Berkshire Hathaway Energy A Berkshire Hathaway Company
Forward-Looking Statements This presentation contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon Berkshire Hathaway Energy Company (BHE) and its subsidiaries, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries or Sierra Pacific Power Company and its subsidiaries (collectively, the Registrants), as applicable, current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others: – general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective Registrant's operations or related industries; – changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition; – the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner; – changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers; – performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions; – the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts; – a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations; – changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs; – the financial condition and creditworthiness of the respective Registrant's significant customers and suppliers; – changes in business strategy or development plans; – availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates; – changes in the respective Registrant's credit ratings; – risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
Forward-Looking Statements – hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings; – the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts; – the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates; – fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar; – increases in employee healthcare costs; – the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements; – changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions; – the ability to successfully integrate future acquired operations into a Registrant's business; – unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions; – the availability and price of natural gas in applicable geographic regions and demand for natural gas supply; – the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and – other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the United States Securities and Exchange Commission (SEC) or in other publicly disseminated written documents. Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants’ filings with the SEC. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive. This presentation includes certain non-Generally Accepted Accounting Principles (GAAP) financial measures as defined by the SEC’s Regulation G. Refer to the BHE Appendix in this presentation for a reconciliation of those non-GAAP financial measures to the most directly comparable GAAP measures.
Calvin Haack Vice President and Treasurer Berkshire Hathaway Energy
Energy Assets Assets $92 billion Revenues $19.8 billion Customers(1) 8.8 million Employees 23,000 Transmission Line 33,600 Miles Natural Gas Pipeline 16,400 Miles Power Capacity 33,676 MW(2) Renewables 40% Natural Gas 32% Coal 27% Nuclear and Other 1% (1) Includes both electric and natural gas customers and end-users worldwide. Additionally, AltaLink serves approximately 85% of Alberta, Canada’s population (2) Net MW owned in operation and under construction as of December 31, 2018
Berkshire Hathaway Energy Vision To be the best energy company in serving our customers, while delivering sustainable energy solutions Culture Personal responsibility to our customers Strategy Reinvest in our businesses Invest in internal growth • Continue to invest in our employees and • Pursue the development of a value-enhancing operations, maintenance and capital programs energy grid and gas pipeline infrastructure for property, plant and equipment • Create customer solutions through innovative • Position our regulated businesses to meet rate design and redesign changing customer expectations and retain • Grow our portfolio of renewable energy customers (reduce bypass risk) by providing excellent service and competitive rates • Develop strong grid systems, including cybersecurity and physical resilience programs • Reduce the carbon footprint of our operations by participating in energy policy development, resulting in the transformation of our businesses and assets Acquire companies • Advance grid resilience, cybersecurity and • Additive to business model physical security programs Competitive Advantage Berkshire Hathaway ownership
Competitive Advantage • Diversified portfolio of regulated assets – Weather, customer, regulatory, generation, economic and catastrophic risk diversification • Berkshire Hathaway ownership – Access to capital from Berkshire Hathaway allows us to take advantage of market opportunities – Berkshire Hathaway is a long-term owner of assets which promotes stability and helps make Berkshire Hathaway Energy the buyer of choice in many circumstances – Tax appetite of Berkshire Hathaway has allowed us to receive significant cash tax benefits from our parent of $884 million and $636 million in 2018 and 2017, respectively • No dividend requirement – Cash flow is retained in the business and used to help fund growth and strengthen our balance sheet
Diversity in Our Portfolio Berkshire Hathaway Energy’s regulated energy businesses serve customers and end-users across 18 western and Midwestern states in the U.S. and in the U.K. and Canada Our integrated utilities serve approximately 4.9 million customers; Northern DISTRIBUTION Powergrid has 3.9 million end-users, making it the third-largest distribution company in Great Britain We own significant transmission infrastructure in 15 states and the province TRANSMISSION of Alberta; with our assets at PacifiCorp, NV Energy and AltaLink, we are the largest transmission owner in the Western Interconnection BHE Pipeline Group transported approximately 8% of the total natural gas PIPELINES consumed in the United States during 2018 We own 33,676 MW of power capacity in operation and under construction, GENERATION with resource diversity ranging from natural gas and coal to renewable sources As of December 31, 2018, we had invested $25 billion in solar, wind, RENEWABLES geothermal and biomass generation
Revenue and Net Income Diversification • Diversified revenue sources reduce regulatory concentrations • In 2018, approximately 84% of adjusted net income was from investment-grade regulated subsidiaries. A significant portion of the remaining non-regulated adjusted net income is from contracted generation assets at BHE Renewables 2018 Energy Revenue(1) 2018 Adjusted Net Income(2) $16 Billion $2.8 Billion Other HomeServices Alberta 4% BHE 5% Nevada 5% Renewables 19% United 11% PacifiCorp Kingdom 24% 7% BHE FERC Transmission 8% 7% Idaho 2% Washington Iowa 2% 18% BHE Pipeline Illinois Group 4% 13% California 5% MidAmerican Funding Wyoming Northern 22% 5% Powergrid Oregon Utah 8% NV Energy 7% 14% 10% (1) Excludes HomeServices and equity income, which add further diversification (2) Percentages exclude Corporate/other
Building a Culture of Sustainability • Address long-term issues, risks and opportunities through a comprehensive sustainability lens, aligned with our vision and core principles • Align with the objectives of providing safe, reliable and affordable clean energy • Committed and supportive leadership and owners • Committed and engaged employees • Renewables expansion • Carbon reduction efforts Environmental • Environmental Respect Index • Methane reduction • Species protection • Green bonds • BHE CARES – Global Giving • Veterans Engagement and Social and Volunteering Retention Network • Customer First • Diversity and Inclusion Policy • Berkshire Hathaway Energy • Financial planning process Code of Business Conduct • Strategic repositioning Governance • Berkshire Hathaway Inc. Ethics and Compliance Policy
Support a Cleaner Energy Future $30 Billion Renewable Commitment $31.4 ($ billions) $3.3 $24.8 $0.9 $1.9 $0.9 $6.5 $6.5 Remaining capital to be deployed • $5.2 billion – Wind development and repowering • $1.4 billion – Wind tax equity funding $20.7 $15.5 Wind Solar Geothermal and Other Wind Tax Equity 2018A Net Owned Operating Capacity (MW) 2022E December 2018 December 2020 Wind Solar Other Wind Solar Other PacifiCorp 1,030 - 32 1,980 - 32 MidAmerican Energy 5,158 - - 6,598 - - NV Energy - 15 5 - 15 5 BHE Renewables 1,665 1,536 338 1,665 1,536 338 7,853 1,551 375 10,243 1,551 375 • In addition to owned renewable capacity, Berkshire Hathaway Energy’s regulated utilities have renewable energy power purchase agreements for more than 4,100 MW. NV Energy plans to purchase approximately 1,400 MW of additional solar energy and PacifiCorp plans to purchase approximately 1,000 MW of additional wind and solar energy
Asset Profile • Berkshire Hathaway Energy is growing its renewable energy portfolio and continues to de-risk its balance sheet as it relates to carbon-based generation assets. In 2018, only 9% of our overall net investment in property, plant and equipment was invested in coal generation assets, while 7% was invested in natural gas generation assets Net PP&E as of December 31, 2018 Berkshire Hathaway Energy Renewables, T&D and Other 84% Natural Gas Generation 7% Coal Generation 9% PacifiCorp MidAmerican Energy Nevada Power Sierra Pacific 79% 70% 87% 66% 9% 34% 21% 12% 5% 16% 1% 0%
Generation Diversification 2006 BHE Power Capacity – 16,386 MW 2018 BHE Power Capacity – 33,676 MW Geothermal Coal Geothermal Hydro1% 27% 3% Coal 4% Total Hydro 58% 8% Solar Renewables 5% 16% Total Wind Renewables 5% 40% Nuclear and Other Natural Gas 3% Wind 32% 30% Natural Gas 23% Nuclear and Other 1% 2006 BHE Power Generation – 83 TWh 2018 BHE Power Generation – 122 TWh Geothermal Coal Geothermal Coal Hydro 2% 45% Total 5% 3% (1) Hydro 74% Renewables Solar 12% 5% Total 3% Wind Renewables(1) 2% 26% Wind Nuclear and 18% Other 5% Natural Gas 9% Nuclear and Other 3% Natural Gas 26% • In 2006, Berkshire Hathaway Energy acquired PacifiCorp. Since this acquisition, we have significantly changed our generation mix by growing our renewable portfolio of assets (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, or (b) sold to third parties in the form of RECs or other environmental commodities
Berkshire Hathaway Ownership is Unique to the Utility Industry • Our support is explicit from our Aa2/AA rated parent – We are not like any other utility holding company. Our balance sheet and credit strength are supported by a strong owner with over $100 billion of cash liquidity, as of December 31, 2018 – We do not pay dividends, which allows us to continue to grow the business and maintain credit quality – We retain more dollars of earnings than any other U.S. electric utility As of December 31, 2018 Adjusted Retained Common Dividend Net Income to Adjusted Common Earnings as % of Adjusted ($ in millions) Common(1) Earnings(1) Dividend(1) per day Earnings Market Cap(2) Berkshire Hathaway Energy: 2018 Actual$ 2,568 $ 2,817 $ - $7.7 0% Privately Held Peer Group Comparison: NextEra Energy$ 6,638 $ 3,673 $ 2,101 $4.3 57%$ 83,086 Duke Energy 2,666 3,339 2,471 2.4 74% 62,740 Southern Company 2,226 3,128 2,425 1.9 78% 45,404 Exelon Corporation 2,010 3,026 1,332 4.6 44% 43,665 Dominion Energy 2,447 2,651 2,185 1.3 82% 48,664 American Electric Power 1,924 1,945 1,251 1.9 64% 36,865 Sempra Energy 924 1,503 877 1.7 58% 29,619 Public Service Enterprise 1,438 1,582 910 1.8 58% 26,233 Xcel Energy Inc. 1,261 1,261 730 1.5 58% 25,327 Consolidated Edison, Inc. 1,382 1,349 842 1.4 62% 24,544 Peer Median 1,967 2,298 1,292 1.9 60% (1) As reported by company public filings (2) Calculated using reported shares outstanding on each respective balance sheet for the period ending December 31, 2018, per S&P Capital IQ
Berkshire Hathaway Energy Financial Summary • Since being acquired by Berkshire Hathaway in March 2000, Berkshire Hathaway Energy has realized significant growth in its assets, net income and cash flows Property, Plant and Equipment (Net) BHE Shareholders’ Equity ($ billions) ($ billions) $29.6 $75.0 $68.6 $28.2 $62.5 $65.9 $30.0 $24.3 $60.0 $24.0 $45.0 $18.0 $30.0 $12.0 $15.0 $6.5 $6.0 $1.7 $0.0 $0.0 2001 2016 2017 2018 2001 2016 2017 2018 Net Income Attributable to BHE Cash Flows From Operations ($ billions) (2) ($ billions) (1) $3.0 $2.8 $8.0 $2.5 $2.6 $6.8 $2.4 $6.1 $6.1 $6.0 $1.8 $4.0 $1.2 $0.6 $2.0 $0.1 $0.8 $0.0 $0.0 2001 2016 2017 2018 2001 2016 2017 2018 (1) Adjusted net income in 2017 of $2.6 billion excludes a $516 million benefit as a result of 2017 Tax Reform, and a charge of $263 million from tender offers for certain long-term debt completed in December 2017. Including the impact of these adjustments, 2017 reported net income was $2.9 billion (2) Adjusted net Income in 2018 of $2.8 billion excludes a $134 million benefit as a result of 2017 Tax Reform, and an after-tax unrealized loss of $383 million related to our investment in BYD. Including the impact of these adjustments, 2018 reported net income was $2.6 billion
Berkshire Hathaway Energy Growing the Business • We have significantly grown our assets while de-risking the business since being acquired by Berkshire Hathaway in 2000, reducing total debt(1) / total assets from 58% to 43% and improving our credit ratings $100 $8,000 2001 – 2018 CAGR $90 Total Assets 12% $7,000 Net Income(2) 19% $80 Cash Flows From Operations 13% $6,000 $70 $5,000 $60 $50 $4,000 ($ billions) $40 ($ millions) $3,000 $30 Total Assets and Total Debt Total Assets $2,000 $20 $1,000 $10 Net Income and Cash From Operations Flows $- $- 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Assets Total Debt Net Income(2) Cash Flows From Operations (1) Total Debt excludes Junior Subordinated Debentures and Berkshire Hathaway Energy trust preferred securities. As of December 31, 2018, $100 million of junior subordinated debentures remained outstanding (2) Starting in 2017, net income reflects adjusted net income
2018 Net Income ($ millions) Years Ended December 31 Net Income Attributable to BHE 2018 2017 2016 PacifiCorp$ 739 $ 763 $ 764 MidAmerican Funding 669 601 532 NV Energy 317 365 359 Northern Powergrid 239 251 342 BHE Pipeline Group 387 270 249 BHE Transmission 210 224 214 BHE Renewables 329 236 179 HomeServices 145 118 127 BHE and Other (218) (211) (224) Adjusted Net income attributable to BHE(1) 2,817 2,617 2,542 Unrealized Loss on BYD, net of Income Taxes (383) - - Debt Tender Offer Premium - (263) - 2017 Tax Reform 134 516 - Net income attributable to BHE$ 2,568 $ 2,870 $ 2,542 (1) See appendix for a detailed reconciliation of 2017 and 2018 net income adjustments
U.S. Regulatory Overview Adjustment Mechanisms Capital Renewable Energy Fuel Recovery Transmission Forward Recovery Rider Efficiency Decoupling Mechanism Rider Test Year Mechanism (REC/PTC) Rider PacifiCorp Utah (1) Wyoming (1) Idaho Oregon Washington California MidAmerican Energy Iowa – Electric Illinois – Electric South Dakota – Electric Iowa – Gas Illinois – Gas South Dakota - Gas NV Energy Nevada Power Sierra Pacific Power – Electric Sierra Pacific Power – Gas (1) PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecast test periods
