2011 EEI Financial Conference Patrick J. Goodman Senior Vice President and Chief Financial Officer

Forward-Looking Statements 2 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 Company’s control and could cause actual results to differ materially from those expressed or implied by the Company’s 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; – 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 3 – 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 review of factors should not be construed as exclusive.

MidAmerican Energy Holdings Company Energy Assets Revenues $11.1 billion for the 12 months ended September 30, 2011 Assets $46 billion as of September 30, 2011 Customers Electric: 6.2 million Natural Gas: 0.7 million Employees 15,800 as of September 30, 2011 Natural Gas Transmission Pipeline Design Capacity More than 7.0 billion cubic feet per day Generation Capacity 19,345 megawatts(1) Noncarbon Generation More than 4,800 megawatts(1) 25% of total generation capacity (1) Net MW owned in operation and under construction as of September 30, 2011 4 United Kingdom Philippines

Corporate Strategy • Own and operate a portfolio of high-quality utility businesses – Focus on operational efficiency, cost control and customer service – Cooperative approach with regulators and customers – Pursue internal capital investment opportunities to expand regulated asset base • Maintain prudent financial and risk management policies – Committed to holdings company and subsidiary credit profile – Stable and highly diversified asset base • Grow and diversify through a disciplined acquisition strategy – Target additional energy assets – Focus on long-term risk-adjusted returns – Continue to utilize ring-fencing approach – Capitalize on access to long-term capital from Berkshire Hathaway – Continue track record of proven integration capabilities and improving operating and financial performance MidAmerican’s Strategy Has Delivered Outstanding Results 5

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 tax benefits currently • Berkshire Hathaway provides MidAmerican with a $2 billion equity commitment through February 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 6

Environmental Update 7 • MidAmerican Energy Company has been installing controls in anticipation of the final Cross-State Air Pollution Rule and is well- positioned to comply with the rules, given the allowance allocations in 2012 and 2014 • Iowa was one of the states included in the supplemental proposal for inclusion in the seasonal NOx reduction requirements • Unless the Cross-State Air Pollution Rule changes substantially in response to the numerous petitions for reconsideration and lawsuits, MidAmerican believes it will continue to be well-positioned to comply, based on the planned projects • PacifiCorp is not subject to the Cross-State Air Pollution Rule; emission reduction projects are based on regional haze requirements

Consolidated Environmental Position 8 • Of MidAmerican’s nearly 10,800 MW of operated or wholly owned coal-fueled generation: – 91% of generation has nitrogen oxides controls with low-NOx burners and/or over-fire air – 78% of generation has scrubbers for sulfur dioxide control – 7% of generation has activated carbon injection for mercury controls; an additional 17% meets the proposed mercury limits without additional controls – 46% of generation has baghouses for particulate matter control • To ensure timely compliance, MidAmerican continues to review proposed regulations and legislation and analyze associated impacts of environmental requirements on the coal-fueled fleet

Environmental Position By Utility 9 • Of PacifiCorp’s 6,700 MW of operated or wholly owned coal-fueled generation: – 85% of generation has nitrogen oxides controls with low-NOx burners and over- fire air – 92% of generation has scrubbers for sulfur dioxide control – 41% of generation has baghouses for particulate matter control – 27% of generation meets proposed mercury emissions limits • 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 and 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

PacifiCorp ___________________________ (1) Net owned megawatts in operation and under construction as of September 30, 2011 • Headquartered in Portland, Oregon • 6,380 employees • 1.7 million electric customers in six western states • 11,261 megawatts(1) of owned generation capacity • Generating capacity by fuel type 9/30/11(1) 3/31/06 – Coal 55% 72% – Natural gas 25% 13% – Hydro 10% 14% – Wind and geothermal 10% 1% 10 (a) Access to other entities’ transmission lines through wheeling arrangements

