2014 EEI Financial Conference November 11-14, 2014 Patrick J. Goodman Executive Vice President and Chief Financial Officer
This presentation contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as “will,” “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “intend,” “potential,” “plan,” “forecast” and similar terms. These statements are based upon Berkshire Hathaway Energy Company’s (“BHE”) and its subsidiaries’ (collectively, the “Company”) current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of the Company and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others: – general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including reliability and safety standards, affecting the Company’s operations or related industries; – changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition; – the outcome of rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company’s ability to recover costs in rates in a timely manner; – changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and distributed generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the Company’s ability to obtain long-term contracts with customers and suppliers; – a high degree of variance between actual and forecasted load or generation that could impact the Company’s hedging strategy and the cost of balancing its generation resources with its retail load obligations; – performance and availability of the Company’s facilities, including the impacts of outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions; – changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs; – the financial condition and creditworthiness of the Company’s significant customers and suppliers; – changes in business strategy or development plans; – availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for BHE’s and its subsidiaries’ credit facilities; – changes in BHE’s and its subsidiaries’ credit ratings; – risks relating to nuclear generation; – the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts; Forward-Looking Statements 2
– the impact of inflation on costs and the Company’s ability to recover such costs in regulated rates; – increases in employee healthcare costs, including the implementation of the Affordable Care Act; – the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements; – changes in the residential real estate brokerage and mortgage industries and regulations that could affect brokerage and mortgage transaction levels; – unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions; – the availability and price of natural gas in applicable geographic regions and demand for natural gas supply; – the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company’s consolidated financial results; – the Company’s ability to successfully integrate future acquired operations into its business; – the occurrence of any event, change or other circumstances that could give rise to the termination of the Share Purchase Agreement to acquire 100% of AltaLink, L.P. (“AltaLink”) or the failure to consummate the transaction, including the failure to receive the required regulatory approvals, the taking of governmental action (including the passage of legislation) to block the transaction or the failure to satisfy other closing conditions; – the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the Company’s control or by a breakdown or failure of the Company’s operating assets, including storms, floods, fires, earthquakes, explosions, landslides, mining accidents, litigation, wars, terrorism and embargoes; and – other business or investment considerations that may be disclosed from time to time in BHE’s filings with the United States Securities and Exchange Commission (“SEC”) or in other publicly disseminated written documents. Further details of the potential risks and uncertainties affecting the Company are described in BHE’s filings with the SEC. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive. All financial, operating, statistical or other graphic information (or illustrations) relating to AltaLink have been derived, without independent verification by us, from AltaLink’s reports on its website under investor relations. The pro forma financial, operating, statistical and other information contained in this presentation showing the pro forma effect of consummating our planned acquisition of AltaLink represents the combination of AltaLink's publicly reported information with our comparable publicly reported information. Such pro forma combined financial information has not been adjusted to eliminate intercompany items and has not otherwise been prepared in accordance with GAAP requirements for pro forma consolidated financial information. Similarly, the pro forma combined operating and statistical data has not been adjusted to eliminate the effects of intercompany transactions. Forward-Looking Statements 3
BHE’s strategy has delivered outstanding results • Own and operate a portfolio of high-quality utility businesses – Focus on customer service, operational efficiency and cost control – Cooperative approach with regulators and customers – Pursue internal capital investment opportunities to expand regulated asset base • Maintain prudent financial and risk management policies – Committed to holdings company and subsidiary credit profile – Stable and highly diversified asset base • Grow and diversify through a disciplined acquisition strategy – Target additional energy assets – Focus on long-term risk-adjusted returns – Continue to utilize ring-fencing approach – Capitalize on access to long-term capital from Berkshire Hathaway – Continue track record of proven integration capabilities and improving operating and financial performance Proven Corporate Strategy 4
Berkshire Hathaway Energy 5 • BHE’s integrated utilities operate in 11 states • Northern Powergrid has 3.9 million end-users, making it the third-largest electricity distribution company in Great Britain • Together, Northern Natural Gas and Kern River deliver approximately 8% of the natural gas consumed in the U.S. • MidAmerican Solar has 1,271 MW under construction and in operation and currently owns two of the largest solar projects in the U.S. • BHE has 5,047 MW of wind generation under construction and in operation – 7% of the U.S. wind market • Comparable companies Company Name Sept. 30, 2014 Market Cap(1) (billions) LTM June 30, 2014 Net Income(1) (billions) Duke Energy $52.9 $2.21 NextEra Energy Inc. $41.0 $1.95 Dominion Resources $40.3 $1.58 Southern Company $39.1 $2.30 Exelon Corp. $29.3 $1.88 BHE Net Income: LTM Sept. 30, 2014 $2.06 billion(2) BHE retains more equity than any of its utility peers (1)As reported by Bloomberg (2)Includes financial results from NVE post acquisition close date of Dec. 19, 2013
Berkshire Hathaway Energy 6 As of, and for the 12 months ended, Sept. 30, 2014 • 8.4 million electric and natural gas customers and end-users worldwide • 19,700 employees worldwide • $74.0 billion of assets • $16.4 billion of revenue • 25,000 miles of transmission lines • 16,400 miles of natural gas pipeline • Approximately 29,000 MW of owned generation capacity(1) • 29% of owned generation capacity is renewable or noncarbon (1) Net MW owned in operation and under construction as of Sept. 30, 2014
7 Berkshire Hathaway Energy + AltaLink • 11.4 million electric and natural gas customers and end-users worldwide • 20,500 employees worldwide • Nearly $80.4 billion of assets(1) • $17.0 billion of revenue(1) • 32,500 miles of transmission lines AltaLink Benefits to BHE – Aligns well with core principles – Opportunity to expand footprint in Canada – Continues to diversify regional and regulated business mix – Expands our wires-only business – Provides additional opportunities to deploy capital and grow (1)Includes AltaLink assets as of Sept. 30, 2014 and revenue for the 12 months ended Sept. 30, 2014, excluding consolidation adjustments. Assumed exchange rate of $1.000 USD = $1.120 CAD
