission riders, rate equalization • Illinois electric – Filed December 2013 – Approved November 2014 – Annualized base increase of $16 million – Transmission rider for all transmission revenue requirement – Existing energy rider in place • South Dakota electric and gas – Filed August 2014 – Requests $4 million annualized increase; approval pending – Transmission and energy riders requested Rate Activity

• Stepped increase in annualized base rates totaling $135m- $45m through 2014; $45m at January 1, 2015, and January 1, 2016 • Energy adjustment clause – Recovery of change in retail fuel costs – Wholesale margins retained by MidAmerican Energy – Recovery of pre-tax change in production tax credits as they expire for wind in-service as of December 31, 2012 • Transmission rider – Recovery of MISO-billed costs Iowa Electric Rate Case

• 10-year equalization of rates among three current pricing zones • Revenue sharing mechanism – 80% sharing with customers on returns exceeding 11%, 100% sharing with customers on returns exceeding 14% • Customer share of revenue sharing retained by MidAmerican Energy and used to reduce rate base Iowa Electric Rate Case

• Forecast Iowa electric net plant with Wind VIII and IX – 58% of Iowa electric net plant subject to rate-making principles – 11.9% weighted average return on equity – 24 years weighted average remaining life Iowa Electric Net Plant Subject to Ratemaking Principles Annual Growth Rates: 2010 = 4.2% 2011 = 1.2% 2012 = 0.6% 2013 = 1.7% 2014 = 6.7% 2015 = 3.4% $5,196 58% $3,780 42% Forecast Iowa Electric Net Plant (millions) Subject to Rate Principles Subject to General Rate Order

Operational Capital Management • Operating capital varies with major generation outages and system requirements • Development capital varies with the completion of major initiatives: – Wind generation projects 2008 and 2011-2015 – Air quality environmental projects 2008 and 2012-2014 – Multi-value transmission projects 2014-2017 ($ millions) ($ Millions) 2015-2017 Current Plan Prior Plan Operating $ 1,103 $ 1,012 Development 1,374 1,124 Total $ 2,477 $ 2,136 MidAmerican Energy Capital Expenditures(1) (1) Capital expenditures are reported as incurred and accrued

• Wind VIII – IUB approval allows ROE of 11.625% for the life of the assets – $1.9b cost cap established – Construction of 44 MW (nominal ratings) was completed in 2013; 511 MW (nominal ratings) was completed in 2014 – Construction of the remaining 495 MW to be completed in 2015 – Turbine purchases and balance of plant under fixed-price contracts • Wind IX – IUB approval allows ROE of 11.5% for the life of the assets – $243m cost cap established – Construction of 162 MW (nominal ratings) to be completed in 2015 – Turbine purchases and balance of plant under fixed-price contracts Wind Expansion

• Projects delivered at a cost that provides significant value to customers due to: – Fixed rate credits to the energy adjustment clause of $3.3m, $6.6m and $10.0m in 2015, 2016 and 2017 and beyond, respectively, for Wind VIII and $2.0m for Wind IX – Production tax credits for 10 years from the in-service date for all projects – Low-cost generation in the future • MidAmerican Energy continues to evaluate additional wind generation opportunities in Iowa Wind Expansion

MidAmerican Energy Wind Resources (1) Net MW owned in operation and under development as of Dec. 31, 2014, net of interconnection limitations MW Total Cost ($ millions) 2004 161 $164 2005 200 225 2006 99 177 2007 201 389 2008 620 1,291 2011 594 960 2012 405 660 2013 44 66 2014 508 808 2015 625 1,077 Total 3,457 $5,817 Owned Wind Generation Capacity (1)

Environmental Respect – Wind Energy Global Leader “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.” 2010 Actual 20.0% 2011 Actual 23.1% 2012 Actual 34.0% 2013 Actual 37.9% 2014 Actual 39.6% 2015 Plan 46.0% 2016 Plan 50.9% MidAmerican Energy Wind Generation as a Percent of Retail Sales (1) – Governor Terry E. Branstad Iowa (1) Comparison is provided to show the relative size of wind generation capability and does not represent actual deliveries of wind energy to retail customers. 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.

• Distributed generation activities in Iowa – Iowa Utilities Board inquiry which is gathering information related to policy and technical issues: net metering, interconnection of DG, customer awareness and protection – Inquiry on avoided costs • MidAmerican Energy’s approach to distributed generation in Iowa – Focused on keeping costs low for all customers and avoiding cross-subsidization – Considering how to add solar generation options for customers Distributed Generation in Iowa

Iowa Typical Residential Summer Demand with 5 kWDC Solar DG System 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 K il o w at t Customer Demand 4am 8am 12pm 4pm 8pm 12am 100% Utility-Provided Power DG Peak 12-2 PM Customer Demand Peak 4-7 PM DG customer uses grid to export excess power 100% Utility-Provided Power Utility-Provided Power Utility-Provided Grid Services Utility and DG System-Provided Power 23.99 hours/day utility provides all grid services 9.5 hours/day both utility and DG system provides power 8 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

