MidAmerican Energy Holdings Company 2012 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 generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition; – the outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company’s ability to recover costs in a timely manner; – changes in economic, industry, competition or weather conditions, as well as demographic trends, 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 that could impact the Company’s hedging strategy and the cost of balancing its generation resources and wholesale activities with its retail load obligations; – performance and availability of the Company’s generating facilities, including the impacts of outages or repairs, transmission constraints, weather and operating conditions; – changes in prices, availability and demand for both purchases and sales of 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 derivative contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in the commodity prices, interest rates and other conditions that affect the fair value of derivative contracts; – the impact of inflation on costs and our ability to recover such costs in regulated rates; – increases in employee healthcare costs; – the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements; – changes in the residential real estate brokerage 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 generating facilities and infrastructure additions; – the availability and price of natural gas in applicable geographic regions; – 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, 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 REVENUES $11.2 billion ASSETS $48 billion CUSTOMERS Electric 6.3 million Natural Gas 0.7 million EMPLOYEES 15,800 NATURAL GAS TRANSMISSION PIPELINE DESIGN CAPACITY Approximately 7.7 billion cubic feet per day GENERATION CAPACITY 20,494 MW(1) Coal 47% Natural Gas 24% Wind 17% Hydro 6% Solar 3% Nuclear and other 3% (1) Net MW owned in operation and under construction as of Dec. 31, 2011, adjusted to include acquisitions of Topaz (550 MW), Agua Caliente (142 MW), and Bishop Hill II (81 MW) United Kingdom Philippines

MidAmerican Competitive Advantage • Diversified portfolio of regulated assets – Weather, customer, regulatory, generation, economic and catastrophic risk diversity • 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 has allowed us to realize significant tax benefits, such as bonus depreciation, PTC and EITC • Berkshire Hathaway provides MidAmerican with a $2 billion equity commitment through Feb. 28, 2014 – Access to capital even in times of industry and general market stress • No other utility has this quality of explicit financial support – Commitment can only be drawn for two purposes: • Paying MidAmerican parent debt when due • Funding the general corporate purposes and capital requirements of MidAmerican’s regulated subsidiaries – Future mergers and acquisitions funded separate from this agreement

MidAmerican Funding 18.6% PacifiCorp 41.8% Northern Powergrid 18.5% MidAmerican Energy Pipeline Group 15.7% MidAmerican Renewables 4.2% HomeServices 1.2% • Diversification of revenue sources reduces regulatory concentrations • In 2011, 95% of EBITDA is from investment-grade regulated subsidiaries Consolidated EBITDA(2): $4.1 Billion Iowa 22.0% Utah 19.3% Oregon 10.8% Wyoming 8.1% Washington 3.1% Idaho 2.7% California 0.9% Illinois 10.1% Texas 1.4% South Dakota 1.2% Other 0.7% FERC 9.5% United Kingdom 9.9% Philippines 0.3% MidAmerican 2011 (1) Excludes HomeServices, which has operations in 20 states and adds further diversification, and equity income from MidAmerican Geothermal (2) Refer to the Appendix for the calculation of EBITDA; percentages exclude MidAmerican and Other MidAmerican 2011 Energy Revenue(1): $10.2 Billion Revenue and EBITDA Diversification

$1,189 $1,204 $1,157 $1,238 $1,331 $0 $500 $1,000 $1,500 $2,000 2007 2008 2009 2010 2011 Millions MidAmerican Financial Summary $26.2 $28.5 $30.9 $31.9 $34.2 $0.0 $7.5 $15.0 $22.5 $30.0 $37.5 2007 2008 2009 2010 2011 Billions $2,335 $2,587 $3,572 $2,759 $3,220 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 2007 2008 2009 2010 2011 Millions $9.3 $10.2 $12.6 $13.2 $14.1 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 $16.0 2007 2008 2009 2010 2011 Billions Net Income Attributable to MidAmerican MidAmerican Shareholders’ Equity Property, Plant and Equipment (Net) Cash Flows from Operations $1,850 (1) (1) $1,850 million net income includes $646 million of after-tax gains related to the termination fee and profit from the investment in Constellation Energy

Credit Metrics and Ratings (1) Refer to the Appendix for the calculations of key ratios (2) Ratings for PacifiCorp and Kern River Funding Corp. are senior secured rating • MidAmerican Key Credit Ratios(1) – Zero dividends paid to Berkshire Hathaway and tax benefits have allowed for an accelerated improvement in credit ratios • Ratings (Issuer or senior unsecured ratings unless noted) Moody’s S&P Fitch MidAmerican Energy Holdings Company 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) A3 A- A- Northern Powergrid (Northeast) A3 A- A Northern Powergrid (Yorkshire) A3 A- A 2011 2010 2009 2001 FFO Int rest Cov rage 4.1x 3.9x 3.9x 2.3x FFO to Debt 18.1% 17.3% 17.7% 9.1% Debt to Total Capitalization 58.2% 58.7% 59.0% 72.2%

Reportable Segment Information Operating Income ($ millions) 2011 2010 2009 PacifiCorp $ 1,099 $ 1,055 $ 1,079 MidAmerican Funding 428 460 469 MidAmerican Energy Pipeline Group 468 472 558 Northern Powergrid Holdings 615 474 394 MidAmerican Renewables 106 88 128 HomeServices 24 17 11 MidAmerican and Other (56) (64) (174) Total operating income 2,684 2,502 2,465 Interest expense (1,170) (1,173) (1,195) Interest expense on MidAmerican subordinated debt – Berkshire (13) (30) (58) Interest expense on MidAmerican subordinated debt – other (13) (22) (22) Capitalized interest 40 54 41 Interest and dividend income 14 24 38 Other, net 51 110 146 Income before income tax expense and other 1,593 1,465 1,415 Income tax expense (294) (198) (282) Other, net 32 (29) 24 Net income attributable to MidAmerican 1,331$ 1,238$ 1,157$ Years Ended Dec. 31

Projected Capital Expenditures and Cash Flows from Operations • MidAmerican and its subsidiaries will spend approximately $10.9 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 (1) Cash flows from operations in 2011 and 2012 include benefits from bonus depreciation legislation of $428 million and $765 million, respectively (1) $(1,000) $(500) $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 $5,000 2007A 2008A 2009A 2010A 2011A 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Capital Expenditures - variance to prior year projection Cash Flows from Operations Capital Expenditures (including Chehalis acquisition in 2008) $ m ill ion s

