Exhibit 99.1

Welcome and Introduction

Patrick J. Goodman

Senior Vice President

and

Chief Financial Officer

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 the Private Securities Litigation Reform Act
of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as
“may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “intend,” “potential,”
“plan,” “forecast,” and similar terms. These statements are based upon the Company’s 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 in the jurisdictions in which the Company’s facilities

are located;

–

financial condition and creditworthiness of significant customers and suppliers;

–

changes in governmental, legislative or regulatory requirements affecting the Company or the electric or

gas utility, pipeline or power generation industries;

–

the outcome of general rate cases and other proceedings conducted by regulatory commissions or other

governmental and legal bodies;

–

changes in economic, industry or weather conditions, as well as demographic trends, that could affect

customer growth and usage or supply of electricity and gas;

–

changes in prices and availability for both purchases and sales of wholesale electricity, coal, natural gas,

other fuel sources and fuel transportation that could have significant impact on energy costs;

–

changes in business strategy or development plans;

–

availability, terms and deployment of capital;

–

performance of generation facilities, including unscheduled outages or repairs;

–

risks relating to nuclear generation;

Forward Looking Statements

–

the impact of derivative instruments used to mitigate or manage interest rate risk and volume and price

risk and changes in the commodity prices, interest rates and other conditions that affect the value of the
derivatives;

–

the impact of increases in healthcare costs, changes in interest rates, mortality, morbidity and

investment performance on pension and other postretirement benefits expense, as well as the impact of
changes in legislation on funding requirements;

–

changes in MEHC’s and its subsidiaries’ credit ratings;

–

unanticipated construction delays, changes in costs, receipt of required permits and authorizations,

ability to fund capital projects and other factors that could affect future generation plants and
infrastructure additions;

–

the impact of new accounting pronouncements or changes in current accounting estimates and

assumptions on financial results;

–

changes in, and compliance with, environmental laws, regulations, decisions and policies that could

increase operating and capital improvement costs, reduce plant output and/or delay plant construction;

–

the Company’s ability to successfully integrate PacifiCorp’s operations into the Company’s business;

–

other risks or unforeseen events, including wars, the effects of terrorism, embargos and other

catastrophic events; and

–

other business or investment considerations that may be disclosed from time to time in filings with the

SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Company are described in MEHC’s filings

with the SEC, including Item 1A. Risk Factors and other discussions contained in this Form 10-K. These
forward looking statements speak only as of the date of this presentation. 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.

Income from Continuing Operations ⁽¹⁾

Shareholders’ Equity

Property, Plant and Equipment (Net)

Total Assets

5-Yr. CAGR = 44.0%

5-Yr. CAGR = 23.6%

5-Yr. CAGR = 36.3%

5-Yr. CAGR = 29.9%

___________________________

2006 includes PacifiCorp since date of acquisition, March 21, 2006

MEHC Growth Summary

Overview

David L. Sokol

Chairman of the Board

and

Chief Executive Officer

•

18,000 employees

•

$36 billion in assets

•

$10 billion in revenue

•

6.9 million electric and natural gas customers

•

17,600 miles of interstate natural gas pipeline

•

16,386 net MW owned in operation or under

construction (57% coal, 23% gas, 17%
renewable, 3% nuclear and other)

86.6%

13.4%

Berkshire Continues to Pursue Energy Sector Investment Diversification Through MEHC

•

Provides MEHC with a $3.5 billion 5-year equity commitment from ‘AAA’ rated parent

–

Access to capital even in times of utility sector and general market stress; no other utility has this

quality of explicit financial support

–

Commitment can only be drawn for two purposes:

•

Paying MEHC parent debt when due

•

Making equity contributions to any of MEHC’s regulated subsidiaries

•

Future M&A activity will not be funded from this equity commitment

Berkshire Equity Commitment

Berkshire’s Energy Sector Strategy

•

MEHC serves as the investment vehicle for Berkshire in the energy sector

–

Provides opportunities to invest a significant amount of capital

–

The PacifiCorp acquisition clearly demonstrates Berkshire’s willingness to make sizable

investments through MEHC

–

Future acquisitions will be funded in a credit positive manner

•

Berkshire continues to leverage MEHC’s management expertise and ability to effectively integrate

significant acquisitions

Berkshire Investment Criteria

•

Long-term investment horizon: “Forever is our holding period.”

•

Search for fairly priced companies with appropriate business mixes

•

Limited operating synergies as regulated utility businesses are operated on a

stand-alone basis

•

Provide significant access to equity capital, management expertise and best practices

across the MEHC portfolio of companies

•

Objective is to maintain or improve credit ratings for regulated utilities (each entity

ring-fenced) and to achieve single ‘A’ or better credit ratings

Operating Philosophy

•

Focus on customer service, operational efficiency and cost control

•

Produce outcomes that benefit all stakeholders, including customers, investors and