AltaLink Acquisition 8 AltaLink Service Territory ALBERTA, CANADA Calgary Edmonton • On May 1, 2014, BHE announced the acquisition of AltaLink from SNC- Lavalin Group Inc. – Purchase price of approximately CAD$3.2 billion (approximately USD$2.9 billion) – BHE’s shareholders have committed to provide the capital to fund the entire purchase price of AltaLink; however, BHE expects to fund the purchase price on a long-term basis with capital from Berkshire Hathaway and by issuing senior unsecured debt at BHE • AltaLink is a transmission only service provider providing transmission service at 69 kilovolts and higher – Supplies electricity to 3 million Albertans, 85% of Alberta’s population • AltaLink owns 60% of the transmission system in Alberta, Canada, with 12,000 km of lines and 280 substations – No volume or commodity exposure – Strong, stable regulatory environment – Revenue from AA- rated Alberta Electric System Operator (“AESO”) • In a May 2, 2014, release, DBRS acknowledged that AltaLink will benefit from the financial flexibility that comes with being a part of the BHE family • On May 5, 2014, S&P placed AltaLink Investments, L.P. (“AILP”), the holding company of operating company AltaLink, on positive outlook due to the strategic importance AILP will have with BHE • Transaction expected to close in late 2014, pending Alberta Utilities Commission (“AUC”) approval – AUC applies the no-harm test for the purpose of determining whether a transaction under review is in the public interest – Approval of the transaction by the Minister of Industry was granted on July 25, 2014, concluding that the transaction was “likely to be a net benefit to Canada” (1) Assumed exchange rate of $1.000 USD = $1.120 CAD AltaLink, L.P. Key Financial Inf rmation LTM ($USD in millions) (1) 9/30/2014 2013 2012 Revenue 617 477 363 Operating Income 310 231 164 Assets 6,366 5,233 3,648
AltaLink Ownership Structure 9 .01% A3/BBB+/BBB+ Aa2/AA/A+ 90% MidAmerican (Alberta) Canada Holdings Corp AltaLink Holdings, L.P. (AHLP) AltaLink Investments, L.P. (AILP) (S&P: BBB- ; DBRS: BBB) AltaLink, L.P. (ALP) (S&P: A- ; DBRS: A) AltaLink Management Ltd (AML) (General Partner) 99.99% 99.99% 99.99% AltaLink Investment Management Ltd (AIML) (General Partner) Note: The above ownership structure is a high-level summary and does not include all entities that are part of the transaction structure
AltaLink Regulatory Framework 10 • Located in a stable regulatory environment • AltaLink receives all regulated transmission tariffs from the AESO, including settlement of deferral and reserve accounts, under AUC regulated tariffs – AltaLink uses various AUC approved deferral and reserve accounts to track and true-up variances between forecasted approved revenue and actual amounts earned – Annual transmission tariffs from the AESO are received in equal monthly installments based on the AUC-approved revenue requirement • Tariffs based on cost-of-service regulatory model under a forward test year basis – CWIP approved for use in rate base – Current approved return on equity is 8.75% with an approved capital structure of 37% equity – Entitled to recover prudent forecast operating expenses, including depreciation and property taxes – Tariffs include recovery of income taxes that the AUC deems would have been paid if AltaLink was a tax-paying entity – Return on debt is approved by the AUC, based on a forecast cost of borrowing for the year applied to the approved debt portion of the capital structure • Allowed equity return is calculated by multiplying the mid-year investments in rate base and CWIP by the approved equity ratio and rate of return • AltaLink is a ring-fenced entity as required by the AUC • The province of Alberta passed legislation requiring that no transmission congestion should exist on the system Alberta Utilities Commission Transmission Facility Owners (TFO) Alberta Electric System Operator (AESO) Users (Distribution Companies, Direct Connects, Generators) Regulator Approves regulated transmission tariff e.g., AltaLink, ATCO, ENMAX, EPCOR, FortisAlberta TFO provides transmission service AESO provides open transmission access Users pay transmission tariff to AESO Not for profit supported by Province of Alberta (AAA/Stable/A-1+) AESO pays 12 equal monthly payments to TFOs equivalent to their approved revenue requirement
AltaLink Capital Investment Plan and Regulatory Update 11 • 2014 gross direct assigned capital expenditures are forecasted to be CAD$1.7 billion • The AESO’s 2011 Long Range Transmission System Plan identified the potential for CAD$13.5 billion in existing and proposed transmission development projects over the next 10 years – The need for the plan is driven by industrial load growth, increased wind generation development and general enhancements of grid reliability – AESO determines need and defends it in front of the AUC – AESO directs AltaLink to construct the project and determines the required in-service date – AltaLink files facilities application with the AUC – Upon AUC approval, Altalink constructs the project, including securing permitting and rights of way AltaLink Historical Rate Base and Capital Expenditures AltaLink Current Regulatory Proceedings • In January 2014, Altalink submitted a compliance filing to the AUC for approval of its final revenue requirements for 2013 and 2014, based on the conditions of the AUC’s November 2013 decision. In September 2014, the AUC approved the final revenue requirement with minimal adjustments • Altalink will file in November 2014, for a request to set its revenue requirement for 2015 and 2016 • Altalink will file in December 2014, to true up its deferral account balances for capital and other expenditures from 2012 and 2013 (CAD$ in millions) 2013 2012 2011 Mid-Year Rate Base 2,486 1,782 1,552 Mid-Year CWIP 1,159 794 397 Total 3,645 2,576 1,949 Annual Capital Expe ditures 1,720 975 619
Alberta Economic Overview 12 • The Alberta economy continues to post healthy economic growth • Housing starts and population growth are steady • Alberta electricity consumption is projected to grow at a 4.4% CAGR through 2020, primarily driven by oilsands load expansion growing at 11% CAGR Real GDP Growth(1) Alberta Electricity Consumption (GWh 000’s)(2) Alberta Housing Starts and Population Growth(1) 74 75 78 81 86 91 95 99 0 15 30 45 60 75 90 105 2013 2014f 2015f 2016f 2017f 2018f 2019f 2020f Industrial Oilsands Residential Commercial Farm (1) Sources: Statistics Canada, International Monetary Fund and Alberta Treasury Board and Finance Budget 2014 forecast (2) Source: AESO 2014 Long-term Outlook
AltaLink Transaction Approval Status 13 Required Approval Date of Filing Completion Competition Bureau – Canada May 21, 2014 June 4, 2014 Industry Canada – Investment Canada Act May 27, 2014 July 25, 2014 Alberta Utilities Commission (“AUC”) May 23, 2014 Final Decision Pending We expect to close by year end Key recent dates for AUC approval: • BHE’s Canadian subsidiary and applicants filed written arguments Sept. 25, 2014 • Reply arguments were submitted by the interveners Oct. 16, 2014 • BHE’s Canadian subsidiary and applicants filed rebuttal arguments Oct. 20, 2014, closing the AUC record
• Diversified portfolio of regulated assets – Weather, customer, regulatory, generation, economic and catastrophic risk diversity • Berkshire Hathaway ownership – Access to capital from Berkshire Hathaway allows us to take advantage of market opportunities – Berkshire Hathaway is a long-term holder of assets; its owner for life philosophy promotes stability and helps make BHE the buyer of choice in many circumstances – Tax appetite of Berkshire Hathaway has allowed us to realize significant tax benefits • No dividend requirement – Cash flow is retained in the business and used to help fund growth and strengthen our balance sheet BHE Competitive Advantage 14
Core Principles Six core principles are the moat Plan – Execute – Measure – Correct 15
Customer Service – Deliver Reliable and Cost-Effective Service 16 Mastio Results Interstate Pipelines 2003 2014 Kern River 10 1 Northern Natural Gas 43 2 TQS Results 2014 Top 5 Utilities on Overall Customer Satisfaction Rank Utility Very Satisfied 1 Southern Company 96.8% 2 Berkshire Hathaway Energy 93.4% 3 Portland General 90.5% 4 NV Energy 88.1% 5 We Energies 87.5% 49 Company name not available 40.0% Top 3 for the 11th consecutive year No. 1 for the 9th consecutive year
Employee Commitment – Improve Safety Culture and Work Environment 0 1 2 3 4 5 6 7 8 9 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Berkshire Hathaway Energy Incident Rate BHE Incident Rate 1.41 AltaLink NV Energy step change 34% improvement 2.16 Berkshire Hathaway Energy Businesses with Incident Rate ≤ 1.0 CalEnergy Philippines Northern Powergrid Northern Natural Gas Kern River MidAmerican Transmission MidAmerican Energy Company Rocky Mountain Power 19 years 11 years 5 years 2 years 2 years 1 year 1 year Industry Median Top Decile 17