Projected Capital Expenditures and Debt Maturities Projected Capital Expenditures Long-Term Debt Maturities(1) (1) Excludes subordinated debt, capital leases and nonregulated project debt ($ millions) - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 $ mi llion s PacifiCorp MidAmerican Funding Northern Powergrid Renewables, NNG, Kern River & Other 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 MidAmerican Parent (742)$ -$ (250)$ -$ -$ -$ (650)$ -$ -$ -$ PacifiCorp (17) (261) (253) (122) (57) (52) (586) (350) (38) (428) MidA erican Energy - (944) (350) - (34) (254) (350) - - - Northern Natural Gas (300) - - (100) - - (200) - - (200) Kern River (88) (80) (81) (85) (190) (62) (129) - - - Northern Powergrid - - - - - - (62) (62) (526) - (1,147)$ (1,285)$ (934)$ (307)$ (281)$ (368)$ (1,977)$ (412)$ (564)$ (628)$

Hydroelectric Significant Renewable Energy Experience • MidAmerican owns one of the largest renewable energy portfolios in the U.S. and is highly experienced in the renewables sector, with more than 5,500 MW of renewable generation capacity in operation or under construction 1. CE Turbo, CA, 5 MW 11. Intrepid, IA, 176 MW 21. Rogue River System, OR, 52 MW 31. Rolling Hills, WY, 99 MW 2. Del Ranch, CA, 19 MW 12. Pomeroy, IA, 286 MW 22. Lewis River System, WA, 578 MW 32. Seven Mile Hill I & II, WY, 119 MW 3. Elmore, CA, 19 MW 13. Rolling Hills, IA, 444 MW 23. Leaning Juniper 1, OR, 101 MW 33. Blundell, UT, 34 MW 4. Leathers, CA, 19 MW 14. Victory, IA, 99 MW 24. Goodnoe Hills, WA, 94 MW 34. Camas Co-Gen, WA, 14 MW 5. Salton Sea Projects I-V, CA, 85 MW 15. Walnut, IA, 153 MW 25. Marengo I & II, WA, 210 MW 35. Casecnan, Philippines, 128 MW 6. Vulcan, CA, 17 MW 16. Wind Projects, IA, 407 MW * 26. Dunlap Ranch I, WY, 111 MW 36. Wailuku, HI, 5 MW 7. Adair, IA, 175 MW 17. Laurel, IA, 120 MW 27. Foote Creek, WY, 32 MW 37. Topaz Solar, CA, 550 MW * 8. Carroll, IA, 150 MW 18. Bear River System, ID, 105 MW 28. Glenrock I & III, WY, 138 MW 38. Agua Caliente, AZ, 142 MW * 9. Century, IA, 200 MW 19. Klamath River System, OR, 170 MW 29. High Plains, WY, 99 MW 39. Bishop Hill, IL, 81 MW * 10. Charles City, IA, 75 MW 20. North Umpqua River, OR, 204 MW 30. McFadden Ridge I, WY, 28 MW Minor Hydroelectric Facilities, 39 MW Geothermal Wind Biomass 5 6 1 2 3 4 7 8 9 10 11 12 13 15 14 23 33 24 34 25 26 27 32 28 29 30 31 Solar 38 Philippines 36 18 19 20 21 35 22 16 17 37 39 * Denotes under construction Solar * Denotes under construction

MidAmerican Growth Opportunities • Transmission and generation investments at PacifiCorp and MidAmerican Energy • Continued transmission build-out within our Electric Transmission Texas, LLC joint venture with AEP • Build cycle for Northern Powergrid electric distribution assets • MidAmerican Renewables

Financing Plan 2012-2013 • PacifiCorp – Issued $650 million of 10-year and 30-year bonds at 2.95% and 4.10%, respectively, January 2012, to refinance its short-term borrowing position, fund capital expenditures and for general corporate purposes – Completed a re-opener of the 10-year, 2.95% bond by issuing $100 million in March 2012; proceeds were used to call and repay $84 million of higher interest rate fixed-rate pollution control revenue bonds • Topaz Solar Farms, LLC – $850 million issued in February 2012 at 5.75% and approximately $430 million is planned in late 2012 or 2013 • Kern River anticipates an issuance to finance the capital costs of the Apex Expansion project, which went into service in October 2011 • Northern Natural Gas anticipates refinancing its October 2012 $300 million maturity • Northern Powergrid (Yorkshire) plc anticipates a 2012 Sterling debt issuance in support of capital investments • Electric Transmission Texas, LLC anticipates a June 2012 debt issuance to fund its continued expansion in ERCOT • Wind and solar financing options are being considered and will be determined by the size and number of projects obtained • MidAmerican financing will depend on the number of opportunities we acquire

Questions

Richard Walje President and CEO Rocky Mountain Power

Overview • Headquartered in Portland, Oregon • 6,400 employees • 1.7 million electricity customers • 11,234 net MW generation capacity(1) • Generating capacity by fuel type(1) – Coal 55% – Natural gas 25% – Hydro 10% – Wind, geothermal and other 10% (a) Access to other entities’ transmission lines through wheeling arrangements (1) Net MW owned in operation and under construction as of Dec. 31, 2011

Overview Rocky Mountain Power service territory • 100-year anniversary • 1,011,000 electric customers • Weather-normalized retail sales increased 2.5%, from 35.6 TWh in 2010 to 36.5 TWh in 2011 • Tariff increases of more than $200 million (9%) in Utah, Wyoming and Idaho during 2011 and 2012 • Safety remains a top priority, with continued year- on-year improvements • Improved customer satisfaction as measured by rankings in national surveys for residential and small-business customers • Utah, Wyoming and Idaho electric rates remain among the lowest in the nation

Forecast of Economic Recovery and Load Growth 2011 compared to 2010: • Strong recovery by industrial and commercial sectors (3.7% and 3.3% growth) • Modest growth in residential sector (0.6% growth) Forecast for 2012 and 2013: • Industrial sector sales dip in 2012, as several large customers increase self-generation • Healthy growth for industrial and commercial sectors, primarily due to extractive industries • Modest residential growth Key economic factors: • Brisk oil and gas development in Utah and Wyoming • Low electricity costs attract energy- intensive industries • Continued population growth Annual Growth Rates: 2008 = 4.0% 2009 = (2.6%) 2010 = 4.2% 2011 = 2.5% 2012 = (0.6%) 2013 = 2.7% 30 31 32 33 34 35 36 37 38 39 40 2007 2008 2009 2010 2011 2012 Fcst 2013 Fcst T er a w a tt -h o u rs Rocky Mountain Power Retail Load Weather-Normalized Annual Growth Rates: 2008 = 4.0% 2009 = (2.6%) 2010 = 4.2% 2011 = 2.5% 2012 = (0.6%) 2013 = 2.7%