regulators

•

Operate with a long-term focus

•

Plan, execute, measure, correct

•

Prudent financial and risk management policies

•

Disciplined acquisition strategy

•

Management development and succession

VFT and associated upgrades

Proposed South Texas 345 kV

projects

CREZ Transmission Plan

Additional EHV Backbone System

King

Singleton

Buchanan

Zorn

Martin

Lake

Monticello

Valley

Spring

Comanche

San

Angelo

McCamey

Oklaunion

Red Creek

Morgan Creek

Gulf States

Coleto

Creek

Hilje

Sol

LAREDO

CORPUS

CHRISTI

VICTORIA

SAN ANTONIO

DALLAS/FT. WORTH

HOUSTON

AUSTIN

MIDLAND/ODESSA

WICHITA

FALLS

ABILENE

WACO

McALLEN

Cities/Towns

Substations

Caballo

•

Jointly-owned utility company will

design, construct and operate ERCOT
transmission assets

•

Up to $1 billion in new projects are

anticipated over the next several years

•

Executed joint venture agreement in

January 2007

•

Regulatory approval to operate as an

electric transmission utility in Texas is
expected in second half 2007

•

Target capital structure 40% equity

and 60% debt

Electric Transmission Texas, LLC

PacifiCorp Service

Territory

Thermal Plants

Gas-Fueled Thermal Plants

Wind Projects

Geothermal Plants

Coal Mines

Hydro Systems

Generation Developments

500 kV transmission lines

345 kV transmission lines

230 kV transmission lines

___________________________

Since date of acquisition, March 21, 2006

Includes projects currently under construction

•

2006 Operating Income: $528.4 million ⁽¹⁾

•

Assets: $13.9 billion

•

Headquartered in Portland, Oregon

•

6,500 employees

•

1.7 million electricity customers

•

9,262 net MW owned ⁽²⁾

•

Generating capacity by fuel type ⁽²⁾

–

Coal 66%

–

Natural gas 18%

–

Hydro 13%

–

Wind and geothermal 3%

MidAmerican Energy

Company Service Territory

Major Generating Facilities

CBEC 4 – Under Construction

Wind Generation

Wind Generation Under Construction

___________________________

Includes projects currently under construction

•

2006 Operating Income: $420.6 million

•

Assets: $6.5 billion

•

Headquartered in Des Moines, Iowa

•

3,700 employees

•

1.4 million electric and natural gas customers

•

5,681 net MW owned ⁽¹⁾

•

Generating capacity by fuel type ⁽¹⁾

–

Coal 58%

–

Natural gas 23%

–

Wind 10%

–

Nuclear 8%

–

Other 1%

•

2006 Operating Income: $269.1 million

•

Assets: $2.3 billion

•

Headquartered in Omaha, Nebraska

•

1,000 employees

•

15,900-mile interstate natural gas transmission

pipeline

•

Market area design capacity of 4.9 Bcf/d plus

2.1 Bcf/d field area capacity

•

Five natural gas storage facilities with a total

firm capacity of 65 Bcf

•

2006 Operating Income: $216.9 million

•

Assets: $2.1 billion

•

Headquartered in Salt Lake City, Utah

•

160 employees

•

1,680-mile interstate natural gas transmission

pipeline

•

Delivers natural gas from Rocky Mountain

basins to markets in Utah, Nevada,
California and Arizona

•

Greater than 2 Bcf/d peak capacity

•

Headquartered in Newcastle, U.K.

•

760 employees

•

1.6 million electricity customers

•

5,560 square miles of service

territory

•

26,719 miles of transmission and

distribution line

•

Headquartered in Leeds, U.K.

•

890 employees

•

2.2 million electricity customers

•

4,131 square miles of service

territory

•

34,797 miles of transmission and

distribution line

U.K.

Edinburgh

London

Newcastle

Leeds

•

2006 Operating Income: $515.7 million

•

Assets: $6.6 billion

•

2006 Operating Income: $244.3 million

•

Assets: $1.1 billion

•

490 employees

•

1,443 net MW owned

•

15 plants in the United States and three

facilities in the Philippines

–

Two of the Philippine geothermal plants

will be returned to the Philippine
government pursuant to their contracts in
2007

•

Generating capacity by fuel type

–

Natural gas 52%

–

Geothermal 37%

–

Hydro 11%

CalEnergy Generation Operations

Philippines

•

2006 Operating Income: $54.7 million

•

Assets: $795.2 million

•

3,550 employees

•

20,000 sales associates

Second-largest full-service residential real estate brokerage firm in the U.S.

Awards

•

MEHC was named the 2006 Utility of the Year by Electric Light

& Power magazine, one of the pre-eminent publications in the
utility industry

•

MEC received the prestigious J.D. Power and Associates

Founder’s Award for its dedication, commitment and continuous
improvement in customer service

•

Other significant awards:

–

For the past three years PacifiCorp has been ranked 1^st and

MEC has been ranked 2^nd in industrial customer satisfaction

by TQS Research

–

MEHC’s pipeline group has been ranked 1^st in the 2007

MASTIOGALE survey of customer satisfaction for the second
consecutive year

•

Customer diversity

•

Regulatory diversity

•

Weather diversity

•

Economic diversity

•

Catastrophic-risk diversity

PacifiCorp Service Territory

MidAmerican Energy Company Service Territory

Kern River Pipeline

Northern Natural Gas Pipeline

NEDL Service Territory

YEDL Service Territory

U.K.

Diversity of Regulated Assets

As the utility sector enters its first comprehensive capital expenditure

build-out since the 1980’s, many analysts project the industry to be cash flow
negative for the next few years

MEHC has no dividend requirement and therefore its 100% reinvestment of

free cash flow and access to equity capital from Berkshire under any market
condition clearly differentiates the quality of MEHC’s credit from its peers

MEHC’s Competitive Advantage

•

MEHC’s cash flow is derived from a diversified portfolio of businesses which

demonstrate low historical correlation amongst one another and macro economic
variables

•

Approximately 89% of MEHC’s operating income in 2006 was generated from

rate-regulated businesses

Todd M. Raba

President

MidAmerican Energy

Company Service Territory

Major Generating Facilities

CBEC 4 – Under Construction

Wind Generation

Wind Generation Under

Construction

___________________________

Includes projects currently under construction

Overview

•

Headquartered in Des Moines, Iowa

•

3,700 employees

•

1.4 million electric and natural gas

customers

•

5,681 net MW owned ⁽¹⁾

•

Generating capacity by fuel type ⁽¹⁾

–

Coal 58%

–

Natural gas 23%

–

Wind 10%

–

Nuclear 8%

–

Other 1%

Alternative Regulation in Iowa

Case Study

•

Two independent prongs

–

Legislative – Rate-making principles (H.F. 577) apply to investor owned utilities in Iowa

–

Regulatory – Iowa Utilities Board (IUB) and Office of Consumer Advocate (OCA) are

receptive to rate-making proposals that are specific to a single utility

•

MEC has been successful with both

Case Study

Legislative Background

•

1984 – Significant costs related to newly-built generation were not allowed to be included

in rates, increasing risk of investing in the industry

Iowa enacted legislation that discouraged regulated utilities from building

generation

Incremental electric needs met through conservation, energy efficiency and

renewables

As a result, only one combustion turbine was added during the period (1984 -

2002)

