20050817Revised Goodman direct, exhibits.pdf

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, iDAHO PUBLIC
, u ILl I IE S COMMISSION
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BEFORE THE IDAHO PUBLIC UTILITIE:S COMMiSSION
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IN THEMA TTER OF THE JOINT
APPLICATION OF MlDAMERlCAN
. ENERGY HOLDINGS COMPANY AND
PACIFICORP DBA UTAH POWER &
, LIGHT COMPANY FOR AN ORDER
. AUTHORIZING PROPOSED
TRANSACTION
CASE NO. P AC-O5~O8
) DirectTestimony of Patrick J. Goodman
P A CIF! CO RP
CASE NO. PAC-E~05-
. ,
July 2005
Introduction
Please state your name and business address.
My name is Patrick J. Goodman, and my business address is 666 Grand Avenue
Suite 2900, Des Moines, Iowa, 50309.
By whom are you employed and in what capacity?
I am employed by MidAmerican Energy Holdings Company ("MEHC"). I serve
as senior vice president and chief financial officer of MEHC and as a director and
officer of many MEHC subsidiaries.
Please summarize your education and business experience.
After receiving a bachelors degree in accounting from the University of Nebraska
at Omaha in 1989, I was employed as a senior audit associate at Price Waterhouse
Coopers, then known as Coopers & Lybrand, until 1993. I then joined National
Indemnity Company and was employed there until 1995 as a financial manager.
After that I joined MEHC, then known as CalEnergy Company Inc.
CalEnergy ). At MEHC, I have served in various financial positions, including
senior vice president and chief accounting officer, and assumed my present
position in 1999. In addition, I am also a Certified Public Accountant.
Summary of Testimony
What is the purpose of your direct testimony in this proceeding?
My testimony will accomplish the following things:
discuss the Scottish Power pIc ("ScottishPower ) corporate structure and
identify the ScottishPower subsidiaries that MEHC is proposing to
acquIre;
Goodman, Di -
PacifiCorp
discuss MEHC's corporate structure and PacifiCorp s place in that
structure;
discuss MEHC's capital structure;
describe MEHC's financing for, and the mechanics of, the proposed
transaction;
describe the financial forecast for the acquisition;
enumerate certain financial and structural commitments that MEHC is
proposing as part of the acquisition approval process;
describe the "ring-fencing" protections MEHC will employ; and
describe the rights of MEHC's largest investor, Berkshire Hathaway Inc.
Berkshire Hathaway ) with regard to the proposed transaction.
ScottishPower Corporate Structure
Please describe your understanding of the ScottishPower corporate structure
prior to the proposed acquisition of PacifiCorp by MEHC.
The ScottishPower corporate structure prior to the proposed acquisition is shown
on Exhibit No.9, which is adapted from a similar illustration contained in
PacifiCorp s March 31 2005, Form 10-K report. MEHC is purchasing the
company identified as PacifiCorp from PacifiCorp Holdings, Inc. ("PHI"
PacifiCorp is a vertically integrated electric utility serving retail customers in the
states of California, Idaho, Oregon, Utah, Washington and Wyoming.
Subsidiaries of PacifiCorp that support its electric utility operations by providing
coal mining facilities and services, environmental remediation, and management
of deforestation carbon credits are also being purchased by MEHC. The
Goodman, Di - 2
PacifiCorp
REVISED 8/17/05
remaining subsidiaries of PHI, including PPM Energy, Inc., will remain with
ScottishPower.
MERC Corporate Structure
Please discuss MERC's corporate structure and PacifiCorp s place in that
structure.
Upon completion of the transaction, PacifiCorp will be an indirect wholly-owned
subsidiary ofMERC as illustrated in the simplified MERC organizational chart
provided with my testimony as Exhibit No.1 O. This structure will help facilitate
the implementation of the "ring-fencing" concept that is addressed later in my
testimony.
MERC Capital Structure
Please describe MERC's capital structure.
Table 1 below illustrates the pre-transaction capitalizations ofMERC and
PacifiCorp, followed by the pro forma, combined capitalization ofMERC after
the proposed transaction occurs. At this point I would direct your attention to the
MERC capitalization prior to the acquisition. It can be seen that MERC'
stockholder s equity is composed of five items:
zero coupon convertible preferred stock
common stock
additional paid-in capital
retained earnings, and
accumulated other comprehensive loss, net.
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PacifiCorp
The first two items show no entry as they are intended to record the par value of
these components. However, since they are both zero par value issuances, the
entire contributed value of these components is recorded in the third item,
additional paid-in capital. The fourth item represents the earnings of the
corporation retained and reinvested into the business. The final item represents
the gain and loss on a variety of other comprehensive income items that are
further identified on the Consolidated Statements of Stockholders' Equity
disclosure which is on page 61 of Exhibit No. 11, MERC's 2004 report on Form
10- K.
The long-term debt of MEHC contains items identified as:
Parent company senior debt
Parent company subordinated debt
Subsidiary and project debt, and
Preferred securities of subsidiaries.