Return on Equity Net Income Divided by Average Equity(1) Allowed Entity 2018 2017 ROE PacifiCorp 9.7% 10.3% 9.8% MidAmerican Energy 11.2% 11.0% 10.5%(2) Nevada Power 8.1% 9.0% 9.4%(3) Sierra Pacific 7.5% 9.5% 9.6% Northern Natural Gas 13.4% 11.3% 12.0% Kern River 17.7% 10.6% 11.55% (1) Based on 13-point average equity, including as reported net income and equity (2) Effective January 1, 2018, revenue sharing will be triggered each year by MidAmerican Energy’s actual returns above a threshold calculated annually. Effective January 1, 2019, the threshold is capped at 11% with customer sharing set at 90% (3) Nevada Power is permitted to earn up to 9.7% before 50% revenue sharing commences
Low Cost Competitive Rates Company Weighted Average Retail Rate ($/kWh) U.S. National Average(1) $0.1089 Pacific Power $0.0956 12% lower than the U.S. National Average Rocky Mountain Power $0.0781 28% lower than the U.S. National Average MidAmerican Energy $0.0731 33% lower than the U.S. National Average Nevada Power $0.1018 7% lower than the U.S. National Average Sierra Pacific $0.0814 25% lower than the U.S. National Average BHE Pipeline Group Mastio #1 for the 14th consecutive year Highest Average Rates ($/kWh) by State(1): Hawaii – $0.2719; Massachusetts – $0.1992; Connecticut – $0.1851; New Hampshire – $0.1787; Rhode Island – $0.1766 (1) Source: Edison Electric Institute (Summer 2018)
Credit Ratios Support Our Credit Ratings Unadjusted Credit Metrics FFO Interest Coverage FFO / Debt Debt / Total Capitalization Credit Ratings(1) Average 2018 2017 2016 Average 2018 2017 2016 2018 2017 2016 Berkshire Hathaway Energy(2) A3 / A- 4.4x 4.5x 4.4x 4.3x 16.0% 16.3% 15.8% 16.0% 57% 58% 59% Regulated U.S. Utilities PacifiCorp(2) (3) A1 / A+ 5.4x 5.1x 5.3x 5.7x 23.2% 22.3% 23.1% 24.1% 47% 48% 50% MidAmerican Energy(2) (3) Aa2 / A+ 7.4x 6.8x 7.6x 7.8x 27.3% 23.4% 28.1% 30.4% 47% 47% 46% Nevada Power(2) (3) A2 / A+ 4.8x 4.8x 4.9x 4.6x 22.5% 23.0% 22.8% 21.6% 49% 53% 51% Sierra Pacific(2) (3) A2 / A+ 6.1x 6.8x 6.1x 5.4x 20.6% 22.0% 19.1% 20.7% 48% 50% 51% Regulated Pipelines and Electric Distribution Northern Natural Gas A2 / A 9.1x 8.6x 9.2x 9.5x 38.1% 31.5% 41.1% 41.8% 37% 34% 36% AltaLink, L.P.(3) – / A / A 3.1x 2.9x 3.1x 3.2x 11.8% 11.3% 12.2% 11.8% 60% 60% 62% Northern Powergrid Holdings Baa1 / A- 4.7x 4.4x 4.5x 5.1x 18.8% 17.2% 17.7% 21.7% 42% 43% 43% Northern Powergrid (Northeast) A3 / A Northern Powergrid (Yorkshire) A3 / A (1) Moody’s / S&P / DBRS. Ratings are issuer or senior unsecured ratings unless otherwise noted (2) Refer to the Appendix for the calculations of key ratios (3) Ratings are senior secured ratings
Capital Expenditures and Cash Flows • Berkshire Hathaway Energy and its subsidiaries will spend approximately $16.5 billion from 2019 – 2021 for growth and operating capital expenditures, which primarily consist of new wind generation project expansions, repowering of existing wind facilities and transmission and distribution capital expenditures $8,000 $6,400 $4,800 Free Cash Flow $3,200 ($ millions) $1,600 $- 2014A 2015A 2016A 2017A 2018A 2019F 2020F 2021F 2022F 2023F BHE Cash Flows from Operations BHE Total Capital Expenditures BHE Operating Capital Expenditures 2019 – 2023: $12 Billion Free + 2019 – 2023: $21 Billion Free Cash Cash Flow above Total Capex Flow above Operating Capex
Capital Investment Plan $7,500 7,096 Capex Current Plan Prior Plan $6,000 5,529 by Type 2019-2021 2019-2021 Variance Operating $ 8,746 $ 8,795 $ (49) $4,500 3,920 Wind Generation 4,990 3,739 1,251 (Growth) $3,000 ($ millions) Other Growth 1,727 1,442 285 $1,500 Electric Transmission 1,082 1,047 35 (Growth) $- 2019 2020 2021 Total $ 16,545 $ 15,023 $ 1,522 Operating Wind Generation (Growth) Other Growth Electric Transmission (Growth) Capex Current Plan Prior Plan by Business 2019-2021 2019-2021 Variance $7,500 7,096 PacifiCorp $ 5,431 $ 4,746 $ 685 $6,000 5,529 MidAmerican Energy 5,039 4,587 452 NV Energy 1,935 1,678 257 $4,500 3,920 Northern Powergrid 1,564 1,564 - $3,000 BHE Pipeline Group 1,481 1,351 130 ($ millions) $1,500 BHE Renewables 245 245 - BHE Transmission 701 701 - $- HomeServices and 2019 2020 2021 149 151 (2) Other PacifiCorp MidAmerican Funding NV Energy Northern Powergrid BHE Pipeline Group BHE Renewables Total $ 16,545 $ 15,023 $ 1,522 BHE Transmission HomeServices and Other
PG&E Bankruptcy Update • PG&E’s bankruptcy filing in January 2019 had no impact to our regulated subsidiaries. We have two solar projects, Topaz and Agua Caliente, that have PPAs with PG&E and both projects issued debt which is non-recourse to Berkshire Hathaway Energy • Since the bankruptcy petition, PG&E has paid in full the invoices for both Topaz and Agua Caliente. PG&E has stated in its public filings it will pay suppliers in full under normal terms for post-petition goods and services received ($ millions) Topaz Agua Caliente BHE Ownership 100% 49% (1) Project 550 MW 142 MW PPA Maturity October 2039 (25 Years) June 2039 (25 Years) (1) Debt (as of 12/31/2018) $924.8 $385.0 • We are participating with a coalition of renewable developers, operators and investors to deliver a clear and concise message to the bankruptcy court, the CPUC, the FERC, Governor Newsom and legislators supporting preservation of existing contracts (1) Reflects Berkshire Hathaway Energy’s 49% interest. Total project size is 290 MW, and total debt for the project as of December 31, 2018, was $785.7 million
2019 Financing Plan Completed Debt Offerings and Refinancings • MidAmerican Energy – In January 2019, issued $1.5 billion of First Mortgage, green bonds comprised of two tranches: $600 million 10-year offering at 3.65% coupon, and $900 million 30-year offering at 4.25% coupon – In February 2019, redeemed $500 million 2.4% First Mortgage bonds • Nevada Power – In January 2019, issued a $500 million of 10-year First Mortgage bonds at 3.70% coupon – On March 15, 2019, redeemed $497.7 million 7.125% First Mortgage bonds • PacifiCorp – In February 2019, issued $1.0 billion of First Mortgage bonds comprised of two tranches: $400 million 10-year offering at 3.50% coupon, and $600 million 30-year offering at 4.15% coupon – On January 15, 2019, redeemed $350 million 5.5% First Mortgage bonds Anticipated Debt Offerings • Sierra Pacific Power – Anticipate up to $130 million tax-exempt debt offering in the 2nd quarter 2019 • Northern Powergrid – Northeast – Anticipate up to £150 million debt financing in 2nd quarter 2019 • A Berkshire Hathaway Energy debt offering is possible and is dependent on capital markets and investment opportunities
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Berkshire Hathaway Energy Appendix
Organizational Structure 2018 Berkshire Hathaway Inc. ($ billions) Revenue $ 247.8 Net Income(1) $ 4.0 Aa2/AA Equity $ 348.7 90% 2018 Berkshire Hathaway Energy ($ billions) Revenue $ 19.8 Net Income $ 2.6 A3/A- Equity $ 29.6 A1/A+ (2) Aa2/A+ (2) A2/A Regulated Electric Baa2/A- Regulated Electric Baa1/A- Regulated Natural Regulated Natural Utility Holding Company and Gas Utility Holding Company Gas Transmission Gas Transmission A/A(2) S&P / DBRS Regulated Contracted Real Estate Alberta Canada Electric Non-utility Power Brokerage, Mortgage Regulated Transmission Transmission Generation and Franchises Nevada Power Sierra Pacific Power Northern Powergrid Northern Powergrid Company Company (Northeast) Ltd. (Yorkshire) plc A2/A+(2) A2/A+(2) A3/A A3/A Regulated Electric Regulated Electric U.K. Regulated U.K. Regulated Utility and Gas Utility Electric Distribution Electric Distribution (1) Warren Buffett’s 2018 Berkshire Hathaway Shareholder Letter states – “The components of that figure are $24.8 billion in operating earnings, a $3.0 billion non-cash loss from an impairment of intangible assets (arising almost entirely from our equity interest in Kraft Heinz), $2.8 billion in realized capital gains from the sale of investment securities and a $20.6 billion loss from a reduction in the amount of unrealized capital gains” (2) Ratings for PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and AltaLink L.P. are senior secured ratings
Reportable Segment Information Years Ended December 31 ($ millions) 2018 2017 2016 Operating Income: PacifiCorp$ 1,051 $ 1,440 $ 1,429 MidAmerican Funding 550 531 551 NV Energy 607 766 774 Northern Powergrid 486 488 500 BHE Pipeline Group 525 473 455 BHE Transmission 313 322 92 BHE Renewables 325 316 256 HomeServices 214 214 212 BHE and Other 1 (41) (22) Total operating income 4,072 4,509 4,247 Interest expense - senior & subsidiary (1,833) (1,822) (1,789) Interest expense - junior subordinated debentures (5) (19) (65) Capitalized interest and other, net 269 265 457 Income before income tax expense and equity income (loss) 2,503 2,933 2,850 Income tax expense (benefit) (294) 353 403 Equity income (loss) 43 77 123 Net income 2,840 2,657 2,570 Net income attributable to noncontrolling interests 23 40 28 Adjusted Net income attributable to BHE 2,817 2,617 2,542 Unrealized Loss on BYD, net of Income Taxes (383) - - Debt Tender Offer Premium - (263) - 2017 Tax Reform 134 516 - Net income attributable to BHE $ 2,568 $ 2,870 $ 2,542
Tax Reform Treatment of Lower Tax Rate Treatment of Deferred Income Taxes PacifiCorp Utah In April 2018, the UPSC ordered a rate reduction of $61 million, or In November 2018, the UPSC approved an all-party settlement that 3.1%, effective May 1, 2018, which will remain in effect until the continues the current rate reduction of $61 million, with other next general rate case benefits provided to customers through a combination of accelerated depreciation of certain thermal steam plant units and deferral to offset costs in the next general rate case Wyoming In April 2018, PacifiCorp filed a partial settlement related to the In June 2018, the WPSC approved the rate reduction on an interim impact of 2017 Tax Reform with the WPSC that provides a rate basis. In June 2018, PacifiCorp filed reports with the WPSC with the reduction of $23 million, or 3.3%, effective July 1, 2018, through calculation of the full impact of the tax law change on revenue June 30, 2019, with the remaining tax savings to be deferred with requirement. These reports initiated the next phase of the offsets to other costs proceedings including a hearing held in January 2019. In March 2019, the WPSC approved the stipulation in part and retained the $23 million reduction in rates, with other savings to be deferred with offsets to other costs Idaho In May 2018, the IPUC approved an all-party settlement to PacifiCorp’s proposal to defer additional benefits to offset other implement a rate reduction of $6 million, or 2.2%, effective costs is pending with the IPUC June 1, 2018, through May 31, 2019 Oregon In January 2019, the OPUC approved amortization of the current In January 2019, the OPUC approved continued deferral of excess income tax expense benefits, which results in a rate reduction of deferred income tax balances until PacifiCorp’s next general rate $48.2 million, or 3.7%, effective February 1, 2019 case Washington In December 2018, the WUTC approved amortization of the current In December 2018, the WUTC approved continued deferral of income tax expense benefits, which results in a rate reduction of excess deferred income tax balances until PacifiCorp’s next general $8.3 million, or 2.3%, effective January 1, 2019 rate case California In May 2018, the CPUC approved PacifiCorp’s application requesting authorization to establish a tax reform deferral account to record the 2018 tax impacts due to tax reform. PacifiCorp has requested a decision in its 2019 general rate case authorizing the company to file an advice letter in 2019 to return the savings to customers
Tax Reform Treatment of Lower Tax Rate Treatment of Deferred Income Taxes MidAmerican Energy Iowa The IUB approved a rate reduction tariff through a rider Electric excess accumulated deferred income taxes (EADIT) (retroactive to January 1, 2018), based on an annual calculation amortization is deferred as a regulatory liability, which reduces rate of the benefit of the rate reduction. The revenue reduction for base, until the next regulatory rate review, at which time its disposition electric and gas operations totaled $82 million for 2018, or 3.9% will be determined. Gas EADIT amortization is deferred as a regulatory of sales revenue liability (subject to a carrying charge) until 2021, at which time and thereafter it must be refunded to customers Illinois Effective April 1, 2018, the ICC ordered a rate reduction The rider returns the annual amortization of excess accumulated through a rider, based on the impact of the rate reduction on the deferred income taxes to customers via the rider respective test years supporting current rates. The revenue reduction for electric and gas operations totaled $7 million for 2018, or 3.9% of sales revenue NV Energy Nevada PUCN procedural order granted a $59 million rate reduction, or PUCN issued an order in October 2018 and NVE has filed a petition for Power 3.0% refund, effective April 1, 2018 reconsideration. The order requires amortization of EADIT on protected assets to a new regulatory liability as of January 1, 2018. Unprotected Sierra Pacific PUCN procedural order granted a $25 million rate reduction, balances were capitalized as a regulatory liability. Revenue requirement including $22 million for electric and $3 million for gas, or 3.4% treatment for both protected and unprotected balances will be and 2.6%, respectively, effective April 1, 2018 addressed in subsequent general rate cases BHE Pipeline Group (FERC - Regulated) Northern Northern filed its FERC 501-G form with the FERC on October 11, 2018, along with written commentary explaining why no rate change is Natural Gas appropriate. Comments were filed both in support of and against Northern’s position. On January 16, 2019, the FERC initiated an investigation, pursuant to Section 5 of the Natural Gas Act, to determine whether the rates currently charged by Northern are just and reasonable. Northern is required to file a full cost and revenue study by April 1, 2019. Northern expects to file a general Section 4 rate case, as soon as July 1, 2019, which would supersede a Section 5 rate action to address its significant investment. Northern believes a rate increase will result from the Section 4 rate case and higher rates would be implemented subject to refund in early 2020 Kern River Kern River filed and received approval of its proposal to provide an 11% credit for tax reform to customers, effective November 15, 2018. Kern River was the first to implement a rate reduction through the FERC 501-G process. Kern River’s 501-G docket was closed February 27, 2019
Rate Base PacifiCorp MidAmerican Energy ($ billions) ($ billions) $11.8 $16.0 $14.0 $13.9 $13.7 $14.2 $12.0 $10.0 $8.9 $12.0 $9.0 $8.3 $8.0 $6.0 $4.0 $3.0 $0.0 $0.0 2016A 2017A 2018A 2019F 2016A 2017A 2018A 2019F NV Energy BHE Pipeline Group ($ billions) ($ billions) $8.0 $4.0 $3.6 $6.8 $6.7 $6.8 $6.6 $3.0 $3.0 $3.1 $6.0 $3.0 $4.0 $2.0 $2.0 $1.0 $0.0 $0.0 2016A 2017A 2018A 2019F 2016A 2017A 2018A 2019F Note: Rate base represents mid-year averages
Rate Base Northern Powergrid AltaLink, L.P. (£ billions) (C$ billions) £4.0 $8.0 $7.4 $7.5 $7.5 £3.2 £3.3 $7.0 £2.9 £3.0 £3.0 $6.0 £2.0 $4.0 £1.0 $2.0 £0.0 $0.0 2016A 2017A 2018A 2019F 2016A 2017A 2018A 2019F Berkshire Hathaway Energy ($ billions) $50.0 $46.4 $41.2 $42.1 $43.5 $40.0 $30.0 $20.0 $10.0 $0.0 2016A 2017A 2018A 2019F (1) (2) PAC MEC Northern Powergrid BHE Pipeline Group NVE AltaLink, L.P. Note: Rate base represents mid-year averages (1) Northern Powergrid rate base converted into USD at the June 30 USD/GBP FX rate each year including 1.33 (2016), 1.30 (2017), 1.32 (2018) and 1.35 (2019 estimate) (2) AltaLink, L.P. rate base converted into USD at the June 30 CAD/USD FX rate each year including 1.29 (2016), 1.30 (2017), 1.31 (2018) and 1.30 (2019 estimate)