•

1996 – Deregulation of the electric utility industry begins in California

•

1999 – Iowa decides not to follow popular nationwide trend toward electric industry

deregulation

•

2000 – Skyrocketing prices in the California market raise concerns about inadequacy of

generating capacity in the United States

MEC projected a need for new power plants to replace expiring power purchase

contracts and to satisfy load growth not met by energy efficiency and
renewables

2001 Legislative Debate

Case Study

•

Prior legislation and energy policy made power purchases from outside the state the

only cost-effective option for satisfying electric-supply needs

•

The legislature and the governor recognized the reliability and economic benefits of

additional rate-regulated generation being constructed in Iowa

•

MEC was asked what it would take to encourage the construction of regulated

generation in Iowa

•

The utilities, IUB, OCA, legislature and governor worked cooperatively to produce H.F.

577

Case Study

H.F. 577 Objective

•

H.F. 577 facilitates portfolio diversity by replacing the least-cost standard with a

reasonable cost standard

•

H.F. 577 mitigates regulatory risk and market price risk by providing for binding

regulatory review and determination of rate-making principles for proposed generation
investments prior to significant expenditures

–

Prudence review occurs prior to investment rather than after considerable investment

is made

•

A similar process is provided for investments in environmental improvements to

existing coal-fired generation

Case Study

H.F. 577 Rate-Making Principles

•

The rate-making principles process can be pursued at the option of the utility

•

The utility itself determines which rate-making principles are important to it for its

proposed investment

•

The generation facility must be located in Iowa and a baseload facility of at least 300

MW in size, a combined-cycle facility or a renewable facility

•

The utility must have in place an IUB-approved energy efficiency plan

•

The IUB is required to issue a decision on the principles

•

The rate-making principles apply for the life of the investment and are binding upon

future regulators

•

If the utility does not accept the rate-making principles as approved, the utility is not

required to pursue the project

Case Study

Revenue Sharing

•

The settlement of a contested case over MEC’s electric revenues in 1997 included:

–

Elimination of MEC’s fuel adjustment clause

–

An agreement that MEC and customers would share revenue above certain return on

equity (ROE) levels

–

Customer’s share was refunded through bill credits and checks

–

Refunds were given to customers related to earnings in years 1998 through 2000

•

MEC recognized that customers did not give long-term credit to rate reductions and bill

credits and that customers do not like rate increases

•

Because MEC would need to invest in new generation, increasing rate base by 65% over

six years, rate increases would be likely

•

Proposed to off-set the cost of new generation with the customers’ portion of revenue

sharing instead of providing bill credits or checks

•

Beginning with earnings from 2001, revenue-sharing dollars were applied to new

generation

•

Revenue sharing is specific to MEC through stipulation and agreement as approved by

the IUB, not by legislation

Case Study

MidAmerican Settlements

•

MEC is currently operating under a series of settlements that:

–

Provide rate-making principles for three major generation construction projects

•

Greater Des Moines Energy Center

•

Council Bluffs Energy Center Unit 4

•

Iowa Wind Projects

–

Allow returns over 11.75% to be shared between customers and MEC

•

11.75% - 13% share 40% customers / 60% company

•

13% - 14% share 50% customers / 50% company

•

Over 14% share 83.3% customers / 16.7% company

–

Customers’ share is used to off-set the cost of generation through 2010

•

As of December 31, 2006, customers’ share of revenue sharing has totaled $290 million

–

No general rate increase through at least 2012

–

If ROE falls below 10%, MEC may file for a rate increase

Case Study

Everyone Wins

•

Customers will face much smaller rate increases in the future

•

Customers enjoy the benefits of no general rate increase through at least 2012

•

Significant economic benefit to Iowa

•

IUB now has the legal authority to pre-approve without concerns about binding future boards

•

Significant new generation (over $2.5 billion in 6 years) is being, or has been, built in Iowa

–

Greater Des Moines Energy Center 491 MW Dec. 2004

–

Council Bluffs Energy Center Unit 4 790 MW June 2007

–

Iowa Wind Projects 583 MW 2004 – 2007

New Generation – Natural Gas

Greater Des Moines Energy Center is a 491 MW combined-cycle natural gas plant that was completed in December 2004

Council Bluffs Energy Center Unit 4

New Generation – Coal

Unit 4 to begin commercial operation in June 2007

New Generation – Coal

•

The Council Bluffs Energy Center Unit 4 is the largest power plant ever built in Iowa

•

The $1.2 billion, 790 MW facility uses advanced-supercritical coal-fueled technology

–

State-of-the-art power cycle design for high efficiency and low emissions per MWh

–

The plant applies the best available control technology to control air emissions and

meet or exceed all required standards for a new coal-fueled generation facility

–

First new coal-fueled plant in the United States with mercury control technology

•

A new 124 mile, 345kV transmission line and associated substation modifications were

completed in the summer of 2006 and will help to relieve transmission constraints and
improve transmission system reliability between Unit 4 and the central Iowa energy
market

June 2007

Commercial

Operation

March 2007

Initial Fire of Main

Boiler on Coal

Today

June 2006

Boiler Hydrostatic

Test

September 2003

Groundbreaking

February 2005

Boiler Structural Steel

Erection Complete

Percent

Complete

- 100

September 2000

Project Initiation

2004

2005

2006

2007

November 2006

Initial Fire of Main

Boiler on Oil

Project Timeline

Overall project 99% complete

New Generation – Wind

Renewable wind energy will comprise more than 10% of our Iowa generating

portfolio by the end of 2007

Additional Wind Project

Opportunities and Challenges

•

Working on a new agreement with OCA for

additional projects

•

Anticipate filing rate-making principles later this

month

•

Completion dates would span 2007 and 2008

Phil A. Jones

President

and

Chief Operating Officer

•

Headquartered in Newcastle, U.K.