The parent company senior and subordinated debt represent the long-term debt of
MEHC. The parent company subordinated debt consists of amounts issued to
Berkshire Hathaway, and other amounts issued to third parties. The item
identified as "Subsidiary and project debt" represents the long-term, primarily
non-recourse, debt of the various subsidiaries of MEHC after being consolidated
with the parent's financial statements.
The "Preferred securities of subsidiaries," contained in MEHC'
consolidated capitalization, represents preferred stock issued by MEHC'
subsidiaries.
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Pacifi Corp
REVISED 8/17/05
Table 1
MidAmerican Energy Holdings Company
Unaudited Pro forma Consolidated Long-Term Capitalization
As of March 31, 2005
(In millions)
Long-term Debt:
Parent company senior debt
Parent company subordinated debt(2)
Subsidiary and project debt
Total long-term debt
Preferred securities of subsidiaries
Stockholders' equity:
Zero coupon convertible preferred stock, no par value
Preferred stock, $100 stated value
Common stock, no par value
Additional paid-in capital
PacifiCor Pro Forma
MEHC Adjustments MEHC Pro Forma
773.19.709.(1) $4,482.19.
586.4 11.4%586.4
358.45.629.987.43.
10,718.629 709 70.
89.41.3 (3)
Accumulated other com rehensive loss net
Total stockholders' equity
Total long-term capitalization
41.3 (41.3)(3)
950.894.(2,894.(4)370.4
3,419.(1)
309.3 446.4 (446.4)(4)309.
(4)
28.
$ 7 793 100.
Retained earnings
For the purposes of the pro fonna long-tenn capitalization table, it has been assumed that the acquisition was completed on March 31, 2005. Consequently, the totallong-tenn capitalization ofPacifiCorp does not reflect
the following:
the additional equity investment by ScottishPower in PacifiCorp of$500.0 million during the fiscal year ended March 31, 2006;
expected dividends, totaling $214.8 million, to be paid to ScottishPower by PacifiCorp for the fiscal year ending March 31, 2006;
expected earnings, debt issuances and debt retirements ofPacifiCorp for the fiscal year ending March 31,2006; and
expected earnings, debt issuance and debt retirement ofMEHC and its current subsidiaries for the period ending March 31,2006.
Certain reclassifications have been made to PacifiCorp s historical presentation in order to confonn to MEHC's historical presentation.
(1) Pursuant to tenns of the Stock Purchase Agreement, MEHC will pay ScottishPower $5.1 billion in cash in exchange forl00% ofPacifiCorp s common stock. The total estimated purchase price of the acquisition
as follows (in millions):
Common stock or zero coupon convertible non-voting preferred stock ofMEHC
Long-tenn senior unsecured debt ofMEHC
Total estimated purchase price
(2) Parent company subordinated debt consists of the following at March 31, 2005:
Berkshire trust preferred securities
Other trust preferred securities
Total parent company subordinated debt
419.
1.709.
129.
289.
297.
1.586.4
(3) Pursuant to the tenns of the Stock Purchase Agreement, PacifiCorps preferred stock which is classified in PacifiCorps March 31, 2005 balance sheet as part of stockholders equity will remain outstanding. For
purposes of the pro fonna capitalization table the preferred stock, totaling $41.3 million, was reclassified to preferred securities ofsubsidiaries.
(4) Represents the pro fonna adjustments to eliminate the historical stockholders' equity ofPacifiCorp.
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PacifiCorp
To what extent has MEHC employed long-term debt in its capital structure?
Table 1 indicates that, on a consolidated basis, MEHC's balance sheet reflects a
capital structure that is composed of approximately 77.1 percent debt. While the
proportion of debt may appear relatively high, it is important to note that much of
the debt on the consolidated balance sheet is issued by creditworthy non-recourse
subsidiaries.
What are the credit ratings that are currently assigned to MERC by the
major credit rating agencies?
MEHC holds an investment grade credit rating from Standard & Poor' s, Moody
Investors Service, and FitchRatings. In addition, MEHC's utility subsidiaries are
, all creditworthy entities. MEHC's largest investor, Berkshire Hathaway, has
credit ratings from each of the rating agencies that are the highest, most secure
credit ratings a corporation can receive.
The individual agency ratings are shown in the table, below, for Berkshire
Hathaway and for MEHC and MEHC's regulated subsidiaries senior unsecured
debt. After the announcement of this transaction, FitchRatings affirmed MEHC'
senior unsecured debt at BBB , with a stable outlook. Standard & Poor s placed
MERC's corporate rating and senior unsecured debt rating of BBB- on
CreditWatch-Positive, and Moody s Investors Service affirmed MERC's senior
unsecured debt rating of Baa3 while noting a positive rating outlook for MEHC.