• By April 2016, nearly 700 MW of operated coal-fueled generation will be limited to natural gas or retired, resulting in 100% of coal-fueled generation capacity controlled with scrubbers, baghouses and mercury controls • Neal Unit 3 and Unit 4 and Ottumwa Generating Station scrubber and baghouse projects recently completed • Walter Scott Unit 3, Louisa, Neal Unit 3 and Neal Unit 4 activated carbon injection systems for mercury control are on track to be completed by April 2015 • Walter Scott Units 1 and 2 to be retired prior to April 15, 2015; Neal Units 1 and 2 to be retired prior to April 15, 2016 Environmental Position

• Anticipated future projects – Ash pond closures – Bottom ash dry handling – Cooling water intake structure retrofits for fish handling – Compliance with the Clean Power Plan • Projected environmental capital spend – $108m 2015-2017 – $364m 2018-2024 Environmental Position

• MidAmerican Energy ash ponds – Five ash ponds are located at facilities on the Missouri River; three ash ponds are located at facilities on the Mississippi River – All underground infrastructure that traverse ponds pose little risk of failure due to locations in dry areas of a pond, lack of direct connection to surface water, or use in maintaining pond levels prior to discharge – All ponds were ranked “low hazard” by EPA • Pond monitoring program – Implemented in 2011 – Includes information on maintenance history and appropriate operating and maintenance criteria to manage potential risk – Requires facilities to complete inspections, including • Quarterly visual inspections to review physical conditions • Annual structural integrity inspections • Periodic third-party engineering inspections Ash Ponds

EPA Coal Combustion Residuals Rule • EPA issued a Subtitle D, non-hazardous, final rule in December 2014 that covers active and inactive coal ash ponds and landfills • Existing landfills are largely grandfathered under the rule; new landfills and lateral expansions of existing landfills must be constructed with liners and leachate collection systems • There will be five active ash ponds, three inactive ash ponds and four active landfills affected by the rule • MidAmerican Energy is developing closure plans for the affected ponds and anticipates that closure activities will be completed between 2015 and 2020, which greatly mitigates any risk from this rule

Clean Power Plan • MidAmerican Energy is well positioned to meet the proposed emission requirements – Completed plant efficiency improvements – Wind expansions will count toward compliance – Long history with customer energy efficiency programs • No additional coal plant retirements expected • As proposed, do not anticipate significant impacts to customer rates • MidAmerican Energy continues to engage in state and federal efforts to shape the final Clean Power Plan, including implementation activities to ensure customers and costs are appropriately considered

• MidAmerican Energy is constructing portions of four 345-kV multi-value projects (MVP) within the MISO footprint, totaling approximately 245 miles; approved by the MISO board in December 2011 • Expenditures predominantly in 2014-2017, totaling approximately $472m, excluding equity AFUDC • MVPs are eligible for incentive rate treatment in MISO tariff, including construction work in progress in rate base and recovery of prudent costs incurred if projects are abandoned Transmission Development

• MVP revenue requirements broadly recovered from all MISO load; approximately 96% recovered from other MISO participants • MVP expected to provide multiple benefits, including improved reliability, reduced congestion and support for additional generation development • All transmission investments utilize forward-looking rate treatment in MISO tariff, mitigating rate lag Transmission Development

• BHE is committed to being an industry leader in enhancing security at its critical asset sites using current and emerging technologies • We have been investing to improve security – the focus in 2014 and 2015 has been hardening top-tier assets against cyber and physical attacks • We organize asset sites into categories based on operations criticality and projected security risk • To enhance overall security, we organized physical and cyber risk assessments with various federal agencies, the National Guard and state law enforcement agencies • We also benchmark with the industry and other industries to drive program excellence Industry Discussion – Physical Asset Security

• MidAmerican Energy executive leadership has U.S. security clearance and maintains close coordination with federal and state intelligence organizations for cyber and physical threats • MidAmerican Energy’s CEO serves on the Electric Subsector Coordinating Council, which is a forum for 18 industry CEOs to organize with senior U.S. and Canadian security officials • We actively meet with our various state regulators and stakeholders to communicate improvements, risk mitigation and any related costs, including enhanced cyber monitoring • MidAmerican Energy is piloting the CIP version 5 implementation for the industry and shaping the regulatory environment through engagement at FERC, NERC and the regional reliability organizations Industry Discussion – Physical Asset Security

2015 Fixed-Income Investor Conference Bill Fehrman President and CEO BHE Renewables

BHE Solar BHE Geothermal Geothermal Plants Natural Gas Plants BHE Wind BHE Hydro CalEnergy Philippines BHE Renewables

Solar Star Aerial View – February 2015 Helicopter landing pad SCE Whirlwind Substation Kern County Los Angeles County Solar Star 1 Solar Star 2 • 113

• Solar Star 1 and 2 will deliver 579 MWAC when complete • Located on over 4,000 acres in Kern and Los Angeles counties, California • 20-year power purchase agreement with Southern California Edison • Fixed-price engineering, procurement and construction agreements and 20-year operations and maintenance agreements executed with SunPower • The projects utilize 1.7 million SunPower monocrystalline silicon modules and single axis tracking technology • The Solar Star projects are approximately 99% complete, and 495 MW have achieved block substantial completion as of February 28, 2015 – The final two blocks (84 MW) are expected to be completed by June 2015, to support project substantial completion in July 2015, four months ahead of schedule • Through December 2014, revenue exceeded expectations; the plant continues to perform well • In March 2015, the Series B Senior Secured notes were issued for $325.0m at 3.95% Solar Star 1 and 2 Summary

