MidAmerican Energy Holdings Company 2013 Fixed-Income Investor Conference A Berkshire Hathaway Company

Forward-Looking Statements This presentation contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 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 MidAmerican Energy Holdings Company’s (“MidAmerican”) 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 laws and regulations 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 and new technologies, 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 MidAmerican’s and its subsidiaries’ credit facilities;

Forward-Looking Statements – changes in MidAmerican’s and its subsidiaries’ credit ratings; – risks relating to nuclear generation; – the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts; – the impact of inflation on costs and the Company’s ability to recover such costs in regulated rates; – increases in employee healthcare costs, including the implementation of the Affordable Care Act; – the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements; – changes in the residential real estate brokerage and mortgage industries and regulations that could affect brokerage and mortgage transaction levels; – unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions; – the availability and price of natural gas in applicable geographic regions and demand for natural gas supply; – the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company’s consolidated financial results; – the Company’s ability to successfully integrate future acquired operations into its business; – other risks or unforeseen events, including the effects of storms, floods, fires, explosions, litigation, wars, terrorism, embargoes and other catastrophic events; and – other business or investment considerations that may be disclosed from time to time in MidAmerican’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 MidAmerican’s filings with the SEC. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive. This presentation includes certain non-GAAP financial measures as defined by the SEC’s Regulation G. Refer to the Appendix in this presentation for a reconciliation of those non-GAAP financial measures to the most directly comparable GAAP measures.

Patrick J. Goodman Executive Vice President and Chief Financial Officer MidAmerican Energy Holdings Company

Energy Assets (1) Net MW owned in operation and under construction as of Dec. 31, 2012 Assets $52 billion Revenues $11.5 billion Customers Electric 6.4 million Natural Gas 0.7 million Employees 16,000 Natural Gas Transmission Pipeline Design Capacity Approximately 7.7 billion cubic feet per day Generation Capacity 21,363 MW(1) Coal 45% Natural Gas 23% Wind 17% Hydro 6% Solar 6% Nuclear and other 3%

MidAmerican Competitive Advantage • Diversified portfolio of regulated assets – Weather, customer, regulatory, generation, economic and catastrophic risk diversity • Stable operating cash flows – 94% of EBITDA from investment-grade regulated subsidiaries • No dividend requirement – Cash flow is retained in the business and used to help fund growth and improve credit metrics • 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 MidAmerican the buyer of choice in the eyes of certain sellers and regulators – Tax appetite of Berkshire Hathaway allows us to realize tax benefits currently

Revenue and EBITDA Diversification • Diversification of revenue sources reduces regulatory concentrations • In 2012, 94% of EBITDA was from investment-grade regulated subsidiaries MidAmerican 2012 Energy Revenue(1): $10.2 Billion MidAmerican 2012 Consolidated EBITDA(2): $4.2 Billion Iowa 20.9% Utah 20.9% Oregon 10.9% Wyoming 8.1% Washington 3.3% Idaho 3.3% California 0.9% Illinois 7.9% Texas 1.0% South Dakota 1.0% Other 1.1% FERC 9.4% United Kingdom 10.1% Philippines 1.2% MidAmerican Funding 18.8% PacifiCorp 41.8% Northern Powergrid 17.6% MidAmerican Energy Pipeline Group 15.9% MidAmerican Renewables 3.5% HomeServices 2.4% (1) Excludes HomeServices and equity income, which add further diversification (2) Refer to the Appendix for the calculation of EBITDA; percentages exclude Corporate/other

MidAmerican Financial Summary • Continued solid growth and returns $30.9 $31.9 $34.2 $37.6 $0 $10 $20 $30 $40 2009 2010 2011 2012 Billions $1,157 $1,238 $1,331 $1,472 $0 $400 $800 $1,200 $1,600 2009 2010 2011 2012 Millions $3,572 $2,759 $3,220 $4,327 $0 $1,000 $2,000 $3,000 $4,000 $5,000 2009 2010 2011 2012 Millions $12.6 $13.2 $14.1 $15.7 $0 $5 $10 $15 $20 2009 2010 2011 2012 Billions Net Income Attributable to MidAmerican MidAmerican Shareholders’ Equity Property, Plant and Equipment (Net) Cash Flows From Operations

Reportable Segment Information Years Ended Dec. 31 ($ millions) 2012 2011 2010 PacifiCorp 1,034$ 1,099$ 1,055$ MidAmerican Funding 369 428 460 MidAmerican Energy Pipeline Group 465 468 472 Northern Powergrid Holdings 565 615 474 MidAmerican Renewables 93 106 88 HomeServices 62 24 17 Corporate/other (21) (56) (64) Total operating income 2,567 2,684 2,502 Interest expense (1,176) (1,196) (1,225) Capitalized interest 54 40 54 Allowance for equity AFUDC 74 72 89 Other, net 56 (7) 45 Income before income tax expense, equity income and noncontrolling interests 1,575 1,593 1,465 Income tax expense (148) (294) (198) Equity income 68 53 43 Net income attributable to noncontrolling interests (23) (21) (72) Net income attributable to MidAmerican shareholders 1,472$ 1,331$ 1,238$

Credit Metrics and Ratings • MidAmerican Key Credit Ratios(1) – Zero dividends paid to Berkshire Hathaway (BRK) and tax benefits received from BRK have allowed for an accelerated improvement in credit ratios – As credit metrics have improved, the BRK equity commitment agreement is not necessary to support the credit rating; MidAmerican’s current intention is to not extend the BRK equity commitment • BRK would be open to extending the equity commitment if necessary as a result of an acquisition or other credit event • Ratings (Issuer or senior unsecured ratings unless noted) (1) Refer to the Appendix for the calculations of key ratios (2) Ratings for PacifiCorp and Kern River Funding Corp. are senior secured ratings 2012 2011 2010 2001 FFO Interest Coverage 4.6x 4.1x 3.9x 2.3x FF to Adjusted Debt 19.8% 18.1% 17.3% 9.1% Adjusted Debt to Total Capitalization 57.6 58.2 58.7 72.2 Moody’s S&P Fitch MidAmerican Baa1 BBB+ BBB+ PacifiCorp (2) A2 A A- MidAmerican Energy Company A2 A- A Northern Natural Gas Company A2 A A Kern River Funding Corp. (2) A2 A- A- Northern Powergrid (Northeast) A3 A- A- Northern Powergrid (Yorkshire) A3 A- A

Segment Credit Metrics 2012 2011 2010 Regulated Utilities PacifiCorp FFO Interest Coverage 4.8x 4.8x 5.6x FFO to Debt 21.3% 21.6% 27.7% Debt to Total Capitalization 47.3% 48.6% 46.8% MidAmerican Energy FFO Interest Coverage 7.7x 8.1x 6.6x FFO to Debt 29.2% 36.1% 30.4% Debt to Total Capitalization 47.3% 48.8% 49.2% Regulated Pipelines Northern Natural Gas FFO Interest Coverage 6.3x 6.5x 6.2x FFO to Debt 30.8% 32.6% 31.3% Debt to Total Capitalization 41.1% 42.7% 45.2% Kern River FFO Interest Coverage 7.5x 6.3x 4.9x FFO to Debt 39.5% 31.7% 23.3% Debt to Total Capitalization 41.6% 45.2% 52.9% Regulated Distribution Northern Powergrid FFO Interest Coverage 4.7x 4.6x 3.5x FFO to Debt 21.4% 25.4% 19.2% Debt to Total Capitalization 47.4% 49.2% 50.0%

Return on Equity Net Income Divided by Average Equity Entity 2012 2011 Allowed ROE PacifiCorp 8.4% (1) 7.8% 9.9% MidAmerican Energy 10.4% 10.3% 11.1% Northern Natural Gas 10.9% 10.4% 12.0% Kern River 11.3% 13.8% 11.55% (1) 2012 excludes $102 million after-tax impact of charges for USA Power litigation and certain fire and other damage claims

Capital Expenditures and Cash Flows • MidAmerican and its subsidiaries will spend approximately $11.8 billion over the next three years for development and maintenance capital expenditures, which includes new environmental capital expenditures, transmission, and generation project expansions, including solar, wind and natural gas plant additions – MidAmerican Renewables is projected to spend approximately $4.3 billion over the next three years $- $1,000 $2,000 $3,000 $4,000 $5,000 2010A 2011A 2012A 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 MidAmerican Capital Expenditures MidAmerican Cash Flows from Operations MidAmerican Renewables Capital Expenditures MidAmerican Renewables Cash Flows from Operations $ m illi on s

$0 $1,000 $2,000 $3,000 $4,000 $5,000 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 $ m illio ns PacifiCorp MidAmerican Funding Northern Powergrid Holdings MidAmerican Renewables MidAmerican Pipeline Group and Other Projected Capital Expenditures For each year, the left column represents current projections and the right column represents prior year projections. • 2013-2021 capital expenditures projections have been reduced by $2.4 billion from prior year projections primarily due to revised load growth assumptions