Long-Term Debt Summary as of December 31, 2018 Consolidated Berkshire Hathaway Energy Wt. Avg. Wt. Avg. $ (millions) Coupon Life (Years)(1) Berkshire Hathaway Energy - Parent 8,577 4.62% 17.3 PacifiCorp 7,036 5.04% 13.5 MidAmerican Funding 5,599 4.17% 17.5 NV Energy 4,318 4.92% 10.2 Northern Powergrid(2) 2,626 5.16% 7.6 Northern Natural Gas 1,042 4.46% 21.6 BHE Canada(3) 3,842 3.87% 16.9 BHE Renewables 3,401 4.78% 8.6 HomeServices 233 4.00% 3.0 Total Berkshire Hathaway Energy Long-Term Debt 36,674 4.63% 14.3 Berkshire Hathaway Energy - Parent Junior Subordinated Debentures 100 5.00% 38.5 Northern Electric Preferred Stock - Perpetual 56 8.06% 30.0 PacifiCorp Preferred Stock - Perpetual 2 6.75% 30.0 Total Berkshire Hathaway Energy Preferred Stock and Jr. Sub. Debentures 158 6.11% 35.3 Total Berkshire Hathaway Energy Long-Term Securities 36,832 4.63% 14.4 (1) Weighted average life assumes perpetual preferred stock has an average life of 30 years (2) USD to GBP exchange rate at $1.2757/pound (3) CAD to USD exchange rate at $1.365/USD • In January 2019, MidAmerican Energy issued $1.5 billion First Mortgage, green bonds. Proceeds were used to finance development of the 2,000 MW Wind XI project and repowering of some of the company’s existing wind facilities • In January 2019, Nevada Power issued $500 million First Mortgage bonds to repay maturing debt • In February 2019, PacifiCorp issued $1.0 billion First Mortgage bonds to finance development of its Energy Vision 2020 projects and to repay maturing debt
Debt Maturities as of December 31, 2018 Long-Term Debt Maturities(1) $4,000 $3,500 $3,000 2,464 2,490 $2,500 $2,000 1,797 1,758 1,603 ($ millions) $1,500 1,308 1,222 1,242 968 $1,000 836 $500 $- 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 PacifiCorp MidAmerican Funding NV Energy Northern Powergrid BHE Pipeline Group BHE Renewables BHE Canada HomeServices Berkshire Hathaway Energy (1) Excludes capital leases
Jurisdictional Strength – Unemployment Rates 14.0% 70.0% 12.0% 68.0% 10.0% 66.0% 8.0% 64.0% Unemployment Unemployment Rates 6.0% 62.0% U.S. Labor Participation 4.0% 60.0% 2.0% 58.0% 2011 2012 2013 2014 2015 2016 2017 2018 (1) Iowa Nevada Alberta U.K. PAC Territory U.S. Labor Participation Source: Bloomberg, Bureau of Labor and Statistics (1) Weighted average of Oregon, Utah and Wyoming
Retail Electric Sales – Weather Normalized December 31 Variance (GWh) 2018 2017 Actual Percent PacifiCorp Residential 16,312 16,130 182 1.1% Commercial 18,023 17,508 515 2.9% Industrial and Other 20,776 20,885 (109) -0.5% Total 55,111 54,523 588 1.1% MidAmerican Energy Residential 6,359 6,235 124 2.0% Commercial 3,797 3,797 - 0.0% Industrial and Other 15,191 14,523 668 4.6% Total 25,347 24,555 792 3.2% Nevada Power Residential 9,373 9,331 42 0.5% Commercial 4,689 4,603 86 1.9% Industrial and Other 5,651 6,343 (692) -10.9% Distribution Only Service 2,479 1,795 684 38.1% Total 22,192 22,072 120 0.5% Sierra Pacific Residential 2,437 2,403 34 1.4% Commercial 2,993 2,940 53 1.8% Industrial and Other 3,397 3,179 218 6.9% Distribution Only Service 1,515 1,395 120 8.6% Total 10,342 9,917 425 4.3% Northern Powergrid Residential 12,642 12,657 (15) -0.1% Commercial 4,237 4,374 (137) -3.1% Industrial and Other 18,540 18,304 236 1.3% Total 35,419 35,335 84 0.2%
Retail Electric Sales – Actual December 31 Variance (GWh) 2018 2017 Actual Percent PacifiCorp Residential 16,227 16,625 (398) -2.4% Commercial 18,078 17,726 352 2.0% Industrial and Other 20,810 20,899 (89) -0.4% Total 55,115 55,250 (135) -0.2% MidAmerican Energy Residential 6,763 6,207 556 9.0% Commercial 3,897 3,761 136 3.6% Industrial and Other 15,191 14,524 667 4.6% Total 25,851 24,492 1,359 5.5% Nevada Power Residential 9,970 9,501 469 4.9% Commercial 4,778 4,656 122 2.6% Industrial and Other 5,748 6,413 (665) -10.4% Distribution Only Service 2,521 1,830 691 37.8% Total 23,017 22,400 617 2.8% Sierra Pacific Residential 2,483 2,492 (9) -0.4% Commercial 2,998 2,954 44 1.5% Industrial and Other 3,403 3,192 211 6.6% Distribution Only Service 1,516 1,394 122 8.8% Total 10,400 10,032 368 3.7% Northern Powergrid Residential 12,538 12,634 (96) -0.8% Commercial 4,258 4,340 (82) -1.9% Industrial and Other 18,618 18,316 302 1.6% Total 35,414 35,290 124 0.4%
Retail Electric Sales – Weather Normalized 50,000 155,000 45,000 150,000 40,000 145,000 35,000 140,000 30,000 135,000 25,000 130,000 20,000 125,000 15,000 120,000 10,000 115,000 Weather Normalized GWh Normalized Weather 5,000 110,000 BHE Total Weather Normalized GWh 0 105,000 2012 2013 2014 2015 2016 2017 2018 2019F Northern Powergrid - CAGR (1.1%) Rocky Mountain Power - CAGR 0.2% MidAmerican Energy - CAGR 2.4% Nevada Power - CAGR 1.0% Pacific Power - CAGR 0.3% Sierra Pacific - CAGR 2.2% BHE Total - CAGR 0.5%
Private Generation Penetration Rate Berkshire Hathaway Energy – Impact of Private Generation Private Generation Total Electric Private Generation Customers as of Customers as of Portion of December 2018 December 2018 Total Customers MidAmerican Energy Company Iowa 751 693,304 0.11% Illinois 39 85,389 0.05% South Dakota 0 5,107 0.00% PacifiCorp Utah 33,794 925,431 3.65% Oregon 6,859 591,239 1.16% Wyoming 314 141,361 0.22% Washington 1,167 131,788 0.89% Idaho 691 80,483 0.86% California 451 45,204 1.00% NV Energy Nevada 35,903 1,292,014 2.78% Total Customers 79,969 3,991,320 2.00%
Affordable Clean Energy Rule • Limited to on-site, heat rate improvements at coal-fueled facilities as best system of emissions reduction • Redefines and rebalances relative roles of federal government and states’ responsibilities with the EPA defining the legal standard of best system of emission reduction with “candidate measures” and states determining what the “actual measures” need to be to improve efficiency • States would be required to evaluate heat rate improvement candidate technologies and measures to establish unit-specific standards of performance, measured in terms of pounds of carbon dioxide per megawatt hour • States will have three years from finalization of the rule to submit plans to the EPA, which would have one year to determine approvability. If a state does not submit a plan or a submitted plan is not approved, the EPA would have two years to develop a federal plan • Does not repeal the EPA’s greenhouse gas endangerment finding, although the EPA continues to evaluate the same • Comments were due October 31, 2018. Final rule was delayed by government shutdown and is now expected by the end of second quarter 2019 • Full impacts will not be known until the rule is finalized and state plans are approved • Material impacts are not anticipated, as affected companies have historically pursued cost- effective plant efficiency improvement projects • Berkshire Hathaway Energy will continue to work with state regulators and key stakeholders to provide safe, reliable and affordable clean energy to our customers and reduce our carbon footprint
Wind Investments Total Invested as of Expected Power Estimated ($ billions) 12/31/18 Investment Capacity (MW) Completion MidAmerican Energy Wind XI $2.2 $3.4 2,000 2019 Wind XII $0.1 $0.9 591 2020 Wind Repowering $1.0 $2.4 2,251 2022 PacifiCorp New Wind $0.1 $1.2 950 2020 Wind Repowering $0.4 $1.1 1,030 2020 BHE Renewables Wind Tax Equity (Not Funded to-date) $0.0 $1.4 2019, 2020 Total Investment $3.8 $10.4
Reducing Carbon Footprint • Through fuel switching and retirements, our utilities expect to eliminate 4,542 MW of coal generation through 2032 (a 43% reduction in coal capacity since 2013 when our plans were initiated) Coal MW as of Dec. 31, 2013(1) Year Retired 10,509 MW Riverside 3 2014 (4) MW Reid Gardner 1-3 2014 (300) MW Carbon 1 and 2 2015 (172) MW Riverside 5 – conversion to natural gas 2015 (124) MW Walter Scott 1 and 2 2015 (124) MW Neal 1 and 2 2016 (390) MW Reid Gardner 4 2017 (257) MW Naughton 3 – natural gas conversion or retirement(2) 2019 (280) MW Navajo – interest to be divested 2019 (255) MW Cholla 4 – assumed retirement 2020 (395) MW North Valmy 1 – planned retirement 2021 (127) MW Craig 1 – natural gas conversion or retirement 2025 (82) MW North Valmy 2 – planned retirement 2025 (134) MW Dave Johnston 1-4 – assumed retirement 2027 (751) MW Jim Bridger 1 – assumed retirement 2028 (354) MW Naughton 1 and 2 – assumed retirement 2029 (357) MW Hayden 1 and 2 – assumed retirement 2030 (77) MW Jim Bridger 2 – assumed retirement 2032 (359) MW Coal MW as of Dec. 31, 2032 5,967 MW (1) Adjusted for re-rating of coal plants between December 31, 2013, and December 31, 2018, including plants still in operation and retired (2) PacifiCorp removed the unit from coal-fueled service on January 30, 2019, and is evaluating converting it to a natural gas-fueled generation resource
Berkshire Hathaway Energy 2018 Adjusted Net Income Reconciliation ($ millions) Net Income Unrealized Net Income adjusted Tax Reform Loss on BYD as reported PacifiCorp$ 739 $ - $ - $ 739 MidAmerican Funding 669 - - 669 NV Energy 317 - - 317 Northern Powergrid 239 - - 239 BHE Pipeline Group 387 - - 387 BHE Transmission 210 - - 210 BHE Renewables 329 - - 329 HomeServices 145 - - 145 BHE and Other (218) 134 (383) (467) Net Income 2,817 134 (383) 2,568 Operating Revenue 19,787 - - 19,787 Total Operating Costs and Expenses 15,715 - - 15,715 Operating Income 4,072 - - 4,072 Interest Expense - Senior & Subsidiary (1,833) - - (1,833) Interest Expense - Junior Subordinated Debentures (5) - - (5) Capitalized interest and other, net 269 - (538) (269) Income Tax (Benefit) Expense (294) (134) (155) (583) Equity (Loss) Income 43 - - 43 Net Income Attributable to Noncontrolling Interests 23 - - 23 Net Income$ 2,817 $ 134 $ (383) $ 2,568
Berkshire Hathaway Energy 2017 Adjusted Net Income Reconciliation ($ millions) Net Income Debt Tender Net Income adjusted Tax Reform Offer Premium as reported PacifiCorp$ 763 $ 6 $ - $ 769 MidAmerican Funding 601 (10) (17) 574 NV Energy 365 (19) - 346 Northern Powergrid 251 - - 251 BHE Pipeline Group 270 7 - 277 BHE Transmission 224 - - 224 BHE Renewables 236 628 - 864 HomeServices 118 31 - 149 BHE and Other (211) (127) (246) (584) Net Income 2,617 516 (263) 2,870 Operating Revenue 18,614 - - 18,614 Total Operating Costs and Expenses 14,105 (13) - 14,092 Operating Income 4,509 13 - 4,522 Interest Expense - Senior & Subsidiary (1,822) - - (1,822) Interest Expense - Junior Subordinated Debentures (19) - - (19) Capitalized interest and other, net 265 - (439) (174) Income Tax (Benefit) Expense 353 (731) (176) (554) Equity (Loss) Income 77 (228) - (151) Net Income Attributable to Noncontrolling Interests 40 - - 40 Net Income$ 2,617 $ 516 $ (263) $ 2,870
Berkshire Hathaway Energy Non-GAAP Financial Measures ($ millions) FFO 2018 2017 2016 Net cash flows from operating activities$ 6,770 $ 6,078 $ 6,104 +/- Changes in other operating assets and liabilities (389) 165 (192) FFO$ 6,381 $ 6,243 $ 5,912 Adjusted Interest Interest expense$ 1,838 $ 1,841 $ 1,854 Interest expense on subordinated debt (5) (19) (65) Adjusted Interest$ 1,833 $ 1,822 $ 1,789 FFO Interest Coverage (1) 4.5x 4.4x 4.3x Adjusted Debt Debt(2) $ 39,290 $ 39,681 $ 37,985 Subordinated debt (100) (100) (944) Adjusted Debt$ 39,190 $ 39,581 $ 37,041 FFO to Adjusted Debt(3) 16.3% 15.8% 16.0% Capitalization Berkshire Hathaway Energy shareholders’ equity$ 29,593 $ 28,176 $ 24,327 Adjusted debt 39,190 39,581 37,041 Subordinated debt 100 100 944 Noncontrolling interests 130 132 136 Capitalization$ 69,013 $ 67,989 $ 62,448 Adjusted Debt to Total Capitalization(4) 56.8% 58.2% 59.3% (1) FFO Interest Coverage equals the sum of FFO and Adjusted Interest divided by Adjusted Interest (2) Debt includes short-term debt, Berkshire Hathaway Energy senior debt, Berkshire Hathaway Energy subordinated debt and subsidiary debt (including current maturities) (3) FFO to Adjusted Debt equals FFO divided by Adjusted Debt (4) Adjusted Debt to Total Capitalization equals Adjusted Debt divided by Capitalization
PacifiCorp Non-GAAP Financial Measures ($ millions) FFO 2018 2017 2016 Net cash flows from operating activities$ 1,811 $ 1,602 $ 1,594 +/- Changes in other operating assets and liabilities (236) 39 177 FFO$ 1,575 $ 1,641 $ 1,771 Interest expense$ 384 $ 381 $ 380 FFO Interest Coverage(1) 5.1x 5.3x 5.7x Debt (2) $ 7,066 $ 7,105 $ 7,349 FFO to Debt(3) 22.3% 23.1% 24.1% Capitalization PacifiCorp shareholders’ equity$ 7,845 $ 7,555 $ 7,390 Debt 7,066 7,105 7,349 Capitalization$ 14,911 $ 14,660 $ 14,739 Debt to Total Capitalization(4) 47.4% 48.5% 49.9% (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
MidAmerican Energy Non-GAAP Financial Measures ($ millions) FFO 2018 2017 2016 Net cash flows from operating activities$ 1,508 $ 1,396 $ 1,403 +/- Changes in other operating assets and liabilities (190) 19 (65) FFO$ 1,318 $ 1,415 $ 1,338 Interest expense$ 227 $ 214 $ 196 FFO Interest Coverage(1) 6.8x 7.6x 7.8x Debt (2) $ 5,621 $ 5,042 $ 4,400 FFO to Debt(3) 23.4% 28.1% 30.4% Capitalization MidAmerican Energy shareholder's equity$ 6,446 $ 5,764 $ 5,160 Debt 5,621 5,042 4,400 Capitalization$ 12,067 $ 10,806 $ 9,560 Debt to Total Capitalization(4) 46.6% 46.7% 46.0% (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
Nevada Power Non-GAAP Financial Measures ($ millions) FFO 2018 2017 2016 Net cash flows from operating activities$ 619 $ 665 $ 771 +/- Changes in other operating assets and liabilities 30 37 (109) FFO$ 649 $ 702 $ 662 Interest expense$ 170 $ 179 $ 185 FFO Interest Coverage(1) 4.8x 4.9x 4.6x Debt (2) $ 2,816 $ 3,075 $ 3,066 FFO to Debt(3) 23.0% 22.8% 21.6% Capitalization Nevada Power shareholder's equity$ 2,904 $ 2,678 $ 2,972 Debt 2,816 3,075 3,066 Capitalization$ 5,720 $ 5,753 $ 6,038 Debt to Total Capitalization(4) 49.2% 53.5% 50.8% (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
Sierra Pacific Non-GAAP Financial Measures ($ millions) FFO 2018 2017 2016 Net cash flows from operating activities$ 275 $ 181 $ 243 +/- Changes in other operating assets and liabilities (20) 39 (4) FFO$ 255 $ 220 $ 239 Interest expense$ 44 $ 43 $ 54 FFO Interest Coverage(1) 6.8x 6.1x 5.4x Debt (2) $ 1,158 $ 1,154 $ 1,153 FFO to Debt(3) 22.0% 19.1% 20.7% Capitalization Sierra Pacific Power shareholder's equity$ 1,264 $ 1,172 $ 1,108 Debt 1,158 1,154 1,153 Capitalization$ 2,422 $ 2,326 $ 2,261 Debt to Total Capitalization(4) 47.8% 49.6% 51.0% (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
Stefan Bird Gary Hoogeveen President and CEO President and CEO Pacific Power Rocky Mountain Power
PacifiCorp Retail Sales 2018 compared to 2017 up 1.1% • Commercial sales up 2.9% PacifiCorp Retail Sales (weather-normalized) • Residential sales up 1.1% 63 • Industrial sales down 0.8% 56 49 2019 forecast vs. 2018 is flat 42 35 • Industrial sales – lower due to changes Annual Growth Rate in large customer operating projections TWh 28 2013 = 0.3% 2014 = 1.2% • Commercial sales – higher due to 21 2015 = (0.9%) 2016 = (0.7%) expansion of data centers, partially offset 14 2017 = 0.5% by energy efficiencies 2018 = 1.1% 7 2019 = (0.0%) • Residential sales – flat due to decline 2020 = 0.3% 0 in use-per-customer, offset by new 2012 2013 2014 2015 2016 2017 2018 2019F 2020F customer growth