PacifiCorp – Business Update • Retail load for the nine-month period ended September 30, 2011, was 40,488 gigawatt-hours, a 3% increase versus the first nine months of 2010 – Commercial load increased primarily in Utah and Oregon, industrial load increased in Utah and residential loads increased in Oregon primarily due to cooler weather • Lake Side II, a 637-MW gas-fueled plant (combined-cycle combustion turbine) under construction next to the existing Lake Side plant, with completion in 2014 • Populus-to-Terminal, the first segment of the Energy Gateway Transmission Expansion Program, was completed in late 2010 • Mona-to-Oquirrh, the second segment of the Energy Gateway Transmission Expansion Program, is under construction and planned for completion in 2013 • May 2011 debt issuance of $400 million at 3.85% due June 15, 2021 11

Rocky Mountain Power Regulatory Accomplishments • Utah ― 2010 major plant addition cases: $64 million (4%) increase effective January 1, 2011, and recovery of $16 million of deferred costs ― 2011 rate case: $117 million (7%) increase effective September 21, 2011 ― Resolution of deferred net power cost case, with collection of $60 million offset by a credit of $33 million for resolution of the deferred renewable energy certificate sales revenue case ― Energy balancing account mechanism approved to begin October 1, 2011; power cost forecast included in base rates in each rate case, 70% of any difference between actual and forecast incremental power costs recovered via mechanism • Wyoming ― 2011 PCAM: settlement approved for $14 million in deferred net power cost recovery effective April 1, 2011 ― 2010 rate case: $62 million rate increase (11%) and a renewable energy certificate sales revenue tariff rider of $17 million (-3%), both of which became effective September 22, 2011 ― Commission approved replacing PCAM with a new energy cost adjustment mechanism February 4, 2011; power cost forecast included in base rates in each rate case, 70% of any difference between actual and forecast incremental power costs recovered via mechanism • Idaho ― 2011 energy cost adjustment mechanism: approved for $13 million (7%) effective April 1, 2011 ― 2011 rate case: settlement reached with majority of parties in the 2011 general rate case that, if approved by the IPUC, will increase retail rates $17 million per year effective January 1, 2012, and January 1, 2013, representing a 8% and 7% overall increase in those years, respectively; settlement also will resolve dispute related to recovery of Populus-to-Terminal transmission line with full inclusion in rate base in a future case with a rate change on or after January 1, 2014 12

• Oregon – Power costs update of $60 million (6%) effective January 1, 2011, through the transition adjustment mechanism – Order approving 2010 general rate case settlement authorized annual increase of $80 million (8%) effective January 1, 2011, including Populus-to-Terminal segment of transmission plan, two new wind resources, environmental improvement projects, system reliability, hydro relicensing and other investments – Order approving the 2009 Senate Bill 408 tax adjustment for $16 million (1%), including interest, effective April 2011 – 2012 TAM: $51 million (4%) settlement in September 2011; filing will be updated and adjusted in November 2011, with new rates effective January 1, 2012 • Washington – 2010 rate case increase of $33 million (12%) offset by a renewable energy credit revenue tariff rider to credit $5 million (-2%) to customers, effective April 3, 2011; tariff rider credit will be trued-up to reflect actual revenues – 2011 rate case: $13 million (4%) filed in July 2011 with an effective date no later than June 1, 2012 – Renewable energy certificate sales revenue proceeding regarding disposition of revenues for prior periods; potentially requiring refunds for 2009 and 2010 • California – Rate case increase of $4 million (5%) effective January 1, 2011 – 2010 power cost increase of $9 million (11%) effective January 1, 2011, through energy cost adjustment clause – 2011 ECAC increase of $2 million (2%) effective January 1, 2012 – Next rate case filing for rates effective January 1, 2014, due to three-year rate case cycle – Adjustment mechanism filings will continue for major plant additions and annual attrition adjustment 13 Pacific Power Regulatory Accomplishments