MidAmerican Renewables Created a New Business Unit – MidAmerican Renewables • Significant renewables experience and skill sets in our businesses • A government program providing federal guarantees expired Sept. 30, 2011 • A number of solar projects did not meet the qualifying deadline – financing alternatives were limited • Berkshire Hathaway’s taxable income created an economic advantage • 1,652 MW under construction and in-service, $7 billion investment • Production tax credit extension in 2013 provides advantage to MidAmerican Renewables; positioned to act quickly MidAmerican Solar MidAmerican Geothermal Geothermal Plants Natural Gas Plants MidAmerican Wind MidAmerican Hydro CalEnergy Philippines

Renewables Portfolio (1) 82% of the company’s interests in the Imperial Valley projects’ contract capacity are sold to SCE Acquired/ developed in 2012 Location Installed PPA Expiration Power Purchaser Net or Contract Capacity (MW) Net Owned Capacity (MW) SOLAR: Topaz California 2013-2015 2040 PG&E 550 550 Agua Caliente Arizona 2012-2014 2039 PG&E 290 142 Antelope Valley I and II California 2013-2015 2035 SCE 579 579 1,419 1,271 WIND: Pinyon Pines I and II California 2012 2035 SCE 300 300 Bishop Hill II Illinois 2012 2032 Ameren 81 81 381 381 GEOTHERMAL: Imperial Valley Projects California 1982-2000 2016-2029 (1) 327 164 HYDROELECTRIC: Casecnan Project Philippines 2001 2021 NIA 150 128 Wailuku Hawaii 1993 2023 Hawaii Electric 10 5 160 133 NATURAL GAS: Saranac New York 1994 2013 EDF Trading 240 90 P wer Resources Texas 1988 2015 EDF Trading 212 106 Yuma Arizona 1994 2024 SDG&E 50 25 Cordova Illinois 2001 2019 Constellation 537 537 1,039 758 Total Available Generating Capacity 3,326 2,707

MidAmerican Transmission • MidAmerican Transmission is comprised of a 50% equity interest in Electric Transmission Texas and a 50% equity interest in Electric Transmission America; American Electric Power owns the remaining 50% – ETT owns and operates electric transmission assets in ERCOT; as of Dec. 31, 2012, a total of $879 million worth of transmission assets were in-service and an estimated $2.2 billion is to be placed in-service between 2013 and 2022 – ETA has a 50:50 joint venture with Westar Energy to build transmission assets in Kansas; construction began during 2012, and the assets are expected to cost approximately $180 million and be completed on or before December 2014 • A MidAmerican Canadian subsidiary entered into a joint venture with Renewable Energy Systems Canada Inc. to sponsor a competitive proposal for Ontario’s East-West Tie Line transmission project – $413 million (CAD) firm bid with escalation (2013 dollars) – Bid submitted Jan. 4, 2013 – Decision expected mid-2013 by Ontario Energy Board MidAmerican Transmission, LLC ($ in millions) 2012 2011 2010 Net Income Attributable to MidAmerican Transmission 26 15 5 Total Assets 428 270 127 Contributions from MidAmerican 97 95 50 Total Member's Equity 340 217 107

Canadian Generation JV Opportunities • MidAmerican and TransAlta created a new strategic partnership to develop, build and operate new natural gas-fueled electricity generation projects in Canada – Development opportunities for natural gas-fueled generation resources are expected in the areas of cogeneration, liquid natural gas exports, oil sands development, mining load and coal plant retirements – Focused on pursuing highly rated customer-oriented gas generation projects with strong supporting power purchase agreements in the British Columbia, Alberta and Saskatchewan areas

Financing Plan 2013 • PacifiCorp – Closed on a $600 million five-year credit facility in late March 2013 to replace the existing five-year facility maturing July 2013 – Plan a mid-year 2013 debt financing • MidAmerican Energy – Closed on a $600 million five-year credit facility in late March 2013 to replace the existing five-year facility maturing July 2013 – Plan a second half 2013 debt financing • Topaz Solar Farms, LLC – Non-recourse project financing is planned in second quarter 2013 • Antelope Valley Solar Project – Non-recourse project financing is planned in mid-2013 • Electric Transmission Texas, LLC – Plan a first half 2013 debt financing to fund its continued expansion in ERCOT

Questions

Richard Walje President and CEO Rocky Mountain Power

Overview • Headquartered in Portland, Oregon • 6,300 employees • 1.8 million electricity customers • 136,000 square miles of service territory • 11,224 net MW generation capacity(1) • Generating capacity by fuel type(1) – Coal 55% – Natural gas 25% – Hydro(2) 10% –Wind, geothermal and other(2) 10% (a) Access to other entities’ transmission lines through wheeling arrangements (1) Net owned megawatts in operation and under construction as of Dec. 31, 2012 (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

Diversification – Retail Revenue PacifiCorp ($4.3 billion) Residential 38% Commercial 32% Industrial 26% Irrigation 3% Other 1% PacifiCorp Revenue by State ($4.3 billion) Utah 43% Oregon 27% Wyoming 15% Washington 7% Idaho 6% California 2% Rocky Mountain Power ($2.7 billion) Residential 32% Commercial 30% Industrial 34% Irrigation 3% Other 1% Pacific Power ($1.6 billion) Residential 48% Commercial 36% Industrial 12% Irrigation 3% Other 1%

• 1,021,000 electric customers • Weather normalized retail load was 36.7 TWh in 2012 vs. 36.5 TWh in 2011, a 0.4% increase; forecast to remain flat through 2014 • Two-year rate increase plans approved in Idaho in 2011 and in Utah and Wyoming in 2012; allows customers to plan for future electric rates • Improved customer satisfaction as measured by rankings in national surveys • Utah, Wyoming and Idaho electric rates remain among the lowest in the nation Overview Rocky Mountain Power Service Territory

Utah • Two-step general rate increase approved with increases of $100 million (6%) in October 2012 and $54 million (3%) in September 2013 • Energy balancing account mechanism approved in 2011; commission approved collection of $60 million in deferred costs over three years effective June 2012 and $8 million collected over two years effective March 2013 • Renewable energy credit balancing account approved in 2011; commission approved a credit of $4 million returned to customers over one year effective June 2012 Wyoming • Two-step general rate increase approved with increases of $32 million (5%) in October 2012 and $18 million (3%) in October 2013 • Recovery of $27 million excess net power costs approved through the energy cost adjustment mechanism; recovery occurs over three years effective May 2012 • 2012 renewable energy credit revenue adjustment mechanism resulted in a rate increase of $1 million and an overall credit to customers of $15 million Regulatory Accomplishments

Regulatory Accomplishments Idaho • General rate increases of $17 million (8%) in January 2012 and $17 million (7%) in January 2013 as a result of a general rate case settlement in 2011 • Recovery of $18 million deferred power costs through the energy cost adjustment mechanism approved effective April 2012 Cost Adjustment Mechanisms • Energy cost recovery and renewable energy credit balancing account mechanisms in place in each state • Customers pay the costs and receive the benefits associated with fluctuating power costs and sales of RECs; balanced outcome between the company and customers • In Utah and Wyoming, 70% of the difference between base net power costs established in a general rate case and actual power costs are deferred and recovered • In Idaho, 90% of the difference between base net power costs established in a general rate case and actual power costs are deferred and recovered • In all states, 100% of the difference between base-line REC sales and actual sales are deferred and recovered/refunded • Annual filings are required to seek recovery/refund of deferred energy costs and REC sales

Future Rate Case Strategy • Utah’s two-step rate plan stipulation allows for the next rate case to be filed Jan. 1, 2014, or later, with new rates effective Sept. 1, 2014, or later • Wyoming’s two-step rate plan stipulation allows for the next rate case to be filed March 1, 2014, or later, with new rates effective Jan. 1, 2015, or later • A rate case in Idaho can be filed after May 31, 2013, with new rates effective Jan. 1, 2014, or later • The need for and timing of new rate case filings is being evaluated

Economic Outlook and Load Growth 2012 compared to 2011 • Industrial sales down 0.7%; realized industrial growth rate of 3.7% offset by several large customers’ self-generation • Residential and commercial loads flat Forecast for 2013 and 2014 • Industrial sector sales decline in 2013 as customers increase self-generation; 2014 sales increase due to projected growth in the extractive industries • Slow residential and commercial growth as energy efficiency gains offset the addition of new customers Key economic factors • Brisk oil and gas development in Wyoming and Utah • Low energy costs contribute to economic growth in the industrial and commercial sectors • Continued population growth, with low state unemployment rates in Utah and Wyoming 0 10 20 30 40 50 60 2008 2009 2010 2011 2012 2013 Fcst 2014 Fcst T er a w a tt -h o ur s Rocky Mountain Power Retail Load Weather-Normalized Annual Growth Rates: 2009 = (2.6%) 2010 = 4.2% 2011 = 2.5% 2012 = 0.4% 2013 = (0.6%) 2014 = 1.1%