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Pacifi Corp
REVISED 8/17/05
Table 2
Credit Ratings - July 2005
Standard & Poor Moody s Investor FitchRatings
Service
Berkshire Hathaway AAA Aaa AAA
MidAmerican
Energy Holdings BBB-Baa3 BBB
Company
MidAmerican
Energy Company
Northern Natural
Gas Company
Kern River Gas
TransmIssion Co.
Northern Electric
Distribution Ltd BBB+
Yorkshire Electricity
Distribution pic BBB+
Financing and Mechanics of the Transaction
Please describe the steps that will be taken to effectuate the transaction.
A limited liability company ("LLC"), PPW Holdings LLC, has been established
as a direct subsidiary of MEHC. This LLC will receive, as an equity infusion
$5.1 billion raised by MEHC through the sale of either common stock or zero
coupon convertible preferred stock to Berkshire Hathaway and the issuance of
long-term senior notes, preferred stock, or other securities with equity
characteristics to third parties. However, the LLC will have no debt of its own.
The LLC will, as provided in the Stock Purchase Agreement, pay PHI $5.1 billion
in cash, at closing, in exchange for 100 percent of the common stock of
PacifiCorp. In addition, it is projected that approximately $4.3 billion in net debt
and preferred stock ofPacifiCorp will remain outstanding as obligations of
PacifiCorp.
Prior to the expected closing date of March 31, 2006, ScottishPower has
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REVISED 8/17/05
agreed to make $500 million in additional capital contributions to PacifiCorp, and
PacifiCorp is expected to pay $214.8 million of dividends to ScottishPower.
Provision for additional capital contributions have been made in the Stock
Purchase Agreement if the acquisition has not closed by that date.
Please describe how the acquisition of PacifiCorp by MERC will be financed.
As described above, MEHC expects to fund the transaction with the proceeds
from an investment by Berkshire Hathaway of approximately $3.4 billion in either
common stock or zero coupon non-voting convertible preferred stock ofMEHC
and the issuance by MEHC to third parties of approximately $1.7 billion of long-
term senior notes, preferred stock, or other securities with equity characteristics.
However, the transaction is not conditioned on such financing and if funds were
not available from third parties, Berkshire Hathaway is expected to provide any
required funding. The pro forma capital structure ofMEHC after the acquisition
is shown in Table 1 above, assuming $1.7 billion of long-term debt is issued by
MEHC. The pro forma schedule is unaffected if, ultimately, either common stock
or zero coupon convertible preferred stock is issued. The timing and composition
of these financings are flexible and subject to modification as market conditions
change. It is not anticipated that there would be any restrictive covenants
associated with the proposed financing different from those typical of an
investment grade financing.
Are you aware of any benefits to PacifiCorp due to MERC's relationship
with Berkshire Rathaway?
MEHC believes that PacifiCorp s cost of debt will benefit from the acquisition
due to the association with MEHC's largest investor, Berkshire Hathaway.
Historically, MEHC's utility subsidiaries have been able to issue long-term debt
Goodman, Di - 8
PacifiCorp
at spread levels below their peers with similar ratings. Based on market data
independently obtained from IP Morgan and ABN AMRO, the average interest
rate savings on MidAmerican Energy Company s last ten year debt issuance was
approximately 10 basis points. If this ten basis point difference is applied to the
incremental long-term debt issuances contained in PacifiCorp s financial forecast
incremental interest costs might be as much as $26.7 million lower over the next
ten years. Extending the same assumptions out twenty years implies possible
savings totaling $71.1 million.
Market dynamics change every day based on a variety of factors, thus
MEHC cannot guarantee that a 10 basis point savings on debt issuances of similar
maturity will be achievable going forward indefinitely. However, MEHC is
prepared to commit that over the next five years it will demonstrate that
PacifiCorp can issue new long-term debt at a yield ten basis points below its
similarly rated peers. If MEHC is unsuccessful in demonstrating that it has done
so, MEHC will accept up to a ten basis point reduction to the yield it actually
incurred on any incremental debt issuances for any PacifiCorp revenue
requirement calculation effective for the five year period subsequent to the
closing of the proposed acquisition. Based on PacifiCorp s financial forecast of
future debt issuance, this represents a guaranteed total cost savings over the five
year period of approximately $6.3 million.
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PacifiCorp
The Application in this proceeding notes that Standard & Poor s has placed
PacifiCorp s credit rating on credit watch with negative implications, based
upon Standard & Poor s view of PacifiCorp s weaker stand-alone metrics.
Can you quantify the approximate impact upon PacifiCorp s incremental
long-term financing costs if PacifiCorp were on a stand-alone basis and
suffered a credit rating downgrade?
Under the assumption that PacifiCorp is a stand-alone company and it suffered a
one notch credit downgrade by all three major credit rating agencies, the impact
under current market conditions would be approximately 10 to 15 basis points.
Over the next ten years, given PacifiCorp s financing plan and assuming market
conditions stay the same, that would imply an increase in cost of approximately
$26.7 million. In today s market, if only Standard and Poor s downgraded
PacifiCorp (i.e., leaving the company "split rated") the impact of the downgrade
would be approximately 5 basis points.