•

760 employees

•

1.6 million electricity customers

•

5,560 square miles of service territory

•

26,719 miles of transmission and

distribution line

•

Headquartered in Leeds, U.K.

•

890 employees

•

2.2 million electricity customers

•

4,131 square miles of service territory

•

34,797 miles of transmission

and distribution line

Overview

Combined in September 2001

U.K.

Edinburgh

London

Newcastle

Leeds

Distribution

Supply

Metering

Post-Privatization

Public Electricity
Supply (PES)
Activities

CE Electric UK

Activities

Distribution

Metering

TRANSACTIONS

Focused on ‘Wires Only’

•

Electricity distribution requires a licence enforced by the British regulator Ofgem

•

Licences oblige operators to transport electricity on non-discriminatory and

price-controlled terms on behalf of suppliers

•

Price controls are generally set for five years following a price control review, current

period extends to the end of March 2010

•

Metering is a separately price controlled activity and the services are provided through

a contract with a third party

Distribution Price Control Reviews

•

Price controls are set to recover Ofgem’s view of efficient costs over the next five years

•

Ofgem takes account of

–

Required quality of service outputs

–

Operating costs and comparative efficiency

–

Future capital expenditure

–

Regulatory asset value and depreciation

–

Pensions costs

–

(Forward) cost of capital

–

Tax

–

Financial ratios and investment grade rating targets

•

U.K. regulation tries to provide strong efficiency incentives for opex and capex

Key Issue	Objective	Outcome
Capital investment	• Capital program perceived as credible	• CE: fully funded capex plan
Operating costs	• Secure the recovery of our operating costs	• CE: fully funded opex forecast
WACC	• Secure an improvement	• Increased to 6.91% pre-tax (real) • Shifted to post-tax basis
Pensions	• Recover a significant contribution to our pension deficits	• 74% recovery of deficiency cost • Pass-through for future market risk
Incentives	• Retain efficiency and performance incentives	• Cost efficiency retained • Other incentives enhanced

The Last Price Control Review:

DPCR4 – Effective April 1, 2005

Rank	Group	Average Efficiency Factor
1	Scottish & Southern	105%
2	CE	101%
3	Central Networks	94%
4	WPD	90%
5	ScottishPower	87%
6	United Utilities	81%
7	EDF	79%

DPCR4 Cost Efficiency Assessment

Performance Benchmarking

•

CE was one of only two

groups (the other being
SSE) to be provided with
funding for both its capital
and operating costs

•

Ranked 2^nd on a group basis

for operating cost efficiency

Performance to Date

Operating Costs

Operating costs continue to benchmark well. Our analysis shows CE companies

improving their overall positions compared with the DPCR4 final proposals

Over/(under)

spend to

allowance

Year ended 31 March

£m (05/06 prices)

Actual

Net Opex

2006

DPCR4

Allowance

2006

Scottish and Southern

-6

-3

CE Electric

WPD

Central Networks

120

111

EDF

172

162

ScottishPower

107

Total

693

660

* Outperformance in relation to allowance in United Utilities (£3m) occurred only after

adjusting for the impact of significant proceeds from the disposal of non operational

assets

Capital Investment

Delivering a strong performance and increasing the value of the asset

CE UK capex allowance / investment

100

120

140

160

180

2005/06

Actual

2006/07

2007/08

2008/09

2009/10

Actual/Plan

Ofgem Allowance

RAV as at March 31

1250.0

1350.0

1450.0

1550.0

1650.0

1750.0

1850.0

1950.0

2050.0

2005

2006

2007

2008

2009

2010

£447 million RAV growth

projected across the price control
period

The current capex plan (including 2005/06 actuals) results in out-performance of 5% (£38 million) over the DPCR4 period

Our Focus For DPCR5

•

Continue to build credibility by delivery of a strong all-round performance

•

Securing an acceptable weighted average cost of capital

•

Defend against unfavorable changes in operating cost assessment

•

Continue to advocate rewards for those who set out (and deliver) credible forecasts

•

Proper treatment of input prices – recognize genuine increases in commodity and

service market rates

•

Optimize the exposure of revenue to performance-related revenue drivers

•

Stronger initiatives to encourage connection of environmentally friendly generation

Secure Cash-Flows	Stable regulatory environment Monopoly characteristics Growth through efficiencies and additions to asset base
Financial Structure	Conservative financial structure, declining leverage No new long-term borrowings required during current regulatory period Well structured debt covenants AAA insurance wrap on some bonds
Management	Proven track record on cost control and operational performance Strength of parent

Key Strengths

Questions

Patrick Reiten

President

Richard Walje

President

Overview

___________________________

Includes projects currently under construction

PacifiCorp Service Territory

Thermal Plants

Gas-Fueled Thermal Plants

Wind Projects

Geothermal Plants

Coal Mines

Hydro Systems

Generation Developments

500 kV transmission lines

345 kV transmission lines

230 kV transmission lines

•

Headquartered in Portland, Oregon

•

6,500 employees

•

1.7 million electricity customers

•

9,262 net MW owned ⁽¹⁾

•

Generating capacity by fuel type ⁽¹⁾

–

Coal 66%

–

Natural gas 18%

–

Hydro 13%

–

Wind and geothermal 3%

PacifiCorp Organization

Following its acquisition from ScottishPower in March 2006, PacifiCorp

remains an integrated utility but functionally was reorganized into three
operating units to promote more localized decision making

•

Pacific Power

–

Headquartered in Portland

–

Serving customers in Oregon, Washington and California

–

Pat Reiten, president

•

Rocky Mountain Power

–

Headquartered in Salt Lake City

–

Serving customers in Utah, Idaho and Wyoming

–

Rich Walje, president

•

PacifiCorp Energy

–

Includes electric generation, commercial and energy trading, and coal-mining

operations

–

Headquartered in Salt Lake City

–

Bill Fehrman, president

2006 Regulatory Highlights

•

Seven rate cases pending at transaction close

–

Rate settlements reached and approved in all but one state

–

Total revenue increase of more than $200 million

–

Regulatory mechanisms were negotiated to mitigate future rate increase pressures including