Environmental Respect – Diversify to Prepare for the Future 18 Dec. 31, 2000 BHE Generation Capacity Mix (1) Sept. 30, 2014 BHE Generation Capacity Mix (1) (1) Net MW owned in operation and under construction Coal 36% Natural Gas 35% Nuclear and other 3% Wind 17% Hydro 4% Solar 5% • By the end of 2015, BHE will have invested over $15 billion in wind and solar renewable generation through MidAmerican Energy, PacifiCorp and MidAmerican Renewables • The acquisition of NV Energy further diversified our generation mix by adding more natural gas Coal 51% Natural Gas 27% Nuclear 7% Hydro 2% Geothermal, Solar, Wind 12% Other 1%
Environmental Respect – MidAmerican Renewables 19 Jumbo Road 300 MW – $408 million Imperial Valley 327 MW Wailuku Hydro Project 5 MW Pinyon Pines I and II 300 MW – $910 million Solar Star Projects 579 MWAC – $2.75 billion Bishop Hill II 81 MW – $188 million Agua Caliente 142 MWAC – $833 million Topaz Solar Farms 550 MWAC – $2.44 billion • Upon completion of all current projects, MidAmerican Renewables will have invested approximately $7.5 billion in wind and solar renewable generation
Regulatory Integrity – Achieve Balanced Outcomes Distributed Generation = Utility provides power and all grid services 51.9% of the time = Customer generates a portion of the required energy 20.3% of the time (power and grid support needed) = Customer generates all of the required energy and small amounts of excess energy 27.8% of the time (standby power and grid support needed) 25.2% 45.2% 26.7% DG Peak 2-4 PM Utility Peak 6 PM 10.8% 9.5% 27.8% Generation equals demand DG customer uses grid to export excess power 20
Regulatory Integrity – Achieve Balanced Outcomes Distributed Generation – BHE Views • 43 U.S. states; Washington, D.C.; and four U.S. territories allow customers to install DG and net meter (generating an offset to retail rates) – Net metering exists in all of BHE’s states except South Dakota • 51.9% of the time the DG customer is consuming power and fully relying on grid services – The DG customer must pay full retail rates during this period. Retail rates include fixed charges (customer service costs and distribution costs), demand-based charges (distribution costs and transmission costs) and variable energy charges (transmission costs and power generation costs) • 20.3% of the time the DG customer is consuming power and utilizing grid services, while generating a portion of the customer’s own power needs – The DG customer must pay for the power consumed (variable energy charge) and certain grid costs (fixed and demand-based charges) required to support the customer’s activities • 27.8% of the time the DG customer generates all of the energy requirements and small amounts of excess energy – The DG customer will receive the appropriate price for power delivered (at market price) and will pay certain grid costs ( fixed and demand charges) that support the customer’s activities 21
Regulatory Integrity – Achieve Balanced Outcomes Distributed Generation 22 Total Electric Customers as of July 31, 2014 Net Metered Customers as of July 31, 2014 Net Metered Portion of Total Customers South Dakota 4,622 0 0.00% California 44,733 171 0.38% Idaho 73,821 124 0.17% Illinois 85,131 15 0.02% Washington 127,909 195 0.15% Wyoming 138,714 181 0.13% Oregon 560,853 3,681 0.66% Iowa 655,483 152 0.02% Utah 833,797 2,872 0.34% Nevada 1,206,312 4,298 0.36% Total 3,731,375 11,689 0.31% Berkshire Hathaway Energy – Impact of Distributed Generation
Midwest Region(2) MidAmerican Energy Company $0.0672 Midwest Region $0.0927 Regulatory Integrity – Achieve Balanced Outcomes 23 Company Average Rate ($/kWh) Pacific Region(1) Pacific Power $0.0902 Nevada Power $0.1056 Pacific Region $0.1345 Mountain Region(1) Rocky Mountain Power $0.0777 Sierra Pacific Power $0.0914 Mountain Region $0.0948 Highest Average Rates ($/kWh) by State(1): Hawaii – $0.3308; New York – $0.1729; Massachusetts – $0.1582; Connecticut – $0.1548; New Hampshire – $0.1530 (1) Source: Edison Electric Institute (2) Source: U.S. Energy Information Administration
24 Projected Capital Expenditures Operational Excellence – Reinvesting in Our Business (1) Includes Wind IX investment of $279 million for 2015 1,091 1,093 906 1,643 1,504 458 670 557 536 2,298 905 54 322 142 149 548 479 508 $6,572 $4,680 $2,611 $0 $1,200 $2,400 $3,600 $4,800 $6,000 $7,200 2014 2015 2016 $ m il li o n s PacifiCorp MidAmerican Funding Northern Powergrid Holdings MidAmerican Renewables Pipelines and Other NV Energy (1)
25 Financial Strength – Pro Forma Revenue and EBITDA Diversification • Diversified revenue sources reduces regulatory concentrations • For the 12 months ended Sept. 30, 2014, 92% of Pro Forma EBITDA is from investment- grade regulated subsidiaries (1) Excludes HomeServices and equity income, which add further diversification; and includes AltaLink LTM, excluding consolidation adjustments (2) See Appendix for calculation of EBITDA; percentages exclude Corporate/other and include AltaLink Note: Assumed exchange rate of $1.000 USD = $1.120 CAD BHE LTM Sept. 30, 2014 Energy Revenue(1): $15.0 Billion PacifiCorp 33.7% NV Energy 14.8% MidAmerican Funding 13.5% Northern Powergrid 12.6% Pipelines 10.5% AltaLink 7.1% MidAmerican Renewables 5.4% HomeServices 2.4% BHE LTM Sept. 30, 2014 EBITDA(2): $6.3 Billion Iowa 17.5% Nevada 16.9% Utah 15.5% Oregon 8.4% Wyoming 6.0% Illinois 5.5% Washington 2.5% Idaho 2.5% FERC 7.1% United Kingdom 7.8% Alberta 4.1% Philippines 0.8% Other 5.4%
• Since being acquired by Berkshire Hathaway in March 2000, BHE has realized significant growth in its assets, net income and cash flows $6.5 $34.2 $37.6 $50.1 $53.0 $0 $10 $20 $30 $40 $50 $60 2001 2011 2012 2013 Sept. 2014 Billions $143 $1,331 $1,472 $1,636 $2,058 $0 $700 $1,400 $2,100 2001 2011 2012 2013 LTM 9/30/14 Millions $847 $3,220 $4,327 $4,669 $5,326 $0 $1,100 $2,200 $3,300 $4,400 $5,500 2001 2011 2012 2013 LTM 9/30/14 Millions $1.7 $14.1 $15.7 $18.7 $20.7 $0 $5 $10 $15 $20 2001 2011 2012 2013 Sept. 2014 Billions Net Income Attributable to BHE BHE Shareholders’ Equity Property, Plant and Equipment (Net) Cash Flows From Operations 26 Berkshire Hathaway Energy Financial Summary
Credit Metrics and Financial Strength 27 • BHE key credit ratios(1) – Credit ratios continue to be strong and supportive of our credit rating as business performance has remained resilient to challenging economic conditions in our industry and equity is retained and reinvested • Ratings (issuer or senior unsecured ratings unless noted) (1) Refer to the appendix for the calculations of key ratios (2) 2013 Adjusted Debt is Adjusted Debt Excluding NVE Related Debt (3) Ratings for PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Kern River Funding Corp., and AltaLink L.P are senior secured ratings LTM 9/30/14 2013 2012 2001 FFO Interest Coverage 4.5x 4.5x 4.6x 2.3x FFO to Adjusted Debt (2) 17.7% 18.9% 19.8% 9.1% Adjusted Debt to Total Capitalization 56.8% 58.1% 57.6% 72.2% Total Assets ($ billions) $74.0 $70.0 $52.5 $13.0 Moody’s S&P Fitch Berkshire Hathaway Energy A3 BBB+ BBB+ PacifiCorp (3) A1 A A MidAmerican Energy Company (3) Aa2 A A+ Nevada Power Company (3) A2 A A- Sierra Pacific Power (3) A2 A A- Northern Natural Gas Company A2 A- A Moody’s S&P Fitch DBRS Kern River Funding Corp. (3) 2 A- A- - Northern Powergrid (Northeast) 3 A- A- - Northern Powergrid (Yorkshire) 3 A- A - AltaLink L.P. (3) - A- - A AltaLink Investments L.P. - BBB- - BBB
Credit Metrics 28 Note: Refer to the appendix for the calculations of key ratios LTM 9/30/14 2013 2012 LTM 9/30/14 2013 2012 Regulated Utilities Regulated Pipelines PacifiCorp Northern Natural Gas FFO Interest Coverage 5.2x 5.0x 4.8x FFO Interest Coverage 7.8x 7.9x 6.3x FFO to Debt 22.6% 22.1% 21.3% FFO to Debt 33.5% 33.9% 30.8% Debt to Total Capitalization 48.1% 46.9% 47.3% Debt to Total Capitalization 41.2% 39.8% 41.1% MidAmerican Energy Kern River FFO Interest Coverage 5.7x 6.9x 7.7x FFO Interest Coverage 7.5x 7.2x 7.0x FFO to Debt 20.4% 24.9% 29.2% FFO to Debt 43.9% 40.5% 39.5% Debt to Total Capitalization 49.0% 48.0% 47.3% Debt to Total Capitalization 37.8% 39.8% 41.6% Nevada Power Company Regulated Distribution FFO Interest Coverage 4.2x 3.5x 4.1x Northern Powergrid FFO to Debt 18.4% 14.8% 20.2% FFO Interest Coverage 4.7x 4.2x 4.7x Debt to Total Capitalization 53.3% 55.3% 53.3% FFO to Debt 21.6% 17.9% 21.4% Debt to Total Capitalization 43.2% 45.2% 47.4% Sierra Pacific Power Company FFO Interest Coverage 5.5x 4.9x 5.2x FFO to Debt 21.9% 20.2% 23.3% Debt to Total Capitalization 52.6% 54.2% 53.2%