As I have previously mentioned, market dynamics are constantly changing
and the spread over treasury securities of debt instruments of different credit
qualities often widen and narrow as a result. Over the course of the past ten years
for example, Credit Suisse First Boston indicates that the spread between the yield
on BBB+ and A- public utility bonds has ranged from today s relatively tight
spreads of 10 to 15 basis points to as much as 40 to 60 basis points. Thus the
potential cost over the next ten years to PacifiCorp and its customers of a ratings
downgrade could be multiples of the cost mentioned abQve.
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PacifiCorp
What is MERC's current estimate of the excess of the purchase price over
the book value of the PacifiCorp assets to be acquired and the liabilities to
remain outstanding as of the expected closing date?
This figure will change as ScottishPower makes additional equity investments in
PacifiCorp, as dividends are paid by PacifiCorp to ScottishPower, and as a result
of any retained earnings by PacifiCorp between March 31 , 2005 and the closing
date of the proposed acquisition. As of the expected closing date (March 31
2006), the excess of the purchase price over the book value of the assets to be
acquired and the liabilities to remain outstanding at PacifiCorp is expected to be
approximately $1.2 billion. MEHC witness Abel's testimony also addresses this
preffilum.
In and of itself, as a result of the closing of this transaction, will PacifiCorp
financial statements change?
No. PacifiCorp s U.S. financial statements, prepared using generally accepted
accounting principles ("GAAP"), will not be impacted by the closing of this
transaction. PacifiCorp will maintain its own accounting system, separate from
MEHC's accounting system. The acquisition will be accounted for in accordance
with GAAP. The premium paid by MEHC for PacifiCorp will be recorded in the
accounts of the acquisition company and not in the utility accounts of PacifiCorp.
As indicated in the commitments sponsored by MEHC witness Mr. Gale
in Exhibit No.2, MEHC and PacifiCorp will not propose to recover the
acquisition premium in PacifiCorp s regulated retail rates; provided, however
that if the Commission in a rate order issued subsequent to the closing of the
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PacifiCorp
transaction reduces PacifiCorp' s retail revenue requirement through the
imputation of benefits (other than those benefits committed to in this transaction)
accruing from the acquisition company (PPW Holdings LLC) or MEHC, MEHC
and PacifiCorp will have the right to propose upon rehearing and in subsequent
cases a symmetrical adjustment to recognize the acquisition premium in retail
revenue requirement.
However, as noted by MEHC witness Thomas Specketer, upon the closing
of the transaction, it is MEHC intent to transition PacifiCorp' s financial reporting
to a calendar year-end in contrast to its present March 31 fiscal year-end.
Will the proposed transaction have any impact on the availability of
PacifiCorp s books and records?
No. All PacifiCorp financial books and records will continue to be kept in
Portland, Oregon, and will continue to be available to the Commission upon
request during normal business hours at PacifiCorp s offices in Portland, Oregon
Salt Lake City, Utah, and elsewhere in accordance with current practice.
As indicated by the commitments in MEHC witness Mr.Gale s Exhibit
No., MEHC and PacifiCorp will also provide the Commission access to all
books of account, as well as all documents, data, and records of their affiliated
interests, which pertain to transactions between PacifiCorp and its affiliated
interests.
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PacifiCorp
Financial Forecast for the Acquisition
Describe the financial forecast used for the purposes of reviewing the
proposed acquisition.
In completing its due diligence review of the proposed acquisition, MEHC relied
on a financial forecast provided by ScottishPower. MEHC satisfied itself that the
plan provided by ScottishPower was reasonable and did not revise that plan.
Describe the magnitude of the proposed capital expenditure program that
has been forecasted for PacifiCorp.
PacifiCorp is projecting at least $1 billion per year in capital expenditures over
the next five years for generation, transmission and distribution projects.
Commitments Concerning the Acquisition Approval Process
Please describe the financial and structural commitments that MERC is
prepared to undertake as part of the acquisition approval process.
MEHC witness Mr. Gale s Exhibit No.2 enumerates many of the commitments
that MEHC is prepared to undertake as part of the acquisition approval process.
MEHC witness Abel discusses additional new commitments designed to provide
benefits to retail customers of PacifiCorp. I will sponsor the commitments
contained in Table 3, below.
Goodman, Di -
PacifiCorp
, ,.
Table 3
Commitments' ,that MER C is Prepared to Undertake
as Part of the Acquisition Approval Process
Regulatory Oversight
Accounting
Systems
PacifiCorp will maintain its own accounting
system, separate from MEHC's accounting
system. All PacifiCorp financial books and
records will be kept in Portland, Oregon, and
will continue to be available to the Commission
upon request, at PacifiCorp s offices in
Portland, Oregon, Salt Lake City, Utah, and
elsewhere in accordance with current practice.