Capital Initiatives • The 2013 capital plan incorporates numerous efficiency improvements and cost reduction initiatives, including: – Revised design and construction standards that lower the cost of delivered work – Efficiency improvements in delivery of work units through improved scoping and planning – Revised equipment loading guidelines that will increase the utilization of existing assets to allow deferral and reduction of investment • The 10-year capital plan has been reduced 12.7% from the previous plan while delivering greater volumes in several areas: – 28% increase in planned new service connections driven by improving economic conditions – 30% increase in asset replacement volumes to improve asset health and system reliability New Service Load Growth Replacement Mandated / Regulatory Other Subtransmission and Distribution Capital Investment Allocation (2013-2022)

O&M Expense Trending • O&M expenses have generally remained flat over the past several years $146.3 $145.6 $156.2 $141.0 $138.5 $0 $25 $50 $75 $100 $125 $150 $175 2009 2010 2011 2012 2013 Forecast ($ millions)

Operational Excellence Irrigation Demand Response Program • 286 MW of potential demand response from connected Idaho and Utah irrigation load in 2012 • Performance improvement initiative in 2011 and 2012 – Invested $1.3 million in distribution system improvements to accommodate increased participation in the Idaho irrigation program – Efficiency improvements for a 42% reduction in operation costs • Performance-based third-party aggregator contract for 2013 – Contractor responsible for equipment and performance – Improved performance and additional reduction in costs 4.28 3.65 2.55 1.21 1.16 1.11 1.83 1.63 0 1 2 3 4 5 2005 2006 2007 2008 2009 2010 2011 2012 OSHA Recordable Rate Safety • Safety has greatly improved over the last seven years • Continues as a top priority in 2013

Service Quality Improvements • Focus on using data and processes to eliminate outages that will improve reliability at the best possible cost • Program has been enhanced to target unknown and weather-caused interruptions to prevent recurrence of an outage • Newly developed tool uses Web-based notices to alert key engineering and operations staff of recent reliability events on devices (breakers and fuses) that exceed defined performance levels; also tracks corrective progress made during these investigations • Best practice examination across MidAmerican’s electric utilities has identified additional improvement areas for program enhancements Operational Excellence

• Customer satisfaction rankings in national surveys – TQS customer satisfaction: In 2012, ranked No. 3 nationwide with 94.9% of customers reporting “very satisfied” –MSI small- and mid-sized business customer satisfaction; ranking improved from No. 40 in 2011 to No. 8 in 2012 0% 20% 40% 60% 80% 100% 120% 2000 2002 2004 2006 2008 2010 2012 Customer Service Rocky Mountain Power TQS Customer Satisfaction Trends 2000-2012 • Customer and community visibility tour across service territory to stay connected • Write-offs and customer bad debt expense in top quartile for industry; strong economy in service territory and proactive company initiatives to help customers reduce energy usage, manage payments, and receive energy assistance • Energy efficiency programs for all classes of customers • Over 41,500 customers enrolled in Blue Sky program supporting renewable energy

Pat Reiten President and CEO Pacific Power

• 733,000 electric customers • Weather-normalized retail load was 17.6 TWh in 2012 vs. 17.7 TWh in 2011, a 0.4% decrease; forecast to remain flat from 2012 to 2013 • 2012 rate case outcomes with revenue increases were received in Oregon and Washington; 2013 Washington (14%) and Oregon (5%) rate case filings pending • Network reliability has continued to improve over the last six years • Ranked 15th nationally in 2012 in industrial and top 10 in MSI residential customer satisfaction Overview

Oregon 2012 • 2012 general rate order approved, effective Jan. 1, 2013 – Multiparty partial stipulation for a rate increase of $24 million (2%) – Capital and operating expenses related to emissions control investments at certain coal-fueled generating facilities approved, but ordered a one-year credit to customers of $17 million (1%) based on 10% of Oregon’s allocated share of emissions control investments in the case – Mona-Oquirrh separate tariff rider, effective on operational date of transmission line in 2013, increasing rates by $11 million (1%) – Power cost adjustment mechanism with modifications from the company’s filing – Transition Adjustment Mechanism increase of $2 million (<1%) 2013 • 2013 general rate case filing supports an increase of $56 million (5%); new rates proposed to become effective Jan. 1, 2014 – Rate request will be reduced by $11 million (1%) for the Mona-Oquirhh tariff rider – Requests prudence determination for Lake Side 2 generating plant; rate change effective on project completion date, resulting in an increase in rates of $23 million (2%) in mid-2014 – Initial filing for the 2014 transition adjustment mechanism supports decrease of $1 million (<1%); filing multiple updates/adjustments during the year; new rates effective Jan. 1, 2014 Regulatory Accomplishments

Washington 2012 • Order approving all-party settlement in the 2011 general rate case resulted in increase of $5 million (2%), effective June 1, 2012 • Order related to renewable energy credit sales revenue requiring the company to credit customers revenues from Jan. 1, 2009, through March 31, 2011 ($17 million); company currently seeking judicial review of commission decision 2013 • General rate case filing supports an increase of $43 million (14%); new rates proposed to become effective Dec. 11, 2013 California • 2012 annual attrition adjustment resulted in a rate increase of $1 million (1%), effective Jan. 1, 2012 • Order approved stipulation with the Division of Ratepayer Advocates for a power cost increase of $2 million (2%), effective March 9, 2012, through energy cost adjustment clause • Approval of post-test year adjustment mechanism for major plant additions related to emission control investments for an increase in rates of $1 million (1%), effective Aug. 25, 2012 • 2013 annual attrition adjustment resulted in a rate increase of $1 million (1%), effective Jan. 1, 2013 Regulatory Accomplishments

Economic Outlook and Load Growth 2012 • Fifth straight year of weather- normalized load decline • Continued impact of recession on industrial loads, down 2.9% • Residential and commercial loads flattened Forecast for 2013 and 2014 • Overall, no recovery in 2013 • Slight recovery in Oregon commercial load in 2014 • The company continues to identify and implement initiatives to manage costs and mitigate lower revenues under the current load forecast - 5 10 15 20 25 30 35 40 2007 2008 2009 2010 2011 2012 2013 Fcst 2014 Fcst T er ra w a tt -h o ur s Pacific Power Retail Load Weather-Normalized Annual growth rate: 2008 = (1.6%) 2009 = (3.7%) 2010 = (0.7%) 2011 = (0.7%) 2012 = (0.4%) 2013 = 0.0% 2014 = 0.4%

Capital Initiatives • The 2013 capital plan incorporates numerous efficiency improvements and cost reduction initiatives, including: – Revised design and construction standards that lower the cost of delivered work – Efficiency improvements in delivery of work units through improved scoping and planning – Revised equipment loading guidelines that will increase the utilization of existing assets to allow deferral and reduction of investment • The 10-year capital plan is reduced 13.2% from the previous plan due to changes in several areas: – Planned new service connections are 49.5% lower, due to economic drivers in the outer years – Asset replacement volumes remain essentially unchanged, with reductions driven through lower unit pricing New Service Load Growth Replacement Mandated / Regulatory Other Technology Subtransmission and Distribution Capital Investment Allocation (2013-2022)

O&M Expense Trending • O&M expense has generally remained flat over the past several years $259.3 $256.1 $271.4 $263.8 $256.9 $0 $50 $100 $150 $200 $250 $300 2009 2010 2011 2012 2013 Forecast ($ millions)

Operations and System Performance • Priority companywide safety initiative; all-inclusive, prevention and case management reduced 2012 recordable incident rate by 36% • Leading 2013 MidAmerican-wide key customer satisfaction improvement initiative – Integrated account management; best practices – Technology tools • Companywide business resource realignment through efficiencies, consolidation and reductions – PacifiCorp plan revised; focus on expense and capital reductions over the next several years Operational Excellence

System Reliability • Significant continued improvement in reliability and frequency of service interruption • Work plans and capital investment targeted key customer and geographic areas • Web-based notification tool alerts local staff to investigate and promptly correct conditions that can cause breakers, fuses or reclosers to operate more frequently than specified limits Reliability improves 33% 0 0.5 1 1.5 2 2.5 0 50 100 150 200 250 Eve n ts M in u te s Pacific Power 365-Day Rolling History Reliability Stress Period Rolling SAIDI Rolling SAIFI Linear (Rolling SAIDI) 2007 2008 2009 2010 2011 2012

Compliance/Regulatory Issues – Results • Filed all-party settlement in federal transmission rate case Feb. 22, 2013 – FERC order approving the settlement is expected in second quarter 2013 – Formula will establish rates that include an annual rate projection each June, based on current capital investments and loads; also includes a true-up to actual costs for the prior calendar year rates – Formula is designed to recover PacifiCorp’s full transmission revenue requirement • Any revenues from third-party wholesale transmission customers are returned to retail customers as a revenue credit against net power costs • Continued work on Bonneville Power Administration’s wind curtailment policy; landmark FERC ruling affecting non-jurisdictional utilities upheld • Signed MOU with California Independent System Operator for Energy Imbalance Market