Topaz Solar Farms Aerial View – Complete Legend Project & Stewardship Land

• Topaz Solar Farms was commissioned and commercial operations declared October 27, 2014; Topaz is delivering 550 MWAC • Located on 4,700 project acres in San Luis Obispo County, California • 25-year power purchase agreement with Pacific Gas and Electric Company • 25-year operations and maintenance agreement with First Solar • The project utilizes approximately 8.4 million First Solar fixed tilt, thin-film panels • Through December 2014, revenue exceeded expectations; the plant continues to perform well Topaz Solar Farms Summary

Agua Caliente Aerial View – Complete 500 kV Transmission Line Switchyard

• Agua Caliente was commissioned and commercial operations declared June 23, 2014, and is delivering 290 MWAC • The project is located on 2,340 acres in Yuma County, Arizona • BHE Solar is a 49% owner of the project • 25-year power purchase agreement with Pacific Gas and Electric Company • 25-year firm price operations and maintenance agreement with First Solar • The project uses approximately 4.95 million First Solar fixed tilt, thin-film panels • Through December 2014, revenue exceeded expectations; the plant continues to perform well Agua Caliente Summary

• 81 MW wind farm located in Henry County, approximately 20 miles southeast of Rock Island, Illinois • 50 General Electric 1.62 MW wind turbines • 20-year power purchase agreement with Ameren Illinois Company (Baa1/BBB+/BBB) • Commercial operation date – December 7, 2012 • Turbines are performing well • Currently meeting or exceeding operational and budgetary targets Bishop Hill II Wind

• 300 MW wind farm located in the Tehachapi/Mojave region of Kern County, California, approximately 75 miles north of Los Angeles • 100 Vestas 3.0 MW wind turbines • 23-year power purchase agreement with Southern California Edison Company (A2/BBB+/A) • Commercial operation date – January 1, 2013 • Turbines are performing well • Currently meeting availability targets Pinyon Pines Wind I and II

Jumbo Road Wind • On June 17, 2014, BHE Wind closed on the acquisition from Lincoln Renewable Energy, LLC of its 300 MW Jumbo Road wind project located in Castro County, Texas, near Amarillo • The project has an 18-year power purchase agreement with Austin Energy (AA/Aa2/AA-) • Construction progressed very well, and the project will be fully completed during second quarter 2015

Kingfisher Wind Tax Equity Investment • On January 21, 2015, BHE Wind closed on its tax equity investment for the 298 MW Kingfisher wind project located in Kingfisher County, Oklahoma, near Oklahoma City • The project is PTC-qualified and has a 20- year energy and renewable energy credit hedge with Morgan Stanley • The project has begun construction and is expected to be in-service by October 2015 • BHE Wind will fund its estimated $270m commitment when the project achieves commercial operation in October 2015 Kingfisher Project Location

BHE Geothermal • Operates 10 geothermal facilities in the Imperial Valley with a combined installed capacity of 338 MW • BHE Geothermal has been remarketing eight of its plants that are scheduled to come off contract between 2016 and 2020, totaling 287 MW • All plants have been included in a portfolio contract structure, enabling new customers to contract for portions of the generation portfolio – 203 MW of the portfolio has been contracted, leaving only 84 MW outstanding • Certain geothermal facilities have long-term power purchase agreements with Southern California Edison; following two successive five-year fixed price amendments, on May 1, 2012, these long-term power purchase agreements reverted back to Southern California Edison’s avoided cost of energy, which is correlated to the cost of natural gas; revenues are reduced due to the current low price for natural gas

• BHE Renewables is pursuing a diversified strategy for future development, including: – Direct ownership of utility-scale wind and solar assets with long-term offtake agreements – Development of the recently acquired 400 MW Grande Prairie wind project in Nebraska and the 74 MW Community Solar Gardens projects in Minnesota – Tax equity investment opportunities for hedged or contracted utility-scale wind and solar projects – Investments in solar distributed generation assets Renewables Opportunities

Questions

2015 Fixed-Income Investor Conference Mark Hewett President and CEO BHE Pipeline Group

• 850 employees • 14,700-mile interstate natural gas transmission pipeline system • Market Area design capacity of 5.7 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 73 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 961 Bcf over the prior three years – 986 Bcf in 2014 Northern Natural Gas Overview

• In February 2015, set a new market area monthly daily average delivery of 4.083 Bcf/day. Also, set new single-day market area delivery record of 4.891 Bcf/day on February 18, 2015 • In March 2015, set a new market area single-day delivery record for the month of March of 4.477 Bcf/day • In 2014, field area transportation revenue higher by 56% compared to 2013 and 67% compared to 2012 – Significantly higher revenue in 2014 due to impact from Polar Vortex – Approximately 52% of 2014 Field Area revenue from long-term contracts • Successfully renegotiated 0.3 Bcf/day of Market Area contracts at higher rates, increasing annual revenue by $0.9m • Market area expansions: – 2014 completed projects for CF Industries and other market area shippers for a total capital expenditure of $91m and annual revenue of $31m – Future expansions totaling $18m of capital expenditures and $9m of annual revenue • Permian expansions: – 2014 completed projects with $12m of capital and $8m of annual revenue – Future expansions totaling $66m of capital and $18m of annual revenue • Increased the integrity and reliability of the pipeline while managing operating costs and staffing • Working cooperatively with our customers on an asset modernization investment recovery mechanism Northern Natural Gas Business Update