MEHC and PacifiCorp will provide the
Commission access to all books of account, as
well as all documents, data, and records of their
affiliated interests, which pertain to transactions
between PacifiCorp and its affiliated interests.
Any diversified holdings and investments~,
non-utility business or foreign utilities) of
MEHC and PacifiCorp following approval of
the transaction, will be held in a separate
company(ies) other than PacifiCorp, the entity
for utility operations. Ring-fencing provisions
(i.e., measures providing for separate financial
and accounting treatment) will be provided for
each of these diversified activities, including but
not limited to provisions protecting the
regulated utility from the liabilities or financial
distress of MEHC. This condition will not
prohibit the holding of diversified businesses.
Affiliate
Transactions
Non
Jurisdictional
Affiliates
Financial Integrity
Separate Credit Ratings PacifiCorp will maintain separate debt and, if
outstanding, preferred stock ratings. PacifiCorp
will maintain its own corporate credit rating, as
well as ratings for each long-term debt and
preferred stock (if any) issuance.
MEHC and PacifiCorp will exclude all costs of
the transaction from PacifiCorp s utility
accounts. Within 90 days following completion
of the transaction, MEHC will provide a
preliminary accounting of these costs. Further,
MEHC will provide the Commission with a
Costs of the Transaction
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PacifiCorp
Premium Paid
Rating Agency Presentations
Minimum Common Equity
Ratio
Capital Requirements to Meet
Obligation to Serve
Assuming Liabilities/Pledging
Assets
REVISED 8/17/05
final accounting of these costs within 30 days of
the accounting close.
The premium paid by MEHC for PacifiCorp
will be recorded in the accounts of the
acquisition company and not in the utility
accounts ofPacifiCorp. MEHC and PacifiCorp
will not propose to recover the acquisition
premium in PacifiCorp s regulated retail rates;
provided, however, that if the Commission In a
rate order issued subsequent to the closing of
the transaction reduces PacifiCorp s retail
revenue requirement through the imputation of
benefits (other than those benefits committed to
in this transaction) accruing from the
acquisition company (PPW Holdings LLC),
Berkshire Hathaway, or MEHC, MEHC and
PacifiCorp will have the right to propose upon
rehearing and in subsequent cases a
symmetrical adjustment to recognize the
acquisition premium in retail revenue
requirement.
MEHC and PacifiCorp will provide the
Commission with unrestricted access to all
written information provided to credit rating
agencies that pertains to PacifiCorp.
PacifiCorp will not make any distribution to
PPW Holdings LLC or MEHC that will reduce
PacifiCorp s common equity capital below 40
percent of its total capital without Commission
approval. PacifiCorp s total capital is defined
as common equity, preferred equity and long-
term debt. Long-term debt is defined as debt
with a term of one year or more. The
CommissIon and PacifiCorp may reexamine this
minimum common equity percentage as
financial conditions or accounting standards
change, and may request that it be adjusted.
The capital requirements of PacifiCorp, as
determined to be necessary to meet its
obligation to serve the public, will be given a
high priority by the Board of Directors of
MEHC and PacifiCorp.
PacifiCorp will not, without the approval of the
Commission, assume any obligation or liability
as guarantor, endorser, surety or otherwise for
MEHC or its affiliates, provided that this
condition will not prevent PacifiCorp from
Goodman, Di - 15
PacifiCorp
assuming any obligation or liability on behalf of
a subsidiary of PacifiCorp. MERC will not
pledge any of the assets of the regulated
business of PacifiCorp as backing for any
securities which MEHC or its affiliates (but
excluding PacifiCorp and its subsidiaries) may
Issue.
Additional Net Benefit
Reduced Cost of Debt MEHC commits that over the next five years it
will demonstrate that PacifiCorp s incremental
long-term debt issuances will be at a yield ten
(10) basis points below its similarly rated peers.
If it is unsuccessful in demonstrating that
PacifiCorp has done so, PacifiCorp will accept
up to a ten (10) basis point reduction to the
yield it actually incurred on any incremental
long-term debt issuances for any revenue
requirement calculation effective for the five
year period subsequent to the approval of the
proposed acquisition.
Ring-Fencing
Please describe the "ring-fencing" protections MEHC will employ to isolate
PacifiCorp from MEHC and MEHC's other subsidiaries.
MEHC will utilize the LLC, identified earlier in my testimony as PPW Holdings
LLC. Among the LLC's obligations and limitations are the following. The LLC
will:
have a single purpose, that being to own the common equity of
Pacifi Corp;
have an independent director from whom assent is required to place the
LLC or PacifiCorp into bankruptcy;
require PacifiCorp to maintain separate books, financial records and
employees, and will prohibit the commingling of assets;
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PacifiCorp
have a non-recourse structure which precludes liabilities of MERC, or its
subsidiaries, from being assessed against the LLC or PacifiCorp;
prohibit the LLC's or PacifiCorp s credit from being made available to
satisfy obligations of, or to be pledged for the benefit of, any other
company;
prohibit the LLC or PacifiCorp from acquiring the obligations or securities
of MEHC or any of its other affiliates except, of course, that PacifiCorp
may purchase its own obligations; and
require the consent of the independent director, and rating agency
confirmation, that there will be no credit downgrade for any amendment to
the above mentioned protections.