• Feb. 12, 2013, PacifiCorp and California ISO signed a memorandum of understanding to develop an Energy Imbalance Market • Will provide automated dispatch to maintain short-term gaps between energy supply and demand versus current hourly, bilateral electricity scheduling system • Additional geographic and resource diversity results in cost and reliability benefits • Annual benefits expected to range from $21 million to $129 million for PacifiCorp and CAISO – Modest cost to establish, currently under review – Benefits depend upon transmission availability and other variables • Additional participants will increase benefits, reduce costs • PacifiCorp not joining CAISO as a full participant or releasing asset control • Under plan, EIM is scheduled to go live in October 2014 • PacifiCorp continues support and participation in Northwest Power Pool and other regional initiatives Energy Imbalance Market/MOU

Energy Imbalance Market Footprint COB Palo Verde Crag NOB Mona Four Corners Mead PacifiCorp Transmission CAISO Transmission PacifiCorp Generation and Service Area

• Multiyear, multisegment, multibillion dollar investment plan – Designed to provide up to 3,000 MW of new transmission capacity (1,500 MW on both Gateway West [D/E] and Gateway South [F]) to serve PacifiCorp customers’ long-term needs – Approximately 2,000 miles – Populus-Terminal (Segment B) completed in November 2010 – Mona-Oquirrh (Segment C) under construction; completion May 2013 – Sigurd-Red Butte (Segment G) construction begins Spring 2013 – Progress continues on longer-term segments, including Gateway West and Gateway South – Development opportunities exist with third parties for two lines west of Hemingway Energy Gateway Transmission Expansion

Gateway West • Status: In-service target 2016-2021; currently in permitting process; final EIS target April 2013 • Challenges: Permitting delays; customer expectations Boardman to Hemingway • Status: In-service target 2018; joint permitting agreement signed; currently in permitting process; draft EIS target 2013 • Challenges: Permitting delays; federal preferred route selection PGE/Cascade Crossing • Status: In-service target 2016-2017; memorandum of understanding signed between Portland General Electric and Bonneville Power Administration; currently in permitting process; draft EIS target 2013 – Discussion of a joint project with PacifiCorp continues • Challenges: MOU changes the project, eliminating a portion of the planned new construction; possible permitting impacts with recent project plan changes to topology Energy Gateway Key Challenges Looking Forward

Micheal Dunn President and CEO PacifiCorp Energy

Diversified Resource Portfolio 11,224 net MW generation capacity(1) • 6,139 MW coal • 2,861 MW natural gas • 1,145 MW hydroelectric • 1,031 MW wind • 34 MW geothermal • 14 MW other (1) Net MW owned in operation and under construction as of Dec. 31, 2012 (a) Access to other entities’ transmission lines through wheeling arrangements

Generating Capacity by Fuel Type March 31, 2006 Dec. 31, 2012 8,470 MW (1) 11,224 MW (1) Coal 72% Natural Gas 13% Hydroelectric 14% Wind, Geothermal and Other 1% (1) Net MW owned in operation and under construction Coal 55% Natural Gas 25% Hydroelectric 10% Wind, Geothermal and Other 10%

Lake Side 2 Construction Status • 645-MW combined-cycle combustion turbine generating facility under construction adjacent to the Lake Side 1 plant in Vineyard, Utah • The project is forecast to be within budget and to achieve commercial operation June 1, 2014 • Engineering and procurement are complete • The major foundations and structures are complete • All major equipment has been delivered to the site and is being assembled • Plan to fire the combustion turbines for the first time in fourth quarter 2013 Cooling Tower Turbine Pedestal Combustion Turbine 22 Combustion Turbine 21

Lake Side 2 Construction Status Lake Side 2 looking east; February 2013 Cooling Tower Turbine Pedestal Combustion Turbine 22 Combustion Turbine 21

Capital Requirements Under the Current Resource Plan • 2013-2015 Capital Plan ($ millions) Current 2013-2015 Prior 2013-2015 – New generation and conversion $ 236 $ 800 – Environmental compliance 440 611 – Hydro projects 66 63 – Maintenance capital 564 611 Note: Excluding AFUDC $1,306 New generation and conversion Environmental compliance Hydro projects Maintenance capital 18% 34% 5% 43% $2,085

• Regional Haze Rules • Mercury and Air Toxics Standard • Clean Water Act 316(b) Cooling Water Intake Rule Making • Coal Combustion Residuals Rule Making • Steam Electric Power Generating Effluent Guidelines Environmental Protection Agency Mandates

Environmental Position (1) Excludes minority-owned Craig, Colstrip and Hayden plants • Of PacifiCorp’s nearly 5,765 MW(1) of operated or wholly owned coal- fueled generation – 86% of generation has nitrogen oxides controls with low-NOx burners and over-fire air – 93% of generation has scrubbers for sulfur dioxide control – 56% of generation has baghouses for particulate matter control – 27% 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 and installation of one baghouse, 96% of coal-fueled generation will be controlled by scrubbers and 69% 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 early 2015 – Plan to convert Naughton Unit 3 (330 MW) to gas

PacifiCorp Capital Cost of Compliance Project Regional Haze Rules HAPs MACT CCR Management Clean Water Act Scrubbers, Baghouses, Low-NOx Burners and Selective Catalytic Reduction $1.2 billion Coal Fleet Mercury Controls $21 million Coal Fleet Coal Combustion Residue Management (including asset retirement obligation) $290 million Clean Water Act § 316(b) Compliance $6 million Note: Including AFUDC and escalation Total 2013-2022 PacifiCorp Environmental Capital: $1.5 billion (2013-2015 $523 million) (2013-2015: $406 million) (2013-2015: $21 million) (2013-2015: $95 million) (2013-2015: $1 million)

Decreasing Carbon Footprint Note: PacifiCorp’s share of generation from all thermal, hydro, wind and geothermal resources 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 1,900 2,000 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 L bs C O 2/M W h M Wh G ene ra ted (0 00 's ) PacifiCorp CO2 Emission Intensity Coal Hydro Geothermal and Other Natural Gas Wind CO2 lb/MWh

Questions

Bill Fehrman President and CEO MidAmerican Energy Company

Overview MidAmerican Energy Service Territory Major Generating Facilities Wind Projects IOWA SOUTH DAKOTA NEBRASKA KANSAS MISSOURI ILLINOIS WISCONSIN MINNESOTA • Headquartered in Des Moines, Iowa • 3,500 employees • 1.4 million electric and natural gas customers in four Midwestern states • 11,000 square miles of service territory • 7,432 MW(1) of owned generation capacity • Generating capacity by fuel type 12/31/12(1) 12/31/00 – Coal 45% 70% – Natural Gas and Other 18% 21% – Wind(2) 31% 0% – Nuclear and Hydroelectric 6% 9% (1) Net owned megawatts in operation as of Dec. 31, 2012 (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

Business Update • Regulatory Integrity – Focus is on a balanced outcomes for our customers, communities, regulators and legislators – Significant use of binding rate-making principles in Iowa in advance of construction provides for greater regulatory certainty during future rate cases while meeting the expectations of policymakers and regulators – Approximately 50% of Iowa electric rate base was subject to advanced rate-making principles at the end of 2012 – Adjustment clause approved in Iowa received broad support from Office of Consumer Advocate and major industrial group; new clause mitigates customer rate shock while providing needed additional revenue for 2012 and 2013

2012 Iowa Electric Rate Activity • MidAmerican Energy has not increased Iowa base electric rates since 1995 • Environmental cost adjustment and fuel adjustment clauses proposed to recover associated expenses • Agreements with the Office of Consumer Advocate and a major industrial group supporting the proposal • Clauses combined, not subject to actual costs, and approved • Total recoveries of $39 million (3% increase) for 2012 and an additional $37 million (3% increase from 2012) for 2013, resulting in a total of $76 million in 2013 • Revenue-sharing mechanism similar to past arrangements except with a lower (10%) return on equity triggering sharing • Collections began March 2, 2012

2013 Iowa Electric Rate Activity • Base rate filing expected mid-May • Proposed energy adjustment clause – Recovery of change in retail fuel costs – Recovery of pre-tax change in production tax credits – Recovery of change in environmental consumables and allowances • Proposed transmission rider – Recovery of Midwest Independent System Operator-billed costs • Proposed 10-year equalization of rates among three current pricing zones • Revenue sharing mechanism • Settlement discussions with Office of Consumer Advocate and large industrial customers are underway

Business Update • Financial Strength – Maintained strong financial results despite persistent low wholesale power prices impacted by low natural gas prices – overall 2012 return on equity exceeded 10% – Power prices in 2012 were the lowest since 2003, and regional MISO power prices averaged $20.97/MWh in 2012 compared to $25.11/MWh in 2011 – Additional production tax credits earned from new wind turbines installed in 2011-2012 0 5 10 15 20 25 30 35 40 2008 2009 2010 2011 2012 2013 Fcst 2014 Fcst T W h MidAmerican Energy Retail Load Weather-Normalized Annual Growth Rates: 2009 = (2.6%) 2010 = 4.2% 2011 = 1.2% 2012 = (0.2%) 2013 = 3.7% 2014 = 3.6% – MidAmerican Energy realized favorable cash flows from income tax benefits in 2009 ($227 million), 2010 ($124 million), 2011 ($221 million) and 2012 ($692 million) related to bonus depreciation, production tax credits and tax method changes – Forecast loads for 2013 and 2014 reflect strong growth rates – Adjustment clause mechanism implemented in Iowa improved revenue $39 million in 2012 and an additional $37 million in 2013 – Fuel adjustment clause reinstated in Illinois