Cost Adjustment Mechanisms • Over the last two years, energy cost recovery and renewable energy credit balancing mechanisms were adopted or extended in each state • Customers pay the costs and receive the benefits associated with fluctuating power costs and sales of RECs • Enables a 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

• Utah – General rate increase of $117 million (7%) in September 2011 enables recovery of capital investments to serve growing needs of customers and rising coal costs – Energy balancing account was approved in 2011; commission decision on a one-year $29 million request is anticipated in June 2012 – Pending general rate increase of $172 million (10%) due to new investment and higher power plant operating costs to comply with regulatory mandates; commission decision anticipated in October 2012 • Idaho – Commission approved a one-year $10 million recovery in April 2011 for the energy cost adjustment mechanism; filed for a one-year energy cost recovery of $13 million effective April 2012, pending commission order – General rate increase of $17 million (8%) in January 2012 enables recovery of capital investments to serve growing needs of customers and compliance with environmental mandates and covers rising power costs; additional increase of $17 million (7%) approved, effective January 2013 Regulatory Accomplishments

• Wyoming – General rate increase of $10 million (2%) in February 2011, primarily enables recovery of new transmission investment, including the first phase of Populus-to-Terminal – One-year power cost recovery of $14 million was effective in 2011 – September 2011 general rate increase of $62 million (11%) enables recovery of new capital investment to serve growing customer needs and rising power costs, as beneficial long-term power purchase contracts expired – Renewable energy credit revenue adjustment mechanism established in September 2011, with $17 million one-year credit – Pending one-year $29 million recovery under the energy cost adjustment mechanism and a one-year $15 million renewable energy credit; commission decision anticipated in May 2012 – Pending general rate increase of $63 million (10%) due to capital investments to serve growing load, compliance with environmental mandates and rising cost of new coal contracts; commission decision anticipated in October 2012 Regulatory Accomplishments

• Significant commitment to reliability and compliance initiatives – transmission line clearances, critical infrastructure and avian protection • Work plans target pockets of reliability issues to improve reliability in the worst performing areas 100 120 140 160 180 200 220 240 2005 2006 2007 2008 2009 2010 2011 M inute s System Average Interruption Duration Index Service Quality Improvement • Successfully managed restoration of service after intense December 2011 wind storm in Utah; at the peak, 84,000 customers were without power; more than 700 employees and contractors were deployed to restore service • New program implemented in 2011 to reduce the number of human- caused outages Reliability improves 17%

Program Initiatives • Review of engineering standards for transmission and distribution construction to reduce the total life- cycle cost of new assets • Benchmarking transmission and distribution business processes and costs • Multiyear plan to upgrade infrastructure in Casper, Wyoming, started in 2007; capacity expansion projects are on track to be complete by June 2015 • New demand-side management programs will be implemented in 2012 to mitigate load growth and load peak New Service Connections Load Growth Mandated & Regulatory Replacement Other • Initiated a vehicle idling campaign; the benefits include compliance with anti-idling ordinances, improved air quality, and reduced gas consumption Distribution and Local Transmission Capital Investment Allocation

Operational Excellence • Six years of improvement in employee safety; top 5% of the electric utility industry • Customer service initiatives in paperless billing, electronic payment options for customers, expansion of automated meter reading, and customer communication improvements • Balanced outcomes, with multiyear contract negotiated with a major union • Energy efficiency programs have enabled 5% energy savings for customers; by 2020 the cumulative energy efficiency savings are expected to reach 10% of total energy consumed 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 2005 2006 2007 2008 2009 2010 2011 O S H A R ec o rd a b le Ra te Safety Improvement Continues

Pat Reiten President and CEO Pacific Power

• Ranked seventh nationally in industrial and top 10 in MSI residential customer satisfaction • Long-term agreements and multiyear extension reached with three employee unions in Pacific Power service territory Overview • 731,000 electric customers • Weather-normalized retail load was 17.7 TWh in 2011 vs. 17.8 TWh in 2010, a 0.6% decrease; forecast to decrease 0.5% from 2011 to 2012 • Rate case settlements with fair revenue results were received in Oregon and California; Washington rate case order (1.5%) due/effective June 1, 2012 • Surcharges to fund Klamath dam removal approved in California • Network reliability has remained consistent over the last five years Pacific Power service territory

16 17 18 19 20 2007 2008 2009 2010 2011 2012 Fcst 2013 Fcst Pacific Power Retail Load Weather-Normalized Retail Load Forecast In 2011: • Fourth straight year of weather-normalized load decline • Continued impact of recession on residential loads, down 3%, and industrial down 0.3% • Improved commercial loads from new data centers, up 1.8% Forecast for 2012 and 2013: • Overall, no recovery in 2012 and moderate recovery in commercial and industrial load in 2013, offset by lighting efficiency standards • The company has implemented initiatives to manage costs and mitigate lower revenues under the declining load forecast Annual Growth Rates: 2008 = (1.1%) 2009 = (3.7%) 2010 = (0.7%) 2011 = (0.7%) 2012 = (0.2%) 2013 = 0.6% T er rawa tt -hou rs

Regulatory Accomplishments • Oregon – Rate increase of $51 million (4%), effective Jan. 1, 2012, through the Transition Adjustment Mechanism, reflecting higher power costs – 2012 general rate case filing supports an increase of $41 million (3%), with new rates proposed to become effective Jan. 1, 2013 – General rate case requests a prudence determination for the Mona-to-Oquirrh transmission line; a rate change would go into effect after the project is complete, resulting in an increase in rates of $13 million (1%) in mid-2013 – Initial filing for the 2013 Transition Adjustment Mechanism supports an increase of $10 million (1%); filing will be updated and adjusted during the year, with new rates effective Jan. 1, 2013 • California – Annual attrition adjustment resulted in a rate increase of $1 million (1%), effective Jan. 1, 2012 – Order approving stipulation with the Division of Ratepayer Advocates for a power cost increase of $2 million (2%), effective March 9, 2012, through the Energy Cost Adjustment Clause; next filing will occur Aug. 1, 2012, with rates effective Jan. 1, 2013 – Adjustment mechanism filings will continue through 2013 for major plant additions and annual attrition adjustment • Washington – All-party settlement reached in 2010 general rate case, pending commission approval; provides an increase of $5 million (2%), effective June 1, 2012 – Awaiting commission order on renewable energy credit proceeding