This structure, colloquially referred to as "ring-fencing," is recognized by the
major rating agencies as an effective means to separate the credit quality of a
parent from a subsidiary.
PacifiCorp, as a subsidiary of PPW Holdings LLC, will retain its own
capital structure, its own credit rating, and through the ring-fencing structure, will
be effectively isolated from any credit issues that might arise at MEHC or any of
its other subsidiaries.
Description of the Rights of Berkshire Rathaway
Please describe the rights Berkshire Rathaway currently has as a result of its
ownership of $1.63 billion of zero coupon convertible preferred stock of
MEH C.
Berkshire Hathaway s rights as a holder of MEHC zero coupon convertible
Goodman, Di - 17
Pacifi Corp
preferred stock can be summarized as follows. The securities:
are not mandatorily redeemable by MEHC or at the option of Berkshire
Hathaway;
participate in dividends and other distributions to common shareholders as
if they were common shares but otherwise possess no dividend rights;
have no voting rights;
are convertible into common shares on a 1 for 1 basis, as adjusted for
splits, combinations, reclassifications and other capital changes by MEHC;
upon liquidation, would have a prior right to available proceeds up to $1
per share, after which the common stock would have a right to available
proceeds up to $1 per share (subject to certain adjustments), after which
the preferred stock and common stock would share ratably in any
remaining proceeds; and
the dividend and distribution arrangements previously described cannot be
modified without the positive consent of Berkshire Hathaway.
Berkshire Hathaway currently holds 9.9 percent of the common shares of
MEHC and 41 263,395 shares of MEHC's zero coupon convertible preferred
stock. While the convertible preferred stock does not vote with the common stock
in the election of directors, the convertible preferred stock gives Berkshire
Hathaway the right to elect 20 percent of MEHC' s Board of Directors (currently
two of the ten members of the MEHC Board of Directors). Additionally, the prior
approval of Berkshire Hathaway, as the holder of convertible preferred stock, is
required for MEHC to undertake certain fundamental transactions
~,
the
Goodman, Di - 18
PacifiCorp
PacifiCorp acquisition). The prior approval of Berkshire Hathaway is not
required for transactions undertaken directly by MEHC subsidiaries.
You stated that the zero coupon convertible preferred stock would
participate in dividends or other distributions to the same extent as the
common shareholders. What has been MEHC's dividend history?
Since the issuance of the zero coupon convertible preferred stock in March 2000
MEHC has not declared or paid a dividend to its common shareholders or to
Berkshire Hathaway. Instead, earnings have been retained at the operating
company level to maintain or improve credit quality and support the capital
investment programs of MEHC' s regulated subsidiaries.
For instance, MidAmerican Energy Company, when purchased by MEHC
in March 1999, had an equity-to-total-capital ratio of approximately 48 percent as
of December 31, 1998. As of December 31 , 2004 that ratio is approximately 53
percent, despite extensive capital expenditure programs undertaken by
MidAmerican Energy Company.
Please describe the conversion mechanism of the zero coupon convertible
preferred stock of MEHC?
The zero coupon convertible preferred stock of MEHC is convertible into MEHC
common shares at the option of Berkshire Hathaway if either of two events
occurs. First, if the conversion would not cause Berkshire Hathaway (or any
affiliate of Berkshire Hathaway) to become regulated as a registered holding
company or as a subsidiary of a registered holding company under the Public
Utility Holding Company Act of 1935 and any successor legislation ("PUHCA"
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Pacifi Corp
REVISED 8/17/05
Second, in the event ofMEHC's involuntary or voluntary liquidation, dissolution
recapitalization, winding-up or termination or a merger, consolidation or sale of
all or substantially all ofMEHC's assets.
Please describe the rights Berkshire Rathaway will have upon conversion of
the zero coupon convertible preferred stock of MERC.
Upon conversion Berkshire Hathaway would have the rights of a common
stockholder and the ability to elect nine of the ten members ofMEHC's board of
directors. The additional $3.4 billion of common shares associated with the
PacifiCorp transaction (or zero coupon convertible preferred stock, if issued and
then converted) will increase Berkshire Hathaway s proportion of ownership but
would otherwise not affect any of the rights Berkshire Hathaway had without the
additional investment.
Why have you provided this information regarding Berkshire Rathaway
conversion rights?
On or shortly after the effective date of repeal ofPUHCA, Berkshire Hathaway
will exercise its conversion rights. This will create a technical change in control
ofMEHC. Although the conversion will occur prior to the close of this
transaction, MEHC and PacifiCorp wish to provide the Commission with this
notice of the conversion which is associated with the repeal ofPUHCA.
What regulatory approvals are required to allow Berkshire Rathaway to
convert its convertible preferred stock investment in MERC to common
Equity?