Business Update • Environmental Respect – Continued investment in emissions control projects • Work is underway for dry scrubber and baghouse projects at Neal Energy Center Units 3 and 4; MidAmerican Energy costs are expected to be approximately $277 million • Similar project in progress at Ottumwa Generating Station; MidAmerican Energy costs are expected to be approximately $201 million – Completed construction of 407 MW of wind generation in 2012 • Customer Service – MidAmerican Energy has ranked in the top quartile in the nation in J.D. Power and Associates Electric Utility Business Customer Satisfaction Study every year since 2004 – Customer bad debt experience has been stable throughout the 2008 economic downturn and subsequent recovery • Employee Commitment – Continued reinforcement of safety culture; OSHA recordable rate for 2012 was 16.5% lower than 2011 – Focused on control of benefit costs and overall staffing levels; employee counts lower in 2012 than 2008 3.27 3.06 2.86 2.42 2.12 1.77 0 1 2 3 4 2007 2008 2009 2010 2011 2012 OSHA Recordable Rate

Operational Excellence • Significant operational focus on minimizing plant emissions and improving plant availability • Long-term maintenance contracts are in place for the Greater Des Moines Energy Center and all wind projects • Ranked No. 1 in the nation in ownership of wind-powered electric generation among rate-regulated utilities, with 2,285 MW of owned and operated generation • Strict attention to cost management; operations and maintenance costs (excluding energy efficiency costs recovered through a rider) have not increased from 2008 levels despite major plant additions

Wind VII Expansion • MidAmerican Energy received approval from the Iowa Utilities Board to add 1,001 MW of new wind generation in Iowa through 2012 – Approval allows ROE of 12.2% for the life of the assets – Construction of 594 MW was completed in 2011, utilizing Siemens turbines at a total cost of $1.0 billion; payment of $669 million of costs is deferred until December 2013 – Construction of the remaining 407 MW completed in 2012, also utilizing Siemens turbines at a cost of $0.7 billion; payment of $426 million of costs is deferred until December 2015 • Projects delivered at a cost of under $1,625/kw and provide a significant value to customers due to: – Development cost deferral mechanism – Production tax credits for 10 years from the in-service date of the projects – 2011 project eligible for 100% federal bonus depreciation; 2012 project eligible for 50% federal bonus depreciation – Low-cost generation in the future • MidAmerican Energy continues to evaluate additional wind generation opportunities in Iowa

Dec. 31, 2000 Dec. 31, 2012 (1) Net MW owned in operation 4,086 MW (1) 7,432 MW (1) Generating Capacity by Fuel Type Coal 70% Natural Gas and Other 21% Wind 0% Nuclear and Hydroelectric 9% Coal 45% Natural Gas and Other 18% Wind 31% Nuclear and Hydroelectric 6%

Wind Benefit – Decreasing Carbon Footprint Note: MidAmerican Energy Company sold the environmental attributes of some of this generation to third parties and values do not represent the carbon footprint of energy delivered to MidAmerican Energy Company’s retail customers Decreasing Carbon Footprint 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 1,900 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2000 2003 2005 2007 2009 2011 2012 L bs C O 2 / M W h MWh G e n e ra ted (000's ) MEC CO2 Emission Intensity Coal Nuclear and Other Wind Natural Gas CO2 lb/MWH

MidAmerican Energy Company Capital Cost of Compliance Total 2013-2022 MidAmerican Energy Environmental Capital: $472 million (2013-2015: $420 million) Project CAIR/CATR HAPs MACT CCR Management Neal Units 3 and 4: Scrubber and Baghouse $143 million (2013-2015: $143 million) Ottumwa: Scrubber and Baghouse $135 million (2013-2015: $135 million) Neal Units 3 and 4: Selective Noncatalytic Reduction $24 million (2013-2015: $24 million) Coal Fleet Mercury Controls $13 million (2013-2015: $13 million) Coal Fleet Ash Pond Closures $114 million (2013-2015: $62 million) Coal Fleet Bottom Ash Dry Handling $43 million (2013-2015: $43 million) Subtotal: $302 million (2013-2015: $302 million) $13 million (2013-2015: $13 million) $157 million (2013-2015: $105 million)

Environmental Position • Of MidAmerican Energy Company’s nearly 4,100 MW of operated 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 – 55% of generation has scrubbers and baghouses for sulfur dioxide control – 20% of generation has activated carbon injection for mercury control • MidAmerican Energy reached an agreement with Sierra Club that would require the smaller coal-fueled units to cease burning coal by April 2016; this equates to approximately 20% of coal-fueled generation or 673 megawatts of capacity • By 2016, nearly 700 MW of operated coal-fueled generation will either be converted to natural gas or retired, resulting in 100% of coal-fueled generation controlled with scrubbers, baghouses, and mercury controls, and 63% with post- combustion NOx controls – Riverside Units 3 and 5 (137 MW) will likely be converted to natural gas – Walter Scott, Jr. Unit 1 (37 MW) and Unit 2 (81 MW) will likely be retired – George Neal Unit 1 (134 MW) and Unit 2 (284 MW) will likely be converted to natural gas or retired

• MidAmerican Energy plans to construct portions of four 345-kV multi- value projects within the MISO footprint, totaling approximately 245 miles; approved by the MISO board in December 2011 • Expenditures predominantly in 2014-2017, totaling approximately $550 million • MVP projects are eligible for incentive rate treatment in MISO tariff, including construction work in progress in rate base and recovery of prudent costs incurred if projects are abandoned • MVP project revenue requirements broadly recovered from all MISO load; approximately 95% recovered from other MISO participants • MVP projects expected to provide multiple benefits, including improved reliability, reduced congestion, and support for additional generation development • All transmission investments utilize forward-looking rate treatment in MISO tariff, mitigating rate lag Transmission Development

Questions

Mark Hewett President and CEO, MidAmerican Energy Pipeline Group President and CEO, Northern Natural Gas Company

Overview • Headquartered in Omaha, Nebraska • 840 employees • 14,900-mile interstate natural gas transmission pipeline system • Market Area design capacity of 5.5 Bcf/day plus 2.0 Bcf/day Field Area delivery capacity to the Market Area • Five natural gas storage facilities, with a total firm capacity of more than 73 Bcf and more than 2.0 Bcf of peak day delivery capability • Access to five major natural gas supply regions and direct access to two non-traditional (tight sands and shale) supply regions • Annual average deliveries of 932 Bcf over the prior three years

Business Update • Solid operating results in 2012 – Continued to demonstrate financial strength even during the stagnant economy and flat price spreads – Successfully renegotiated Market Area contracts at higher rates – Increased Field Area revenue by nearly 10% compared to 2011 and 2010 • Built new lateral line to processing plant with a three-year term and annual revenue of $4 million – Increased the integrity and reliability of the pipeline while managing operating costs and staffing – On a regulatory basis, earned slightly above our allowed rate of return • Northern Natural Gas’ prices are competitive with other pipelines (minimizes level of discounting needed in competitive markets) • In the 17th Edition Mastio & Company pipeline industry survey, Northern Natural Gas ranked No. 1 out of 16 mega-pipelines and No. 1 out of 38 interstate pipelines in customer satisfaction • Successfully issued $250 million 30-year senior bonds at an interest rate of 4.10% – Repaid $300 million senior notes with 5.375% interest rate resulting in continued strengthening of the balance sheet

Transportation - Market 78% Transportation - Field 10% Storage 12% Revenue Stability and Long-Term Contracts 2013-2014 23% 2015-2016 12% 2017-2018 34% 2019-2020 22% 2021+ 9% Market Area Transportation Contract Maturities (1) (1) Based on maximum daily quantities of Market Area entitlement in decatherms as of Feb. 19, 2013 2012 Transportation and Storage Revenue $565 Million • 64% of 2012 transportation and storage demand revenue was from utilities • In 2012, completed approximately 1.1 Bcf/day in contract renewals with a 7% increase in rates, which provides additional $6 million in annual revenue and average term of seven years • 75% of 2012 storage revenue resulted from long-term contracts, with an average remaining contract life of approximately nine years  Northern Natural Gas currently contracts 100% of its firm storage service • Shippers that do not meet credit standards are required to post collateral Average remaining contract life of 5 years

• Northern has completed more than 20 Market Area expansions since 2007, resulting in 723,500 Dth/day of incremental capacity • Total project investment of more than $370 million through 2012 • Additional contracted firm service in 2013 of 19,000 Dth/day with minimal capital requirements • Continued expansions in 2014 and beyond to support long-term agreements • Several opportunities for incremental industrial and power demand have the potential to bring additional load to Northern Natural Gas’ system Market Area Expansion Projects Minnesota $250.0 million 466,000 Dth/day South Dakota $8.0 million 60,000 Dth/day Nebraska $25.0 million 58,000 Dth/day Iowa $88.0 million 122,000 Dth/day Wisconsin $1.0 million 17,500 Dth/day