0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2006 2007 2008 2009 2010 2011 Pacific Power SAIFI Excluding Major Events • Significant continued improvement in reliability and frequency of service interruption • Work plans and capital investment targeted key customer and geographic areas • Reliability and customer response beyond compliance are consistently reported to regulators System Average Interruption Frequency Reliability improves 33%

• Local 659 – 480 employees; new five-year agreement; 1.5% average wage increase – HSA: 90/10 cost share; ramp to 80/20 on June 1, 2012, through term end • Local 125 – 370 employees; new four-year agreement; 1.6% average wage increase – Trust: 75/25 cost share; ramp to 70/30 on Jan. 26, 2015, through term end • Local 197 – 28 employees; five-year extension at 2% average wage increase – Deductible: 75/25 cost share with $300 deductible; ramp to 70/30 with $400 deductible in 2013 through term end Long-term Labor Agreements

Operations, Maintenance, Administrative and General Expenses Trending • O&M expenses have generally remained flat over the past several years $176.1 $186.7 $179.1 $177.4 $181.6 $0.0 $50.0 $100.0 $150.0 $200.0 2007 2008 2009 2010 2011 ($ millions)

Operational Excellence Operations and System Performance • Major companywide safety initiative; all-inclusive, prevention and case management • Continue to offset cost increases through efficiencies – Consolidation of operation centers in Washington – Cost reductions achieved through purchase of three district offices previously leased in Oregon and California • Continuing augmentation of regular California system investment to reduce outage frequency and duration

Compliance/Regulatory Issues – 2011 Results • Settled Feb. 14, 2008, reliability event investigation – Approved by FERC on Dec. 1, 2011 • Repealed SB 408 tax true-up law in Oregon – Corrective law signed May 24, 2011 • Fought Bonneville Power Administration wind curtailment policy; drove landmark FERC ruling affecting nonpublic utilities • Settled Bonneville Power Administration Residential Exchange dispute

Energy Gateway Transmission Expansion • Multiyear, multisegment, multibillion dollar investment plan • Designed to provide 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 • First segment (B) completed in November 2010 • Second segment (C) under construction • Progress continues on longer-term segments, including Gateway West and Gateway South • MOUs signed with third parties for two lines west of Hemingway

Energy Gateway Progress Update Mona to Oquirrh • 100 miles, single-circuit 500 kV and double-circuit 345 kV • Under construction and on schedule • 280 foundations and 110 towers installed out of 471 total for the project • Scheduled in-service by May 2013 Sigurd to Red Butte • 160 miles, single-circuit 345 kV • Draft EIS issued in May 2011; final EIS anticipated in May 2012 • Scheduled in-service June 2015 Gateway South • 400 miles, single-circuit 500 kV • BLM public scoping completed in June 2011; draft EIS expected in summer 2013 • Scheduled in-service 2017-2020 Mona-to-Oquirrh 500-kV towers

Energy Gateway Progress Update (continued) Gateway West • More than 1,000 miles, single-circuit 230 kV and single-circuit 500 kV • Draft EIS issued July 2011; final EIS targeted for October 2012 • Selected by federal Rapid Response Team for prioritized federal permitting • One of two planned 230-kV lines between Windstar and Aeolus is no longer needed • Scheduled in-service between 2016 and 2021 West of Hemingway (Hemingway-Captain Jack Alternative) • Permitting agreement signed with Idaho Power and BPA on 500-kV Boardman-Hemingway • Discussions continue with Portland General Electric on 500-kV Cascade Crossing (Boardman-Bethel)

Energy Gateway Key Challenges Schedule uncertainty • Gateway West Draft Environmental Impact Study was delayed 29 months from BLM’s original schedule • No agency preferred route included in Gateway West DEIS, adding time to the process • Delays make timing difficult relative to Integrated Resource Plan (Wyoming wind) Policy uncertainty • Sage Grouse – fluctuating requirements; states/federal inconsistency • Private land vs. public land use Conflicting directives, priorities • Reliability requirements (line separation) vs. land use policy (line consolidation) • Environmentally/agency preferred route vs. local community preference Routing dispute resolution • Role of counties, state, federal agencies and proponents is unclear, resulting in delays • Different processes, numerous opportunities for legal challenges

The Road to Transmission Policy Improvement

Rapid Response Team Pilot Projects

Micheal Dunn President and CEO PacifiCorp Energy

Diversified Resource Portfolio 11,234 net MW generation capacity(1) • 6,157 MW coal-fueled generation • 2,853 MW natural gas-fueled generation • 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, 2011 (a) Access to other entities’ transmission lines through wheeling arrangements

March 31, 2006 Dec. 31, 2011 8,470 MW (1) 11,234 MW (1) Generating Capacity by Fuel Type Coal 72% Natural Gas 13% Hydroelectric 14% Wind, Geothermal and Other 1% Coal 55% Natural Gas 25% Hydroelectric 10% Wind, Geothermal and Other 10% (1) Net MW owned in operation and under construction

Plan to Meet Customer Needs Source: PacifiCorp 2011 Integrated Resource Plan Update, March 2012 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Meg awa tts Obligation + Reserves New Firm Market Purchases DSM and Other New Gas Resources Existing Owned and Contracted Resources

Capital Requirements Under the Current Resource Plan • 2012-2014 Capital Plan ($ millions) – New generation $ 909 – Environmental compliance 642 – Hydro license implementation 133 – Maintenance capital 507 Note: Excluding AFUDC $2,191 New generation Environmental compliance Hydro license implementation Maintenance capital 42% 29% 6% 23%

• Regional Haze Rules – PacifiCorp’s comprehensive air initiative began in 2005 – EPA to act on Utah and Wyoming state implementation plans in April and May, respectively • Mercury and Air Toxics Standard (MATS) – Final rule promulgated Feb. 16, 2012 – Compliance deadline April 16, 2015 • Proposed Clean Water Act 316(b) Cooling Water Intake Rule Making – Final rule is required by July 27, 2012 – Standards are required to be met as soon as possible following the effective date of the rule but no later than eight years thereafter • Proposed Coal Combustion Residuals Rule Making – EPA final rule not expected prior to late 2012 – Anticipate five-year compliance time frame after promulgation of rules Environmental Protection Agency Mandates

• Of PacifiCorp’s 5,765 MW(1) of operated or wholly owned coal-fueled generation: – 83% of generation has nitrogen oxides controls, consisting of low-NOx burners and over-fire air – 91% of generation has scrubbers for sulfur dioxide control – 44% of generation has baghouses for particulate matter control Current Environmental Position (1) Excludes minority-owned Craig, Colstrip and Hayden plants