PacifiCorp Capital Investment Plan 2019-2021 forecast vs. prior plan up $685 million ($ millions) Current Prior • Growth projects are $682 million higher from prior year primarily 2019-2021 Plan Plan driven by additional growth expenditures including wind investments Growth $ 3,289 $ 2,607 to deliver cost-effective wind fleet repowering and greenfield wind Operating 2,142 2,139 opportunities to be placed in-service in 2019-2021, as well as a new Total $ 5,431 $ 4,746 transmission line. The growth projects are forecast to yield net savings to customers $2,500 $2,000 $1,463 $1,500 $1,684 $ Millions $1,000 $629 $334 $142 $273 $500 $798 $735 $569 $496 $628 $609 $- 2016 2017 2018 2019F 2020F 2021F Operating Growth
Energy Vision 2020 Overview • Approximately $3 billion to expand the amount of wind New Wind power serving customers 500 kV HVAC County • 1,030 MW of repowered existing wind facilities PacifiCorp Service Area • 1,150 MW of new wind facilities (950 MW owned and 200 MW contracted) • 140-mile segment of 500kV transmission • Provides approximately $447 million of present-value benefits for customers (2017 - 2050) Key Milestones Date Obtain regulatory pre-approvals for new wind and transmission resources (Idaho, Utah and Complete Wyoming) Obtain regulatory pre-approvals for Complete repowering (Idaho, Utah and Wyoming) Issue EPC limited notice-to-proceed for new Complete Existing / Repowered Wind wind and transmission line contracts PacifiCorp Service Area Complete acquisition of all required rights-of- March 31, 2019 way and easements for transmission line Issue EPC full notice-to-proceed for new April 1, 2019 wind and transmission line contracts March to Complete 2019 repowering projects December 2019 June to Complete 2020 repowering projects December 2020 Begin delivery of wind turbine generators May 5, 2020 (new wind projects) New wind and transmission in-service December 31, 2020
Wildfires • The Western Governors Association and key legislators are becoming more focused on the need for comprehensive plans to mitigate wildfire impacts to the residents of the western states. They are collaborating with jurisdictional federal administrators and the Department of Interior and are evaluating methods to better withstand the impacts of wildfires which have been increasing in frequency and scope • In California, Senate Bill 901 outlined a series of requirements for the state. California is the only state in PacifiCorp’s service territory that has inverse condemnation, which allows for strict liability if a fire is caused by an electrical facility owned by a utility, regardless of whether the utility was negligent in maintaining the facility • PacifiCorp analyzed fire history with ignition sources as available from CALFIRE data sources(1). – Utility power lines contributed to 0% in PacifiCorp’s California service territory, compared to 2.84% of all ignitions in all of northern California – To put that in perspective, lightning was a contributing factor to 63% of about 240 records in PacifiCorp’s California service territory, compared to nearly 54% of about 1,200 records in all of northern California • In Oregon, Gov. Kate Brown formed a blue ribbon panel, on which Stefan Bird will be a member • In Washington, public utilities commission staff members are beginning to look at the impacts of wildfires on electric reliability • In Utah, House Bill 135 seeks to establish a grant program for wildland fire prevention (1) The records used do not include grass fires of less than 100 acres or timber fires of less than 5 acres
California Service Territory and Wildfire Plan Objectives California Senate Bill 901 requires electric utilities to develop annual wildfire mitigation plans to prevent, combat and respond to wildfires within their service territories PacifiCorp provides electricity to approximately 45,000 customers via 63 substations and 3,300 miles of transmission and distribution lines across nearly 11,000 square miles Regulatory Steps Date Wildfire mitigation plans filed February 6, 2019 Workshop on plans held February 13, 2019 Focused issue-specific workshops held Week of February 25, 2019 Intervenor testimony on plans served March 4, 2019 Evidentiary hearings on plans held March 11, 2019 Concurrent opening & reply briefs/comments March 22 and March 27, 2019 California Public Utilities Commission approves wildfire mitigation plans May 6, 2019
Wildfire Mitigation Plans Berkshire Hathaway Energy has developed Wildfire Mitigation Plans (WMPs) across its Western Utilities WMP 2019 Overview: • Risk-based approach to identify FIRE High Consequence Area (FHCA) • FHCAs are determined by population and structure density, fuel loading, accessibility and climatology • Mitigation plans developed to minimize risk from electrical assets Key Components: • Enhanced situational awareness through active monitoring of Red Flag warnings, public weather data and installation of local weather stations • Yearly asset inspection frequency with accelerated correction time • Implementing increased vegetation clearance standards on distribution circuits of at least a 12-foot pruning cycle, with an objective of maintaining a 4 foot clearance in FHCA • Asset Hardening – Insulated conductor – Strategic pole replacement to increase loading capabilities and fire resiliency – Installation of additional Supervisory Control & Data Acquisition (SCADA) controls – Improved construction standards for new and retrofit applications to reduce potential ignition sources • Enhanced Operational Practices – Modified reclosing procedures during fire season – Proactive de-energization in FHCA – Line inspections before re-energization – De-energization for all areas – real time potential damage or fire risk is assessed by emergency response or emergency action center • Improved response through community outreach and coordination
Pacific Power Retail Sales Pacific Power Oregon 141 GWh (1.1%) Retail Sales Weather Normalized 2019 19 2018 2017 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 18 GWh Annual Growth Rate 17 2013 = 0.0% Washington 119 GWh (3.0%) TWh 2014 = 1.3% 16 2015 = (0.5%) 2016 = 0.4% 2019 2017 = 0.2% 2018 15 2018 = (0.9%) 2019 = 1.4% 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2017 2020 = 0.4% GWh 14 2012 2013 2014 2015 2016 2017 2018 2019F 2020F California ‐5 GWh (‐0.7%) 2019 forecast sales compared to 2018 up 1.4% • Industrial sales – higher due to improved economic conditions in Oregon and Washington 2019 2018 • Commercial sales – higher due to economic growth and 2017 expansion of data centers 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 • Residential sales – flat due to customer growth offset by GWh energy efficiencies
Pacific Power Regulatory Update PacifiCorp • In September 2018, PacifiCorp filed applications in Oregon, Idaho, Utah, Washington and Wyoming for depreciation rate changes that would increase depreciation expense by approximately $300 million, effective January 1, 2021. The study will be evaluated by the states for approval in 2019 or early 2020 Oregon (authorized ROE 9.8%) • Pacific Power customer pledge to not increase base rates prior to 2021; the last general rate case was filed in 2013 • Transition Adjustment Mechanism rate decrease of $0.66 million, or 0.1%, for changes in forecast net power costs and production tax credits, effective January 1, 2019 • The Public Utility Commission of Oregon approved amortization of the current income tax expense benefits, which results in a rate reduction of $48.2 million, or 3.7%, effective February 1, 2019; in January 2019, the OPUC approved continued deferral of excess deferred income tax balances until PacifiCorp’s next general rate case Washington (authorized ROE 9.5%) • No general rate case in the near future; the last rate case with a two-year rate plan was filed in 2015 • Washington’s decoupling mechanism measures company annualized earnings and provides for rate adjustments based on an earnings test. The 2018 result showed the company over earned and will surcredit approximately $3.2 million, or 1.0%, to customers • Power Cost Adjustment Clause rate decrease of $17.9 million, or 5.1%, effective November 1, 2018, expiring October 31, 2019 • The Washington Utilities and Transportation Commission approved amortization of the current income tax expense benefits, which results in a rate reduction of $8.3 million, or 2.3%, effective January 1, 2019, and approved continued deferral of excess deferred income tax balances until PacifiCorp’s next general rate case California (authorized ROE 10.6%) • A general rate case was filed April 2018 using a 2019 test period and an order is pending; the last general rate case was filed in 2009 • Energy Cost Adjustment Clause and Greenhouse Gas Allowance Costs and Revenues Application rate increase of $2.4 million, or 2.1%, for changes in forecast net power costs and greenhouse gas costs effective January 1, 2019 • In May 2018, the California Public Utilities Commission approved PacifiCorp’s application requesting authorization to establish a tax reform deferral account to record the 2018 tax impacts due to tax reform. PacifiCorp has requested a decision in its 2019 general rate case authorizing the company to file an advice letter in 2019 to return savings to customers
Oregon Clean Electricity and Coal Transition Plan Update • Senate Bill 1547 was signed into law March 8, 2016 – Increases renewable portfolio standard to 27% by 2025, 35% by 2030, 45% by 2035, 50% by 2040 • With Energy Vision 2020 resources, Pacific Power’s compliance position is sufficient through 2036 – Removes coal from Oregon rates by January 1, 2030 – Incorporates production tax credits in annual power cost mechanism – Establishes community solar program • Community solar rule making completed in 2017, implementation underway; program administrator selected in September 2018 with contract negotiations in process - final contract expected to be executed by the state of Oregon in 2019 – Authorizes utilities to invest in electric vehicle charging • Electric utility transportation electrification proposals were approved in early March 2018 with pilot programs underway; a progress update to be made on March 31, 2019 – Maintains level playing field for service territory acquisitions by requiring acquirer to meet renewable portfolio standard requirements and pay for any stranded costs
Pacific Power State Carbon Policy Proposals • Washington Senate Bill 5116 and House Bill 1211 – Clean Energy Transformation Act Status: Senate Bill 5116 will be voted out of the House Finance Committee late March 2019. Its companion bill, HB 1211 is no longer under consideration Key provisions: – Coal out of rates by 2025 – 80% renewable by 2030 with compliance options for remaining 20% – 2% cost cap – Compliance penalty = $100/MWh – Sets mandate of 100% carbon free electricity sector by 2045 (no penalty) – Includes two amendments that PacifiCorp requested on excluding voluntary green customers for compliance, and addressing market purchases • Oregon House Bill 2020 – Oregon Cap & Trade Status: Provided invited testimony February 8, 2019; four “road shows” were held February 22, 2019 through March 2, 2019, throughout the state. Informational meetings were held throughout March. The first round of “co-chair amendments” are expected to be released late March 2019 Key provisions: – Establishes new greenhouse gas goals: 45% below 1990 emissions levels by 2035; 80% below 1990 emissions levels by 2050 – Allocates allowances directly to investor-owned utilities through 2030: customers are not responsible for paying for emissions reductions already covered by Renewable Portfolio Standard or Senate Bill 1547 – From 2031-2050, investor-owned utility allocations decline at same rate as cap – If emit more than forecast, must acquire additional allowances in the market – Electricity Price Containment Reserve can be used for unforeseen emissions
Pacific Power 100% Renewable Customer Solutions • Facebook data center, Prineville, OR – Partnership results in 437 MW of new solar developments – Pacific Power is currently implementing two 100 MW projects in Prineville • New renewable energy offering: Blue Sky Select – Allows customers to procure renewable energy credits from specified facilities – Agreements signed with Portland Trailblazers, Oregon Convention Center • Community renewable energy – City of Bend: Joint MOU with commitments including 100% renewable energy for city operations by 2030; 100% renewable energy community-wide by 2050 – City of Portland:100% renewable energy by 2035
Pacific Power Electric Vehicle and Storage Pilot Programs Electric Transportation Pilot Programs • Pacific Power is currently implementing pilot programs to increase awareness about electric transportation and to stimulate development of new charging stations in areas underserved by current charging infrastructure • The three programs focus on: 1. Education and outreach to customers 2. Public fast-charging stations (currently Oregon only) 3. Grants to business customers to install charging infrastructure • $6.7 million budgeted for electric transportation pilots across three states Energy Storage Pilot • Pacific Power will construct, own and operate 2 MW / 6 MWh battery storage in Corvallis, Oregon • Proposed site next to existing generation facility • Partnership with Oregon State University for micro- grid research • Planned in-service third quarter 2020
Advanced Metering Infrastructure Projects Scope Benefits Pacific Power: $126 million capital investment • Provides customers financial benefits over the life of the • Oregon projects against a status quo alternative o 590,000 smart meters – Installs are 67% complete • Customers gain access to near real-time consumption o Build field area network – 100% complete data and information to proactively manage their o In-service January 2018 – December 2019 monthly usage • California • Improved outage detection and response o 47,000 smart meters – Mass installs completed • Enables remote connect/disconnect service o Build field area network – 100% complete • Improved system monitoring for real-time operations o In-service December 2018 – 100% complete and distribution system planning • Provides a platform that can be leveraged for future grid Rocky Mountain Power: $103 million capital investment modernization • Idaho o Pilot Project, July 2019: Devil’s Lake feeder o 80,000 smart meters automation for auto isolating and circuit o In-service December 2021 reconfiguration Utah • Enables collection of interval and outage management o Implement a hybrid AMI/AMR system in Utah data leveraging existing Automated Meter Reading o Install 156,000 smart meters (AMR) Meters in Utah o Leverage 764,000 existing AMR meters to capture interval energy usage o In-service October 2021 o Utah AMR to AMI full conversion is planned within the 10-year horizon
Delivering Reliable and Affordable Energy Energy Imbalance Market • The energy imbalance market is in its fifth year, with cumulative benefits totaling $565 million through December 2018 • PacifiCorp and California ISO launched the EIM in November 2014. NV Energy joined in December 2015. Berkshire Hathaway Energy customer benefits total $242 million November 2014 – December 2018 Combined Benefits Balancing Area Authority Total ($ millions) CAISO $147.2 PacifiCorp $175.5 NV Energy $66.2 Arizona Public Service $85.8 Puget Sound Energy $25.1 Portland General Electric $30.4 Idaho Power $26.9 Powerex $7.8 Total $564.9
Gary Hoogeveen President and CEO Rocky Mountain Power