Shale Gas Opportunities • Shale development is supportive of gas demand due to low supply prices • Change in gas flow patterns is occurring across the U.S. • Marcellus shale displacement of the south-central area should result in the softening of Field Area supply prices • Incremental receipt capacity of 1,320,000 Dth/day being attached from Granite Wash and Wolfberry, with 795,000 Dth/day already completed in 2011 and 2012

Shale Expansion Projects • Expanding access to additional unconventional supply from the Granite Wash tight sands and Wolfberry shale plays – Interconnects completed in 2011 and 2012 • Granite Wash production attached through existing interconnects plus four additional connections, with a total receipt capacity of 565,000 Dth/day • Wolfberry production attached through existing interconnects plus three additional connections, with a total receipt capacity of 230,000 Dth/day – Further expansion planned in 2013 • Northern Natural Gas is finalizing plans for additional potential supply connections of 525,000 Dth/day from the Wolfberry shale play

Alaska Gas Storage • MidAmerican owns a 26.5% interest in the Cook Inlet Natural Gas Storage Alaska development with SEMCO Energy Inc. • Construction is complete, with total cost approximately $20 million less than the original projection • Started service April 1, 2012 • Fully contracted (11 Bcf) for 20 years with four Southcentral Alaska utilities • Regulatory approval granted a 12.55% return on equity and 30-year depreciable life; approved with a 50/50 debt-to-equity ratio • Bank construction financing is expected to be replaced with permanent financing • Potential expansion opportunity exists

Gary Hoogeveen President Kern River Gas Transmission Company

Overview • Headquartered in Salt Lake City, Utah • 150 employees • 1,700-mile interstate natural gas transmission pipeline system • Delivers natural gas from Rocky Mountain basin to markets in Utah, Nevada, California and Arizona • Design capacity: 2.2 million Dth per day of natural gas • Nearly 92% of capacity is contracted under long-term contracts NEVADA CALIFORNIA ARIZONA UTAH WYOMING

Business Update • Long-term firm transportation agreements at a fixed reservation rate support existing debt • Debt retirements in 2016 and 2018 correlate with long-term firm contract expirations • As existing contracts expire, eligible shippers have an opportunity to recontract at Period Two rates − Based on 100% equity capital structure and return on equity of 11.55% − Period Two rates range from $0.20/Dth to $0.23/Dth for 15 year contracts, an average decrease of 52% from existing rates − There has been contracting success associated with 275,037 Dth of Period One contracts that have expired or will expire in 2013; approximately 77% of this amount has been contracted under either short- or long-term contracts • Competitive delivered cost to Southern California and Las Vegas • Market demand is stable • Strong long-term business outlook • FERC regulated • Experienced operator • Creditworthy customers

Revenue Long Term Contract Maturities(1) 2012 Revenue Distribution $383 Million (1) Based on design capacity of 2.2 million Dth per day • 94% of revenue is from demand charges • 92% of contracts expire after 2015 • Weighted average shipper rating of BBB/Baa1 • Shippers that do not meet credit standards are required to post collateral • Weighted average contract term of seven years Demand 94% Market Oriented 4% Other 2% 2013 8% 2016 30% 2017 4% 2018 34% 2020 4% 2025-2028 7% 2031-2033 13%

Strong Demand for Services Daily Average Scheduled Volume 2012 Deliveries by State (1) Based on the 2012 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 or Transwestern Pipeline Company, LLC. • Delivered approximately 32%(1) of California’s demand for natural gas • Delivered more than 80%(2) of southern Nevada’s natural gas • During 2012, scheduled throughput averaged 117% of design capacity • Ranked No. 2 out of 38 interstate pipelines in 17th Edition Mastio & Company survey for customer satisfaction California 73% Nevada 22% Utah 5% 0 500 1,000 1,500 2,000 2,500 3,000 2005 2006 2007 2008 2009 2010 2011 2012 D th in m ill io n s Scheduled Design

Long-Term Business Outlook Non-coincident Peak Day Deliveries (Dth/d)(1) Utah LDC (Questar Gas) 463,937 Direct-connect end-users 33,156 497,093 Nevada LDC (Southwest Gas) 523,491 Direct-connect end-users 517,964 1,041,455 California LDC (Southern California Gas) 0 Direct-connect end-users 187,672 187,672 Total 1,726,220 (80% of Kern River capacity) • Questar Gas has multiple interconnects with Questar Pipeline but relies on Kern River to provide peak-day deliveries • Kern River is the sole transporter of natural gas to Southern Nevada, with the exception of 141,000 Dth/d of capacity on Southwest Gas southern system • Southern California gas utilities have other pipeline or storage options on a peak day; however, direct-connect end-users rely on Kern River Markets Are Dependent on Kern River (1) Based on actual peak day deliveries over the past three years and an analysis of the LDCs’ pipeline supply options

Rockies $3.3827 Rockies $3.3827 Rockies $3.3827 Rockies $3.3827 Rockies $3.3827 San Juan $3.3439 San Juan $3.3439 Permian $3.3206 Permian $3.3206 Canadian at Kingsgate $3.3474 Canadian at Sumas $3.6171 Kern River $0.1951 Kern River $0.2224 Kern River $0.3633 Kern River $0.4717 El Paso $0.4514 El Paso $0.4514 Transwestern $0.3659 Transwestern $0.3759 GTN $0.3440 PG&E $0.2110 NWP $0.4100 GTN $0.1669 PG&E $0.2904 Ruby $1.1370 PG&E $0.2110 $3.6408 $3.7147 $3.8028 $3.8035 $3.8090 $3.8769 $3.9007 $3.9640 $4.0079 $4.6467 $4.8260 $0.0000 $1.0000 $2.0000 $3.0000 $4.0000 $5.0000 $6.0000 Kern River Period Two Vintage 15 yr * Kern River Period Two Expansion 15 yr ** Transwestern Transwestern Kern River Period One Vintage 15 yr * El Paso El Paso Kern River Period One Expansion 15 yr ** GTN NWP Ruby $/ D th Demand Transportation Fuel and commodity Natural Gas Lowest-Cost Option to Southern California Source: Platts’ January 2013 Monthly Average Gas Price, Interstate Pipeline FERC Gas Tariffs, California Gas Transmission’s website, and Kern River Period Two rates; Transportation rates include February 2013 fuel * Period One contracts expire Sept.30, 2016, then Period Two rates apply ** Period One contracts expire April 30, 2018, then Period Two rates apply

Questions

Phil Jones President and CEO Northern Powergrid

Northern Powergrid – Wires-Only Distributor Distribution business comparison Licenses Customers (millions) Revenue (millions) RAV (millions) Western Power 4 7.7 £1,219 £5,205 UK Power Networks 3 7.9 1,092 4,837 Northern Powergrid 2 3.9 576 2,334 SSE 2 3.7 739 2,942 Scottish Power 2 3.4 664 2,837 ENW 1 2.4 355 1,494 All data as of March 31, 2012, financial data based on Ofgem’s final proposals for DPCR5 • One of six electricity distribution groups in Great Britain • Stable revenues and cash flows • Key statistics include: –700 major substations –58,000 miles of circuit –10,000 square miles of service area –2,400 employees

Strong Investment Metrics • Return on book equity exceeds expectations • 35% growth in regulated asset value in DPCR5, primarily financed by operating cash flows • We have benefitted from inflation on revenue and regulated asset value (RAV) averaging over 3.4% p.a. since April 2007 • OpCo operating income remains strong, reflecting revenue growth, with a decrease due to pension expense • Strong credit rating of A- compares well with the rest of the sector • Successful debt issuance in 2012, £150 million at 4.375% for 20 years (£ millions) 2012 2011 2010 Revenues £653 £633 £518 12% Compound Annual Growth Operating income 357 384 304 8% Compound Annual Growth Capex 286 193 226 12% Compound Annual Growth RAV 2,480 2,334 2,162 7% Compound Annual Growth Interest cover 4.3x 4.3x 4.2x Debt to RAV gearing 55% 56% 54% Ofgem final proposals for 2010-2015 included growth for revenue and RAV – 7% underlying (real) revenue growth – 4% underlying (real) growth in RAV – Growth supplemented by in excess of 3.4% p.a. inflation from April 2007

Strong Operational Performance • Rated first or second on a range of efficiency measures used in the price control review • Safety performance is amongst the leaders in a high-performing industry • Delivery of the DPCR5 capex program is the main driver of value in the business; we are on target to hit our outputs for DPCR5, achieving an all-time peak capex delivery in 2012 – Staying on target with 60% of outputs delivered three years into the five-year price control period – Publicly forecast 14% outperformance of total cost allowances, with no categories overspent • Customer service is mid-pack but trending positively – Implemented many new Web-based services; the first group to offer online self-service transactions – Consistently exceeded our reliability and availability targets; average HV restoration time improved by 13% in 2012 alone • Successfully leading the largest smart grid project in the U.K., involving more than 13,000 customers • To date, we are the only group to forecast lower like-for-like total costs for the next price control period