PacifiCorp Capital Cost of Compliance Project Regional Haze Rules HAPs MACT CCR Management Scrubbers, Baghouses, Low-NOx Burners and Selective Catalytic Reduction $1.3 billion Coal Fleet Mercury Controls $38 million Coal Fleet Coal Combustion Residue Management (including asset retirement obligation) $284 million Note: Including AFUDC Total 2012-2021 PacifiCorp Environmental Capital: $1.6 billion

Wind Benefit – Decreasing Carbon Footprint Note: PacifiCorp’s share of generation from all thermal, hydro, wind and geothermal resources 1,400 1,500 1,600 1,700 1,800 1,900 2,000 2,100 2,200 0 10,000,000 20,000,000 30,000,000 40,000,000 50,000,000 60,000,000 70,000,000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 L b s C O 2 /M W h M W h Gener a te d Gross MWh Generated CO2 Emissions

• Of PacifiCorp’s 5,593 MW(1) of operated or wholly owned coal-fueled generation: – 96% of generation will have nitrogen oxides controls – 96% of generation will have scrubbers for sulfur dioxide control – 64% of generation will have baghouses for particulate matter control – 100% of generation is expected to have mercury controls or otherwise be compliant with pending regulations 2016 Environmental Position (1) Excludes minority-owned Craig, Colstrip and Hayden plants

Questions

Bill Fehrman President and CEO MidAmerican Energy Company

Overview (1) Net MW owned in operation and under construction as of Dec. 31, 2011 • Headquartered in Des Moines, Iowa • 3,500 employees • 1.4 million electric and natural gas customers in four Midwestern states • 7,432 net MW generation capacity(1) • Generating capacity by fuel type(1) – Coal 45% – Natural gas 17% – Wind 31% – Nuclear and other 7% MidAmerican Energy Service Territory Major Generating Facilities Wind Projects Under Construction Wind Projects SOUTH DAKOTA NEBRASKA KANSAS MISSOURI ILLINOIS WISCONSIN MINNESOTA IOWA

Business Update • Financial Strength – Maintained strong financial results despite low wholesale power prices impacted by low natural gas prices • Regulated electric retail sales (weather-normalized) were 1.2% higher in 2011 than 2010 – Power prices in 2011 were the lowest since 2003, and regional MISO power prices averaged $25.11/MWh in 2011, compared to $26.77/MWh in 2010 19,500 20,000 20,500 21,000 21,500 22,000 22,500 23,000 2007 2008 2009 2010 2011 2012 Fcst 2013 Fcst G W h MidAmerican Energy Retail Load Weather-Normalized Annual Growth Rates: 2008 = 1.8% 2009 = (2.6%) 2010 = 4.2% 2011 = 1.2% 2012 = 2.2% 2013 = 1.6% – MidAmerican Energy realized income tax benefits in 2009, 2010 and 2011 related to bonus depreciation, production tax credits and tax method changes – Forecast load for 2012 and 2013 reflects growth rates more consistent with historical rates – Proposed rider mechanisms in Iowa are expected to offset higher costs in 2012 and 2013

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 $238 million – Completed construction of 594 MW of wind generation in 2011 and will complete an additional 407 MW in 2012 • Regulatory Integrity – Focus is on a balanced outcome 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 54% of Iowa electric rate base is subject to advanced rate-making principles at the end of 2011 – Rider proposal in Iowa has broad support from Office of Consumer Advocate and major industrial group; proposal mitigates customer rate shock while providing needed additional revenue

Business Update • Customer Service – MidAmerican Energy ranked highest among large utilities in the Midwest Region for overall customer satisfaction among business customers (J.D. Power and Associates 2012 Electric Utility Business Customer Satisfaction Study) – 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 2011 was 16.1% lower than 2010 – Focused on control of benefit costs and overall staffing levels 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 3.06 3.27 3.06 2.86 2.42 2.03 OSHA Recordable Rate 2006 2007 2008 2009 2010 2011

Operational Excellence • Significant operational focus on minimizing plant emissions • In the middle of a three-year analysis of potential sites for nuclear generation in Iowa • Long-term maintenance contracts are in place for the Greater Des Moines Energy Center and all wind projects currently in-service • Ranked No. 1 in the nation in ownership of wind-powered electric generation among rate-regulated utilities, with 1,878 MW of owned and operated generation • Strict attention to cost management; operations and maintenance costs (excluding energy efficiency costs recovered through a rider) have been reduced over the last five years $540 $550 $560 $570 $580 $590 $600 $610 2007 2008 2009 2010 2011 $590 $609 $566 $581 $565 O&M Expense Excluding Energy Efficiency Costs (millions)

Iowa Electric Rate Proposal • MidAmerican Energy has not increased Iowa base electric rates since 1995 • Environmental cost adjustment clause to recover depreciation expense and O&M associated with environmental investments in coal generation facilities • Fuel adjustment clause to recover retail coal and coal transportation costs • Total recoveries capped at $39 million (3.4% increase) for 2012 and an additional $37 million (3.2% increase from 2012) for 2013 for aggregate maximum of $76 million • Revenue-sharing mechanism similar to past arrangements except with a lower (10%) return on equity triggering sharing • Interim collections began March 2, 2012 • Proposal mitigates the customer impact of more significant increases anticipated to be required in 2014 • Agreements with the Office of Consumer Advocate and a major industrial group supporting the proposal

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 • New wind generation 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 Dec. 2013 • Construction of the remaining 407 MW are expected to be completed in 2012, also utilizing Siemens turbines at a cost of $0.7 billion; payment of more than half of the cost is deferred until Dec. 2015 • 2011 project eligible for 100% federal bonus depreciation; 2012 project eligible for 50% federal bonus depreciation • Completion in 2012 ensures the availability for the projects of the federal production tax credit

Wind VII Expansion • This opportunity is being delivered at a cost of approximately $1,650/kW, a cost level not seen since 2006 • Projects deliver significant value to customers due to: – Deferral mechanism – Production tax credits for 10 years from the in-service date of the projects – Accelerated tax depreciation, including bonus depreciation – Low-cost generation in the future • Following completion of this expansion, MidAmerican Energy will own 2,285 MW of wind generation

Dec. 31, 2000 Dec. 31, 2011 (1) Net MW owned in operation and under construction 4,086 MW (1) 7,432 MW (1) Generating Capacity by Fuel Type Coal 70% Natural Gas 19% Wind 0% Nuclear and Other 11% Coal 45% Natural Gas 17% Wind 31% Nuclear and Other 7%