Regulatory Environment  PacifiCorp has power cost adjustment mechanisms in five of its six state jurisdictions; a request for an energy cost adjustment mechanism recently was approved in Utah, which results in PacifiCorp having mechanisms in states providing more than 90% of its retail electricity sales  PacifiCorp also has regulatory tools to recover or defer recovery of renewable resource additions or significant investments outside of traditional rate cases in four jurisdictions, representing nearly 80% of retail electricity sales Utah • Integrated resource planning • Preconstruction regulatory approval of investment prudence • Eight-month time limit on consideration of proposed rate increase • Forecast test periods used in most general rate cases • Use of single-issue rate case for major plant additions (>1% of rate base) allowed when a general rate case has occurred within the preceding 18 months; increase recovered through surcharge or deferred accounting • Use of power cost recovery mechanisms allowed by statute – PacifiCorp received approval of a mechanism to recover the difference between base power costs set during a general rate case and actual net power costs • Regulators are required to match cost recovery of renewable energy investment with customers’ receipt of benefits Wyoming • Integrated resource planning • 10-month time period on consideration of proposed rate increase • Rate case test periods may be historical with known and measurable adjustments or forecast data based on each case circumstance • Expired power cost adjustment mechanism based on forecast net power costs, trued-up annually to actual net power costs; subject to dead bands and three-tiered customer sharing bands • Commission approved replacing PCAM with a new energy cost adjustment mechanism February 4, 2011; power cost forecast included in base rates in each rate case, 70% of any difference between actual and forecast incremental power costs recovered via mechanism Note: Red bullets represent regulatory improvements since MidAmerican’s acquisition of PacifiCorp 14

Regulatory Environment Idaho • Integrated resource planning • Seven-month time period on consideration of proposed rate increase • Rate case test periods based on historic data with known and measurable adjustments • Ability to use single-issue rate cases for significant new investment added within 180 days of completion of general rate case • Energy cost adjustment mechanism recovers the difference between base power costs set during a general rate case and actual power costs • Law authorizes utilities to seek commission determination of rate-making principles, including prudence of investment, that will be applicable to a generation or transmission investment prior to significant expenditures being incurred Oregon • Integrated resource planning • Rate case test periods are based on forecast data • 10-month time limit on consideration of proposed rate increase • Regulators authorized to approve power cost recovery mechanisms • Annual transition adjustment mechanism, a mechanism for annual rate adjustments for forecast net power costs; no true-up to actual net variable power costs • Repeal and elimination of annual SB 408 true-up of taxes authorized to be collected in rates compared to taxes paid by PacifiCorp, as defined by Oregon statute and administrative rules, effective May 2011 • Renewable adjustment clause allows annual filing for recovery of revenue requirement of new renewable resources and associated transmission, including return, and deferral until the costs can be reflected in rates 15 Note: Red bullets represent regulatory improvements since MidAmerican’s acquisition of PacifiCorp

Regulatory Environment Washington • Integrated resource planning • Rate case test periods are based on historical data with known and measurable adjustments for costs other than net power costs; commission has accepted use of fully forecast net power costs in rate cases • 11-month time limit on consideration of proposed rate increase • Regulators authorized to approve power cost recovery mechanisms • Law requires commission to allow deferral of costs, including return, related to eligible base load generation and renewable resources until costs can be reflected in rates California • Integrated resource planning • Rate case test periods are based on fully forecast data • Deferral of extraordinary storm damage expenses permitted until recovery is authorized • Three-year rate case cycle with adjustment mechanisms – Energy cost adjustment clause that allows for an annual update to actual and forecast net variable power costs (dollar-for-dollar recovery) – Post test year adjustment mechanism for attrition, a mechanism that allows for an annual adjustment to costs other than net variable power costs tied to the Consumer Price Index forecast for the following year minus a 0.5% productivity offset – Post test year adjustment mechanism for major capital additions, a mechanism that allows for rate adjustments outside the context of a traditional rate case for the California revenue requirement associated with capital additions exceeding $50 million on a total-company basis 16 Note: Red bullets represent regulatory improvements since MidAmerican’s acquisition of PacifiCorp