Outlook for 2013-2023 Price Control Period • Ofgem’s new approach provides a much earlier view of the key parameters – Cost of equity is in a narrow range of 6.7% to 7.0% (before RPI) – Cost of debt based on a transparent index approach, currently 3.0% (before RPI) – Remuneration of existing assets confirmed at 20 years and new assets over 45 years, with potential for transition • A number of difficult issues encountered in previous controls have been resolved, such as cost boundaries and coverage for tax liabilities • The key financeability parameters fit well with our financial structure – The period 2020-2022 sees the maturity of the majority of our high-coupon debt reducing the overall cost of our debt portfolio – Retention of the 20-year life for existing assets eases pressure on credit metrics – Longer asset life creates a larger RPI-protected RAV • The process places greater emphasis on company plans and encourages direct engagement with stakeholders • Ofgem can grant fast-track status if it decides the plan is sufficiently well-justified – At the recent transmission and gas distribution reviews, two electricity transmission companies were fast-tracked out of 12 licensees

Fast-Track Opportunity DPCR5 2014 2015 FAST TRACK Ofgem evaluate plan Final proposals Plans passed NORMAL PRICE CONTROL EXECUTE Final proposals Efficiency assessment and negotiation EXECUTE Mobilize Revise plan 2016 Mobilize 2013 Plans rejected RIIO-ED1 2024 Produce plan • Well-run business • Delivery track record • Listened to stakeholders • Well-justified proposal SUCCESS FACTORS 2012 HEAD START

Northern Powergrid Outlook • Continued delivery capital investment with strong cost controls will enable continued outperformance of DPCR5 final proposals to improve return on equity • Execution of network performance and customer service initiatives to continue to deliver incremental outperformance • Outlook for next price control gives optimism for a reasonable settlement based on confirmation of key parameters and progress to date • Amidst a rapidly changing environment, we continue to look for good quality energy sector opportunities in the U.K. or elsewhere in Europe – The supplier-led rollout of 30 million smart meters by 2019 in the U.K. presents an asset rental opportunity; we are well placed to be part of that market – The concentration of longer-term owners in regulated networks has increased – Premiums have been high when network asset transactions have taken place – U.K. power market overhaul is still causing significant uncertainty around generation investment opportunities – Renewable assets prices are high, with subsidies offering little or no protection to equity – Nevertheless, legally binding carbon targets and security of supply concerns mean that significant investment will be required in the future

Questions

Paul Caudill President MidAmerican Solar

Topaz Solar Farms, LLC Overview • At 550 MWAC delivered, Topaz will be one of the world’s largest solar photovoltaic power plants upon final completion in 2015 – Project is being completed in six development and construction phases, with total projected costs of $2.4 billion – Project site is located on approximately 4,900 acres of land; in addition, some 17,500 acres of mitigation and preservation land were acquired by the company in the development phase of the project – 25-year power purchase agreement with Pacific Gas and Electric Company – Long-term transmission secured with Pacific Gas and Electric Company and California Independent System Operator through three large generation interconnection agreements – Fixed-price engineer, procure, construct and 25-year firm price operations and maintenance agreements executed with First Solar (ability to change O&M provider at our option every five years) California Valley Project Topaz California

Topaz Project Status • Construction and commissioning is on schedule to meet the following installed capacity at year-end – 2013: 281 MW – 2014: 533 MW – 2015: 586 MW • Through late March 2013, project is 39% complete, with more than 3.25 million of the 8.4 million First Solar Series 3 thin-film panels installed • Interconnection activities are complete, with the Pacific Gas and Electric Company switching station and project step-up substation constructed and tested to allow for initial operation • Backfeed power to the site was completed Jan. 24, 2013, and the project was synchronized to the transmission grid Feb. 22, 2013 • As of late March 2013, the plant is delivering 130 MW of electricity to the transmission grid and First Solar has formally turned over 105 MW of the plant to MidAmerican for operation • Independent engineer has confirmed that the project remains on schedule and on budget, and there are no reasons the substantial completion date (May 18, 2015) and guaranteed commercial operation date (Feb. 18, 2016) cannot be achieved

Topaz Aerial View – February 2013

Agua Caliente Solar Overview • 290 MWAC facility located on 2,340 acres in Yuma County, Arizona • MidAmerican Solar is a 49% owner of the project • 25-year power purchase agreement with Pacific Gas and Electric Company • Fixed-price engineer, procure, construct and 25-year firm price operations and maintenance agreements executed with First Solar (ability to change O&M provider at our option every five years) • Supported by U.S. Department of Energy loan guarantee agreement Agua Caliente Arizona

Agua Caliente Project Status • Construction and commissioning of plant by First Solar is proceeding well and is currently 76 days ahead of schedule and on budget, with 253 MW of the total 311 MW turned over to date – Maximum delivery at the point of interconnection limited to 290 MW • Interconnection activities, including the switchyard and substation, were completed in December 2011 • In April 2012, after review by the Department of Energy independent engineer, a change order was processed to allow construction and resulting payments under the engineer, procure, construct agreement to be accelerated; contract price did not change • Plant is being phased onto the transmission grid in 12 blocks of capacity; Blocks 1-9 have been completed and successfully turned over – Block 10 (25.2 MW) turnover projected ahead of schedule on May 10, 2013 – Block 11 (21.4 MW) turnover projected ahead of schedule on Sept. 24, 2013 – Block 12 (11.3 MW) turnover projected ahead of schedule on Jan. 10, 2014 • Guaranteed substantial completion date is March 31, 2014

Agua Caliente Operational Performance • In 2012, plant generated 445,494 MWh of energy compensated under the power purchase agreement • The original 2012 budget generation was 172,489 MWh; the revised 2012 budget generation following the schedule acceleration approved in April 2012 was 296,562 MWh – Majority of the favorable variance was the result of early completion of block capacity and resulting energy put to the grid • Effective availability totaled 99.83% • Plant control system designed to allow inverters to adjust during certain transmission grid disturbances (fault ride through) and dynamic voltage regulation being installed and tested as provision of Department of Energy loan guarantee agreement

Agua Caliente Solar – February 2013

Antelope Valley Solar Projects • On Jan. 2, 2013, MidAmerican announced the acquisition of 579 MW Antelope Valley Solar Projects from SunPower Corporation • Projects are co-located in Kern County and Los Angeles County, California • Both Antelope Valley Solar Project I and Antelope Valley Solar Project II will be built and produce energy to the transmission grid in phases, starting with first block turnovers in December 2013; final completion is expected in fourth quarter 2015 • 20-year power purchase agreements with Southern California Edison • Long-term transmission secured with Southern California Edison through long-term large generator interconnection agreements effective in December 2011 • Fixed-price engineer, procure and construct agreements executed with SunPower Corporation • 20-year operations and maintenance agreement executed with SunPower Corporation – Both projects will utilize SunPower E20 435-watt monocrystalline silicon modules and the T0 single axis tracking technology • Notice to proceed has been provided to SunPower • Site mobilization activities are well underway, with construction activities in progress on first arrays California Project Topaz Antelope Valley

Tom Budler President MidAmerican Wind

• 81 MW wind farm located in Henry County, approximately 20 miles southeast of Rock Island, Illinois • General Electric 1.62 MW wind turbines • 20-year power purchase agreement with Ameren Illinois Company (Baa2/BBB/BBB) • $120 million project financing closed on Aug. 21, 2012 • Commercial operation date – Dec. 7, 2012 • Turbines are performing well • Currently meeting or exceeding operational and budgetary targets Bishop Hill II Wind

• 300 MW wind farm located in the Tehachapi region of Kern County, California, approximately 75 miles north of Los Angeles • Vestas 3.0 MW wind turbines • 23-year power purchase agreement with Southern California Edison (A3/BBB+/A) • Assumed existing project financing • Commercial operation date of Jan. 1, 2013 • Turbines are performing well • Currently meeting or exceeding operational and budgetary targets Pinyon Pines Wind I and II

Questions

Gregory E. Abel Chairman, President and CEO MidAmerican Energy Holdings Company

Strategy • Create a common culture through the application of a consistent set of guiding core principles at each locally managed business • Develop an exceptional employee base, which safely operates and maintains a high-quality portfolio of asset-based businesses serving a diverse set of customers • Deliver a reasonable return on capital, ensuring long-term sustainability • Identify internal growth opportunities • Pursue industry acquisitions

Core Principles Operational Excellence Environmental Respect Customer Service Regulatory Integrity Employee Commitment Financial Strength BALANCED OUTCOMES

Customer Service – Deliver Reliable and Cost-Effective Service Mastio Results TQS Results Interstate Pipelines 2003 2013 Northern Natural Gas 43 1 Kern River 10 2 60 Company name not available 36.8% • Ranked first in major organizational groups category for eighth consecutive year 2012 Top 10 Utilities on Overall Customer Satisfaction Rank Utility Very Satisfied 1 Southern Company 95.1% 2 Portland General Electric 93.9% 3 MidAmerican 92.3% 4 Duke Energy 86.0% 5 South Carolina Electric and Gas 86.0% 6 Avista 84.0% 7 Entergy 83.5% 8 Westar Energy 82.8% 9 We Energies 82.6% 10 Wisconsin Public Service 79.2% Top 10% Goal: No. 1 No. 1 • Ranked in top three for ninth consecutive year