Rocky Mountain Power Retail Sales Rocky Mountain Power Utah ‐210 GWh (‐0.9%) Retail Sales Weather Normalized 2019 38 2018 0 5,000 10,000 15,000 20,000 25,000 2017 37 GWh Annual Growth Rate 36 2013 = 0.5% 2014 = 1.2% Wyoming ‐36 GWh (‐0.4%) TWh 35 2015 = (1.0%) 2016 = (1.3%) 2017 = 0.6% 2019 34 2018 = 2.0% 2018 2019 = (0.6%) 0 5,000 10,000 15,000 20,000 25,000 2017 2020 = 0.2% GWh 33 2012 2013 2014 2015 2016 2017 2018 2019F 2020F Idaho 13 GWh (0.3%) 2019 forecast sales compared to 2018 down 0.6% • Industrial sales – lower due to changes in large customer 2019 operating projections 2018 0 5,000 10,000 15,000 20,000 25,000 2017 • Commercial sales – flat due to expansion of data centers, GWh partially offset by energy efficiencies • Residential sales – flat due to decline in use-per-customer, offset by new customer growth
Rocky Mountain Power Regulatory Update Utah (authorized ROE 9.8%) • Last general rate case filed in 2014; Rocky Mountain Power made a customer pledge to not increase base rates prior to 2021 • Energy Balancing Account filing to recover $2.8 million in excess deferred net power costs from 2017 went into effect on an interim basis May 1, 2018. A hearing was held by the UPSC in February 2019 and a decision is expected by April 2019 for final approval • In May and June 2018, the UPSC approved applications to repower existing wind facilities and build or acquire 1,150 MW of new wind and transmission facilities, totaling approximately $3 billion in new investment • In April 2018, the UPSC ordered a rate reduction of $61 million, or 3.1%, effective May 1, 2018, related to the impact of 2017 Tax Reform, which will remain in effect until the next general rate case; other benefits provided through acceleration of depreciation and deferral to offset costs in the next general rate case Wyoming (authorized ROE 9.5%) • Last general rate case filed in 2015; Rocky Mountain Power made a customer pledge to not increase base rates prior to 2021 • Energy Cost Adjustment Mechanism filing to refund $3.4 million in excess deferred net power costs effective July 1, 2018, on an interim basis, and made final by the WPSC in December 2018 • In April 2018, the WPSC granted conditional certificates of public convenience and necessity for repowering existing wind facilities and building or acquiring 1,150 MW of new wind and transmission facilities, totaling approximately $3 billion in new investment • In April 2018, PacifiCorp filed a partial settlement with the WPSC related to the impact of 2017 Tax Reform that provided a rate reduction of $23 million, or 3.3%, effective July 1, 2018, through June 30, 2019. In March 2019, the WPSC approved the stipulation in part and retained the $23 million reduction in rates, with other savings to be deferred with offsets to other costs Idaho (authorized ROE 9.9%) • Last general rate case filed in 2011 • Energy Cost Adjustment Mechanism filing to recover $8 million in deferred net power costs, changes in production tax credits and other interim capital costs, reduced rates 0.8%, effective June 1, 2018 • In December 2017, the Idaho Public Utilities Commission (IPUC) approved an application to repower existing wind facilities. In July 2018, the IPUC approved the application to build or acquire 1,150 MW of new wind and transmission facilities. Together, the project totals approximately $3 billion in new investment • In May 2018, the IPUC approved an all-party settlement to implement a rate reduction of $6 million, or 2.2%, effective June 1, 2018, through May 31, 2019
Rocky Mountain Power Customer Renewable Solutions Renewable Energy Tariffs • Renewable Energy Purchases for Qualified Customers ≥ 5 MW – Current Customers: University of Utah – will be purchasing output from 20 MW geothermal resource expected to be online September 2019 – Current Customers: Facebook – will be purchasing output from 122 MW solar resource expected to be online June 2020 – Customer Near Term Potential Growth: 160-200 MW solar/wind on behalf of existing and potential new customers • Company Owned Resources – Rocky Mountain Power sponsored legislation in Utah to enable company owned solar resources while capturing the investment tax credit (ITC); the law went into effect in 2018 • Renewable Energy Rider – Optional; Bulk Purchase Option – Renewable Energy Credit (REC) purchases as directed by participating customers • Subscriber Solar Program – 20 MW solar resource went into operation in 2017, and is fully subscribed by customers in 200 kW blocks; both residential and commercial • 100% Renewables with Cities – Working cooperatively with Utah cities on state legislation, Community Renewable Act, enabling cities to achieve their community goals to be 100% renewable by 2032
Rocky Mountain Power Utah Private Generation Update • Net metering was closed to new applications November 15, 2017, and a new Transition Program was initiated December 1, 2017, for a limited number of installations • Net metering interconnections grew in 2018 as interconnections were completed for applications received prior to program cut-off. Since the Transition Program was initiated, approximately 35 MW of a total eligible 240 MW of new customer private generation has either interconnected or is currently in the application process Customer Class Cumulative Applied for Cumulative Interconnected Transition Cap (as of March 1, 2019) (Pending) (Completed) Residential and Small Business 170 MW 10.6 MW 23.5 MW Large Customers 70 MW 0.0 MW 0.8 MW • Transition program applications are Utah Net Metering significantly down compared to prior year Interconnections net metering applications 14,000 Applications Received Totals 12,000 11,134 2017 (Net Metering) 14,622 9,999 10,000 2018 (Transition Program) 4,344 8,000 5,971 • New load research study underway to 6,000 support post-transition program export 3,118 credit. Export credit proceeding to be 4,000 concluded prior to 2021 1,350 2,000 674 - 2013 2014 2015 2016 2017 2018 Residential Non-Residential
Rocky Mountain Power Electric Vehicles and Storage Political and consumer factors influencing the requirement for charging stations • Utah governor’s budget calls for a $100 million investment to clean up Utah’s air • Salt Lake City will be the U.S. 2030 Winter Olympic bid. The Olympic Committee is calling for a zero-emitting transportation system Partnering Electric Vehicle Charging Ports • Live Electric is a collaboration with Rocky Mountain Power, in Utah U.S. Department of Energy, Utah Clean Air Partnership, 3000 Utah Clean Cities and other state and local organizations to create an electric corridor and work place charging by 2500 installing an additional 700 charging stations by 2021 • Park City is installing charging infrastructure for 16 electric 2000 buses by year-end 2019 and 100% of its fleet by 2025 • Utah Transit Authority (UTA) is adding 27 electric buses 1500 and installing advanced charging infrastructure • Zions National Park is installing charging infrastructure for 1000 two electric buses and creating a transition plan for an Ports of Charging Number electric fleet 500 • LYFT is a partner in supporting ridesharing and electric 0 vehicles 2015 2016 2017 2018 2019 Storage Charging Ports Installed Cumulative Charging Ports Installed • Partnering with Utah State University and Hill Airforce Base to assist in planning for installation of an energy storage device for a microgrid facility at Hill Airforce Base • Deploying a smart grid solution in rural Utah, a 650 kW solar array coupled with a 5 MWh battery to provide voltage support and service during peak loading in the area. This is funded through the Utah Sustainable Transportation and Energy Plan (STEP) legislation for innovative technology deployment
PacifiCorp Appendix
PacifiCorp • Six-state service territory ‒ Utah – Oregon ‒ Idaho – Washington ‒ Wyoming – California • 5,400 employees • 1.9 million electricity customers • 141,400 square miles of service territory • 16,500 transmission line miles • 11,830 MW(1) owned power capacity (1) Net MW owned in operation and under construction as of December 31, 2018
PacifiCorp 2018 Retail Electric Sales 2018 Retail Electric Sales by Class – 55,115 GWh 2018 Retail Electric Sales by State – 55,155 GWh Idaho California Washington 7% 1% Industrial, Irrigation Residential 7% and Other 29% 38% Utah Wyoming 45% 17% Commercial Oregon 33% 23% 2018 Retail Electric Revenue by Class – $4.7 billion 2018 Retail Electric Revenue by State $4.7 billion Idaho California Washington 6% 2% Industrial, Irrigation 7% and Other Residential 30% Utah 37% Wyoming 14% 43% Commercial Oregon 33% 28%
PacifiCorp Environmental Position • Power generating fleet increase primarily Asset Profile attributed to: Net Property, Plant and Equipment as of December 31, 2018 – 1,654 MW Natural Gas – Lake Side 1 & 2 and Chehalis Renewables and – 998 MW Wind – 594 MW Eastside and 404 70% Other MW Westside 9% Natural Gas – (172) MW Coal – retired Carbon plant Generation – 950 MW Wind – Energy Vision 2020 projects under construction 21% Coal Generation • Projected environmental capital spend(2) – $51 million from 2019-2021 March 31, 2006 December 31, 2018 Power Capacity – 8,470 MW (1) Power Capacity – 11,830 MW (1) Hydro and Wind and Other Other 15% 17% Natural Gas 13% Hydro 10% Coal 50% Coal 72% Natural Gas 23% (1) Net MW owned in operation and under construction (2) Environmental expenditures forecast includes PacifiCorp’s share of minority-owned Craig, Cholla, Colstrip and Hayden plants. Amounts include debt AFUDC and escalation but exclude non-cash equity AFUDC
PacifiCorp Major Transmission Projects Over $6 billion total investment planned; $1.6 billion placed in-service • Gateway West - 2024 – BLM record of decision on Segments 1-7 & 10 November 2013 – BLM record of decision on Segments 8 & 9 April 2018 • Aeolus-to-Jim Bridger/Anticline – Segment D2 of Gateway West – Planned in-service 2020 • Gateway South - 2024 – BLM record of decision December 2016 • Boardman-to-Hemingway - 2025 – BLM record of decision December 2017 – Oregon Energy Facility Siting Council permit target date August 2020 • Segments In-Service – Populus-to-Terminal November 2010 – Mona-to-Oquirrh May 2013 – Sigurd-to-Red Butte May 2015 – Wallula-to-McNary January 2019
Adam Wright President and CEO MidAmerican Energy
MidAmerican Energy Electric Retail Sales • Economic and Load Data – Service territory has experienced strong electric load growth – Forecast loads for 2019 and 2020 reflect continued growth, but slight moderation of the most recent trend; Growth for the industrial class due to announced data center and biotechnology expansions within MidAmerican Energy’s service territory – Data centers attracted to relatively low, stable electric rates, high reliability of service and MidAmerican Energy’s wind portfolio MidAmerican Energy Electric Retail Sales Weather Normalized 30 25 20 Annual Growth Rates: 15 2014 = 2.6% TWh 2015 = 1.8% 10 2016 = 2.9% 2017 = 3.2% 2018 = 3.2% 5 2019 = 1.5% 2020 = 1.0% 0 2013 2014 2015 2016 2017 2018 2019F 2020F
MidAmerican Energy Capital Investment Plan • Wind XI – Approved in 2016 – up to 2,000 MW ($ millions) Current Prior 2019-2021 Plan Plan – $3.6 billion approved cost cap deemed prudent – 1,151 MW in service through 2018; remainder Operating $ 1,597 $ 1,675 completed by 2019 Growth 3,442 2,912 • Wind XII Total $ 5,039 $ 4,587 – Approved in 2018 – up to 591 MW – $922 million approved cost cap deemed prudent – Completion in 2019-2020 • Wind repowering 2,700 – PTCs reinstated for another ten-year period, some 2,400 at reduced rates – Improved capacity factors from longer blades, more 2,100 efficient equipment resulting in greater generation – GE fleet 1,800 • $952 million incurred through 12/31/2018, $1,919 1,500 including AFUDC $1,806 • 413 turbines comprising 620 original MW 1,200 repowered through 2018 $1,285 ($ millions) $1,206 $841 • 293 turbines comprising 440 original MW 900 repowered in 2019-2020 $682 • 100% of PTC rate expected for all projects 600 – Siemens fleet • $62 million incurred through 12/31/2018, including 300 $526 $625 $596 $431 $491 $376 AFUDC - • 334 turbines comprising 768 original MW 2016 2017 2018 2019F 2020F 2021F repowered in 2019-2021 at 80% of full PTC rate • 176 turbines comprising 407 original MW Operating Growth repowered in 2022 at 60% of full PTC rate
Build Renewable Energy MidAmerican Energy’s MidAmerican Energy Participates in the Iowa Wind Generation(1) Midcontinent Independent System Operator Green MW Cumulative Advantage Installed Investment Percent(2) Capacity ($ billions) 2012 Actual 3% 2,285 $3.7 2013 Actual 6% 2,329 $3.8 2014 Actual 28% 2,832 $4.6 2015 Actual 38% 3,448 $6.0 2016 Actual 47% 4,048 $7.0 2017 Actual 51% 4,388 $8.3 2018 Actual 51% 5,215 $10.0 2019 Plan 75% 6,265 $11.6 2020 Plan 95% 6,655 $12.2 2021 Plan 101% 6,655 $12.8 The size of MISO’s non-renewable installed capacity enables MidAmerican Energy to continue developing wind generation (1) Includes investment in repowered facilities (2) Represents the portion of Iowa retail sales supplied by renewable energy while maintaining satisfactory reliability. Non-renewable as certified by the Iowa Utilities Board sources account for 85% of MISO’s capacity All or some of the renewable attributes associated with the generation have been or may in the future be: (a) sold to third parties, or (b) used to comply with future regulatory requirements
MidAmerican Energy Wind Performance 14,000 40% 12,000 35% 30% 10,000 25% 8,000 20% 6,000 15% Capacity Capacity Factor 4,000 Output (GWh) 10% 2,000 5% - 0% 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Output GWh Capacity Factor ($ millions) 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Wind Production $72 $80 $93 $141 $172 $183 $210 $249 $287 $308 Tax Credits
Rate Status Electric rates among the lowest in the Midwest region and the United States • No expected need for electric base rate increase through Forecast 2020 Iowa Electric Net Plant 2029 • 56% of Iowa electric net plant subject to • All state jurisdictions have energy and transmission cost rider rate-making principles recovery mechanisms; Iowa rider includes PTCs from • 11.5% weighted average return on equity 2,284 MW of the earliest wind projects placed in-service; PTCs from repowered facilities excluded from rider • 32 years weighted average remaining life • Rate base reductions via Iowa revenue sharing and other arrangements mitigate the need for future base rate increases • Iowa revenue sharing for 2019 and beyond reduces rate base for 90% of pre-tax income on ROEs exceeding a weighted average value calculated annually; based on current forecast, $8,479 $6,678 trigger would be 10.6% for 2019 56% 44% • Proceedings concluded in all states but South Dakota to provide customers the benefit of lower income tax expense resulting from 2017 Tax Reform legislation Annual Growth Rates: • For Iowa electric, MidAmerican Energy’s largest jurisdiction, 2010 = 4.2% tax reform mechanism provides customers with the benefits of 2011 = 1.2% tax reform by lowering current bills for the impact of the lower 2012 = 0.6% tax rate (calculated annually) and continuing to reduce rate 2013 = 1.7% base for excess deferred taxes Subject2014 = 6.7% to Rate Principles Subject2015 = 3.4% to General Rate Order