MidAmerican Energy • Headquartered in Des Moines, Iowa • 3,492 employees • 1.4 million electric and natural gas customers in four Midwestern states • 7,029 megawatts(1) of owned generation capacity • Generating capacity by fuel type 9/30/11(1) 12/31/00 – Coal 48% 70% – Natural gas 18% 19% – Wind 27% 0% – Nuclear and other 7% 11% 17 MidAmerican Energy Service Territory Major Generating Facilities 596-MW Wind Project Sites Wind Projects in Production Other Potential Wind Project Sites SOUTH DAKOTA NEBRASKA KANSAS MISSOURI ILLINOIS WISCONSIN MINNESOTA IOWA ___________________________ (1) Net owned megawatts in operation and under construction as of September 30, 2011

MidAmerican Energy – Business Update 18 • Customer growth and improved industrial sales helped increase retail electric sales to 16,650 gigawatt-hours for the nine-month period ended September 30, 2011, a 2% increase over the same period for 2010 and establishing a new peak load of 4,752 megawatts • Managed through historic Missouri River flooding without generation plant disruptions or significant service interruptions • Currently constructing 596 megawatts (nameplate rating) of wind-powered generation facilities in Iowa, 154 megawatts of which went into service in third quarter 2011 and the remainder of which will go into service prior to year-end • Rate principles approved by the Iowa Utilities Board for construction of an additional 405 megawatts of wind-powered generation before year-end 2012 • Scrubber/baghouse construction projects in progress at Neal Energy Center Units 3 and 4, with completion anticipated in early 2014 and late 2013, respectively • Continues to receive high customer satisfaction ratings for gas and electric service

Business Overview • 15,000 miles of natural gas pipeline • 5.5 Bcf per day of market area design capacity, plus 2.0 Bcf per day field area capacity • 73 Bcf firm storage capacity • 89% of 2011 transportation and storage revenue based on demand charges through September 30, 2011 • Issued $200 million of 4.25% senior notes due June 1, 2021 • Increased the integrity and reliability of the pipeline while managing operating costs and staffing • Ranked No. 1 out of 16 mega-pipelines and No. 2 out of 43 interstate pipelines in 2011 Mastio & Company survey for customer satisfaction Northern Natural Gas 19 MINNESOTA WISCONSIN IOWA SOUTH DAKOTA NEBRASKA KANSAS OKLAHOMA TEXAS

Business Overview • 1,700 miles of natural gas pipeline • 2.2 million Dth/day of natural gas, including recent Apex expansion, to markets in Utah, Nevada and California • 94% of 2011 revenue based on demand charges through September 30, 2011 • Apex expansion for 266,000 Dth/day was placed in-service October 2011, one month early and under budget • During third quarter 2011, FERC issued an order on Period Two rates • Kern River delivered nearly 24%(1) of California’s demand for natural gas • Ranked No. 1 out of 43 interstate pipelines in 2011 Mastio & Company survey for customer satisfaction Kern River 20 CALIFORNIA NEVADA ARIZONA UTAH WYOMING (1) 2010 California Gas Report

Northern Powergrid Leeds Edinburgh Middlesbrough Newcastle Upon Tyne Sheffield York Northeast Yorkshire Business Overview • 3.8 million end-users in northern England • 58,000 miles of distribution lines • Approximately 80% of 2011 distribution revenue from residential and commercial customers through September 30, 2011 • Distribution revenue (£ millions) • U.K. Distribution Price Control Review 5 commenced April 2010; plans are in place and delivering out- performance • Completed drawdown of remaining facility with European Investment Bank; £119 million drawdown at a weighted average rate of 4.23% for seven to nine years Nine Months Ended 9/30/11 9/30/10 Residential £195 £172 Commercial 127 111 Industrial 79 79 Other 6 5 Total £407 £367 21