• Reticulated system – economically unfeasible to replicate • Optionality with Field Area – tremendous advantage for customers and Northern Natural Gas to capture opportunities • Long-term contracts with stable markets • Northern Natural Gas’ prices are competitive with other pipelines (minimizes level of discounting needed in competitive markets) • Focus on customer satisfaction – In March 2015, Mastio & Company announced the results of their annual survey; Northern Natural Gas ranked No. 1 among mega-pipelines and No. 2 out of 41 interstate pipelines in customer satisfaction Northern Natural Gas Competitive Advantages

• 90% of revenue is from demand charges • 60% of 2014 transportation and storage demand revenue was from investment-grade utilities • In 2014, completed approximately 0.3 Bcf/day in contract renewals with a 3% increase in rates, which provides additional $0.9m in annual revenue • 82% of 2014 storage revenue resulted from long-term contracts, with an average remaining contract life of approximately seven years  Northern Natural Gas currently contracts 100% of its firm storage service annually • Long-term contracts with creditworthy counterparties – top 10 customer groups have a weighted average credit rating of A3/BBB+ Northern Natural Gas Revenue Stability and Long Term Contracts Transportation - Market 74% Transportation - Field 16% Storage 10% 2015-2016 16% 2017-2018 44% 2019-2020 28% 2021-2022 2% 2023+ 10% Average remaining contract life of approximately 4.5 years 2014 Transportation and Storage Revenue $618 Million Market Area Transportation Contract Maturities (1) (1) Based on maximum daily quantities of market area entitlement in decatherms as of Dec. 31, 2014

• 2014 Market Area Expansions – Total capital expenditures of approximately $91m, serving fertilizer plant expansions, Minnesota LDCs and municipalities – Incremental entitlement of 163,929 Dth/day – Annual demand revenues of $31m, with contract terms from 5 to 11 years • Future Market Area Expansions – Total capital expenditures of approximately $18m, serving LDCs, ethanol and other industrial needs – Incremental entitlement of 65,100 Dth/day (some volumes are being served with existing capacity) – 2016 in-service with annual demand revenues of $9m and average contract term of 5 years • 2014 Field Area Expansions – Total capital expenditures of approximately $12m, serving supply fields in the Permian basin – Incremental entitlement of 158,000 Dth/day – Annual demand revenues of $8m, with contracts expiring in 2019 • Future Field Area Expansions – Total capital expenditures of approximately $66m, serving power plant expansions – Incremental entitlement of 352,000 Dth/day – 2016-2017 in-service with annual demand revenues of $18m and contracts expiring in between 2021-2027 Northern Natural Gas Expansion Projects

• Shale development is supportive of gas demand due to low supply prices • Change in gas flow patterns is occurring across the U.S. • Marcellus shale displacement of the south-central area should result in the softening of Field Area supply prices • Since 2011, the pipeline has connected over 1,595,000 Dth/day of supply access from Wolfberry shale formation and Granite Wash tight sands formation • Finalizing plans for additional supply of 400,000 Dth/day from Wolfberry in 2015 Northern Natural Gas Shale Gas Opportunities

• $1.1b of maintenance capital expenditures since last rate case • Significant maintenance capital expenditures above representative level of depreciation expected throughout 10- year plan • Growth projects and cost-control initiatives have allowed us to carry incremental maintenance capital expenditures to this point • Future incremental maintenance capital expenditures will be recognized in rates • Cost recovery options consist of either a traditional rate case or a limited cost-recovery mechanism specific to incremental maintenance capital expenditures Northern Natural Gas Asset Modernization Program

Northern Natural Gas Alternative Methods To Address Asset Modernization Costs Rate Case Asset Modernization Investment Recovery • Multiple rate cases would be required due to the staged investment through 2024 • Rate case would reflect asset modernization costs plus $550m of past investment not reflected in rates • A rate case would require multiple issues to be addressed: - Market, field, storage - Billing units determination - Market/field cost allocation and required rate design change - Higher depreciation expense - Increased costs for asset retirement obligation • Potential extended proceedings - Single Kern River rate case – 11 years and counting • Narrowly tailored solution to address incremental investment • Single-issue item • Minimizes rate impact • Limits impact to Market Area • Consistent with proposed FERC policy

• Modernize up to $450m of Market Area pipeline, compression and LNG assets • Facilities to be installed or retired from 2016 through 2024 • Asset modernization investment recovery to be assessed beginning in 2017 • Cost of service to derive rate will reflect: – 9.4% after-tax return on capital invested, net of deferred tax benefit – Depreciation expense, including credit for depreciation savings on retired plant • Rate is recalculated annually reflecting cost of service on plant placed in-service in prior year • Capital investment will be reflected in the next general rate case, and the rate mechanism will terminate Northern Natural Gas Proposal – Asset Modernization Investment Recovery