• Our businesses continue to perform well and are meeting or exceeding our expectations Financial Information ($ millions) 29 LTM Years Ended Nine Months Ended 9/30/2014 12/31/2013 12/31/2012 PacifiCorp 1,324$ 1,275$ 1,034$ MidAmerican Funding 443 357 369 NV Energy 640 (42) - Pipelines 455 446 465 Northern Powergrid Holdings 594 501 565 MidAmerican Renewables 324 223 93 HomeServices 113 129 62 Corporate/other (65) (54) (21) Total operating income 3,828 2,835 2,567 Interest expense (1,536) (1,219) (1,176) Interest expense on BHE subordinated debt (59) (3) - Capitalized interest 97 84 54 Allowance for equity funds 98 78 74 Other, net 71 66 56 Income before income tax expense and other 2,499 1,841 1,575 Income tax expense (389) (130) (148) Other (52) (75) 45 Net income attributable to BHE shareholders 2,058$ 1,636$ 1,472$
Retail Electric Sales – Weather Normalized 30 Year-to-Date September 30 Variance (GWh) 2014 2013 Actual Percent PacifiCorp Residential 11,607 11,217 390 3.5% Commercial 12,765 12,557 208 1.7% Industrial and Other 17,129 16,791 338 2.0% Total 41,501 40,565 936 2.3% MidAmerican Energy Residential 4,928 4,902 26 0.5% Commercial 3,114 3,121 (7) -0.2% Industrial and Other 9,138 8,608 530 6.2% Total 17,180 16,631 549 3.3% Nevada Power Residential 7,315 7,376 (61) -0.8% Commercial 3,457 3,388 69 2.0% Industrial and Other 5,861 5,871 (10) -0.2% Total 16,633 16,635 (2) 0.0% Sierra Pacific Power Residential 1,735 1,743 (8) -0.5% Commercial 2,262 2,257 5 0.2% Industrial and Other 2,149 2,095 54 2.6% Total 6,146 6,095 51 0.8% Northern Powergrid Residential 9,385 9,401 (16) -0.2% Commercial 4,305 4,346 (41) -0.9% Industrial and Other 13,645 13,828 (183) -1.3% Total 27,335 27,575 (240) -0.9%
Retail Electric Sales – Actual 31 Year-to-Date September 30 Variance (GWh) 2014 2013 Actual Percent PacifiCorp Residential 11,545 11,883 (338) -2.8% Commercial 12,846 12,839 7 0.1% Industrial and Other 17,185 16,930 255 1.5% Total 41,576 41,652 (76) -0.2% MidAmerican Energy Residential 4,993 5,057 (64) -1.3% Commercial 3,135 3,179 (44) -1.4% Industrial and Other 9,138 8,608 530 6.2% Total 17,266 16,844 422 2.5% Nevada Power Residential 7,436 7,592 (156) -2.1% Commercial 3,474 3,423 51 1.5% Industrial and Other 5,898 5,909 (11) -0.2% Total 16,808 16,924 (116) -0.7% Sierra Pacific Power Residential 1,746 1,794 (48) -2.7% Commercial 2,268 2,268 - 0.0% Industrial and Other 2,157 2,104 53 2.5% Total 6,171 6,166 5 0.1% Northern Powergrid Residential 9,210 9,642 (432) -4.5% Commercial 4,249 4,447 (198) -4.5% Industrial and Other 13,645 13,828 (183) -1.3% Total 27,104 27,917 (813) -2.9%
(1) Net MW owned in operation as of Sept. 30, 2014 (2) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities • Headquartered in Portland, Oregon • 6,000 employees • 1.8 million electric customers in six western states • 11,239 MW of owned generation capacity(1) • Owned generating capacity by fuel type: 9/30/14 3/31/06 – Coal 55% 72% – Natural gas 25% 13% – Hydro(2) 10% 14% – Wind, geothermal and other(2) 10% 1% PacifiCorp 32
PacifiCorp – Business Update 33 • Higher retail prices approved by regulators, primarily to recover capital investments and higher energy costs – Multi-party settlement approved in Utah general rate case for a two-step increase – $35 million, or 2%, in the first year and $19 million, or 1%, in the second year – Separate tariff rider for Lake Side 2 approved in Oregon for an increase of $22 million, or 2% – Multi-party settlement approved in Utah Energy Balancing Account filing to recover $25 million of deferred net power costs over a 12-month period beginning in November 2014 • Actual retail load for the nine months ended Sept. 30, 2014, was 41,576 gigawatt-hours, a 0.2% decrease versus the first nine months of 2013, due to unfavorable weather impacts offsetting higher retail customer usage • Lake Side 2, a 645-MW natural gas-fueled plant (combined-cycle combustion turbine), next to the original Lake Side plant located near Vineyard, Utah, was placed in-service in May 2014 • Sigurd-to-Red Butte transmission line is under construction in Utah, with completion expected in 2015 • PacifiCorp and the California ISO Corporation implemented a new energy imbalance market – Expected to reduce costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrate renewables, and enhance reliability through improved situational awareness and responsiveness – Parallel operations phase successfully launched Oct. 1, 2014, and full market launch Nov. 1, 2014
• Headquartered in Des Moines, Iowa • 3,600 employees • 1.4 million electric and natural gas customers in four Midwestern states • 8,444 MW(1) of owned generation capacity • Owned generating capacity by fuel type: 9/30/14(1) 12/31/00 – Coal 40% 70% – Natural gas 15% 19% – Wind(2) 40% 0% – Nuclear and other 5% 11% MidAmerican Energy 34 SOUTH DAKOTA NEBRASKA KANSAS MISSOURI ILLINOIS WISCONSIN MINNESOTA IOWA MidAmerican Energy Service Territory Major Generating Facilities Wind Projects Wind Projects Under Construction (1) Net MW owned in operation and under construction as of Sept. 30, 2014 (2) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities
MidAmerican Energy – Business Update 35 • Final rates associated with an Iowa electric rate increase filed May 17, 2013, were implemented July 31, 2014, resulting in a phased-in increase to base rates of $135 million at annualized amounts of $45 million (3.6%) effective August 2013, $45 million effective January 2015, and $45 million effective January 2016; and adjustment clauses for retail energy, including the pre-tax value of federal production tax credits, and Midcontinent Independent System Operator (MISO) transmission costs • Illinois electric rate increase filed Dec. 16, 2013, requesting annualized increase to base rates of $22 million and the creation of a new adjustment clause for recovery of certain electric transmission charges. On Nov. 7, 2014, the ICC issued an order approving a retail electric base rate increase for MidAmerican Energy's Illinois customers. The order authorizes MidAmerican Energy to increase rates by $16 million, or 10%, annually and to implement the new adjustment clause for the recovery of electric transmission charges. New rates and the adjustment clause are expected to go into effect by Dec. 1, 2014 • Customer growth, improved industrial sales, and colder winter weather helped offset milder summer weather, resulting in an increase to actual retail electric sales to 17,266 gigawatt-hours for the nine months ended Sept. 30, 2014, a 2.5% increase over the same period for 2013 • Currently constructing 1,050 MW (nominal ratings) of wind-powered generation facilities in Iowa. As of Sept. 30, 2014, MidAmerican Energy has placed in-service 194 MW of wind-powered generating facilities and expects to place an additional 361 MW (nominal ratings) in-service in 2014 and 495 MW (nominal ratings) in-service in 2015, with a cost cap of $1.9 billion established by the Iowa Utilities Board • Currently constructing transmission lines in Iowa and Illinois that are anticipated to go into service in 2015-2018, with an estimated cost of $550 million; projects have been designated as Multi-Value Projects by MISO • Wind IX Project – In October 2014, filed an application with the IUB for ratemaking principles related to the construction of up to 162 MW of additional wind-powered generating facilities expected to be placed in-service by the end of 2015. The filing, which is subject to IUB approval, establishes a cost cap of $279 million • The Louisa Generating Station and Walter Scott, Jr. Energy Center earned recognition through Navigant’s Generation Knowledge Service Plant Operational Excellence Awards. The awards recognize coal-fueled plants that have demonstrated excellence in cost and operational management, as well as improved performance and reliability over the most recent five-year period
• Headquartered in Las Vegas, Nevada • 2,400 employees • 1.2 million electric customers and 200,000 natural gas customers • Provides service to 90% of the Nevada population of 2.8 million, along with a tourist population of 40 million • 6,078 MW(1) of owned generation capacity • Owned generating capacity by fuel type(1) : – Natural gas 82% – Coal 18% NV Energy 36 (1) Net MW owned in operation as of Sept. 30, 2014 NV Energy Electric Service Territory CALIFORNIA ARIZONA UTAH NEVADA NV Energy Gas Service Territory Coal Plants Natural Gas Plants Energy Recovery Plant