Energy Storage • Installed a 1-MW/4-MWh lithium iron phosphate battery, along with the associated inverter and transformer in 2018 • The $3 million project connects to a distribution circuit and is being used in a variety of applications to help the company prepare for possible larger scale implementation of the technology as prices for storage continue to decline • Currently being used for energy balancing purposes, but other possible uses include: reserve capacity, voltage support, frequency regulation, demand response and other potential value streams
MidAmerican Energy Appendix
MidAmerican Energy • Headquartered in Des Moines, Iowa • 3,400 employees MINNESOTA • 1.6 million electric and natural gas customers WISCONSIN SOUTH DAKOTA in four Midwestern states (1) • 11,188 MW of owned capacity NEBRASKA • Owned capacity by fuel type: (1) IOWA 12/31/18 12/31/00 ILLINOIS –Wind(2) 59% 0% – Coal 24% 70% KANSAS MISSOURI – Natural gas 13% 19% – Nuclear and other 4% 11% (1) Net MW owned in operation and under construction as of December 31, 2018 (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 MidAmerican Energy Wind Projects Service Territory renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental Major Generating Facilities commodities
MidAmerican Energy 2018 Retail Electric Sales and Revenue by Class 2018 Retail Electric Sales – 25,851 GWh 2018 Retail Electric Revenue – $1.9 billion Other Other 6% 8% Residential 26% Residential 36% Industrial 40% Industrial 53% Commercial 15% Commercial 16%
Private Generation in Iowa • Private generation activities in Iowa – Iowa Utilities Board approved MidAmerican Energy’s net metering tariff in 2017 as part of a 3-5 year pilot project • Size cap on system equal to customer’s “load” • Annual payout of excess energy: 50% paid to customer; 50% paid to low-income heating assistance program • Payout at avoided cost – Inquiry concluded: Avoided costs set at locational marginal price • MidAmerican Energy’s approach to private generation in Iowa – Focused on keeping costs low for all customers – Pursuing legislative policy changes to eliminate inter-class cross- subsidization through proper tariff design
MidAmerican Energy Environmental Position • MidAmerican Energy has 2,705 MW(1) of Asset Profile coal-fueled power capacity Net Property, Plant and Equipment as of December 31, 2018 • Projected environmental capital spend(2) 87% Renewables – $73 million from 2019-2021 and Other Natural Gas Generation Coal 12% Generation 1% December 31, 2000 December 31, 2018 Power Capacity – 4,086 MW (3) Power Capacity – 11,188 MW (3) Nuclear and Other 11% Wind 59% Coal 70% Coal 24% Natural Gas 19% Nuclear and other Natural Gas 4% (1) Net owned capacity as of December 31, 2017 13% (2) Environmental capital expenditures forecast excludes equity AFUDC (3) Net MW owned in operation and under construction
Doug Cannon President and CEO NV Energy
NV Energy Electric Retail Sales Nevada Power System Load Comparison 2018 vs. 2017 Electric Retail Sales Weather Normalized Nevada Power 24 • Commercial up 1.9% due to solid customer growth • Residential up 0.4% due to solid customer growth Annual Growth Rate partially offset by energy efficiency and private 18 Annual Growth Rate 2014 = (0.7%) generation 2015 = 1.7% 2015 = 1.7% • Industrial down 11.3% due to new distribution-only 12 2016 = 1.5% TWh 2017 = 0.6% service customers in 2018. Including DOS, sales were 2018 = 0.5% down 0.4%. Retail and convention space increases 6 2019 = 1.6%2.8% were offset by energy efficiency programs 2020 = 0.8%(0.9%) Sierra Pacific 0 2012 2013 2014 2015 2016 2017 2018 2019F 2020F • Industrial up 6.9% primarily led by manufacturing • Residential up 1.4% primarily due to robust customer Sierra Pacific growth Electric Retail Sales • Large mining up 0.9% as metal prices rise slowly Weather Normalized Load Forecast For 2019 and 2020 12 Nevada Power 10 Annual Growth Rate • Retail, small hotel, recreation facilities and residential 8 2014 = (0.4%) customer growth drives load growth in 2019 2015 = 3.5% 6 2016 = 2.2% Sierra Pacific TWh 2017 = 1.8% • Increasing data center and manufacturing loads will 4 2018 = 4.3% help drive non-residential load growth 2019 = 2.8% 2 2020 = 3.2% 0 2012 2013 2014 2015 2016 2017 2018 2019F 2020F
NV Energy Capital Investment Plan • Capital investment for 2019-2021 increased ($ millions) Current Prior $257 million from prior plan due to an increase 2019-2021 Plan Plan in planned growth projects Operating $ 1,298 $ 1,298 Growth $ 637 $ 380 Total $ 1,935 $ 1,678 700 $320 600 $165 $152 $1 500 $138 400 $93 300 ($ millions) $528 $459 $474 200 $364 $365 $365 100 - 2016 2017 2018 2019F 2020F 2021F Operating Growth
NV Energy Regulatory Update • Sierra Pacific Power Company General Rate Review – Preparations on the 2019 Sierra Pacific Power Company general rate review application are underway – Application must be filed before June 3, 2019, pursuant to Nevada law • Joint Integrated Resource Plan – In December 2018, NV Energy successfully received approval of its combined integrated resource plan – Key elements of the approved plan included 1,001 megawatts of new solar photovoltaic purchase power agreements with 100 megawatts of energy storage – Approval resulted in an unprecedented, concrete plan for creating $2.2 billion of progressive, clean energy resource investment opportunities in Nevada, and approval to conditionally retire North Valmy Generating Station Unit 1 coal facility in 2021, furthering NV Energy’s carbon reduction commitment – NV Energy subsequently issued a request for proposals for up to 350 megawatts of additional renewable energy and battery energy storage systems, and up to 600 megawatts of non-technology specific firm capacity and energy resources • Consolidated Deferred Energy Accounting Adjustment Filings – In March 2019, NV Energy filed its annual deferred energy filing, including the sharing of 50% of Nevada Power’s earnings with customers above a 9.7% return on equity, 2018 estimated at $43.3 million • Tax Rate Reduction Rider – In March 2018, the Public Utilities Commission of Nevada (PUCN) approved NV Energy’s request to reduce rates for its electric and natural gas customers in Nevada by $83.7 million; request was made as a result of 2017 Tax Reform – In September 2018, the PUCN issued an order requiring the capitalization of all excess deferred income taxes associated with the 2017 Tax Reform until the next general rate case filing – In December 2018, NV Energy filed a petition for judicial review challenging the PUCN’s authority to expand the scope of the company’s filing to address adjusted accumulated deferred income taxes
2019 Legislative Session • Nevada’s 80th Legislative Session began February 4, 2019, and will run for 180 days • Legislators submitted over 1,000 bill draft requests to the Legislative Council Bureau; NV Energy is tracking 20+ specific energy bills and 50+ other business-related items • NV Energy is working closely with legislative leaders on numerous energy-related measures that have been proposed during the 2019 legislative session Modifications to Nevada Revised Statute 704B process (alternative energy provider for customers with a load of one megawatt or larger) Increase to the renewable portfolio standard Implementation of community solar program Modification of existing three-year general rate review cycle • NV Energy continues to maintain relations fostered through the Coalition to Defeat Question 3 to aid in legislative support in 2019
Wildfire Risks • NV Energy is acutely focused on wildfire risks – Looking at California, one of the key reasons the severity of fires in California is so high centers around the high population numbers in the wildland-urban interface where wildfires are more likely to occur – Nevada does not have the same population and density numbers in these type of wildland- urban interface areas throughout the state • Proactive Wildfire Mitigation Plans – Increased circuit patrols, inspections and maintenance – Fire season circuit settings that place systems in non-reclosing mode – Vegetation management plans • Prioritization of high risk areas • Shorter vegetation management cycles – Fire threat mapping – Focus resources and attention on higher risk areas (e.g. Lake Tahoe region) – Camera and weather monitoring – Proactive outage management including de-energization – System hardening including deployment of covered conductor, iron ductile/steel poles and fire resistant pole wrap on wooden poles
Nevada Revised Statute 704B Alternative Energy Providers • Alternative energy providers continue to actively market to NV Energy’s customers • By directly accessing wholesale energy markets, customers avoid: – Generation-related capital, operations and maintenance expense – Older vintage, high-priced renewable energy contracts to meet renewable portfolio standard • Options to address further customer bypass activity include: – Alternative pricing plans based on renewable energy resources • Optional Pricing Proposal tariff filed November 16, 2018 • Regulatory decision expected before July 10, 2019 • The program, if approved, allows customers who use more than 8,760 MWh of electricity per year to enter into a fixed energy price tied to renewable energy only; designed to enhance NV Energy’s value proposition by providing predictable energy prices and savings – NV Energy general rates continue to decline or remain flat year-over-year – Proactive customer outreach and education on value of NV Energy fully bundled service – Active participation in alternative energy provider regulatory proceedings, focusing on fair treatment for the remaining customers and a more structured approach to resource planning considerations
Nevada Revised Statute 704B Alternative Energy Providers Peak Load Impact Fee Pending Customer Applicant Status (MW) ($ millions) Existing Customer Load Station Casinos LLC (south) 44.5 $14.95 Order issued Nov 1, 2018; transition under way Georgia Pacific (south) 3.4 $1.29 Order issued Feb 20, 2019 Golden Road Motor Inn, Inc. dba Atlantis Casino Resort 3.9 $1.76 Order issued Feb 20, 2019 Spa (north) Boyd Gaming Corporation (south) 39 TBD Application filed; proceedings scheduled Gaughan South LLC dba South Point Hotel and Casino 10.63 TBD Application filed; proceedings scheduled MEI-GSR Holdings LLC (north) 8 TBD Application filed; proceedings scheduled Las Vegas Resort Holdings LLC dba SLS Las Vegas 5 TBD Application filed; proceedings scheduled (south) Nevada Property 1 LLC dba The Cosmopolitan of Las 20 TBD Application filed Vegas (south) Las Vegas Convention and Visitors Authority (south) 17 TBD Application filed Eldorado Resorts, Inc. 10 TBD Formal Letter of Intent Total 161.43 New Customers to Nevada Fulcrum Sierra Biofuels, LLC (north) Est. 25 $0 Order issued Nov 1, 2018; transition under way Google (north) Est. 42 TBD Informal letter Google (south) Unknown TBD Informal letter LV Stadium Events Company, LLC (south) Unknown $0 Order issued Feb 1, 2019 Two Blackbirds Hospitality Management LLC (south) 27 TBD Formal Letter of Intent Air Liquide Advanced Technologies U.S. LP Est. 12 TBD Application filed (north/south) MSG Las Vegas, LLC (south) Unknown TBD Application filed; proceedings scheduled Wynn West (south) Unknown TBD Informal letter • In 2016-2018, 400 MW of customer peak load transitioned to distribution-only service, with impact fees of approximately $175 million
NV Energy Appendix
NV Energy • Headquartered in Las Vegas, Nevada, with territory throughout Nevada • 2,400 employees • 1.29 million electric and 169,000 gas customers • Service to 90% of Nevada’s population, along with tourist population in excess of 43 million • 6,011 MW(1) of owned power generation (91% natural gas, 9% coal/renewable/other) Nevada Power Sierra Pacific • Provides electric services to • Provides electric and gas Las Vegas and surrounding services to Reno and northern areas Nevada • 942,000 electric customers • 350,000 electric customers and • 4,639 MW of owned power 169,000 gas customers capacity • 1,372 MW of owned power capacity (1) Net MW owned in operation as of December 31, 2018
NV Energy 2018 Retail Electric Sales and Revenue by Class Nevada Power Sierra Pacific Power 2018 Retail Electric Sales – 23,017 GWh 2018 Retail Electric Sales – 10,400 GWh Distribution- Other Distribution- Other Only Service 1% Only Service 0% 11% 15% Residential 24% Residential Industrial 43% 24% Industrial 32% Commercial Commercial 21% 29% Nevada Power Sierra Pacific Power 2018 Retail Electric Revenue – $2.1 billion 2018 Retail Electric Revenue – $700 million Distribution- Other Distribution- Other Only Service 1% Only Service 1% 1% 1% Residential Industrial 38% Residential Industrial 20% 57% 25% Commercial 21% Commercial 35%
NV Energy Environmental Position • NV Energy is reducing use of coal-fueled generation December 31, 2018 (2) – 2019 elimination of Navajo interest (255 MW) Power Capacity – 6,011 MW – 2021 conditional retirement of North Valmy Unit 1 (127 MW) – 2025 retirement of North Valmy Unit 2 (134 MW) • Decommissioning expenditures of $66.3 million in 2019-2021 associated with coal retirements • Forecast(1) environmental expenditures include Coal and Other $4 million in 2019, $4.2 million in 2020 and 9% $4 million in 2021 Natural Gas 91% Nevada Power Asset Profile Sierra Pacific Asset Profile Net Property, Plant and Equipment as of December 31, 2018 Net Property, Plant and Equipment as of December 31, 2018 79% 66% 34% 0% 5% 16% Renewables and Other Natural Gas Generation Renewables and Other Natural Gas Generation Coal Generation Coal Generation (1) Environmental capital expenditures forecast excludes equity AFUDC (2) Net MW owned in operation and under construction
Reduction of Coal-Fueled Generating Stations NV Energy continues to move toward the elimination of coal-fueled electric generating plants by 2025 • Reid Gardner Generating Station, 557 MW coal plant Decommissioned in 2017; demolition is underway through 2019, with site remediation activities to follow • Navajo Generating Station, 2,250 MW coal plant Six owners: NV Energy (11.3%), Salt River Project (operator), Arizona Public Service, Tucson Electric, Los Angeles Department of Water and Power and U.S. Bureau of Reclamation Scheduled for retirement on or before December 22, 2019, and will begin decommissioning activities in 2020 • North Valmy Generating Station, 522 MW coal plant Two units, co-owned equally with Idaho Power Company Public Utilities Commission of Nevada approved 2018 integrated resource plan with a conditional retirement of Unit 1 by December 31, 2021, and Unit 2 by December 31, 2025 Retirement of Unit 1 by 2021 is conditional on maintaining reliable system operations for NV Energy’s customers through a stable transmission grid
Private Generation • Excess energy compensation is tiered in four 80 MW tranches at 95%, 88%, 81% and 75% of authorized rate for that customer class – Tier 1 at 95% credit reached 80 MW capacity August 3, 2018 – Tier 2 at 88% is open for new applications, which is expected to reach capacity by June 2019 • Private generation forecast to reduce NV Energy’s load by 212 GWh by 2020 – Forecast variables include changes to rate of solar installations due to declining excess energy credit or availability of incentive funding, changes in solar adoption of new construction market and reduced solar system costs Private Generation Applications Private Generation Implementation (Residential) 250 200 150 100 Gigawatt-hours 50 0 2018 2019 2020 Source: www.puc.nv.gov, updated February 2019 Nevada Power Company Sierra Pacific Power Company *The numbers shown will fluctuate as customer-generator applications are submitted, withdrawn or expire.