Kern River Gas Transmission Overview • Headquartered in Salt Lake City, Utah • 158 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 98% of capacity contracted under long-term contracts CALIFORNIA UTAH WYOMING ARIZONA NEVADA

• Continue to sell available firm capacity long-term at rates above market value – Limited amount of un-contracted firm capacity – Value of capacity is projected to increase more than 50% over the next three years • $0.25/Dth/day in 2016 to $0.38/Dth/day in 2018 • Provide a competitive delivered cost to southern California and southern Nevada • Growth of natural gas-fueled electric generation in the Southwest U.S. and Mexico increases demand for U.S. pipeline capacity and provides incremental opportunity for Kern River • 2014 scheduled throughput averaged 107% of design capacity • Kern River 2004 rate case update Kern River Gas Transmission Business Update

Kern River Gas Transmission Competitive Advantage • Kern River’s Period Two rates are the lowest delivered cost interstate pipeline options to southern California • Kern River is directly connected to end-use markets in Nevada and California – Avoids rate stack • State of the art transmission system • Limited incremental cost to comply with stricter pipeline safety standards • Exceptional customer service – In March 2015, Mastio & Company announced the results of their annual survey; Kern River ranked No. 1 out of 41 interstate pipelines in customer satisfaction – Kern River has been No.1 in five of the last seven years and No. 2 in the other two years

Demand 94% Market- Oriented 4% Other 2% (1) Based on total system design capacity of 2.2 million Dth per day Kern River Gas Transmission Revenue Stability and Long Term Contracts Contract Maturities(1) • 94% of revenue is from demand charges • 98% of capacity is committed to contracts that expire after 2015 • Weighted average contract term of five years • Weighted average shipper rating of BBB+/Baa1 • Shippers that do not meet credit standards are required to post collateral 2014 Revenue Distribution $354 Million Uncontracted 1% 2016 31% 2017-2018 42% 2019-2020 4% 2021-2022 1% 2023+ 20% 2015 1%

Kern River Gas Transmission Strong Demand for Services Daily Average Scheduled Volume 2014 Deliveries by State (1) Based on the 2014 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. • Delivered approximately 23%(1) of California’s demand for natural gas in 2013 • Received 28% of Rockies natural gas supply in 2014 • Delivered more than 78%(2) of southern Nevada’s natural gas • During 2014, scheduled throughput averaged 107% of design capacity 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 2007 2008 2009 2010 2011 2012 2013 2014 Sched Design

Kern River Gas Transmission Long-Term Business Outlook Non-Coincident Peak Day Deliveries (Dth/d)(1) Utah LDC (Questar Gas) 504,717 Direct-connect end-users 24,156 528,873 Nevada LDC (Southwest Gas) 504,203 Direct-connect end-users 520,912 1,025,115 California LDC (Southern California Gas) 0 Direct-connect end-users 191,602 191,602 Total 1,745,590 (81% of Kern River capacity) • Questar Gas has multiple interconnects with Questar Pipeline but relies on Kern River to provide peak-day deliveries • Kern River is the sole transporter of natural gas to southern Nevada, with the exception of 141,000 Dth/day of capacity on Southwest Gas’ southern system • Southern California Gas has other pipeline or storage options on a peak day; however, direct- connect end-users rely on Kern River Markets are Dependent on Kern River (1) Based on actual peak day deliveries over the past three years and an analysis of the LDCs’ pipeline supply options

Kern River Gas Transmission Market Competitive Period Two Rates • Kern River has 638,070 Dth/d of capacity under contracts that expire in 2016 • Shippers can extend service for this capacity at rates that are below the current prospective value for Kern River capacity

Lowest-Cost Option to Southern California

Questions

2015 Fixed-Income Investor Conference Phil Jones President and CEO Northern Powergrid Holdings Company

Northern Powergrid – Wires-Only Distributor Distribution business comparison Licenses End-Users (millions) Revenue (£millions) RAV (£millions) Western Power Distribution 4 7.8 1,501 5,911 UK Power Networks 3 7.9 1,354 5,432 Northern Powergrid 2 3.9 694 2,659 SSE 2 3.7 876 3,205 Scottish Power 2 3.5 740 3,019 ENW 1 2.4 469 1,672 All data twelve-months ended March 31, 2014, financial data based on Ofgem’s final proposals for DPCR5 • One of six electricity distribution groups in Great Britain • Stable inflation protected revenues and cash flows • Key statistics include: – 725 major substations – 58,000 miles of circuit – 10,000 square miles of service area – 2,500 employees

Strong Investment Metrics • Return on regulatory equity exceeds expectations • 42% growth in regulated asset value in DPCR5, primarily financed by operating cash flows • Inflation protection applies to revenue and regulated asset value (RAV) – averaging 3.2% per year since April 2007 • Operating income remains strong, reflecting revenue growth • Strong credit ratings compare well with the rest of the sector Years Ended Dec. 31, (£ millions) - US GAAP 2014 2013 2012 Revenues 780 657 653 Operating income 409 323 357 Capex 411 431 286 RAV 2,776 2,660 2,504 Interest cover 4.4x 3.9x 4.3x Debt to RAV gearing 56% 56% 55% Ofgem’s DPCR5 final proposals for the 2010-15 period included growth for revenue and RAV – 7% underlying (real) revenue growth – 4% underlying (real) growth in RAV – RAV growth supplemented by 3.2% per year inflation from April 2007