NV Energy – Business Update 37 • Nevada Power Company filed a general rate change application May 2014; the Public Utilities Commission of Nevada approved a settlement agreement October 2014, resulting in no change in Nevada Power Company’s general revenue requirement • Nevada Power Company submitted an emissions reduction capacity replacement plan to the Public Utilities Commission of Nevada in May 2014 – The plan included the retirement of approximately 800 MW of coal generation and the replacement of that generation through the acquisition of existing natural gas fueled generation (Las Vegas Cogeneration Units 1 and 2 and Sun-Peak) and renewable energy generation (Nellis Solar Project and the Moapa Solar Project) – On Oct. 28, 2014, the Public Utilities Commission of Nevada issued an order modifying Nevada Power Company’s plan, in part, by excluding the 200 MW Moapa Solar Project – Nevada Power Company is assessing the impact of this modification on its emissions reduction capacity replacement plan. – Under the applicable statutes, Nevada Power Company can (1) file a motion for reconsideration; (2) accept the modified plan approved by the Public Utilities Commission of Nevada or (3) withdraw its plan and file a new plan within 180 days • In August 2014, the Public Utilities Commission of Nevada approved the companies’ request to optimize generation assets by participating in the energy imbalance market organized by the California ISO; the companies are slated to begin participation in October 2015 • In March 2015, the companies will present to the Public Utilities Commission of Nevada the results of jointly dispatching the northern and southern generation fleets, which has reduced the overall cost of providing electric service to customers • Nevada Power Company will file its triennial integrated resource plan before July 1, 2015, which will address the long- term resource needs of southern Nevada
• 14,700 miles of natural gas pipeline • 5.5 Bcf per day of market area design capacity, plus 2.0 Bcf per day field area capacity • More than 73 Bcf firm service and operational storage cycle capacity • 90% of 2014 transportation and storage revenue based on demand charges through Sept. 30, 2014 • Increased the integrity and reliability of the pipeline while managing operating costs and staffing • Ranked No. 1 among 16 mega-pipelines and No. 2 among 42 interstate pipelines in 2014 Mastio & Company survey for customer satisfaction • Excellent performance during Polar Vortex this past winter – January and February 2014 were 27% colder than normal, compared to 4% colder than normal for 2013 and 14% warmer than normal for 2012 – Averaged 675,000 Dth/day more than 2013 and 945,000 Dth/day more than 2012 in January and February – Peak day on Jan. 6, 2014, of 5.14 Bcf – 7% higher than previous peak of 4.82 Bcf – Worked with customers to deliver unscheduled natural gas of up to 300,000 Dth/day when an upstream pipeline ruptured Northern Natural Gas 38 MINNESOTA WISCONSIN IOWA SOUTH DAKOTA NEBRASKA KANSAS OKLAHOMA TEXAS
• 1,700 miles of natural gas pipeline • Design capacity of 2.2 million Dth per day of natural gas • 95% of 2014 revenue is based on demand charges through Sept. 30, 2014 • Kern River delivered nearly 23%(1) of California’s demand for natural gas • Ranked No. 1 among 42 interstate pipelines in 2014 Mastio & Company survey for customer satisfaction Kern River 39 CALIFORNIA NEVADA ARIZONA UTAH WYOMING (1) 2014 California Gas Report
Leeds Edinburgh Middlesbrough Newcastle Upon Tyne Sheffield York Northeast Yorkshire • 3.9 million end-users in northern England • 93,750 kilometers of distribution lines • Approximately 67% of 2014 distribution revenue from residential and commercial customers through Sept. 30, 2014 • Distribution revenue (£ millions) • U.K. Distribution Price Control Review 5 commenced in April 2010; plans are being executed and are delivering out-performance • In July 2014, draft determinations were received from the regulator for the next price control, Electricity Distribution 1, commencing in April 2015 under the RIIO framework. Final determinations are expected in November 2014 Nine Months Ended 9/30/14 9/30/13 Residential 254 237 Commercial 92 86 Industrial 163 148 Other 9 7 Total 518 478 Northern Powergrid 40
MidAmerican Renewables 41 (1) Based on net owned capacity of 3,405 MW in operation and under construction as of Sept. 30, 2014 (2) 82% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under long-term power purchase agreements expiring in 2016 through 2026. Certain long-term power purchase agreement renewals have been entered into with other parties that expire in 2039 MidAmerican Solar Geothermal Plants Natural Gas Plants MidAmerican Wind MidAmerican Hydro CalEnergy Philippines Solar 37% Wind 20% Geothermal 10% Hydro 4% Natural Gas 29% Portfolio Composition (1) 2013-2015 11% 2016-2026 25% 2027+ 64% Contract Maturities (1) Location Installed PPA Expiration Offtaker Net or Contract Capacity (MW) Net Owned Capacity (MW) SOLAR Solar Star I & II CA 2013-2015 2035 SCE 579 579 Topaz CA 2013-2015 2040 PG&E 550 550 Agua Caliente AZ 2012-2013 2039 PG&E 290 142 1,419 1,271 WIND Pinyon Pines I & II CA 2012 2035 SCE 300 300 Bishop Hill II IL 2012 2032 Ameren 81 81 Jumbo Road TX 2015 2033 Austin Energy 300 300 681 681 GEOTHERMAL Imperial Valley Projects CA 1982-2000 (2) (2) 327 327 HYDROELECTRIC Casecnan Project Phil. 2001 2021 NIA 150 128 Wailuku HI 1993 2023 Hawaii Electric 10 5 160 133 NATURAL GAS Cordova IL 2001 2019 Exelon 551 551 Power Resources TX 1988 2015 EDF Trading 212 212 Saranac NY 1994 2015 TransAlta Energy Mktg 240 180 Yuma AZ 1994 2024 SDG&E 50 50 1,053 993 Total Owned and Under Construction 3,640 3,405
MidAmerican Renewables Update 42 Topaz • Comprises 22 blocks of solar panels, with a nominal facility capacity of 586 MW • As of Sept. 30, 2014, the project was 99% constructed compared to the engineering, procurement and construction schedule of 83%, and 100% of the 8.44 million solar panels have been installed • As of Sept. 30, 2014, 556 MW have been placed in-service under the construction contract, and 542 MW were operating and delivering energy under the power purchase agreement • Construction and commissioning are approximately four months ahead of schedule, and MidAmerican Solar expects the project to reach substantial completion in fourth quarter 2014, with final completion expected in March 2015 • The project is being constructed pursuant to a fixed-price, date-certain, turn-key engineering, procurement and construction contract with a subsidiary of First Solar Solar Star I and II • Comprises 13 blocks of solar panels, with a capacity of 579 MW • As of Sept. 30, 2014, the projects were approximately 80% constructed compared to the engineering, procurement and construction schedule of 72%, which includes 1.39 million solar panels installed out of an expected total of 1.72 million • As of Sept. 30, 2014, 389 MW were operating and delivering energy under the power purchase agreements, including 243 MW placed in-service under the construction contract • On Oct. 1, 2014, an additional 56 MW were placed in-service under the construction contract, bringing the total placed in-service to 299 MW • The Solar Star Projects expect to place an additional 54 MW in-service in 2014 and 226 MW in-service in 2015 • The projects are being constructed pursuant to fixed-price, date-certain, turn-key engineering, procurement and construction contracts with a subsidiary of SunPower Corporation Jumbo Road • Comprises 162 General Electric Company 1.85 MW wind turbines, with a total capacity of 300 MW • On-site construction was initiated in 2013, and as of Sept. 30, 2014, 39 foundations have been installed and four turbines have been erected • The project is being constructed pursuant to fixed-price agreements that include a turbine supply agreement with General Electric Company, a main power transformer purchase agreement with GE Prolec Transformers Inc. and a balance of plant construction contract with Blattner Energy, Inc. • The project is expected to achieve commercial operation by the end of first quarter 2015 CE Generation • In June 2014, BHE, through wholly owned subsidiary MidAmerican Geothermal LLC, acquired the remaining 50% interest in CE Generation, adding 163 MW of geothermal generation and 221 MW of natural gas fueled generation to the portfolio