Mark Hewett President and CEO BHE Pipeline Group
BHE Pipeline Group Shipper Contract Updates Northern Natural Gas – Market Area Kern River – Transportation Transportation Contract Maturities (1) Contract Maturities (2) 2019-2020 14% Uncontracted 2019/2020 14% 13% 2032/2033 2027+ 5% 2021/2022 10% 43% 2021-2022 19% 2031 31% 2025-2028 27% 2023-2024 2025-2026 19% 5% • Market Area Transportation weighted average remaining • Weighted average remaining contract term of nine years contract term of over eight years • Weighted average shipper rating of A-/A3(3) • 81% of 2018 storage revenue resulted from long-term • 73% of capacity is committed to contracts that expire contracts, with an average remaining contract life of after 2020 approximately seven years • Shippers that do not meet credit standards are required • Long-term contracts with creditworthy counterparties – to post collateral top 10 customer groups (60% of 2018 revenue) have a weighted average credit rating of A-/Baa1 • In 2018, completed approximately 0.5 Bcf/day in contract renewals, primarily with maximum rate shippers (2) Based on binding shipper commitments for re-contracting and total system design capacity of 2.2 million Dth per day (3) Weighting based on shipper annual revenue for shippers with published (1) Based on maximum daily quantities of market area entitlement in credit ratings decatherms as of December 31, 2018
Northern Natural Gas Regulatory Update • On January 16, 2019, the FERC initiated a Section 5 rate proceeding against Northern – In the filing the FERC calculated a 2018 pro-forma return of 17.3% – Northern is required to file a cost and revenue study by April 1, 2019 – Base period of the cost and revenue study will be calendar year 2018 • On January 28, 2019, Northern filed a motion to terminate the Section 5 rate proceeding – FERC had a significant error that overstated Northern’s 2018 pro-forma return by 3.6% • Return per FERC’s 501-G form should have been 13.7% – Northern’s 2018 actual return was 13.5% • Northern will file a general Section 4 rate case in 2019 – Section 4 filing could be as early as July 1, 2019, and higher rates (subject to refund) would start on January 1, 2020 – Customers could see rate increase of more than 30% from the Section 4 rate case • Increase will include 2019 maintenance capital spending, change in book depreciation rates, higher return on equity, market adjustments $2,500 – First rate case in 15 years $2,000 • Will apply to approximately 50% of transportation $1,500 and storage revenue from maximum rate $1,000 contracts ($ Millions) $500 – Rate case could last 2–3 years before resolution $- • Potential second Section 4 rate filing in 2020 for incremental capital spending and expected lower revenue Rate Base
Northern Natural Gas Capital Investment Plan • Maintenance capital investment is greater than depreciation expense driving increases in rate base ($ millions) Current Prior 2019-2021 Plan Plan – 2018 book depreciation expense of $82 million Operating $ 1,076 $ 978 compared to operating capital expenditures of Growth $ 316 $ 293 approximately $300 million Total $ 1,392 $ 1,271 700 600 $201 500 400 $114 $90 $1 300 ($ millions) $79 200 $435 $44 $306 $318 $323 100 $186 $140 - 2016 2017 2018 2019F 2020F 2021F Operating Growth
BHE Pipeline Group Competitive Advantages Focus on Customer Satisfaction – Northern Natural Gas ranked #1 and Kern River ranked #2 out of 34 interstate pipelines in Mastio & Company’s 2019 survey; Northern Natural Gas also ranked #1 among mega-pipelines in customer satisfaction and Kern River ranked #1 among regional pipelines in customer satisfaction – Both pipelines have been ranked in the top 2 for the past 10 years – BHE Pipeline Group has been ranked #1 for 14 consecutive years Financial Strength and Stability – Northern Natural Gas – Credit metrics have continued to be strong – Kern River – 100% equity capitalization consistent with tariff design – Kern River filed and received approval of its proposal to provide a credit to customers for tax reform that began on November 15, 2018. The rate credit means an annual cost reduction to eligible customers of approximately $12.8 million. Kern River’s tax credit represented 32% of all rate reductions in the 501-G process. Kern River’s rate credit would be eliminated if either there was a change in income tax rates or a section 5 investigation was initiated against the company Location – Northern Natural Gas – Reticulated system - economically unfeasible to replicate – Northern Natural Gas – Optionality with Field Area - tremendous advantage for customers and pipeline to capture opportunities • Proximity to Permian Basin provided for opportunity to capture increased volumes – Kern River – Directly connected to end-use markets in Nevada and California Competitive Pricing – Northern Natural Gas – Even with a rate increase, prices are competitive with other pipelines which minimizes level of discounting needed in competitive markets. Competitive rates have been increasing in major markets – Kern River – Period Two rates are the lowest delivered cost interstate pipeline options to southern California – Long-term contracts with stable markets for both pipelines Operational Excellence – Northern Natural Gas – Long history of commitment to system reliability and operational excellence – Northern Natural Gas set a new peak day record for Market Area deliveries of 5.62 Bcf in January 2019 and a new February record of 5.15 Bcf. There have been five days in the 2018-2019 winter season with Market Area deliveries in excess of 5 Bcf – Kern River – State of the art transmission system
BHE Pipeline Group Appendix
Northern Natural Gas • Headquartered in Omaha, Nebraska • Approximately 925 employees • 14,700-mile interstate natural gas transmission pipeline system • 6.0 Bcf per day of market area design capacity; 1.73 Bcf per day field area capacity to demarcation and 1.4 Bcf per day of Permian area capacity • More than 79 Bcf of firm service and operational storage cycle capacity • 91% of transportation and storage revenue in 2018 is contracted based on fixed amounts (demand charges) that are not dependent on the volumes transported − Market area transportation contracts have a weighted average contract term of eight years − Storage contracts have a weighted average contract term of seven years • Increased the integrity and reliability of the pipeline • Ranked No. 1 among 16 mega-pipelines and No. 1 among 34 interstate pipelines in 2019 Mastio & Company customer satisfaction survey
Northern Natural Gas Field Area Transportation • Field area revenue becoming less dependent on fluctuating Demarc business − 2018 had significantly higher revenue due to competitive Permian supply prices, resulting in wider than normal transportation rates and higher volumes for delivery to Demarc • Permian Basin revenue increased by 275% from 2012 to 2018 − Increased demand through Permian expansion projects – including growth to power plants and market constraints − Market constraints will decrease to some extent over next few years as additional pipelines are built out of the Permian area ($ millions) Field Area Transportation Mix $120 $100 $101 $80 $72 $72 $60 $50 $40 $49 $40 $40 $40 $35 $36 $20 $28 $23 $23 $19 $- 2012 2013 2014 2015 2016 2017 2018 Demarc Permian & Other
Northern Natural Gas Expansion Projects • 2018-2019 Market Area Expansions – Total capital expenditures of approximately $275 million, primarily serving both residential and industrial growth needs for three large LDCs in Minnesota, a power plant conversion in Minnesota and two new power plants in Michigan – Incremental entitlement of 240,000 Dth/day – Annual demand revenues of $43 million, with contract terms from five to 25 years • 2018 Field Area Expansion – Total capital expenditures of approximately $28 million, serving a gas processing plant – Incremental entitlement of 200,000 Dth/day (volumes ramp up between 2018 and 2019) – Annual demand revenues of $8 million, with a contract term of five years
Kern River Gas Transmission • 1,700-mile interstate natural gas transmission pipeline system • Design capacity of 2.2 million Dth per day of natural gas • 89% of revenue through December 31, 2018, is based on demand charges ‒ Contracted capacity has a weighted average contract term of nine years • Ranked No. 2 among 34 interstate pipelines in 2019 Mastio & Company customer satisfaction survey ($ millions) Current Prior 2019-2021 Plan Plan WYOMING Operating $ 89 $ 80 Growth $ 0 $ 0 Total $ 89 $ 80 NEVADA Capital Expenditures UTAH 50 40 CALIFORNIA 30 20 $42 $31 $33 $36 ($ millions) $22 ARIZONA 10 $20 - 2016 2017 2018 2019F 2020F 2021F Operating
Kern River Gas Transmission Strong Demand for Services Daily Average Scheduled Volume • Received 25% of Rockies natural gas 3,000 supply in 2018 2,500 2,000 • Delivered approximately 22%(1) of 1,500 California’s demand for natural gas in 1,000 2017 Millions Dth in 500 (2) • Delivered more than 80% of 0 southern Nevada’s natural gas 2010 2011 2012 2013 2014 2015 2016 2017 2018 Scheduled Design • During 2018, scheduled throughput averaged 105% of design capacity 2018 Deliveries by State Utah 5% Nevada 25% (1) Based on the 2018 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 California 70%
Lowest-Cost Option to Southern California $5 $4.1395 $4 $0.4508 $3.6381 $0.4508 $3.0699 $2.9585 $2.9237 $0.1798 $1.1370 $3 $2.7155 $2.7775 $2.6639 $0.5700 $0.4100 $0.4514 $0.4514 $0.1550 $0.1796 $0.4508 $/Dth $0.3002 $2 $0.2226 Rockies Rockies Permian Permian San Juan Rockies Rockies $2.4661 $2.4661 $2.4174 $2.4174 $2.3834 $2.4661 $2.4661 $1 AECO $1.7119 $0 Kern River Kern River Transwestern El Paso El Paso PG&E PG&E PG&E Alt P2 Rate Alt P2 Rate GTN GTN Ruby Orig Sys 15-yr 2003 Exp 15-yr TCPL NWP Gas Price Fuel and Commodity Transportation Demand Rate Source: Platts M2M Modeled Natural Gas Curves, 120-Month Daily Assessments Dated February 13, 2019
Richard Weech President and CEO BHE Renewables
BHE Renewables Net or Net Contract Owned PPA Power Capacity Capacity Location Installed Expiration Purchaser (MW) (MW) SOLAR Solar Star I & II CA 2013-2015 2035 SCE 586 586 Topaz CA 2013-2014 2039 PG&E 550 550 Agua Caliente AZ 2012-2013 2039 PG&E 290 142 Alamo 6 TX 2017 2042 CPS 110 110 Community Solar Gardens MN 2016-2018 (2) (2) 98 98 Pearl TX 2017 2042 CPS 50 50 1,684 1,536 WIND Grande Prairie NE 2016 2037 OPPD 400 400 BHE Solar Pinyon Pines I & II CA 2012 2035 SCE 300 300 Geothermal Jumbo Road TX 2015 2033 AE 300 300 Santa Rita TX 2018 2038 Various 300 300 Natural Gas Walnut Ridge IL 2018 2028 USGSA 212 212 BHE Wind Bishop Hill II IL 2012 2032 Ameren 81 81 Marshall Wind KS 2016 2036 (3) 72 72 BHE Hydro 1,665 1,665 CalEnergy Philippines GEOTHERMAL Imperial Valley CA 1982-2000 (4) (4) 338 338 Portfolio Composition (1) HYDROELECTRIC Casecnan Phil. 2001 2021 NIA 150 128 Solar Wind Wailuku HI 1993 2023 HELCO 10 10 32% 38% 160 138 NATURAL GAS Cordova IL 2001 2019 EGC 512 512 Power Resources TX 1988 2021 EDF 212 212 Natural Gas Saranac NY 1994 2019 TEMUS 245 196 6% Yuma AZ 1994 2024 SDG&E 50 50 Hydro Geothermal 1,019 970 4% 20% Total Owned 4,866 4,647 (1) Based on actual generation from January 1 through December 31, 2018 (2) Approximately 100 off-takers for the purchase of all the energy produced by the solar portfolio for a period up to 25 years (3) Separate PPAs exist with Missouri Joint Municipal Electric Commission (20 MW), Kansas Power Pool (25 MW), City of Independence, Missouri (20 MW) and Kansas Municipal Energy Agency (7 MW) (4) 69% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under long-term power purchase agreements expiring in 2019 through 2026. Certain long-term power purchase agreement renewals for 244 MW have been entered into with other parties at fixed prices that expire from 2028-2039, of which 202 MW mature in 2039
BHE Renewables Material Net Income Growth ($m) $400 $329 $350 $300 $236 (1) $250 $179 $200 $124 $150 $121 $100 $50 $- $(50) 2014 2015 2016 2017 2018 Solar Wind (Owned) Wind (Tax Equity) Geothermal & Gas Hydro Parent & Other Total Renewables • Additional new investments and improved operations continue to drive net income growth. Net income grew 39.4% in 2018 (1) Normalized 2017 net income excluding $628 million of tax reform benefits
BHE Renewables 2018 New Wind Capacity Santa Rita • 300 MW project in Texas • Commercial operation achieved in May 2018
BHE Renewables 2018 New Wind Capacity Walnut Ridge • 212 MW project in Illinois • Commercial operation achieved in December 2018
BHE Renewables Tax Equity Investments Invested by Year Future 2015 2016 2017 2018 Commitments Total Capacity (MWs) 204 829 602 808 1,634 4,077 Investment ($m)$ 170 $ 584 $ 403 $ 698 $ 1,400 $ 3,255 • Tax equity investments enable investment in new renewable energy projects • Accounted for as equity method investments
BHE Renewables Operational Performance Owned Generation by Type 5,000 4,000 3,000 2,000 1,000 Thousands MWhs of 0 2014 2015 2016 2017 2018 Solar Wind Geothermal Hydro Natural Gas 2017 2018 Capacity Capacity Factor Factor Wind 36.2% 39.3% Solar 29.8% 29.0% Geothermal 82.4% 84.5% Hydro 38.4% 35.7% Gas Plants 2.4% 9.3% Total 29.7% 32.4%
Scott Thon President and CEO AltaLink
AltaLink, L.P. Strong 2018 Results • Continue to Maintain Top Quartile Operational Performance well ahead of Canadian Peer Group – Safety – Canadian Electricity Association (CEA) President’s Award of excellence for top transmission employee safety for the second consecutive year – Reliability – Best ever reliability of service provided to customers – Customers – Best ever customer satisfaction survey results for direct customers at 96% – Environment – Recognized as a sustainable electricity company by the CEA • Exceeded Customer Savings Offering in the 2017-2018 Negotiated Settlement – Reductions of C$40 million in maintenance capital spending – Savings of C$30.1 million in operating expenses, which was C$14.6 million better than the Negotiated Settlement – Rate levelization measures delivered • Executing on Further Customer Rate Relief through Five-Year Flat Tariff Commitment – 2019-2021 GTA represents the first three years of five-year commitment to flat tariffs of no higher than the 2018 approved revenue requirement of C$904 million • Rate Base is levelling at C$7.6 billion – Strong cash flow more than enough to support a capital program of C$300 – C$400 million per year over the foreseeable future