Wind Benefit – Decreasing Carbon Footprint Note: MidAmerican Energy 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’s retail customers Wind Benefit – Decreasing Carbon Footprint 1,400 1,450 1,500 1,550 1,600 1,650 1,700 1,750 1,800 1,850 0 5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000 35,000,000 2000 2003 2005 2007 2009 2011 L b s C O 2 / M W h MW h G e n e ra te d MEC CO 2 Emission Intensity MWh Generated CO2 Emissions

Environmental Respect – Ongoing Challenges 64 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)

Current Environmental Position • Specifics of air quality regulations are uncertain with the December 2011 court-ordered stay of the Cross-State Air Pollution Rule • Of MidAmerican Energy’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 and enhanced particulate control – 20% of generation has activated carbon injection for mercury control

MidAmerican Energy Company Capital Cost of Compliance Total 2012-2021 MidAmerican Energy Environmental Capital: $587 million, excluding potential costs for Neal 1 and 2 Project CAIR/CSAPR HAPs MACT CCR Management Neal 3 and 4: Scrubber and Baghouse $259 Ottumwa: Scrubber and Baghouse $155 Neal 3 and 4: Selective Noncatalytic Reduction $13 Coal Fleet Mercury Controls $12 Coal Fleet Ash Pond/Landfill Closures or Expansion $104 Coal Fleet Bottom Ash Dry Handling $44 Subtotal: $427 $12 $148 ($ millions)

2015 Environmental Position • Of MidAmerican Energy’s nearly 4,100 MW of operated coal-fueled generation: – 100% of generation will have nitrogen oxides controls • Low-NOx burners and/or over-fire air on all units • One selective catalytic reduction system on Walter Scott, Jr. Energy Center Unit 4 • Two selective noncatalytic reduction systems on Neal 3 and 4 – 83% of generation will have scrubbers and baghouses for sulfur dioxide and enhanced particulate control – 83% of generation will have activated carbon injection for mercury control – Controls at Neal 1 and 2 being evaluated; potential cost of $226 million • Depending on stringency of final regulations, smaller coal-fueled units may have to convert to natural gas or face reduced operation

• MidAmerican Energy plans to construct portions of four 345-kV multi- value projects within the MISO footprint; 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

Bill Fehrman President MidAmerican Renewables, LLC

MidAmerican Renewables, LLC Overview • Established by MidAmerican to own independent power projects, with a focus on renewable resources, such as wind, geothermal, solar and hydro generation • Currently 1,700 MW are owned and in-service or under construction • Substantially all output from the renewables projects is sold pursuant to long-term power purchase agreements • Continue to pursue additional opportunities

MidAmerican Renewables, LLC MidAmerican Wind MidAmerican Solar MidAmerican Geothermal Geothermal Plants Natural Gas Plants MidAmerican Hydro

Project Summary – Portfolio of Assets (1) 82% of the company's interests in the Imperial Valley Projects' contract capacity are sold to Southern California Edison Company Location Installed PPA Expiration Power Purchaser Net or Contract Capacity (MW) Net Owned Capacity (MW) SOLAR Topaz California 2012-2015 2040 PG&E 550 550 Agua Caliente Arizona 2012-2014 2039 PG&E 290 142 840 692 WIND Bishop Hill Illinois 2012 2032 Ameren 81 81 HYDROELECTRIC Wailuku Hawaii 1993 2023 Hawaii Electric 10 5 GEOTHERMAL Imperial Valley Projects California 1982-2000 2016-2026 (1) 327 164 NATURAL GAS Saranac New York 1994 2013 EDF Trading 240 90 Power Resources Texas 1988 2012 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 2,297 1,700

• Topaz – 550-MWAC project located in San Louis Obispo County, California – $2.44 billion total capital cost – 100% owned by MidAmerican – First block expected to come on-line by the end of 2012; fully on-line in 2015 – Contracts with First Solar for engineering, procurement and construction and ongoing operation and maintenance of the project – Power purchase agreement with Pacific Gas and Electric Company for 100% of output from the project at fixed rates over its 25-year life Solar Projects

• Topaz – Transmission interconnection with the 230-kV Morro Bay-to-Midway line – Feb. 24, 2012, closed on $850 million 5.75% debt financing for the project – Significant investment tax credits and tax depreciation generated by the project – Status of construction • Construction is on schedule and on budget • All contractors are mobilized to the site • 5% of the posts and 2% of the tilt brackets are installed Solar Projects

Solar Projects • Agua Caliente – 290-MWAC project located in Yuma County, Arizona – $1.8 billion total capital cost – 49% owned by MidAmerican, 51% owned and operated by NRG – Fixed price contracts with First Solar for engineering, procurement and construction and ongoing operation and maintenance of the project – Power purchase agreement with Pacific Gas and Electric for 100% of output from the project at fixed rates over its 25-year life

Solar Projects • Agua Caliente – Transmission interconnection with the 500-kV North Gila line – U.S. Department of Energy debt financing for the project – Significant investment tax credits and tax depreciation generated by the project – Status of construction • 3 million of the 5 million solar modules installed • 95% of the required posts and tilt brackets in place • Overall, project is on budget and well ahead of schedule

Wind Project • Bishop Hill – 81-MW project located in Henry County, Illinois, 20 miles southeast of Rock Island, Illinois – $183 million total capital cost – 100% owned – Expected to come on-line in fourth quarter 2012 – Turbine supply and maintenance agreement with General Electric – Balance of plant agreement with The Boldt Company – Power purchase agreement with Ameren Illinois Company for approximately 110% of the P99 production from the project, with the remainder sold into the MISO market

Questions

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

Overview • Headquartered in Omaha, Nebraska • 850 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 73 Bcf and more than 2.0 Bcf of peak day delivery capability • Access to five major conventional and two nonconventional (tight sands and shale) supply basins • Annual average deliveries of 930 Bcf over the prior three years

Business Update • Solid operating results in 2011 – Continued to demonstrate financial strength during the economic downturn – Increased the integrity and reliability of the pipeline while managing operating costs and staffing • Identified and executed cost-reduction strategies of $11 million • Achieved authority to stop third-party production in the area of the Cunningham storage facility • Implemented extensive disaster recovery and emergency response plans to prevent flooding from impacting operations • In the 2012 Mastio & Company pipeline industry survey, Northern Natural Gas was ranked No. 1 out of 16 mega-pipelines and No. 2 out of 41 interstate pipelines in customer satisfaction