•

Power and energy cost adjustment mechanisms (WY, CA and OR)

•

Inflation adjustment mechanisms (CA)

•

Single-issue rate-making authority (CA)

•

Multi-step rate increases (UT, WY)

•

Inter-jurisdiction cost allocation protocol approved in ID, OR, UT and WY; and approved for use in the last CA rate case

•

Utah (41% of retail revenues)

–

UPSC approved a $115 million increase (10%) in two phases, fully effective June, 2007

–

Senate Bill 26 provides opportunity to obtain advance approval for resource decisions

•

Oregon (30% of retail revenues)

–

OPUC approved $43 million increase (5%) effective January 1, 2007, for 2005 general rate case

–

Power costs updated annually after 2007 through transition adjustment mechanism (TAM)

–

Authorized an additional $6.1 million (0.7%) following reconsideration of initial application of SB 408 in 2004 general rate case

2006 Regulatory Highlights

•

Wyoming (13% of retail revenues)

–

Total increase of $25 million (6.9%) approved and effective

–

PCAM implemented

–

Application for $2.8 million in recovery pending before PSC

•

Idaho (6% of retail revenues)

–

$8.25 million increase (5.1%) effective for irrigators and two large industrial customers

•

California (2% of retail revenues)

–

CPUC approved $7.3 million increase (10.8%)

–

Energy cost adjustment mechanism for net power costs and inflation plus ability to recover major plant additions

•

Lessons Learned

–

Engage in continual dialogue with commission staff and key intervening parties to help them understand case issues, particularly the company’s planned capital expenditures and O&M budgets prior to filing a general rate case

–

Educate public and key stakeholders on cost drivers behind the proposed rate increase prior to filing the case

Washington Rate Case

•

2005 – Initial request – filed May 2005

Revenue increase – $39.2 million or 17.9%

In April 2006 commission denied any rate relief

Commission rejected proposed allocation method finding a failure to demonstrate that all system resources benefited Washington customers

•

2006 – Initial request – filed October 2006

Revenue increase – $23.2 million or 10.2%

Proposed new west control area allocation method favored by staff

•

2006 – Current status

Staff supports PCAM

Staff testimony proposes a $12 million increase if the PCAM is adopted, $16 million if PCAM is not adopted

Industrial customer group and public counsel testimony proposes a $25 million rate reduction if PCAM is adopted

Company rebuttal proposes PCAM plus a $19 million increase

Hearings March 27 - 30; mid-year 2007 order expected

Oregon SB408

•

Attempts to match the amount of income “Taxes Collected” from customers to the amount of income “Taxes Paid,” as those terms are defined by the statute

Taxes Collected is determined by way of fixed reference to income tax expense expressed as a percentage of retail revenues as authorized by the commission in setting rates for the respective calendar year; percentage is applied to actual retail revenues to determine a hypothetical collection

Taxes Paid is computed as the lowest of 1) the stand-alone tax liability of the utility, 2) the tax liability of the consolidated group of which the utility is a member, or 3) the tax liability derived using the commission developed “Apportionment Method.”

Not an actual-to-actual comparison

•

If “Taxes Collected” and “Taxes Paid” vary by more than $100,000 the difference is either refunded or collected from customers

•

Oregon utilities are sponsoring legislation that would eliminate the hypothetical “Taxes Collected” formula and require the commission to compare actual taxes collected with taxes paid

•

Each affected utility submitted a request for a private letter ruling from the Internal Revenue Service to ensure the statute and its administrative rules comply with the normalization provisions of the Internal Revenue Code

10-Year Business Plan – Overview

•

PacifiCorp 10-year business plan

–

First one under MidAmerican ownership

–

Significant capital investment to meet growing customer demand and improve system reliability

–

Honors transaction commitments

•

Business plan evaluates impact on customers

–

Balance timing of capital spending with rate impacts

•

Business plan is being reviewed with key stakeholders

–

For improved understanding, to solicit feedback and obtain buy-in

10-Year Business Plan – Process

•

Long-term projections of each state’s load growth and customer growth were developed

•

In conjunction with the IRP process, a plan developed for how to meet load growth and replace existing resources

•

Capital and O&M plans were developed by each of the businesses

•

OMAG projections were developed

–

Cost levels from recently completed rate cases were reviewed

–

Targets and initiatives were developed to keep increases in check

–

Reviewed all employee programs in comparison to market

•

Pension benefits have been adjusted

•

The above steps were part of an iterative process; as results were reviewed, changes were made to mitigate customer impacts

10-Year Business Plan – Results

•

Significant capital investment needed, and included in the plan, to meet growing energy needs and to improve system reliability

–

$16 billion over 10 years

•

Reduce need for wholesale purchases

•

Add renewable energy to portfolio

•

Meet customer growth and increased energy usage

•

Add system infrastructure to maintain and enhance reliability

•

Investments-Capital Outlay

T&D Investment

•

Transmission Investment

–

More than $1.2 billion planned capital spending over the next 10 years

–

Three Mile Knoll project to maintain capacity on Path C and improve reliability in southeast Idaho

–

Other Path C upgrades to improve the transfer capability in northern Utah

–

New 345 kV line from central Utah to the southwest

–

New 345 kV line from Bridger to the Wasatch front in 2014

•

Distribution Investment – Pacific Power

–

16,000 new connects in 2007, decreasing to 13,000 by 2016, approximately $32 million to $33 million per year

–

$1 billion in capital spending over the next 10 years

•

Distribution Investment – Rocky Mountain Power

–

20,000 to 28,000 new connects per year, costing $60 million to $80 million per year

–

300MVA of additional distribution substation capacity per year

–

$2.1 billion in capital spending over the next 10 years

Generation Investments

•

Significant new generation capital spending due to

–

Load growth

–

Hydro relicensing

–

Clean air initiatives

–

Commitments for renewable energy

Regulatory Strategy & Challenges

•

Recovering levels of investment which exceed depreciation and sales growth will require rate increases

–

Frequent large rate increases are not compatible with customer satisfaction goals