• BHE – Plans a late fourth quarter 2014 or early 2015 debt offering to fund a portion of the acquisition of AltaLink • PacifiCorp – Anticipates a $250 to $300 million debt financing in 2015 • MidAmerican Energy – Anticipates a $650 million debt financing in 2015 • Nevada Power Company – Planning a debt issuance in first quarter 2015, primarily to repay a $250 million maturity on Jan. 15, 2015 Near-Term Financing Plan 43
Other Joint Development Opportunities 44 Project Location Cost Description Electric Transmission Texas Texas $2.1b in current rate base, approximately $3.0b in total investment planned 50% ownership in joint venture with subsidiary of American Electric Power. Various projects throughout Texas Prairie Wind Transmission Kansas $161.5m 25% ownership in joint venture with Westar Energy and subsidiary of American Electric Power. The 345-kV project is complete and energized Gates to Gregg California $168.6m 50% ownership of 230-kV transmission line assets currently in development with Pacific Gas & Electric TransCanyon Arizona & California $338.0m 50% ownership in joint venture with subsidiary of Pinnacle West Capital Corporation. Delaney-to-Colorado River 500-kV project approved by California ISO in July 2014, competitive solicitation due on Nov. 19, 2014 TAMA Transmission (Fort McMurray) Alberta, Canada (Not disclosed) 50% ownership in joint venture with subsidiary of TransAlta. Competitive solicitation underway with the winning company to be selected in December 2014. 500-kilometer, 500-kV project TAMA – Generation Alberta, Canada N / A Emphasis continues to be placed on smaller cogeneration projects with solid long-term power purchase agreement arrangements; several projects are under development
Appendix
Organizational Structure 46 (1) The acquisition of AltaLink is expected to close in December 2014, subject to approval by the Alberta Utilities Commission (2) Ratings for PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, and Kern River Funding Corp. are senior secured rating A3/BBB+/BBB+ Aa2/AA/A+ 90% Nevada Power Company A2/A/A-(2) Regulated Electric Utility Sierra Pacific Power Company A2/A/A-(2) Regulated Electric and Gas Utility A1/A/A(2) Regulated Electric Utility Aa2/A/A+(2) Regulated Electric and Gas Utility 2013 Berkshire Hathaway Inc. ($ billions) Revenue $ 182.2 Net Income $ 19.5 Equity $ 221.9 2013 BHE ($ billions) Revenue $ 12.6 Net Income $ 1.6 Equity $ 18.7 A2/A-/A-(2) Regulated Natural Gas Transmission A2/A-/A Regulated Natural Gas Transmission Baa1/BBB+/A- Holding Company Baa2/BBB/BBB- Holding Company A-/A S&P, DBRS Alberta Canada Regulated Transmission Real Estate Brokerage and Franchises Regulated Electricity Transmission Contracted Non-utility Power Generation CE Casecnan Water and Energy Northern Powergrid (Northeast) Ltd. A3/A-/A- U.K. Regulated Electric Distribution Northern Powergrid (Yorkshire) plc A3/A-/A U.K. Regulated Electric Distribution
• Utah 2014 General Rate Case: – A multi-party stipulation that provides for a two-step rate increase was approved by the commission in August 2014 – The first increase of $35 million, or 2%, was effective September 2014, and the second increase of $19 million, or 1%, will be effective the later of September 2015 or the in- service date of the Sigurd-to-Red Butte transmission line – Includes recovery of PacifiCorp’s investment in Lake Side 2, which was placed in service in May 2014 and the Mona-to-Oquirrh transmission line, which was placed in service in May 2013 – The stipulation specifies that the Sigurd-to-Red Butte transmission line investment is prudent and that cost recovery will occur in the Step 2 rate change – The stipulation also specifies that PacifiCorp will not otherwise seek any rate increase in Utah (a) prior to Jan. 1, 2016, or (b) with a rate effective date prior to Sept. 1, 2016, with the exception of the year 2 increase and other commission-approved and currently existing rate adjustment mechanisms Rocky Mountain Power Regulatory Accomplishments 47
Rocky Mountain Power Regulatory Accomplishments 48 • Utah (continued) Energy Balancing Account (EBA): – All-party stipulation that provides for recovery of $25 million of deferred net power costs was approved by the commission in October 2014 – Collection of this amount will be combined with the remaining deferral balances currently being collected in the EBA of $19 million, with the total balance of $44 million to be collected over a 12-month period beginning in November 2014 Renewable Energy Credit (REC) Balancing Account: – PacifiCorp’s request for recovery of $17 million over a three-year period was approved by the commission, with rates effective June 2014
• Wyoming 2014 General Rate Case: – In March 2014, PacifiCorp filed a general rate case requesting an annual increase of $36 million, or 5%, which was revised in rebuttal testimony to $32 million, or 5%, in September 2014 – Includes recovery of PacifiCorp’s investment in Lake Side 2, the Mona-to-Oquirrh transmission line and the Sigurd-to-Red Butte transmission line – Hearings were held by the commission in October 2014 – If approved by the commission, new rates will be effective January 2015 Energy Cost Adjustment Mechanism (ECAM) and REC and Sulfur Dioxide Revenue Adjustment Mechanism (RRA): – PacifiCorp’s annual ECAM application requesting $17 million for recovery of deferred net power costs and RRA application requesting a $4 million increase in the RRA surcharge (combined total price increase of 3%) were approved by the commission on an interim basis effective May 2014, and hearings on the final increase were held in November 2014 Rocky Mountain Power Regulatory Accomplishments 49
• Idaho Energy Cost Adjustment Mechanism: – The commission approved recovery of $12 million of deferred net power costs, of which $7 million will be collected over a 12-month period and the remainder collected over a 24-month period, with new rates effective April 2014 Rocky Mountain Power Regulatory Accomplishments 50
• Oregon Transition Adjustment Mechanism: – In October 2014, the commission approved an all-party stipulation for an annual increase of $10 million, or 1%, effective January 2015, subject to market updates through November 2014 Lake Side 2 Tariff Rider: – A separate tariff rider for recovery of $22 million, or 2%, for the Oregon-allocated costs of PacifiCorp’s investment in Lake Side 2 was approved by the commission effective June 2014 – The separate tariff rider was a key provision of the all-party stipulation in the 2013 Oregon general rate case 2013 General Rate Case: – In December 2013, the commission approved the 2013 general rate case stipulation for an annual increase of $24 million, or 2%, effective in January 2014 Pacific Power Regulatory Accomplishments 51
• Washington 2014 General Rate Case: – In May 2014, PacifiCorp filed a general rate case requesting an annual increase of $27 million, or 8%, effective March 2015 – The case also includes the consolidation of four deferred accounting applications that were filed for an additional increase of $7 million REC Revenue Litigation: – In June 2014, a stipulation was achieved settling the appeal of PacifiCorp’s 2010 general rate case order related to the disposition of historical revenues from the sale of renewable energy credits – The settlement provided for a one-time customer credit totaling $13 million, which the commission approved through a separate tariff schedule – As a result of the settlement, the appeal of the commission’s 2010 general rate case order was withdrawn Pacific Power Regulatory Accomplishments 52
• Washington (continued) REC Tracking Mechanism: – In October 2014, PacifiCorp filed for a temporary rate increase of $5 million, or 2%, to recover the amount of RECs reflected in customers’ rates in excess of actual RECs sold from April 3, 2011 through Dec. 31, 2013 – If approved by the commission, the new rates will be effective November 2014 and will remain in effect for approximately one year 2013 General Rate Case: – In December 2013, the commission approved an annual increase of $17 million, or 6%, effective December 2013 – PacifiCorp filed a petition for judicial review of the commission’s December 2013 order, challenging the commission’s rejection of PacifiCorp’s proposed recovery of Washington’s share of the costs associated with power purchase agreements with renewable energy qualified facilities located in California and Oregon and the commission’s approval of a hypothetical capital structure for PacifiCorp Pacific Power Regulatory Accomplishments 53