• During 2014, we closed out a successful DPCR5 period: – Effective cost control in an inflation-protected settlement created strong returns – Exceeded our output delivery and delivered our biggest ever capital program – Progressively improved reliability, outperforming our targets (for DPCR5 and RIIO- ED1) – Customer service is improving, performance is ahead of RIIO-ED1 target • We saw the completion of Ofgem’s RIIO-ED1 decision-making: – A step-change in efficiency rankings between fast-track and Final Determination created very different outcomes across the sector – Outcomes for customers across the country are very inconsistent – We have appealed Ofgem’s decision in our case – British Gas has also appealed the price control of all five of the slow-track DNOs • We are preparing for transition into the new price control period: – We expect to spend our allowances in full, targeting improvement in our outputs – The incentive mechanisms, especially IIS, offer additional upside opportunity – We intend to dividend a modest amount back to BHE to move our capital structure closer to Ofgem’s notional gearing (at a consolidated Northern Powergrid level) Price Control Overview

Our delivery track record gives us confidence of success in meeting the RIIO-ED1 challenge ED1 DPCR5 Ofgem’s view of allowed costs (vs company submission) -7% -10% Cost savings (vs Ofgem allowances) 0% 8% Outputs delivered >100% 116% 2014/15 reliability performance (vs Ofgem targets) +11% +26% RORE: Allowed 8.7% 9.4% RORE: Actual 15.0%

Our recommended remedies would close around £100m of the gap between our plan and Ofgem’s assessment • We support the general direction of Ofgem’s new RIIO regime – It is the first time that we have not accepted our price control settlement in full – It is also the first price control appeal in the new appeals mechanism for energy • Our appeal relates to three specific flaws in the determination: – Ofgem’s decision to demand further cost savings in relation to smart grid technology over and above the ones captured by its original benchmarking exercise – Ofgem’s assessment of the variation in wage rates across the country overstates the extent to which wages differ in different regions – Ofgem’s projections for labor cost increases assume significantly below-inflation pay deals for a skilled workforce that is growing to meet customer demand and the need for greater investment in the network • If the CMA adjusts the settlement as we have asked, less than half of the ‘total cost gap’ between us and Ofgem will be reinstated • The impact would be approximately £10m per year to spend on improved outputs • The process has to complete within 2015 – so we will know our outcome this year

Outlook for the RIIO-ED1 Price Control Period 2015-2023 • Public policy reflects growing political pressure on energy affordability – The outcome of the U.K. election will influence regulatory and energy policy – Competition and Markets Authority review of the energy supply market is high profile but seems less likely to impact regulated networks – The two appeals of the ED1 decision are unlikely to change the landscape in the near-term but could influence Ofgem’s approach to price controls in the long-term • We remain optimistic about the next price control period – We remain able to reinvest earnings in the network to improve outputs and generate strong internal growth – Operating performance is trending positively – we are already ahead of or in-line with ED1 targets – Our strong cost control focus supports the cost and output improvement drive – Realignment of capital structure will mitigate some of the lost return arising from conservative gearing levels and the lower cost of debt allowance

Questions

2015 Fixed-Income Investor Conference Greg Abel Chairman, President and CEO Berkshire Hathaway Energy

Berkshire Hathaway Energy Our Vision To be the best energy company in serving our customers, while delivering sustainable energy solutions Core Principle Be The Best Objectives Customer Service Best customer service Deliver top decile customer satisfaction levels relative to industry peers Employee Commitment Best people – best safety environment Achieve an industry-leading incident rate and have the best people and leaders in the industry Environmental Respect Great stewards of the environment Deliver a more sustainable environment by reducing the intensity of our emissions Regulatory Integrity Respected by our regulators Engage our stakeholders to develop value propositions that minimize or reduce the impact to our customers’ rates Operational Excellence Most efficient and effective operator Accomplish top decile in generation and pipeline asset performance; top quartile in transmission and distribution asset performance Financial Strength Achieve financial commitments and reinvest in assets Deliver strong financial performance for our stakeholders