–

Low embedded generation cost compared to marginal generation cost, coupled with significant load growth, results in the need for more frequent rate increases

•

Implement effective relationship management

–

Communications plan

–

Relationship management plans for regulators, consumer groups and industrial consumer associations

•

Pursue alternative cost recovery mechanisms

–

Power cost adjustment mechanisms

–

Single item cost trackers (e.g., renewable investment)

–

Alternate forms of regulation

–

Implement use of future test periods in all states

•

Review and implement innovative cost-of-service and rate design methodologies

–

Alternatives to embedded cost rate-making for generation costs

Bill Fehrman

President

PacifiCorp’s Asset Portfolio

•

9-12 million tons of coal mined annually

•

6,104 MW coal-fired generation

•

1,702 MW gas-fired generation

•

>1,456 MW renewable generation

–

1,160 MW hydro

–

273 MW wind

–

23 MW geothermal

Generation Investments

•

The embedded cost of generation in 2007 rates is approximately $34/MWh; whether new load is met by owned facilities or purchased power, that embedded cost is significantly below today’s marginal cost of power; as a result, the generation component of rates will increase as new power costs are reflected

–

New generation costs are significantly higher than embedded generation costs

•

New coal and gas plants cost approximately $60/MWh to $70/MWh on a levelized basis without carbon capture

•

New wind projects cost approximately $70/MWh after the production tax credit

–

Hydro capital costs will be $528 million over the next 10 years to meet FERC license requirements

•

New license implementation, excluding Klamath, will result in an output decrease of approximately 150 GWh per year

•

Klamath relicensing could result in an additional loss of 220 GWh or more, beginning in 2015

•

Swift #1 capacity increase of 75 MW, but small energy increase

•

2007 and 2008 generation capital spending projections do not reflect the decision to expedite the addition of renewable energy in those two years

PacifiCorp Energy Coal Generation Projects

Capacity

Resource

Type

In-Service

Date

Location

New Resources

IPP3 @ 37.77%

340

Coal-SCPC

June 2012

Delta, UT

BRIDGER 5 @ 67%

527

Coal-SCPC

June 2014

Point of Rocks, WY

Generation Investments

Resource Additions

•

PacifiCorp recently filed revised request for proposals (RFP) with Utah Public Service Commission, incorporating changes suggested by the commission and independent evaluator

•

Expect to seek up to 1,700 MW for delivery during 2012 - 2014

•

RFP process continues with Oregon commission, following denial in January

•

The business plan assumes the following new coal resource additions:

Resource Development

•

Intermountain Power Project - Unit 3

–

900 MW coal-fired, PacifiCorp Energy share 38%

–

Project in-service 2012

–

Air permit issued – currently being contested

–

Engineer-procure-construct (EPC) request for proposals due April 2007

–

Partnership agreements to be completed by May 2007

–

Targeted to award EPC contract by end of 2007

•

Jim Bridger Project - Unit 5

–

790 MW coal-fired, 67% share, project in-service 2014

–

Assessing supercritical and integrated gasification technologies

–

Owner’s engineer and environmental engineering contracted in 2007

–

EPC request for proposals evaluated in 2007

Generation Investment

Emission Controls

•

PacifiCorp Energy continues to assess current and future emissions control requirements

–

Current emissions control installation costs are estimated at $1.2 billion over the next 10 years, excluding AFUDC

•

2007 business plan is based on the company’s best assessment at this time

•

Emission controls installations have been aligned with major unit overhaul schedules to minimize outages and reduce overall cost impacts

•

Huntington 2 emissions projects including scrubber, baghouse and low NOx burners achieved operational status in November 2006, as scheduled

•

Low NOx burner projects scheduled for completion in 2007 at Hunter 3 and Jim Bridger 3

Bridger Underground Mine Development

•

Access to 57 million tons coal

•

Life – 15 years

•

Total project cost – $184 million

•

Began mining coal in March 2007

Mining Expansion

•

Own or lease approximately 242 million tons of recoverable coal reserves

•

Supplied 33% of 2006 coal requirements

•

On schedule to be on-line by June 15, 2007

•

Project developer - Summit Power

•

EPC contractor - Siemens

•

Needed to meet 2007/2008 load growth

•

535 MW combined-cycle plant includes latest turbine upgrade

•

45 miles south of Salt Lake City

•

$347 million project

Resource Construction – Lake Side

Prior to MEHC, PacifiCorp had not

made significant progress toward its

renewable resource target

Rock River 1

50.0 MW (PPA)

Owned by Shell Wind Energy

Combine Hills

41.0 MW (PPA)

Owned by Eurus Energy America

Foote Creek 1

41.4 MW (jointly owned)

32.6 MW PacifiCorp (~78%)

8.8 MW Eugene Water & Electric (~22%)

PacifiCorp Wind (pre-MEHC)

PacifiCorp is on track to deliver 454 MW

of wind resources by the end of 2007

Marengo

140.4 MW

Under construction

Leaning Juniper 1

100.5 MW

Complete & operational

Additional Projects

in Development

213.2 MW

(112 MW near closing

101.2 MW under negotiation)

PacifiCorp Wind 2007

PacifiCorp Wind

•

Acquisition commitments will be met

•

Opportunities and challenges

–

Extension of production tax credit to December 31, 2008

•

Hedges 2007 construction risk

•

Enables expansion of 2007 projects

•

Enables pursuit of additional economic projects toward fulfilling 1,400 MW commitment

–

Long term (self development)

•

Currently controlled land (cost and risk reducing)

•

Opportunistic site acquisitions

•

Strategic transmission investments

–

Challenges

•

Overall economics due to raw material pricing

•

Access to quality balance of plant contractors

•

Land issues and other development risks

•

North Umpqua (185.5 MW) – Complete

•

Lewis River (510 MW) – Late 2007

•

Klamath, 169 MW project

–

Highly charged, controversial, political and social issue

–

Relicensing initiated in 2000

–

Pursuing both traditional FERC relicensing process and settlement

Ongoing Relicensing

Hydro Relicensing

Iron Gate

Reservoir

Copco 1

Reservoir

J.C. Boyle

Peaking
Reach

J.C. Boyle

Bypass
Reach

J.C. Boyle

Reservoir

Keno

Reservoir

Link Dam

(UKL outlet)