Transportation - Market 79% Transportation - Field 10% Storage 11% Revenue Stability and Long-Term Contracts 2012-2013 24% 2014-2015 11% 2016-2017 33% 2018 - 2019 27% 2020+ 5% Market Area Transportation Contract Maturities (1) (1) Based on maximum daily quantities of market area entitlement in decatherms as of March 15, 2012 2011 Transportation and Storage Revenue $555 Million • 64% of 2011 transportation and storage demand revenue was from utilities • 79% of 2011 storage revenue resulted from long-term contracts, with an average remaining contract life of approximately nine years  Northern Natural Gas contracts 100% of its firm storage service annually  Northern Natural Gas customers highly value the firm storage service as evidenced by the recent purchase of 2 Bcf of available capacity for contract terms over 30 years • Shippers that do not meet credit standards are required to post collateral

Market Area Expansion Projects • Northern Lights is a multiyear expansion project started in 2006 – Part of long-term agreement commitments from large customers in Twin Cities area – Serving power, industrial and native growth loads and, to a lesser extent, ethanol – Total project investment of more than $360 million through 2012 – Increased market area capacity • 2007-2010 projects added 656,000 Dth/day • 2011-2012 projects will add 22,000 Dth/day – Continued expansions expected in 2013 and beyond to support long-term agreements • Additional contracted firm service in 2012 of 16,000 Dth/day with no capital requirements • Several opportunities for new, expanding or converting power plants have the potential to bring additional load to Northern Natural Gas’ system in the Market Area

Shale Gas Opportunities • Shale development is supportive of gas demand due to low supply prices • Change in gas flow patterns across the U.S. is likely • Marcellus shale displacement of the south-central area should result in the softening of field area supply prices • Incremental receipt capacity of 975,000 Dth/day being attached from Granite Wash and Wolfberry

Shale Expansion Projects • Expanding access to additional unconventional supply from the Granite Wash tight sands and Wolfberry shale plays – Interconnects completed in 2011 • Granite Wash production attached through existing interconnects plus four additional connections, with a total receipt capacity of 245,000 Dth/day • Wolfberry production attached through existing interconnects plus two additional connections, with a total receipt capacity of 130,000 Dth/day – Further expansion planned in 2012 • Northern Natural Gas will build a $9 million lateral to connect up to 120,000 Dth/day of Granite Wash production and is finalizing plans for additional potential supply connections of 200,000 Dth/day • Northern Natural Gas is finalizing plans for additional potential supply connections of 280,000 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 nearly complete, with a total expected cost of $161 million, approximately $20 million less than the original projection • Started service April 1, 2012 • Fully contracted (11 Bcf) for 20 years with Southcentral Alaska utilities • Regulatory approval has been received, granting a 12.55% return on equity and 30-year depreciable life; approved with a 50/50 debt-to-equity ratio • Construction financing at LIBOR plus 2.25% is expected to be replaced with permanent financing • Expansion opportunity likely by 2014

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 • 98% 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, 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 $0.18/Dth to $0.23/Dth for 15 year contracts or $0.22/Dth to $0.27/Dth for 10-year contracts, an average decrease of 51% from existing rates • Competitive delivered cost to Southern California and Las Vegas • Market demand is stable and growing • Strong long-term business outlook • FERC regulated • Experienced operator • Creditworthy customers

Long-Term Contracts Contract Maturities(1) 2011 Revenue Distribution $365 Million (1) Based on daily demand quantity • 94% of revenue is from demand charges • 93% of contracts mature 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 eight years Demand 94% Market Oriented 4% Other 2% 2013 7% 2016 31% 2017 4% 2018 35% 2020 4% 2025-2027 7% 2031 12%

Strong Demand for Services Nevada 22% Utah 5% California 73% - 500,000 1,000,000 1,500,000 2,000,000 2,500,000 2005 2006 2007 2008 2009 2010 2011 Scheduled Design Capacity Daily Average Scheduled Volume 2011 Deliveries by State • Delivered approximately 23%(1) of California’s demand for natural gas • Delivered more than 78%(2) of southern Nevada’s natural gas • During 2011, scheduled throughput averaged 116% of design capacity • Ranked No. 1 out of 41 interstate pipelines in 2012 Mastio & Company survey for customer satisfaction (1) Based on the 2011 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.

Non-coincident Peak Day Deliveries (Dth/d)(1) Utah LDC (Questar Gas) 457,994 Direct-connect end-users 14,009 472,003 Nevada LDC (Southwest Gas) 505,100 Direct-connect end-users 576,317 1,081,417 California LDC (Southern California Gas) 0 Direct-connect end-users 424,243 424,243 Total 1,977,663 (91% of Kern River capacity) Long-Term Business Outlook • 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 has other pipeline or storage options on a peak day; however, direct-connect end-users rely on Kern River Markets are Dependent on Kern River (1) Based on actual peak day deliveries over the past three years and an analysis of the LDCs’ pipeline supply options

Rockies $2.5310 Rockies $2.5310 Rockies $2.5310 Rockies $2.5310 Rockies $2.5310 San Juan $2.4797 San Juan $2.4797 Permian $2.4829 Permian $2.4829 Canadian at Kingsgate $2.4769 Canadian at Sumas $2.6059 Kern River $0.1846 Kern River $0.2224 Kern River $0.3633 Kern River $0.4717 El Paso $0.4510 El Paso $0.4510 Transwestern $0.3660 Transwestern $0.3760 GTN $0.3440 PG&E $0.2740 NWP $0.3790 GTN $0.2060 PG&E $0.2740 Ruby $1.1370 PG&E $0.2740 $2.7645 $2.8363 $2.9175 $2.9432 $2.9445 $3.0091 $3.0123 $3.0856 $3.1731 $3.5962 $4.0288 $0.0000 $0.5000 $1.0000 $1.5000 $2.0000 $2.5000 $3.0000 $3.5000 $4.0000 $4.5000 Kern River Period Two Vintage 15 yr * Kern River Period Two Expansion 15 yr ** Transwestern Kern River Period One Vintage 15 yr * Transwestern El Paso El Paso Kern River Period One Expansion 15 yr ** GTN NWP Ruby $/ Dt h Demand Transportation Fuel and commodity Natural Gas Lowest-Cost Option to Southern California Source: Platts (February 2012 Monthly Average Price), Western U.S. Natural Gas Market Review (February 2012) and Kern River Period Two rates. Transportation rates include February 2012 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