Questions

Appendix

Berkshire Hathaway Energy Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Adjusted Interest divided by Adjusted Interest (2) Debt includes short-term debt, Berkshire Hathaway Energy senior debt, Berkshire Hathaway Energy subordinated debt and subsidiary debt (including current maturities) (3) FFO to Adjusted Debt 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 2014 2013 2012 Net cash flows from operating activities 5,146$ 4,669$ 4,327$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 1,170 (449) (40) FFO 6,316$ 4,220$ 4,287$ Adjusted Interest Interest expense 1,711$ 1,222$ 1,176$ Interest expense on subordinated debt (78) (3) - Adjusted Interest 1,633$ 1,219$ 1,176$ FFO Interest Coverage(1) 4.9x 4.5x 4.6x Adjusted Debt Debt(2) 40,094$ 32,244$ 21,622$ Subordinated debt (3,794) (2,594) - Adjusted Debt 36,300$ 29,650$ 21,622$ Acquisition Financing Debt (1,500) (2,000) - Acquisition Subsidiary Debt (4,007) (5,296) - Adjusted Debt Excluding Acquisition Related Debt 30,793$ 22,354$ 21,622$ FFO to Adjusted Debt Excluding Acquisition Related Debt(3) 20.5% 18.9% 19.8% Capitalization Total Berkshire Hathaway Energy shareholders’ equity 20,442$ 18,711$ 15,742$ Adjusted debt 36,300 29,650 21,622 Subordinated debt 3,794 2,594 - Noncontrolling interests 131 105 168 Capitalization 60,667$ 51,060$ 37,532$ Adjusted Debt to Total Capitalization(4) 59.8% 58.1% 57.6%

Berkshire Hathaway Energy Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Adjusted Interest divided by Adjusted Interest (2) Debt includes short-term debt, Berkshire Hathaway Energy senior debt, Berkshire Hathaway Energy subordinated debt and subsidiary debt (including current maturities) (3) FFO to Adjusted Debt equals FFO divided by Adjusted Debt ($ millions) Pro Forma Pro Forma BHE AltaLink Adjustments Total FFO 2014 2014 2014 2014 Net cash flows from operating activities 5,146$ 214$ (85)$ 5,275$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 1,170 (17) 31 1,184 FFO 6,316$ 197$ (54)$ 6,459$ Adjusted Interest Interest expense 1,711$ 157$ 78$ 1,946$ Interest expense on subordinated debt (78) (39) (117) Adjusted Interest 1,633$ 157$ 39$ 1,829$ FFO Inter st Coverage(1) 4.5x Adjusted Debt Debt(2) 40,094$ 40,094$ Subordinated debt (3,794) (3,794) Adjusted Debt 36,300$ 36,300$ FFO to Adjusted Debt(3) 17.8%

Berkshire Hathaway Energy Non-GAAP Financial Measures ($ millions) BHE and AltaLink Pro Forma EBITDA for the year ended Dec. 31, 2014 Berkshire Hathaway Energy EBITDA As Reported Pro Forma Adjustments Pro Forma Combined Net income attributable to BHE 2,095$ 60 2,155 Noncontrolling interests 27 - 27 Interest expense 1,711 235 1,946 Capitalized interest (89) (1) (90) Income tax expense 589 (2) 587 Depreciation and amortization 2,057 117 2,174 EBITDA 6,390$ 409$ 6,799$

PacifiCorp Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2014 2013 2012 Net cash flows from operating activities 1,570$ 1,553$ 1,627$ +/- Changes in other operating assets and liabilities 10 (34) (169) FFO 1,580$ 1,519$ 1,458$ Interest expense 379$ 379$ 380$ FFO Interest Coverage(1) 5.2x 5.0x 4.8x Debt (2) 7,073$ 6,877$ 6,861$ FFO to Debt(3) 22.3% 22.1% 21.3% Capitalization PacifiCorp shareholders’ equity 7,756$ 7,787$ 7,644$ Debt 7,073 6,877 6,861 Capitalization 14,829$ 14,664$ 14,505$ Debt to Total Capitalization(4) 47.7% 46.9% 47.3%

MidAmerican Energy Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2014 2013 2012 Net cash flows from operating activities 823$ 735$ 1,276$ +/- Changes in other operating assets and liabilities 235 151 (323) FFO 1,058$ 886$ 953$ Interest expense 174$ 151$ 143$ FFO Interest Coverage(1) 7.1x 6.9x 7.7x Debt (2) 4,106$ 3,552$ 3,259$ FFO to Debt(3) 25.8% 24.9% 29.2% Capitalization MidAmerican Energy shareholder's equity 4,250$ 3,845$ 3,635$ Debt 4,106 3,552 3,259 Capitalization 8,356$ 7,397$ 6,894$ Debt to Total Capitalization(4) 49.1% 48.0% 47.3%

Nevada Power Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2014 2013 2012 Net cash flows from operating activities 704$ 548$ 702$ +/- Changes in other operating assets and liabilities 95 (19) (29) FFO 799$ 529$ 673$ Interest expense 208$ 215$ 215$ FFO Interest Coverage(1) 4.8x 3.5x 4.1x Debt (2) 3,576$ 3,577$ 3,337$ FFO to Debt(3) 22.3% 14.8% 20.2% Capitalization Total shareholder's equity 2,888$ 2,890$ 2,922$ Debt 3,576 3,577 3,337 Capitalization 6,464$ 6,467$ 6,259$ Debt to Total Capitalization(4) 55.3% 55.3% 53.3%

Sierra Pacific Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2014 2013 2012 Net cash flows from operating activities 246$ 226$ 197$ +/- Changes in other operating assets and liabilities 5 16 78 FFO 251$ 242$ 275$ Interest expense 61$ 62$ 65$ FFO Interest Coverage(1) 5.1x 4.9x 5.2x Debt (2) 1,200$ 1,200$ 1,179$ FFO to Debt(3) 20.9% 20.2% 23.3% Capitalization Total shareholder's equity 998$ 1,016$ 1,039$ Debt 1,200 1,200 1,179 Capitalization 2,198$ 2,216$ 2,218$ Debt to Total Capitalization(4) 54.6% 54.2% 53.2%