PacifiCorp’s Klamath hydroelectric project is located on the Upper Klamath River in southern Oregon and northern California. The project includes five mainstem dams and seven powerhouses, has a total installed capacity of approximately 169 megawatts and plays a critical role in water management

Factors Driving Interest in

IGCC & Challenges

•

Concern about global climate change - up to 90+% of the carbon in syngas can be captured from IGCC plants with commercially available technology; captured CO₂ can be geologically sequestered or utilized for enhanced oil recovery

•

Slightly lower emissions of criteria pollutants

•

Efficiency

•

Potential ease of permitting

•

Challenges

–

Technology and performance risk

–

Carbon capture and sequestration

–

Regulatory recovery

PacifiCorp’s Current IGCC

Development Activities

•

Active discussions with technology suppliers

•

Potential partner in Energy Northwest’s 600 MW Pacific Mountain Energy Center

•

Seeking investment tax credit benefits available under Energy Policy Act of 2005

•

Wyoming Infrastructure Authority proposal at Jim Bridger

Summary From PacifiCorp Perspective

•

Supercritical pulverized coal technology and IGCC are similar in terms of efficiency and emissions

•

IGCC is currently more costly

•

Firm pricing is not available

•

Uncertainty in carbon capture requirements and capture costs creates planning uncertainty

•

New CO₂ capture technologies for pulverized coal hold promise as competitive options to IGCC

Questions

Mark A. Hewett

President

Northern Natural Gas

MEHC Interstate Natural Gas Pipelines

•

Headquartered in Omaha, Nebraska

•

1,000 employees

•

15,900-mile interstate natural gas transmission pipeline

•

Market area design capacity of 4.9 Bcf/d plus 2.1 Bcf/d field area capacity

•

Five natural gas storage facilities with a total firm capacity of 65 Bcf including 4 Bcf of LNG

•

Access to five major supply basins

•

NNG has annual deliveries of approximately 1 Tcf

Overview

Northern Natural Gas

Company Evolution

Today

•

Favorably positioned

–

Strong ownership

–

Significantly out-performing financial goals

–

Competitive markets secured

–

Leader in customer satisfaction

–

Highly reliable service provider

–

Long-term rate stability at competitive levels

–

Growing

–

Leader in employee safety

•

Outstanding potential

2002 Pre-Acquisition

•

Unfavorably positioned

–

Multiple ownership and management changes

–

Financially unstable

–

Lack of capital investment

–

Major customer issues

–

Fundamental operational issues

–

Short-term focus

–

Regulatory-dependent organization

–

Low employee morale

•

Outstanding potential

Strong Market and Competitive Position

Competitive Position

•

Provides customers with flexibility to access multiple supply basins

–

Hugoton, Anadarko, Permian, Rocky Mountain and Western Canada Basins

•

Lowest transportation cost of natural gas to customers in the upper Midwest

•

Strategic location in high demand upper Midwest market areas

•

Strong barriers to entry given widely dispersed load centers in NNG’s upper Midwest market area

•

Customer base dominated by local distribution companies

•

NNG settled its last rate case in 2005

–

Executing on plan to avoid future rate cases

Center Point Energy Minnesota Gas

Xcel Energy, Inc.

Metropolitan Utilities District

101.8 17.9% 2019

76.2 13.4% 2017

21.3 3.7% 2016

2006

Transportation and Storage
Revenue

($ millions)

% of

Transportation and Storage

Revenue

Contract

Term

Market Retention

NNG has retained all major competitive markets

Growth – Northern Lights Project

The Northern Lights expansion project is expected to add more than 400,000 Dth/d of growth to Northern’s market area transportation business by November 2008, representing 10% growth in market area

Northern Lights Phase I

•

24% native growth

•

12% industrial

•

$156.4 million of capital

•

$34.3 million per year in revenues

•

34% power

•

30% ethanol

•

$145.1 million capital

•

374,225 Dth/d (winter)

•

5+ year terms for 85% of volume

•

Facilities

–

58 miles of mainline (24” - 36”)

–

30 miles of branch lines (6” - 24”)

–

12 new, 31 modified TBSs

Growth – Northern Lights Project

Northern Lights Phase II

•

44,200 Dth/d (winter)

•

$9.0 million capital

•

10+ year terms for 88% of the

volume

•

Facilities

–

4,083 hp mainline compression

–

2 miles of 6” lateral pipeline

–

3 new, 2 modified TBSs

Wrenshall

Garner

Redfield

Lyons

Cunningham

•

2006 storage expansion - completed

–

6 Bcf expansion – 4 Bcf Cunningham, 2

Bcf Redfield

–

$11.3 million capital

–

$3.0 million incremental revenue

–

6 Bcf FDD contract with one customer

•

21 years

•

Tariff rate of $0.74/Dth

•

In-service June 1, 2006

•

2008 proposed storage expansion

–

8 Bcf – Redfield

–

$49.5 million capital

–

$10.5 million incremental revenue

–

Market-based rates

•

20 years

•

Rates ranging from $1.30 to $1.50

•

15 customers

•

In-service June 1, 2008

NNG Storage Expansion

•

Headquartered in Salt Lake City, Utah

•

160 employees

•

1,680-mile interstate natural gas transmission pipeline

•

Delivers natural gas from Rocky Mountain basins to markets in Utah, Nevada, California and Arizona

•

Greater than 2 Bcf/d peak capacity

•

In 2006 Kern River became the largest supplier of natural gas to California, with market share exceeding 26%

Overview

Daily Throughput Dth/d

Operational Excellence

Average throughput on the pipeline increased in 2006 by 11% from 2005

•

Market capture in California, Nevada and Arizona

•

Increased Rocky Mountain supply

•

Captured short-haul/limited path hydraulic advantage of the pipeline by serving rapidly growing markets in Las Vegas and Utah