• ETT designs, acquires, constructs, owns and operates transmission facilities in ERCOT – Allowed return on regulated assets based on a 60/40 debt-to-equity capital structure – Authorized return on equity of 9.96% • ETT plans to construct and operate approximately $3 billion of transmission projects • As of September 30, 2011, ETT had $528 million of transmission assets in-service and $460 million of construction work in process, with a total asset value of $988 million • ETT has been awarded approximately $1.4 billion of the $6.5 billion in Competitive Renewable Energy Zones projects, making it the second-largest participant in the CREZ plan – ETT’s current CREZ portfolio value includes nine transmission lines, consisting of 600 line miles and 16 substations – CREZ projects are projected to be completed by year-end 2013 • Other transmission projects in Texas total approximately $1.5 billion Electric Transmission Texas 22

• MidAmerican Energy Holdings Company’s financing plan will depend largely on new investment opportunities • PacifiCorp anticipates an early 2012 debt issuance to refinance its short-term borrowing position and continued capital expenditure program • Northern Natural Gas anticipates refinancing all or a portion of its October 2012 $300 million maturity • Kern River anticipates an early 2012 debt issuance to finance the capital costs of the Apex Expansion project which went into service in October 2011 • Electric Transmission Texas, LLC anticipates debt issuances in 2012 to fund its continued expansion in ERCOT • Northern Powergrid (Yorkshire) plc anticipates a 2012 debt issuance in support of capital investments Financing Plan 2012 23

Financial Results

A2/A-/A Regulated Electric and Gas Utility Independent Electric Power Producer A2/A/A Regulated Gas Transmission A3/A-/A-(1) Regulated Gas Transmission Real Estate Brokerage Baa1/BBB+/BBB+ Baa1/BBB+/BBB+ Holding Company A2/A/A-(1) Regulated Electric Utility Aa2/AA+/A+ 90% Northern Powergrid (Yorkshire) plc A3/A-/A U.K. Regulated Electric Distribution Northern Powergrid (Northeast) Ltd. A3/A-/A U.K. Regulated Electric Distribution ___________________________ (1) PacifiCorp and Kern River ratings are senior secured Organizational Structure 25

$24.0 $26.2 $28.5 $30.9 $31.9 $33.3 $0 $10 $20 $30 $40 2006 2007 2008 2009 2010 Sept. 2011 Billions $916 $1,189 $1,204 $1,157 $1,238 $1,358 $0 $500 $1,000 $1,500 $2,000 2006 2007 2008 2009 2010 LTM 9/30/11 Millions $1,923 $2,335 $2,587 $3,572 $2,759 $3,396 $0 $1,000 $2,000 $3,000 $4,000 2006 2007 2008 2009 2010 LTM 9/30/11 Millions $8.0 $9.3 $10.2 $12.6 $13.2 $13.8 $0 $5 $10 $15 $20 2006 2007 2008 2009 2010 Sept. 2011 Billions MidAmerican Growth Summary 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 26

Financial Information ($ millions) 27 LTM Operating Revenue 9/30/2011 12/31/2010 12/31/2009 PacifiCorp 4,517$ 4,432$ 4,457$ MidAmerican Funding 3,570 3,815 3,699 Northern Natural Gas 630 624 689 Kern River 361 357 372 Northern Powergrid 947 802 825 CalEnergy Philippines 119 105 147 CalEnergy U.S. 31 32 31 HomeServices 991 1,020 1,037 Corporate/other (59) (60) (53) Total operating revenue 11,107$ 11,127$ 11,204$ Years Ended

Financial Information ($ millions) 28 LTM Depreciation and Amortization 9/30/2011 12/31/2010 12/31/2009 PacifiCorp 615$ 572$ 558$ MidAmerican Funding 335 345 336 Northern Natural Gas 67 64 63 Kern River 114 109 101 Northern Powergrid 163 157 165 CalEnergy Philippines 23 23 23 CalEnergy U.S. 8 8 8 HomeServices 12 14 18 Corporate/other (14) (16) (16) Total depreciation and amortization 1,323$ 1,276$ 1,256$ Years Ended