• California Post Test-Year Adjustment Mechanism (PTAM): – In October 2014, PacifiCorp filed its PTAM attrition adjustment for 2015 requesting an increase of $1 million, or 1%, with the new rates to be effective January 2015, subject to approval by the commission – The commission approved a rate increase of $2 million, or 2%, to add Lake Side 2 and the Hunter Unit 1 emissions control equipment to rates effective August 2014, pursuant to PacifiCorp’s PTAM for major capital additions – The PTAM attrition adjustment for 2014 was approved by the commission effective January 2014, for a rate increase of $1 million, or 1% Energy Cost Adjustment Clause (ECAC): – In August 2014, the commission approved an all-party stipulation in the 2014 ECAC application, which resulted in no change in customer rates – In August 2014, PacifiCorp filed for a rate increase of $5 million, or 4%, in the 2015 ECAC application, with new rates to be effective January 2015, subject to approval by the commission General Rate Case Filing Extension: – In June 2014, the commission approved an all-party settlement agreement for an extension of the PTAM attrition factor for 2016 in exchange for PacifiCorp not filing a general rate case with a 2016 test period – As a result of the settlement, PacifiCorp’s next California general rate case will be filed no earlier than November 2015, allowing for six years between rate case filings (last general rate case was filed in November 2009) Pacific Power Regulatory Accomplishments 54
• The Environmental Protection Agency re-proposed standards for greenhouse gas emissions from new fossil-fueled electric generating units in January 2014 • EPA issued proposed standards for greenhouse gas emissions from modified and reconstructed fossil- fueled facilities and existing units on June 2, 2014 • MidAmerican Energy is subject to the Cross-State Air Pollution Rule • Neither PacifiCorp nor NV Energy are subject to the Cross-State Air Pollution Rule; emission reduction projects are based on regional haze requirements at PacifiCorp and state law (SB123) at NV Energy • EPA issued final federal implementation plans for regional haze in Wyoming and Arizona – EPA’s final action (for NOx and PM) in Wyoming requires SCR at the Wyodak plant by March 2019 and requires Dave Johnston Unit 3 to either install SCR by March 2019 or commit to retire the unit in 2027 – The state of Wyoming and PacifiCorp have appealed the decision; the matter is currently stayed – EPA’s action in Arizona (for NOx and PM) is currently being litigated; compliance deadline for installation of SCR on Cholla Unit 4 remains Dec. 5, 2017; alternatives are under discussion • EPA issued a final rule on the Utah regional haze plan in December 2012 – Final rule approved the plan regarding SO2, disapproved the plan regarding NOx and PM, but did not issue a federal implementation plan; EPA has the ability to issue a federal implementation plan within two years, unless the state submits an approvable plan – Utah is submitting a new state implementation plan with a new analysis; public comment period on the Utah Department of Environmental Quality’s proposal closes in early December 2014 Environmental Update 55
• Of BHE’s nearly 10,580 MW(1) of owned coal-fueled generation: – 98% of generation has low-NOx burners and/or over-fire air for nitrogen oxides controls – 93% of generation has scrubbers for sulfur dioxide control – 8% of generation has activated carbon injection for mercury controls; an additional 17% meets the mercury emissions requirements of the Mercury and Air Toxics Standards without the need for additional controls – 64% of generation has baghouses for particulate matter control • To ensure timely compliance, BHE continues to review proposed regulations and legislation and analyze associated current impacts of environmental requirements on the coal-fueled fleet Consolidated Environmental Position 56 (1) Net owned capacity as of Sept. 30, 2014
Environmental Respect – Reducing Coal Fleet Coal MW as of Sept. 30, 2014 10,580 MW Reid Gardner 1-4(1) (557) MW Neal 1 and 2 (401) MW Cholla Unit 4 gas conversion (395) MW Naughton 3 gas conversion (330) MW Navajo(2) (255) MW Carbon 1 and 2 (172) MW Riverside gas conversion (134) MW Walter Scott 1 and 2 (120) MW Coal MW as of Dec. 31, 2025 8,216 MW • Through fuel switching and retirements, BHE’s utilities expect to eliminate 2,364 MW of coal generation over the next 11 years 57 (1) Subject to PUCN approval (2) NV Energy is divesting its interest
• Of PacifiCorp’s 6,150 MW(1) of owned coal-fueled generation: – 94% of generation has nitrogen oxides controls with low-NOx burners and over-fire air – 94% of generation has scrubbers for sulfur dioxide control – 57% of generation has baghouses for particulate matter control – 40% of generation meets the mercury emissions requirements of the Mercury and Air Toxics Standards • Following completion of plans to retire or convert 502 MW of coal-fueled generation by year-end 2018, 96% of coal-fueled generation will be controlled by scrubbers and 62% will be controlled by baghouses; 100% of coal-fueled generation will meet mercury emissions requirements by April 2015 – Plan to retire Carbon Units 1 and 2 (172 MW) in April 2015 and convert Naughton Unit 3 (330 MW) to natural gas by July 2018(2) • Environmental capital expenditures forecast(3) ($ millions): 2014 2015 2016 2017 $161 $121 $73 $30 PacifiCorp Environmental Position (1) Net owned capacity as of Sept. 30, 2014 (2) Natural gas conversion of Naughton Unit 3 is expected to be deferred to 2018, pending EPA approval (3) Environmental capital expenditures forecast includes PacifiCorp’s share of minority-owned Craig, Colstrip and Hayden plants, excluding AFUDC 58
• Of MidAmerican Energy’s 3,357(1) MW of owned coal-fueled generation: – 100% of generation has nitrogen oxides controls • Low-NOx burners and/or over-fire air on all units • One selective catalytic reduction system on Walter Scott, Jr. Energy Center Unit 4 • Two non-selective catalytic reduction systems on Neal Energy Center Unit 3 and Unit 4 – 71% of generation has scrubbers and baghouses for sulfur dioxide control – 20% of generation has activated carbon injection for mercury control • By 2017, after conversion to natural gas or retirement of 655 MW of operated coal- fueled generation, 100% of coal-fueled generation controlled with scrubbers, baghouses and mercury controls, and 57% with post combustion NOx controls – Plan to retire Walter Scott, Jr. Energy Center Units 1 and 2 (120 MW) in 2015 and Neal Energy Center Units 1 and 2 (401 MW) in 2016. Riverside (134 MW) will cease burning coal and operate solely on natural gas in 2015 • Environmental capital expenditures forecast(2) ($ millions): 2014 2015 2016 $ 94 $ 49 $ 56 MidAmerican Energy Environmental Position 59 (1) Net owned capacity as of Sept. 30, 2014 (2) Environmental capital expenditures forecast excludes AFUDC
• Of approximately 1,073(1) MW of owned coal-fueled generating capacity, 812 MW is anticipated to be retired or eliminated – Reid Gardner Units 1-4 (557 MW total) between 2014 and 2017, subject to regulatory approval – Navajo Units 1-3 (255 MW) in 2019 • Tracy Units 1 (53 MW) and 2 (83 MW) (gas/oil fueled) are expected to retire in 2014 NV Energy Environmental Position 60 (1) Net owned capacity as of Sept. 30, 2014
Financial Information 61 ($ millions) LTM Years Ended Nine Months Ended Operating Revenue 9/30/2014 12/31/2013 12/31/2012 PacifiCorp 5,271$ 5,147$ 4,882$ MidAmerican Funding 3,774 3,413 3,247 NV Energy 2,531 (20) - Pipelines 1,067 952 968 Northern Powergrid Holdings 1,176 1,025 1,035 MidAmerican Renewables 567 355 166 HomeServices 2,088 1,809 1,312 Corporate/other (101) (46) (62) Total operating revenue 16,373$ 12,635$ 11,548$
Financial Information 62 ($ millions) LTM Years Ended Nine Months Ended Depreciation and Amortization 9/30/2014 12/31/2013 12/31/2012 PacifiCorp 729$ 692$ 655$ MidAmerican Funding 353 403 393 NV Energy 283 - - Pipelines 194 190 193 Northern Powergrid Holdings 201 180 174 MidAmerican Renewables 120 71 33 HomeServices 33 33 19 Corporate/other (8) (9) (12) Total depreciation and amortization 1,905$ 1,560$ 1,455$