Approvals are required from FERC, the Nuclear Regulatory Commission, the
Iowa Utilities Board and the Illinois Commerce Commission. A filing will also
Goodman, Di - 20
PacifiCorp
REVISED 8/17/05
be required with the U.S. Department of JusticelFederal Trade Commission
pursuant to the Hart-Scott-Rodino Act. As of the date of this testimony, all filings
had been made except the Hart-Scott-Rodino. All required approvals are
expected before year-end 2005.
Will Berkshire Rathaway have any involvement in the day to day operations
of PacifiCorp, either before or after conversion?
, it will not. Prior to conversion, Mr. Scott and associated family interests had
the right to elect a majority of the members of the MEHC Board of Directors, and
Berkshire Hathaway had the right to elect 20% of the Board. Neither Mr. Scott
nor Berkshire Hathaway had any influence or involvement in the day-to-day
operations of the business units ofMEHC. That is not expected to change when
Berkshire Hathaway is able to elect a majority of the Board.
After the conversion, will MEHC (or PacifiCorp if this proposed transaction
is approved) be required to borrow funds from Berkshire Rathaway?
Neither MEHC nor PacifiCorp is or will be required to borrow from Berkshire
Hathaway. However, MEHC may choose to request debt or equity funds from
Berkshire Hathaway, for example, ifit pursues additional acquisitions.
As a general rule, subsidiaries ofMEHC (including PacifiCorp if this
proposed transaction is approved) are expected to operate autonomously from
MEHC and Berkshire Hathaway. This includes arranging their own financing and
being responsible for maintaining and/or improving their credit standing.
Conclusion
Does this conclude your direct testimony?
Yes, it does.
Goodman, Di - 21
PacifiCorp
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(' ExhibitNo. 11
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TiLlItES COHHJSSICWitness: Patrick J. Goodman
f'7't\-.:.J
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ACIFICORP
Exhibit Accompanying Direct Testimony of Patrick . Goodman
MEH C Form 10-
July 2005
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-
Annual Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2004
Commission File No. 0-25551
MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)
Iowa
(State or other jurisdiction of
Incorporation or organization)
94-2213782
(I.R.S. Employer
Identification No.
666 Grand Avenue, Des Moines, IA
(Address of principal executive offices)
50309
(Zip Code)
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: Nt A
Securities registered pursuant to Section 12(g) of the Act: Nt A
, """"'-'VII'Exhibit No. II, page) of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15( d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and
will not be contained, to the best of each of the registrants' knowledge , in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Fonn 10-K.
Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Act).Yes No
All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of
investors. As of January 31, 2005, 9,081 087 shares of common stock were outstanding.
Item 1.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7 A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item IS.
Signatures
Exhibit Index
TABLE OF CONTENTS
PART I
Business
Properties
Legal Proceedings
Submission of Matters to a Vote of Security Holders
PART II
Market for Registrant's Common Equity and Related Stockholder Matters
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Infonnation
PART III
Directors and Executive Officers of the Registrant
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
Certain Relationships and Related Transactions
Principal Accountant Fees and Services
PART IV
Exhibits and Financial Statement Schedules
n:\\;III~UII-' Exhibit No. 11, page 2 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
101
101
101
102
104
108
109
110
111
116
118
PacifiCorp
Exhibit No. II , page 3 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Disclosure Regarding Forward-Looking Statements
This report 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 Refonn Act of 1995. You can typically identify
forward-looking statements by the use of forward-looking words, such as "may,
" "
will
" "
could," "project,
" "
believe
anticipate,
" "
expect
" "
estimate
" "
continue,
" "
potential
" "
plan,
" "
forecast," and similar terms. These statements represent
plans, expectations and beliefs and are subject to risks, uncertainties and other factors. Many of these factors are outside the
Company s control and could cause actual results to differ materially from such forward-looking statements. These factors
include, among others:
general economic and business conditions in the jurisdictions in which its facilities are located;
the financial condition and creditworthiness of our significant customers and suppliers;
governmental, statutory, regulatory or administrative initiatives or ratemaking actions affecting the Company or
the electric or gas utility, pipeline or power generation industries;
weather effects on sales and revenue;
general industry trends;
increased competition in the power generation, electric and gas utility or pipeline industries;
fuel and power costs and availability;
continued availability of accessible gas reserves;
changes in business strategy, development plans or customer or vendor relationships;
. availability, tenD and deployment of capital;
availability of qualified personnel;
unscheduled outages or repairs;
risks relating to nuclear generation;
financial or regulatory accounting principles or policies imposed by the Public Company Accounting Oversight
Board, the Financial Accounting Standards Board ("F ASB"), the Securities and Exchange Commission ("SEC"
and similar entities with regulatory oversight;
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 SEC filings or in other
publicly disseminated written documents.
MidAmerican Energy Holdings Company undertakes no obligation to publicly update or revise any forward-looking
statements, whether as a result of new infonnation, future events or otherwise. The foregoing review of factors should not be
construed as exclusive.