0 1 2 3 4 5 6 7 8 9 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Employee Commitment – Improve Safety Culture and Work Environment MidAmerican Incident Rate Achieved 16% improvement 2012 vs. 2011 1.25 compared to 1.49 Industry Median 1.68 1.00 Continued Focus on Improvement Top Decile 1.07 Trending positively through late March 2013

Environmental Respect – Prepare and Build for the Future Land & Natural Resources Water Climate Air Waste & Chemical Management Transmission Siting and Permitting Avian Protection Endangered Species Vegetation Management Coal Ash PCBs in Electrical Equipment HazMat Transport NSPS – New & Modified Sources NSPS – Existing Sources BACT Permitting International Negotiations 316(b) Effluent Guidelines Limitations Waters of the U.S. NPDES Pesticide Permits Waterbody – Specific Standards Utility MACT Interstate Transport (CAIR/CSAPR) Regional Haze/Visibility Multiple NAAQS New Source Review (NSR)

Operational Excellence – Improve Deployment and Operation of Assets 80 85 90 95 100 2011 2012 2013 2014 2015 2016 MidAmerican Energy Company PacifiCorp Coal Generation Equivalent Availability Top Quartile ≥ 87.8% (%) 92.1 89.9 Top Decile 89.3%

Regulatory Integrity – Respond to Economic Realities Infrastructure • Employees • Generation • Transmission • Distribution • Customer Service • Technology Public Policy • Customers • Customer groups • Regulators • Legislators • Special interest groups

Regulatory Integrity – Respond to Economic Realities Infrastructure • Employees • Generation • Transmission • Distribution • Customer Service • Technology Economic Reality • Rates – value matters • Reliability – expected and must be cost effective • Environmental responsibility – stewardship • Returns – long-term sustainability Public Policy • Customers • Customer groups • Regulators • Legislators • Special interest groups

Financial Strength – Create Opportunities for Reinvestment 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 2012 2013 2014 2015 4.0 4.5 4.4 2.6 Electric Transmission Pipeline Transmission Regulated Generation Regulated Wind Unregulated Wind Unregulated Solar Electric and Gas Distribution Other $ billions Capital Expenditures Total 2013–2015: $11.5 billion Note: Amounts include deferred payments and other non-cash items, except for equity AFUDC of $(0.6) billion in 2012, $(0.2) billion in 2013, $(0.1) billion in 2014 and $0.6 billion in 2015

Questions

Appendix

MidAmerican Non-GAAP Financial Measures FFO 2012 2011 2010 2001 (1) Net cash flows from operating activities 4,327$ 3,220$ 2,759$ 847$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions (40) 382 607 (196) FFO 4,287$ 3,602$ 3,366$ 651$ Adjusted Interest Interest expense 1,176$ 1,196$ 1,225$ 587$ Interest expense on subordinated debt - (26) (52) (88) Adjusted Interest 1,176$ 1,170$ 1,173$ 499$ FFO Interest Coverage (2) 4.6x 4.1x 3.9x 2.3x Adjusted Debt Debt(3) 21,622$ 19,937$ 19,811$ 8,050$ Subordinated debt - (22) (315) (888) Adjusted Debt 21,622$ 19,915$ 19,496$ 7,162$ FFO to Adjusted Debt (4) 19.8% 18.1% 17.3% 9.1% Capitalization Total MidAmerican shareholders’ equity 15,742$ 14,092$ 13,232$ 1,708$ Adjusted debt 21,622 19,915 19,496 7,162 Subordinated debt - 22 315 888 Noncontrolling interests 168 173 176 165 Capitalization 37,532$ 34,202$ 33,219$ 9,923$ Adjusted Debt to Total Capitalization (5) 57.6% 58.2% 58.7% 72.2% EBITDA Net income 1,495$ Interest expense 1,176 Capitalized interest (54) Income tax expense 148 Depreciation and amortization 1,455 EBITDA 4,220$ (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, MidAmerican senior debt, MidAmerican subordinated debt and subsidiary debt (including current maturities) (4) FFO to Adjusted Debt equals FFO divided by Adjusted Debt (5) Adjusted Debt to Total Capitalization equals Adjusted Debt divided by Capitalization ($ millions)

PacifiCorp Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2012 2011 2010 Net cash flows from operating activities 1,627$ 1,636$ 1,410$ +/- Changes in other operating assets and liabilities (169) (144) 373 FFO 1,458$ 1,492$ 1,783$ Interest expense 380$ 392$ 387$ FFO Interest Coverage (1) 4.8x 4.8x 5.6x Debt (2) 6,861$ 6,901$ 6,437$ FFO to Debt (3) 21.3% 21.6% 27.7% Capitalization PacifiCorp shareholders’ equity 7,644$ 7,312$ 7,311$ Debt 6,861 6,901 6,437 Capitalization 14,505$ 14,213$ 13,748$ Debt to Total Capitalization (4) 47.3% 48.6% 46.8%

MidAmerican Energy Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2012 2011 2010 Net cash flows from operating activities 1,276$ 770$ 831$ +/- Changes in other operating assets and liabilities (323) 354 40 FFO 953$ 1,124$ 871$ Interest expense 143$ 158$ 156$ FFO Interest Coverage (1) 7.7x 8.1x 6.6x Debt (2) 3,259$ 3,115$ 2,865$ FFO to Debt (3) 29.2% 36.1% 30.4% Capitalization MidAmerican Energy shareholders’ equity 3,635$ 3,271$ 2,958$ Debt 3,259 3,115 2,865 Noncontrolling interests - 1 1 Capitalization 6,894$ 6,387$ 5,824$ Debt to Total Capitalization (4) 47.3% 48.8% 49.2%

Northern Natural Gas Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2012 2011 2010 Net cash flows from operating activities 304$ 286$ 302$ +/- Changes in other operating assets and liabilities (27) 24 11 FFO 277$ 310$ 313$ Interest expense 52$ 56$ 60$ FFO Interest Coverage (1) 6.3x 6.5x 6.2x Debt (2) 899$ 950$ 1,000$ FFO to Debt (3) 30.8% 32.6% 31.3% Capitalization Northern Natural Gas shareholder’s equity 1,290$ 1,274$ 1,214$ Debt 899 950 1,000 Capitalization 2,189$ 2,224$ 2,214$ Debt to Total Capitalization (4) 41.1% 42.7% 45.2%

Kern River Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2012 2011 2010 Net cash flows from operating activities 249$ 227$ 183$ +/- Changes in other operating assets and liabilities (1) - 1 FFO 248$ 227$ 184$ Interest expense 38$ 43$ 47$ FFO Interest Coverage (1) 7.5x 6.3x 4.9x Debt (2) 628$ 716$ 790$ FFO to Debt (3) 39.5% 31.7% 23.3% Capitalization Partners’ capital 880$ 868$ 704$ Debt 628 716 790 Capitalization 1,508$ 1,584$ 1,494$ Debt to Total Capitalization (4) 41.6% 45.2% 52.9%

Northern Powergrid Non-GAAP Financial Measures (1) FFO Interest Coverage equals the sum of FFO and Interest divided by Interest (2) Debt includes short-term debt and current maturities (3) FFO to Debt equals FFO divided by Debt (4) Debt to Total Capitalization equals Debt divided by Capitalization ($ millions) FFO 2012 2011 2010 Net cash flows from operating activities 413$ 362$ 315$ +/- Changes in other operating assets and liabilities 103 183 52 FFO 516$ 545$ 367$ Interest expense 139$ 151$ 146$ FFO Interest Coverage (1) 4.7x 4.6x 3.5x Debt (2) 2,408$ 2,146$ 1,908$ FFO to Debt (3) 21.4% 25.4% 19.2% Capitalization Northern Powergrid shareholders’ equity 2,611$ 2,161$ 1,849$ Debt 2,408 2,146 1,908 Noncontrolling interests 56 56 57 Capitalization 5,075$ 4,363$ 3,814$ Debt to Total Capitalization (4) 47.4% 49.2% 50.0%

Debt Maturities Long-Term Debt Maturities(1) (1) Excludes capital leases ($ millions) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 MidAmerican Parent -$ 250$ -$ -$ -$ 650$ -$ -$ -$ -$ PacifiCorp 261 253 122 57 52 586 350 38 420 605 MidA erican Energy 669 350 427 34 254 350 - - - - Northern Natural Gas - - 100 - - 200 - - 200 - Kern River 80 81 85 190 62 129 - - - - MidAmerican Renewables 104 37 66 83 84 92 418 46 49 40 Northern Powergrid Holdings - - - - - 65 65 551 - 570 1,114$ 971$ 800$ 364$ 452$ 2,072$ 833$ 635$ 669$ 1,215$

A Berkshire Hathaway Company