Financial Information ($ millions) 29 LTM Operating Income 9/30/2011 12/31/2010 12/31/2009 PacifiCorp 1,098$ 1,055$ 1,079$ MidAmerican Funding 442 460 469 Northern Natural Gas 273 274 337 Kern River 196 198 221 Northern Powergrid 557 474 394 CalEnergy Philippines 84 71 113 CalEnergy U.S. 13 17 15 HomeServices 22 17 11 Corporate/other (37) (64) (174) Total operating income 2,648 2,502 2,465 Interest expense (1,177) (1,173) (1,195) Interest expense on MEHC subordinated debt - Berkshire (17) (30) (58) Interest expense on MEHC subordinated debt - other (15) (22) (22) Capitalized interest 43 54 41 Interest and dividend income 11 24 38 Other 84 110 146 Income before income tax expense and other 1,577 1,465 1,415 Income tax expense (288) (198) (282) Other 69 (29) 24 Net income attributable to MEHC 1,358$ 1,238$ 1,157$ Years Ended

Financial Information ($ millions) 30 LTM Interest Expense 9/30/2011 12/31/2010 12/31/2009 PacifiCorp 409$ 403$ 412$ MidAmerican Funding 186 192 197 Northern Natural Gas 58 60 60 Kern River 48 51 56 Northern Powergrid 153 146 153 CalEnergy Philippines 2 4 4 CalEnergy U.S. 15 16 16 Corporate/other 338 353 377 Total interest expense 1,209$ 1,225$ 1,275$ Years Ended

(1) Excludes amounts for non-cash equity allowances for funds used during construction (2) LTM 9/30/2011 excludes $376 million of amounts accrued as of September 30, 2011, for which payment is not contractually due until December 2013 Financial Information ($ millions) 31 LTM Capital Expenditures (1) 9/30/2011 12/31/2010 12/31/2009 PacifiCorp 1,426$ 1,607$ 2,328$ MidAmerican Funding (2) 553 338 439 Northern Natural Gas 113 136 177 Kern River 226 157 73 Northern Powergrid 314 349 387 Other reportable segments and corporate/other 11 6 9 Total capital expenditures 2,643$ 2,593$ 3,413$ Years Ended

Financial Information ($ millions) 32 Total Assets 9/30/2011 12/31/2010 12/31/2009 PacifiCorp 21,815$ 21,410$ 20,244$ MidAmerican Funding 11,903 11,134 10,732 Northern Natural Gas 2,674 2,795 2,657 Kern River 2,074 1,949 1,875 Northern Powergrid 5,680 5,512 5,622 CalEnergy Philippines 334 336 463 CalEnergy U.S. 586 569 569 HomeServices 666 649 657 Corporate/other 670 1,314 1,865 Total assets 46,402$ 45,668$ 44,684$

Capitalization ($ millions) • As of September 30, 2011, approximately 96% of total debt was fixed-rate debt • As of September 30, 2011, long-term senior debt had a weighted average life of approximately 14.6 years and a weighted average interest rate of approximately 5.8% 33 Capitalization 9/30/2011 12/31/2010 12/31/2001 Short-term debt -$ 320$ 256$ Current portion of long-term debt 1,278 1,143 317 MEHC senior debt 5,113 5,371 1,834 Subsidiary debt 13,331 12,662 4,755 Total senior debt 19,722 19,496 7,162 Current portion of MEHC subordinated debt 43 143 - MEHC subordinated debt 151 172 788 Subsidiary subordinated debt - - 100 Noncontrolling interests 173 176 165 Noncontrolling interests and subordinated debt 367 491 1,053 MEHC shareholders᾽ equity 13,753 13,232 1,708 Total capitalization 33,842$ 33,219$ 9,923$ Senior debt/capitalization 58% 59% 72%