Alberta Economic Outlook Economic Recovery Underway, but Challenges Linger Alberta • In 2018, Alberta was Canada’s third-largest economy and fourth-most populated province Alberta Real GDP Growth • After nation-leading growth of 4.5% in 2017, real GDP is expected to be 2.5% in 2018 7.0% 6.2% • Employment gains have been moderating compared to last year’s strong pace with the 5.7% province adding more than 42,000 jobs since October 2017. The unemployment rate has 5.0% 3.9% 4.5% averaged 6.7% year-to-date but is expected to decline to 6.3% in 2019 • With energy market access issues persisting in 2019, weaker corporate profits and slower 3.0% 2.5% oil production growth will dampen investment and exports for the year. Based on recent developments, 2019 growth is forecast to slow to 2.0% 1.0% • 2018 pool prices increased significantly due to the early retirement of some coal units and -1.0% impact of carbon tax price increase AltaLink -3.0% • No major system upgrades expected in the near-term. Renewables investments will -3.7% -3.7% leverage existing transmission infrastructure -5.0% • After strong growth, load is levelling 2012A 2013A 2014A 2015A 2016A 2017A 2018F • AltaLink is not exposed to volume or price risk Source: Statistics Canada and Alberta Treasury Board & Finance • AltaLink continues to be focused on reducing customer cost 86,000 Alberta Electricity Demand (GWh) Average Pool Prices (C$/MWh) 90.0 80.2 84,000 80.0 70.0 82,000 60.0 49.4 50.3 50.0 80,000 40.0 33.3 78,000 30.0 22.2 20.0 18.3 76,000 10.0 74,000 0.0 2013A 2014A 2015A 2016A 2017A 2018A 2013A 2014A 2015A 2016A 2017A 2018A Source: Alberta Electric System Operator
Flat for Five – Tariff Levelization AltaLink Transmission Tariff $1,000 $980 $960 $940 $920 C$'million $900 $880 $860 $840 2018 2019 2020 2021 2022 2023 Unmitigated Tariff (updated Salvage Percents and no AccumDep Refund) Based on AUC Approved Salvage Flat Tariff Commitment to Customers 2019-2021 GTA • Approved customer rate relief initiatives have delivered savings of about C$650 million for the years 2015-2018 and are expected to deliver additional savings of about C$270 million during the 2019-2021 GTA period • The 2019-2021 GTA includes additional savings of approximately C$200 million for the years 2019-2021 – If approved, this will result in total customer savings of over C$1.1 billion for the period 2015-2021 • The proposed rate relief measures in AltaLink’s 2019-2021 GTA are not expected to have an impact on the company’s credit ratings
AltaLink Regulatory Update Large Regulatory Files Completed in 2018 (DACDA & GCOC) 2014-2015 Direct Assign Capital Deferral Account (DACDA) – Includes 202 projects and total net capital additions of C$4 billion – The DACDA is the final step in the process to approve prudency of capital additions, other deferral account balances and cancelled project expenses – Disallowed approximately C$30 million or about 0.7% of requested capital additions 2018-2020 Generic Cost of Capital (GCOC) – Decision released August 2, 2018 approving an 8.50% ROE and an equity ratio of 37% for 2018 to 2020 and as placeholders for 2021 – The Alberta Utilities Commission (AUC) intends to explore the possibility of returning to a formula-based approach to cost of capital matters as part of the next proceeding. – Currently the AUC considers “comparable investments”, “capital attraction” and “financial integrity”, collectively referred to as the fair return standard, in its GCOC decision making – The AUC found that the flow-through method for calculating deemed income taxes should continue to be used as the default method – The AUC reiterated its position that it is not prepared “to depart from its historical practice of maintaining credit ratings in the A-range”
AltaLink Regulatory Update Future Regulatory Files and UAD 2019-2021 General Tariff Application (GTA) – GTA filed August 23, 2018 – First three years of five-year commitment to flat tariffs at no higher than the 2018 approved revenue requirement of C$904 million – Key issues include depreciation/salvage rates, approval of new salvage methodology and whether a third year of the GTA should be included in the application – All rate relief measures maintain a FFO/Debt rating that supports an “A” category credit rating Utility Asset Disposition (UAD) – Under the UAD Decision dated November 26, 2013, utility shareholders are responsible for the net book value of utility assets that are taken out of utility service as a result of an “extraordinary retirement” before the original cost of the assets has been recovered from customers through depreciation – The Alberta utilities sought to have this decision addressed through legislative reform after having been unsuccessful in the courts. This led to the Alberta Government’s release of Bill 13 • In Q2 2018, the Alberta Government tabled Bill 13 which specifically recognized broad discretion in AUC’s powers including stranded assets and UAD matters • After receiving significant feedback from the financial community, debt and equity investors, the Alberta Government removed all references to UAD from Bill 13 • Alberta Government consultations are planned to resume post-2019 election
Strong Rate Base Capital Investment in Place with Projected Capital Expenditures Normalizing (C$ billions) Rate Base Levelling at C$7.6 billion Gross Capital Expenditures 2.5 8.0 7.7 7.5 7.6 7.6 7.6 0.1 0.1 0.1 7.3 0.1 0.1 0.3 7.0 6.6 2.0 2.0 1.8 6.0 1.3 5.2 5.0 1.5 1.7 4.0 3.7 1.1 7.4 7.5 7.6 7.6 7.6 7.0 1.0 3.0 1.2 5.3 2.0 0.5 0.5 3.5 0.5 0.4 0.4 2.5 0.3 0.3 1.0 0.0 0.0 2013A 2014A 2015A 2016A 2017A 2018A 2019F 2020F 2021F 2013A 2014A 2015A 2016A 2017A 2018A 2019F 2020F 2021F Mid-year Rate Base Mid-year CWIP Growth Maintenance Forecast based on 2019-2021 GTA, August 2018
Alberta Climate Leadership Plan Update • The province reached a settlement with coal generators to phase out all coal plants by 2030 • An economy-wide carbon tax was implemented January 1, 2017, to encourage energy efficiency and cover the cost of transitioning to renewables – Starting January 1, 2018, the carbon levy doubled to C$30 per ton of CO2 emissions based on “best of gas” emission standard • Government targeting to procure 5,000 MW of renewables (wind, solar, hydro) through the Renewable Electricity Program (REP) by 2030 – REP1: 600 MW of wind awarded in December 2017 at a Canadian record low average price of C$37/MWh – REP2 and REP3 auction results announced in December 2018 • REP2: 363 MW, 25% minimum indigenous component. Three successful proponents at an average price of C$38.69/MWh • REP3: 400 MW, same criteria as REP1. Two successful proponents at an average price of C$40.14/MWh • 94% of new generation capacity resulting from REPs 1-3 will directly utilize AltaLink’s transmission system • REPs at high risk of going away with change in government post-2019 election
AltaLink Appendix
AltaLink, L.P. • Owner and operator of regulated electricity transmission facilities in the Province of Alberta – Supplies electricity to approximately 85% of Alberta’s population • Approximately 8,200 miles of transmission lines and 313 substations within the Province of Alberta – No volume or commodity exposure – Supportive regulatory environment – Revenue from AA- rated Alberta Electric System Operator (AESO) • Mid-year 2019 forecast rate base of C$7.6 billion as per the 2019-2021 GTA filing
Financial Strength Strong Cash Flow and Improving Credit Metrics EBITDA (C$ billions) Net Income (C$ millions) $400 $1.0 337 $350 0.8 306 0.8 0.8 292 $0.8 $300 0.6 $250 $0.6 0.5 216 209 0.4 $200 162 $0.4 $150 $100 $0.2 $50 $0.0 $0 2013A 2014A 2015A 2016A 2017A 2018A 2013A 2014A 2015A 2016A 2017A 2018A FFO Interest Cash Flow / Total Debt (as reported by DBRS) FFO / Debt (as reported by S&P) 15% 13.3% 14.0% 13.0% 12.8% 12.3% 13% 11.8% 12.0% 10.9% 11.3% 10.4% 11% 9.9% 10.0% 9.8% 9.6% 10.0% 9% 8.0% 7% 6.0% 5% 4.0% 3% 2.0% 1% 0.0% -1% 2013A 2014A 2015A 2016A 2017A 2018A(1) 2013A 2014A 2015A 2016A 2017A 2018A(1) (1) AltaLink estimate
Regulatory Framework Supports Predictable Revenue • AltaLink receives approved tariff from AESO in equal monthly installments – No exposure to variability in electricity prices – No electricity volume risk • Tariffs based on cost-of-service regulatory model under a forward test year basis • The AESO, who is responsible for system planning, directs substantially all of AltaLink’s capital spending
C$1.1 billion of Proposed and Approved Customer Rate Relief Approved & Proposed Customer Rate Relief: 2015 - 2021 Impact Customer Rate Relief (in millions of dollars) 2015 2016 2017 2018 2019 2020 2021 Discontinuation of CWIP-in-rate base 69 13 4 2 - - - Refund of previously collected CWIP-in-rate base 123 142 - - - - - Change from future income tax to flow through - 68 89 90 90 91 90 Reduction in operating costs - - 8 8 - - - Approved Reduction in capital spending - - - 1 1 1 1 Increase in revenue offsets - - 1 1 - - - Depreciation surplus refund - - 16 16 - - - Reduction in salvage collection - - - - 44 49 56 Depreciation refund - - - - 10 10 10 Proposed Reduction in depreciation - - - - 5 6 6 Total annual rate relief 192 223 118 118 151 157 163 Cumulative relief 192 415 533 650 801 959 1,121 • Approved customer rate relief initiatives have delivered savings of about C$650 million for the years 2015-2018 – C$600 million for the 2015-2016 GTA and C$50 million for 2017-2018 Negotiated Settlement – Approved initiatives will deliver additional customer savings of about C$270 million during the 2019-2021 GTA period • As part of Flat for Five, the 2019-2021 GTA is proposing additional savings of about C$200 million for the years 2019-2021 – If approved this will result in total customer savings of over C$1.1 billion for the period 2015-2021 • Strong customer satisfaction survey results for direct customers, with scores of 91% for 2017 and 96% for 2018
Phil Jones President and CEO Northern Powergrid
Northern Powergrid Regulatory and Political Overview • ED1 performance continues to improve (£ millions) – U.S. GAAP 2018 2017 – Costs and outputs: on target Revenues 764 737 – Customer satisfaction: performance Operating Income 364 379 comparable to the prior year Capex 401 488 – Network performance: 4 consecutive RAV 3,262 3,132 years of strong performance Interest Coverage 3.4x 3.3x – Revenues reduce and RAV grows as Debt to RAV 58% 60% regulatory asset life transitions to 45 years Regulatory Parameters ED1 DPCR5 (2015-2023) (2010-2015) – Inflation protection continues to apply (1) Allowed Equity Returns 6.0% 6.7% (1),(2) – Ofgem confirmed there would be no Allowed Cost of Debt 2.3% 3.6% mid-period review (3) Annual Totex vs DPCR5 95% 100% • Ofgem is signaling a tougher outlook for (4) Average Annual RAV 1.2% 3.7% the RIIO2 reviews with lower base returns, Growth weaker incentives, and a return to five-year Regulatory Asset Life 20-45 20 years price control periods years (1) – Plus RPI inflation (2) – ED1 indexed, figure stated for 2017-2018 (3) – Total activity costs (4) – 2012-2013 prices
Northern Powergrid Regulatory Update • Northern Powergrid’s next price control starts in 2023 • The direction signalled by Ofgem for the forthcoming RIIO2 transmission and gas distribution reviews is more conservative: – The indicative base cost of equity of 4.0% (plus CPIH) is around 2.5 percentage points lower than the current allowed return – A general reduction in incentive strength and a cap on overall returns reduces the scope for outperformance and cash flow – The potential for the introduction of a complex cash flow floor mechanism reduces the pressure on Ofgem to properly compensate risks and ensure financeability • The remaining items, in isolation, appear manageable, however the general direction is to reduce the scope for outperformance • Our strong balance sheet protects Northern Powergrid from the credit risk injected by Ofgem’s wider RIIO2 thinking, but that position is not reflective of the entire sector • We will be among those pushing Ofgem hard to retain a focus on driving efficiency, outputs and long-term investment for customers through well-balanced, incentive- based price controls
U.K. Political Environment • Our assessment of Brexit’s impact on Northern Powergrid is unchanged – the fundamentals of our business are not directly affected by the outcome of negotiations • The nationalization rhetoric continues – it certainly has not increased in prominence; if anything, the likelihood has reduced: – Significant costs of implementation for minimal customer savings means the policy is not popular, even within much of the Labour Party, nor in many of its core supporters (e.g. a number of trade unions) – There is no sign of the Labour Party having the level of support that would be necessary to push something like this through • Our approach remains unchanged – we continue to provide the best possible service to our customers at low cost and continue to stay engaged with regulators and key stakeholders
Northern Powergrid Capital Investment Plan • Operating capital delivers our ED1 output commitments • The smart meter rental business continues to grow with capital expenditure expected in 2019 of £89 million, which is lower than the peak of 2017 as the industry transitions to the second generation of smart meters (£ millions) Current Prior 2019-2021 Plan Plan Operating £ 1,062 £ 1,062 Growth 98 98 Total £ 1,160 £ 1,160 500 400 £8 £134 £89 £98 £93 £1 300 200 £379 (£ millions) £329 £316 £329 £338 £345 100 - 2016 2017 2018 2019F 2020F 2021F Operating Growth
Growth Opportunities in the U.K. • Outlook for the Baltic Gas Project (49% owned by Northern Powergrid) remains encouraging – Final Investment Decision is likely by the end of 2019 • Smart meter rental continues to grow - but deployment has been delayed and is likely to continue into 2020 – Over 2.1 million smart meter units have been deployed to date and we have total contracted volumes of 2.9 million meters with an investment value of £460 million • Looking to the longer term, our existing network provides development opportunities - particularly as the low-carbon agenda continues to signal a need for more investment in networks • Transaction prices have remained high as corporate activity reshapes energy markets. We will continue to monitor opportunities
Northern Powergrid Appendix
Northern Powergrid • 3.9 million end-users in northern England Northeast Yorkshire • Approximately 61,000 miles of Edinburgh distribution lines • Approximately 60% of distribution revenue from residential and commercial customers through December 31, 2018 Newcastle Upon Tyne • Distribution revenue (£ millions): Middlesbrough 12 Months Ending York Customer Type 12/31/2018 12/31/2017 Leeds Residential 305 315 Sheffield Commercial 91 95 Industrial 260 230 Other 9 9 Total 665 649
Comparison of Customer Rates • Ofgem estimates that the average domestic Typical Domestic Customer Charges (2019‐2020) customer in Great Britain will pay £88 per £120 year in 2019-2020 for electricity distribution £100 costs(1) £80 £60 • Our average customer will pay £84.01, which £40 compares favorably to other DNOs £20 • Our prices are approximately 8% lower in £0 UKPN NPg SSE ENW WPD Scottish real terms than in 2015 Power • By the end of the ED1 price control, our Average Northern Powergrid prices are forecast to be 6% lower in real Customer Charges (2015‐2019) £90 terms than in 2015 £88 • Actual customer bills are sensitive to the £86 geographic region in U.K., consumption £84 £82 volumes and timing differences in recouping £80 asset investments via Distribution Use of £78 System charges in customer bills £76 £74 2015/16 2016/17 2017/18 2018/19 2019/20 (1) Nominal terms, Source: Ofgem Annual Report 2017-2018