Financial Information 63 ($ millions) LTM Years Ended Nine Months Ended Interest Expense 9/30/2014 12/31/2013 12/31/2012 PacifiCorp 388$ 390$ 393$ MidAmerican Funding 197 174 167 NV Energy 211 - - Pipelines 77 80 92 Northern Powergrid Holdings 150 141 139 MidAmerican Renewables 170 138 70 HomeServices 5 3 - Corporate/other 397 296 315 Total interest expense 1,595$ 1,222$ 1,176$
(1) Excludes amounts for non-cash equity allowances for funds used during construction and other non-cash items (2)Excludes costs for which payment is not contractually due until a future period of $406 million for the year ended Dec. 31, 2012 Financial Information 64 ($ millions) LTM Years Ended Nine Months Ended Capital Expenditures (1) 9/30/2014 12/31/2013 12/31/2012 PacifiCorp 1,090$ 1,065$ 1,346$ MidAmerican Funding(2) 1,396 1,027 645 NV Energy 264 - - Pipelines 240 177 152 Northern Powergrid Holdings 667 675 454 MidAmerican Renewables 1,794 1,329 770 HomeServices 22 21 8 Corporate/other 9 13 5 Total capital expenditures 5,482$ 4,307$ 3,380$
Financial Information 65 ($ millions) Total Assets 9/30/2014 12/31/2013 12/31/2012 PacifiCorp 23,068$ 22,885$ 22,973$ MidAmerican Funding 15,013 13,992 13,355 NV Energy 14,672 14,233 - Pipelines 4,845 4,908 4,865 Northern Powergrid Holdings 7,151 6,874 6,418 MidAmerican Renewables 5,517 3,875 3,342 HomeServices 1,469 1,381 899 Corporate/other 2,287 1,852 615 Total assets 74,022$ 70,000$ 52,467$
• As of Sept. 30, 2014, approximately 89% of total debt was fixed-rate debt • As of Sept. 30, 2014, long-term adjusted debt had a weighted average life of approximately 14 years and a weighted average interest rate of approximately 5.3% Capitalization 66 ($ millions) BHE Debt to Capitalization Comparison 9/30/2014 12/31/2013 Short-term debt 594$ 232$ Current portion of long-term debt 728 1,188 BHE senior debt 6,366 6,366 Subsidiary debt 22,676 21,864 Total adjusted debt 30,364 29,650 BHE junior subordinated debentures 2,294 2,594 Noncontrolling interests 122 105 BHE shareholders' equity 20,650 18,711 Total capitalization 53,430$ 51,060$ Adjusted debt/capitalization 56.8% 58.1%
Non-GAAP Financial Measures Berkshire Hathaway Energy 67 (1) As a result of changes in accounting guidance, certain amounts have been reclassified to conform to the other periods presented (2) FFO Interest Coverage equals the sum of FFO and Adjusted Interest divided by Adjusted Interest (3) Debt includes short-term debt, BHE senior debt, BHE subordinated debt and subsidiary debt (including current maturities) (4) FFO to Adjusted Debt Excluding NVE Related Debt equals FFO divided by Adjusted Debt Excluding NVE Related Debt (5) Adjusted Debt to Total Capitalization equals Adjusted Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 2001 (1) Net cash flows from operating activities 5,326$ 4,669$ 4,327$ 847$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 52 (449) (40) (196) FFO 5,378$ 4,220$ 4,287$ 651$ Adjusted Interest Interest expense 1,595$ 1,222$ 1,176$ 587$ Interest expense on subordinated debt (59) (3) - (88) Adjusted Interest 1,536$ 1,219$ 1,176$ 499$ FFO Interest Coverage (2) 4.5x 4.5x 4.6x 2.3x Adjusted Debt Debt(3) 32,658$ 32,244$ 21,622$ 8,050$ Subordinated debt (2,294) (2,594) - (888) Adjusted Debt 30,364$ 29,650$ 21,622$ 7,162$ NVE Acquisition Financing Debt (2,000) NVE Subsidiary Debt (5,296) Adjusted Debt Excluding NVE Related Debt 22,354$ FFO to Adjusted Debt Excluding NVE Related Debt (4) 17.7% 18.9% 19.8% 9.1% Capitalization Total BHE shareholders’ equity 20,650$ 18,711$ 15,742$ 1,708$ Adjusted debt 30,364 29,650 21,622 7,162 Subordinated debt 2,294 2,594 - 888 Noncontrolling interests 122 105 168 165 Capitalization 53,430$ 51,060$ 37,532$ 9,923$ Adjusted Debt to Total Capitalization (5) 56.8% 58.1% 57.6% 72.2%
Non-GAAP Financial Measures PacifiCorp 68 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 Net cash flows from operating activities 1,613$ 1,553$ 1,627$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions (14) (34) (169) FFO 1,599$ 1,519$ 1,458$ Interest expense 378$ 379$ 380$ FFO Interest Coverage (1) 5.2x 5.0x 4.8x Debt (2) 7,076$ 6,877$ 6,861$ FFO to Debt (3) 22.6% 22.1% 21.3% Capitalization PacifiCorp shareholders’ equity 7,640$ 7,787$ 7,644$ Debt 7,076 6,877 6,861 Capitalization 14,716$ 14,664$ 14,505$ Debt to Total Capitalization (4) 48.1% 46.9% 47.3%
Non-GAAP Financial Measures MidAmerican Energy 69 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 Net cash flows from operating activities 829$ 735$ 1,276$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions (4) 151 (323) FFO 825$ 886$ 953$ Interest expense 174$ 151$ 143$ FFO Interest Coverage (1) 5.7x 6.9x 7.7x Debt (2) 4,054$ 3,552$ 3,259$ FFO to Debt (3) 20.4% 24.9% 29.2% Capitalization Mid merican Energy shareholders’ equity 4,220$ 3,845$ 3,635$ Debt 4,054 3,552 3,259 Noncontrolling interests - - - Capitalization 8,274$ 7,397$ 6,894$ Debt to Total Capitalization (4) 49.0% 48.0% 47.3%
Non-GAAP Financial Measures Nevada Power Company 70 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 Net cash flows from operating activities 599$ 548$ 702$ +/- Changes in other operating assets and liabilities net of effects from acquisitions 56 (19) (29) FFO 655$ 529$ 673$ Interest expense 204$ 215$ 215$ FFO Interest Coverage (1) 4.2x 3.5x 4.1x Debt (2) 3,567$ 3,577$ 3,337$ FFO to Debt (3) 18.4% 14.8% 20.2% Capitalization Nevada Power shareholder's equity 3,127$ 2,890$ 2,922$ Debt 3,567 3,577 3,337 Capitalization 6,694$ 6,467$ 6,259$ Debt to Total Capitalization (4) 53.3% 55.3% 53.3%
Non-GAAP Financial Measures Sierra Pacific Power Company 71 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 Net cash flows from operating activities 251$ 226$ 197$ +/- Changes in other operating assets and liabilities net of effects from acquisitions 12 16 78 FFO 263$ 242$ 275$ Interest expense 59$ 62$ 65$ FFO Interest Coverage (1) 5.5x 4.9x 5.2x Debt (2) 1,200$ 1,200$ 1,179$ FFO to Debt (3) 21.9% 20.2% 23.3% C pitalization Sierra Pacific Power shareholder's equity 1,083$ 1,016$ 1,039$ Debt 1,200 1,200 1,179 Capitalization 2,283$ 2,216$ 2,218$ Debt to Total Capitalization (4) 52.6% 54.2% 53.2%
Non-GAAP Financial Measures Northern Natural Gas 72 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 Net cash flows from operating activities 317$ 264$ 304$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions (16) 41 (27) FFO 301$ 305$ 277$ Interest expense 44$ 44$ 52$ FFO Interest Coverage (1) 7.8x 7.9x 6.3x Debt (2) 899$ 899$ 899$ FFO to Debt (3) 33.5% 33.9% 30.8% Capitalization Northern Natural Gas shareholder’s equity 1,284$ 1,360$ 1,290$ Debt 899 899 899 Capitalization 2,183$ 2,259$ 2,189$ Debt to Total Capitalization (4) 41.2% 39.8% 41.1%
Non-GAAP Financial Measures Kern River 73 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 Net cash flows from operating activities 205$ 220$ 249$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 8 2 (1) FFO 214$ 222$ 248$ Interest expense 33$ 36$ 41$ FFO Interest Coverage (1) 7.5x 7.2x 7.0x Debt (2) 487$ 548$ 628$ FFO to Debt (3) 43.9% 40.5% 39.5% Capitalization Partners’ capital 801$ 829$ 880$ Debt 487 548 628 Capitalization 1,288$ 1,377$ 1,508$ Debt to Total Capitalization (4) 37.8% 39.8% 41.6%
Non-GAAP Financial Measures Northern Powergrid 74 (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) LTM FFO 9/30/2014 2013 2012 Net cash flows from operating activities 538$ 501$ 413$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 15 (44) 103 FFO 553$ 457$ 516$ Interest expense 151$ 141$ 139$ FFO Interest Coverage (1) 4.7x 4.2x 4.7x Debt (2) 2,553$ 2,546$ 2,408$ FFO to Debt (3) 21.6% 17.9% 21.4% Capitalization Northern Powergrid shareholders’ equity 3,303$ 3,027$ 2,611$ Debt 2,553 2,546 2,408 Noncontrolling interests 56 56 56 Capitalization 5,912$ 5,629$ 5,075$ Debt to Total Capitalization (4) 43.2% 45.2% 47.4%
Non-GAAP Financial Measures Pro Forma EBITDA 75 Note: Assumed exchange rate of $1.000 USD = $1.120 CAD (1) As a limited partnership, AltaLink does not pay income taxes. Accordingly, no income tax expense is recognized in the financial statements (2) Excludes consolidation adjustments ($ millions) LTM 9/30/14 Pro Forma EBITDA BHE AltaLink (1) Total(2) Net income 2,091$ 189$ 2,280$ Interest expense 1,595 111 1,706 Capitalized interest (97) (1) (98) Income tax expense 389 - 389 Depreciation and amortization 1,905 148 2,053 Pro Forma EBITDA 5,883$ 447$ 6,330$