•

Increased share of California market from 21% in 2003 to 26% in 2006

2004 Rate Case Update

•

Rate case filed April 30, 2004

•

Initial commission decision issued October 19, 2006

•

Requests for rehearing filed November 20, 2006

•

Compliance filing submitted December 18, 2006

•

Final order expected mid-2007

Provides Supply Diversity, Operational Reliability, Competitive Rates and Excellent Customer Service

Competitive Position

•

Access to economic Rocky Mountain gas supplies in three western states

–

170 TCF of proven and undiscovered potential reserves

–

Only expanding supply basin in the lower 48 states

•

Supply diversity is provided through pipeline interconnects accessing all Rocky Mountain production basins

•

New and efficient pipeline system, low fuel rates and minimal cost associated with new pipeline safety legislation

•

Pipeline load factor averaged 111% during 2005 and 123% during 2006

•

Direct service to end users avoids rate stacks of local distribution companies (LDC)

•

Ranked #4 out of 41 interstate pipelines in 2007 Mastio survey for customer satisfaction, and experienced zero days of primary firm service interruption

2006 Revenue Distribution

Contract Maturities December 2006

Strong, High Quality Cash Flows with 82% of Contracts Expiring After 2015

Kern River – Revenue Stability

Competitive Threats

and Opportunities

•

LNG on the West Coast

–

Competitive threat may be overstated

•

Schedule delays – particularly upstream liquefaction facilities and host country production sharing agreements

•

Reduced load factor expectations

•

Can North America compete for LNG supply?

Supply constraints in the winter

Sponge in the summer

•

Siting controversy continues to frustrate re-gasification proposals on the West Coast

•

Kern River is presently well positioned to compete if any California LNG re-gasification terminals are successful

Competitive Threats

and Opportunities

•

Potential impacts of Rockies Express

–

1,800 MDth/d of incremental Rocky Mountain supply heading east

–

Rocky Mountain production is currently pipeline capacity constrained

–

Kern River will compete with Rockies Express to attract supply

•

Wellhead net back will win the day

–

Full completion of Rockies Express is not scheduled until June 2009, but initial volumes are expected to flow to the mid-continent in 2008

–

Kern River anticipates Wyoming natural gas prices will increase due to increased access to premium eastern markets

–

Wyoming/California price spreads will narrow until production increases outstrip new pipeline takeaway capacity

–

Incremental Rocky Mountain production is expected to increase by 500-650 MDth per year over the next four years

–

Any impact on Kern River pricing is expected to be seasonal and temporary

Competitive Threats

and Opportunities

•

Growth in the West

–

California is captive to gas-fired generation

–

California ISO set an electric output record on July 24, 2006, which was not anticipated until 2011 (> 50,000 MW)

–

California is again short electric generation and is turning to natural gas to satisfy new electric demand

•

8,400 MW of new gas-fired electric generation is proposed in California

•

1,200 MW of new gas-fired electric generation is approved in Nevada

•

New delivery laterals and a capacity expansion are likely on Kern River by 2010

Questions

Current Topics

David L. Sokol

Chairman of the Board

and

Chief Executive Officer

Industry Overview

•

Repeal of PUHCA

•

Valuations at or near all-time highs

–

Substantial availability of capital

•

Many different business models and regulatory regimes

•

Significant future capex expenditures

•

High commodity prices expected to continue

–

Construction costs escalating rapidly

–

Likely increasingly “tight” generation markets

•

Uncertainties regarding future regulatory and environmental policies

–

Customers potentially at risk

–

Holding pattern in many regions as global climate change debated

–

Deregulation in some areas being reconsidered

Numerous Hurdles Must Be Overcome to Consummate Transactions

–

Rating Agency

–

Management / Employees

–

Shareholders

Will Deals Get Done?

•

Stakeholder management is essential for successful transaction completion

–

Regulatory / Political

–

Environmental

–

Customer

•

Recent outcomes clearly suggest that regulatory and political scrutiny are the largest hurdles

–

EXC / PEG and FPL / CEG

–

Unsuccessful utility LBOs were due to regulatory and political issues

•

A utility’s business mix can have a direct impact with regulators

–

Retention of synergies

–

Affiliate sales relationships

–

Rate pressures (transition to competitive markets)

•

Are “acquirors” interests aligned with good utility stewardship

–

Use of significant leverage (regulators may look through capital structure)

–

Impact to customer service quality and satisfaction

–

Sufficient re-investment

–

Matching of duration of interests

–

Structural credit protections

Phase 1

Global Climate Change Legislation

•

Transitioning to a low-carbon economy cannot take place overnight, but there are measures we should undertake now that will place us on the right path

•

We recommend a phased-in, technology and policy driven approach to provide tools necessary to successfully reduce long-term global greenhouse gas emissions while minimizing the costs and risks to the economy and the impact to customers

In the first phase, we suggest technology development and market transformation activities

•

Adoption of a flexible renewable and clean technology portfolio standard

•

More stringent energy efficiency mandates

•

Policies to encourage efficiency improvements at existing facilities

•

A ten-year, multi-billion dollar public-private research and development program for emissions reductions

•

Removal of the legal and regulatory barriers to the development of new technologies such as carbon sequestration and new nuclear development

•

Tax policies to support these programs, such as long-term energy tax credits

Phase 3

Phase 2

Global Climate Change Legislation

•

In the second phase, as technologies become widely available, a hybrid system of phased-in emissions reductions based on carbon intensity targets, together with a carbon price cap, would be developed

•

The third phase prescribes a 25 percent reduction of U.S. greenhouse gas emissions from 2000 levels by 2030, with additional reductions of 10 percent in each succeeding five-year period through 2050

Cautionary note about the cap and trade concept

•

Cap and trade is a useful tool but it is not a panacea

•

It does not supply emissions-free power

•

It does not bring new technologies on-line

•

It does not reduce prices for renewable energy resources

•

It merely raises prices for carbon-based emissions

Questions

A Berkshire Hathaway Company