Apex Expansion Project – In-Service Muddy Creek Salt Lake City Bakersfield Los Angeles Salt Lake City Apex Expansion Loop Las Vegas Apex Expansion Compression Apex Expansion Pipe Existing Pipeline Mainline Expansion • Expanded by 266,000 Dth per day • 20-year term contract with Nevada Power • Service to Las Vegas, Nevada • $340 million capital cost, $34m below budget (9%) • Closed Wasatch Loop with 28 miles of 36-inch pipe – Increased system reliability • Added 78,000 horsepower of new compression at four locations, and restaged four existing compressors • Placed project in-service Oct. 1, 2011, one month early

Mountain Pass Lateral Pipe Apex Expansion Pipe Existing Pipeline Mountain Pass Lateral Project – Under Construction Muddy Creek Salt Lake City Bakersfield Los Angeles Salt Lake City Las Vegas • Direct-connect to rare earth minerals mine • 8.6 miles, 8-inch pipeline lateral • 24,000 Dth per day of firm service (mainline and lateral) • Annual revenue of $5.2 million • 10-year term contract with Molycorp Minerals LLC • FERC certificate received in January 2012 • Construction began February 2012 • In-service anticipated by June 2012

Questions

Phil Jones President and CEO Northern Powergrid

Northern Powergrid Is a Wires-Only Power Distributor 15 Decembe r 2010, E.ON UK, Page 1 Licenses Customers Revenues RAV £m £m PPL 4 7.6m 1,209 5,019 UKPN 3 7.9m 1,057 4,614 Northern Powergrid 2 3.9m 633 2,231 SSE 2 3.7m 854 2,880 SP 2 3.4m 653 2,754 ENW 1 2.4m 382 1,403 All data at March 2011 Northern Powergrid £m December 2009 December 2010 December 2011 Revenue 527 518 633 Operating Income 253 305 384 RAV 1,998 2,231 2,359 • Major substations – 700 • Circuit length – 58,000 miles • Service territory – 10,000 square miles • Employees – 2,300 • Stable revenues and c sh flows • Opportunity to reinvest cash flows

Delivering DPCR5 • Return on book equity exceeds expectations • 35% growth in regulated asset value in DPCR5, primarily financed by free operating cash flows • Inflation protection providing higher revenues than expected when the price control was settled • Strong credit rating of A- compares well with the rest of the sector Strong investment metrics • Strong cost control routines ensure operational costs continue to be significantly within allowances • Re-engineering of about £1 billion capital investment keeps delivery of outputs inside Ofgem unit cost targets • Procurement activity in 2010-11 locked in market opportunity for the majority of the DPCR5 period • Below-inflation long-term wage settlements secured • Customer and network performance metrics improving • On course for satisfactory resolution to the issues surrounding DPCR4 losses Solid delivery performance 2010 2011 Interest cover 4.2x 4.3x Gearing 55% 58% OpCo revenues (£ million) 534 579 growth 15% 8% RAV (£ million) 2,174 2,359 growth 7% 9% • 7% underlying (real) revenue growth built into Ofgem final proposals for 2010-2015 • 4% underlying (real) growth in RAV built into Ofgem final proposals 2010-2015 • Average inflation April 2007-March 2011 3.13% per annum

U.K. Energy Policy Source: DECC – The Low Carbon Transition Plan July 2009 Source: UK Renewables website – March 2011 • Legally binding targets: 24% CO2 reduction and 30% renewables by 2020 • New nuclear baseload and wind generation remain central to government energy policy • Market mechanism review is still in progress • £1 billion 2,000-MW sub-sea power cable linking Scotland to England and Wales awarded to Siemens and Prysmian • £4 billion SSE and £2 billion Scottish Power plans approved • Ofgem reviewing National Grid’s £18 billion investment proposals, up 57% p.a. compared to prior regulatory period • DPCR5 investment plans 26% greater than prior five years • Ofgem price review for 2015 to 2023 has commenced • Focus will include deploying ‘investment-lite’ solutions to mitigate uncertainty driven by low carbon futures • £11 billion supplier-led rollout of 30 million smart meters by 2019 Growth in lower voltage investment expected to follow Major transmission investment has begun Significant investment in low carbon generation Change in U.K. electricity generation mix Projected U.K. Wind Generation

• Continued delivery of strong cost controls will enable continued outperformance of DPCR5 final proposals to improve return on equity • Capital investment delivery on track to deliver outputs within DPCR5 allowances • Execution of network performance and customer service initiatives to continue to deliver incremental outperformance • Increasing focus on the next price control review (RIIO-ED1) to secure long-term stability through 2023 • Build on learning experiences of customer led network revolution project in preparation for smart grid challenges • Continue to look for energy sector business opportunities in U.K. or elsewhere in Europe to deploy capital and further develop proven management team Northern Powergrid Outlook 102

Questions

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

Finding the Right Balance 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

Questions

Appendix

Non-GAAP Financial Measures (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 Debt equals FFO divided by Adjusted Debt (5) Debt to Total Capitalization equals Adjusted Debt divided by Adjusted Capitalization FFO 2011 2010 2009 2001 (1) Net cash flows from operating activities 3,220$ 2,759$ 3,572$ 847$ +/- Changes in other operating assets and liabilities, net of effects from acquisitions 382 607 (152) (196) FFO 3,602$ 3,366$ 3,420$ 651$ Adjusted Interest Interest expense 1,196$ 1,225$ 1,275$ 587$ Interest expense on MidAmerican subordinated debt (26) (52) (80) (88) Adjusted Interest 1,170$ 1,173$ 1,195$ 499$ FFO Interest Coverage (1) 4.1x 3.9x 3.9x 2.3x Adjusted Debt Debt(2) 19,937$ 19,811$ 19,931$ 8,050$ MidAmerican subordinated debt (22) (315) (590) (888) Adjusted Debt 19,915$ 19,496$ 19,341$ 7,162$ FFO to Debt (3) 18.1% 17.3% 17.7% 9.1% Adjusted Capitalization Total equity 14,265$ 13,408$ 12,843$ 1,873$ Adjusted debt 19,915 19,496 19,341 7,162 MidAmerican subordinated debt 22 315 590 888 Adjusted Capitalization 34,202$ 33,219$ 32,774$ 9,923$ Debt to Total Capitalization (4) 58.2% 58.7% 59.0% 72.2% EBITDA Net income 1,352$ Interest expense 1,196 Capitalized interest (40) Income tax expense 294 Depreciation and amortization 1,341 EBITDA 4,143$

A Berkshire Hathaway Company