Northern Natural Gas Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2014 2013 2012 Net cash flows from operating activities 297$ 264$ 304$ +/- Changes in other operating assets and liabilities 31 41 (27) FFO 328$ 305$ 277$ Interest expense 45$ 44$ 52$ FFO Interest Coverage(1) 8.3x 7.9x 6.3x Debt (2) 899$ 899$ 899$ FFO to Debt(3) 36.5% 33.9% 30.8% Capitalization Northern Natural Gas shareholder’s equity 1,330$ 1,360$ 1,290$ Debt 899 899 899 Capitalization 2,229$ 2,259$ 2,189$ Debt to Total Capitalization(4) 40.3% 39.8% 41.1%

Kern River Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2014 2013 2012 Net cash flows from operating activities 214$ 220$ 249$ +/- Changes in other operating assets and liabilities 8 2 (1) FFO 222$ 222$ 248$ Interest expense 31$ 36$ 41$ FFO Interest Coverage(1) 8.2x 7.2x 7.0x Debt (2) 467$ 548$ 628$ FFO to Debt(3) 47.5% 40.5% 39.5% Capitalization Partners’ capital 818$ 829$ 880$ Debt 467 548 628 Capitalization 1,285$ 1,377$ 1,508$ Debt to Total Capitalization(4) 36.3% 39.8% 41.6%

Northern Powergrid Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization (£ millions) FFO 2014 2013 2012 Net cash flows from operating activities 336£ 321£ 260£ +/- Changes in other operating assets and liabilities 54 (27) 65 FFO 390£ 294£ 325£ Interest expense 91£ 90£ 88£ FFO Interest Coverage(1) 5.3x 4.3x 4.7x Debt (2) 1,613£ 1,540£ 1,482£ FFO to Debt(3) 24.2% 19.1% 21.9% Capitalization Northern Powergrid shareholders’ equity 2,108£ 1,831£ 1,608£ Debt 1,613 1,540 1,482 Noncontrolling interests 37 34 33 Capitalization 3,758£ 3,405£ 3,123£ Debt to Total Capitalization(4) 42.9% 45.2% 47.5%

Debt Maturities As of December 31, 2014 Long-Term Debt Maturities(1) (1) Excludes capital leases ($ millions) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Berkshire Hathaway Energy -$ -$ 400$ 1,000$ -$ 350$ -$ -$ 500$ -$ PacifiCorp 132 57 52 586 350 38 420 605 449 591 MidAmerican Funding 426 34 254 350 500 - - - 314 335 NV Energy 250 660 - 823 500 315 - - 250 - Northern Natural Gas 100 - - 200 - - 200 - - - Kern River 85 191 62 129 - - - - - - BHE Renewables 121 168 172 179 463 92 96 90 89 94 AltaLink 78 129 - 172 172 280 - 237 430 301 Northern Powergrid - - - 62 62 528 - 547 - - 1,193$ 1,239$ 939$ 3,502$ 2,047$ 1,603$ 716$ 1,478$ 2,032$ 1,321$

Long-Term Debt Summary As of December 31, 2014 Consolidated Berkshire Hathaway Energy Wt. Avg. Wt. Avg. $ (millions) Coupon Life (Years) (1) Berkshire Hathaway Energy - Parent 7,860 5.14% 16.0 MidAmerican Funding 4,345 4.39% 13.4 PacifiCorp 7,089 4.94% 14.6 NV Energy 5,138 5.81% 11.0 Northern Natural Gas Company 899 4.90% 13.6 Kern River Gas Transmission Company 467 5.53% 2.0 Northern Powergrid(2) 2,334 6.26% 11.7 AltaLink(3) 3,756 4.28% 18.6 BHE Renewables 2,967 5.42% 10.4 Total Berkshire Hathaway Energy Long-Term Debt 34,855 5.09% 14.3 Berkshire Hathaway Energy - Parent Junior Subordinated Debentures 3,794 3.00% 29.4 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 3,852 3.08% 29.4 Total Berkshire Hathaway Energy Long-Term Securities 38,707 4.89% 15.8 (1) Weighted average life assumes perpetual preferred stock has an average life of 30 years (2) USD to GBP exchange rate at $1.5573/pound (3) CAD to USD exchange rate at $1.1621/USD

Jurisdictional Strength – Unemployment Rates

Retail Load (Weather Normalized)

.01% A3/BBB+/BBB+ Aa2/AA/A+ 90% BHE Canada Holdings Corp AltaLink Holdings, L.P. (AHLP) AltaLink Investments, L.P. (AILP) (S&P: BBB- ; DBRS: BBB) AltaLink, L.P. (ALP) (S&P: A- ; DBRS: A) AltaLink Management Ltd (AML) (General Partner) 99.99% 99.99% 99.99% AltaLink Investment Management Ltd (AIML) (General Partner) Note: The above ownership structure is a high-level summary and does not include all entities that are part of the transaction structure AltaLink Ownership Structure