PacifiCorp
Exhibit No. 11, page 4 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
PART I
Item 1.Business.
General
MidAmerican Energy Holdings Company ("MEHC") and its subsidiaries (together with MEHC, the "Company ) are
organized and managed on seven distinct platforms: MidAmerican Energy Company ("MidAmerican Energy ), Kern River
Gas Transmission Company ("Kern River ), Northern Natural Gas Company ("Northern Natural Gas ), CE Electric UK
Funding ("CE Electric UK") (which includes Northern Electric Distribution Limited ("Northern Electric ) and Yorkshire
Electricity Distribution pIc ("Yorkshire Electricity")), CalEnergy Generation-Foreign (the subsidiaries owning the Upper
Mahiao, Malitbog and Mahanagdong projects (collectively, the "Leyte Projects ) and the Casecnan project), CalEnergy
Generation-Domestic (the subsidiaries owning interests in independent power projects in the United States), and
HomeServices of America, Inc. (collectively with its subsidiaries
, "
HomeServices ). Refer to Note 23 of Notes
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" of this Form 10-K for
additional segment information regarding the Company s platforms. Through these platforms, the Company owns and
operates a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the
United States, two electricity distribution companies in the United Kingdom, a diversified portfolio of domestic and
international independent power projects and the second largest residential real estate brokerage firm in the United States.
MEHC's energy subsidiaries generate, transmit, store, distribute and supply energy. MEHC's electric and natural gas utility
subsidiaries currently serve approximately 4.4 million electricity customers and approximately 680 000 natural gas
customers. Its natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18 300
miles of pipeline in operation and peak delivery capacity of 6.4 billion cubic feet of natural gas per day. The Company has
interests in 6 777 net owned megawatts of power generation facilities in operation and under construction, including 5,203
net owned megawatts in facilities that are part of the regulated return asset base of its electric utility business and 1 574 net
owned megawatts in non-utility power generation facilities. Substantially all of the non-utility power generation facilities
have long-term contracts for the sale of energy and/or capacity from the facilities.
On March 14, 2000, MEHC and an investor group comprising Berkshire Hathaway Inc. ("Berkshire Hathaway ), Walter
Scott, Jr., a director of MEHC, David L. Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel
President and Chief Operating Officer of MEHC, closed on a definitive agreement and plan of merger whereby the investor
group, together with certain of Mr. Scott's family members and family trusts and corporations, acquired all of the outstanding
common stock ofMEHC (the "Teton Transaction
The principal executive offices of MEHC are located at 666 Grand Avenue, Des Moines, Iowa 50309 and its telephone
number is [phone]. MEHC initially incorporated in 1971 under the laws of the State of Delaware and reincorporated
in 1999 in Iowa, at which time it changed its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings
Company.
In this Annual Report, references to "S. dollars
" "
dollars
" "
$" or "cents" are to the currency of the United States
references to "pounds sterling,
" "" "
sterling,
" "
pence" or "" are to the currency of the United Kingdom and references to
pesos" are to the currency of the Philippines. References to kW means kilowatts, MW means megawatts, GW means
gigawatts, kWh means kilowatt hours, MWh means megawatt hours, GWh means gigawatt hours, kV means kilovolts, mmcf
means million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic feet and Dth means decatherms or one
million British thermal units.
Exhibit No. I I , page 5 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
MidAmerican Energy
Business
MidAmerican Energy, an indirect wholly-owned subsidiary of MEHC, owns a public utility headquartered in Iowa with $5.
billion of assets as of December 31, 2004, and operating revenues for 2004 totaling $2.7 billion. MidAmerican Energy is
principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing,
selling and transporting natural gas. MidAmerican Energy distributes electricity at retail in Council Bluffs, Des Moines, Fort
Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island,
Moline and East Moline, Illinois); and a number of adjacent communities and areas. It also distributes natural gas at retail in
Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; Sioux Falls, South
Dakota; and a number of adjacent communities and areas. Additionally, MidAmerican Energy transports natural gas through
its distribution system for a number of end-use customers who have independently secured their supply of natural gas. As of
December 31 , 2004, MidAmerican Energy had approximately 698 000 regulated retail electric customers and 680 000
regulated retail and transportation natural gas customers.
In addition to retail sales and natural gas transportation, MidAmerican Energy sells electric energy and natural gas to other
utilities, marketers and municipalities. These sales are referred to as wholesale sales.
MidAmerican Energy s regulated electric and gas operations are conducted under franchises, certificates, pennits and
licenses obtained from state and local authorities. The franchises, with various expiration dates, are typically for 25-year
tenDS .
MidAmerican Energy has a diverse customer base consisting of residential, agricultural, and a variety of commercial and
industrial customer groups. Among the primary industries served by MidAmerican Energy are those that are concerned with
food products, the manufacturing, processing and fabrication of primary metals, real estate, fann and other non-electrical
machinery, and cement and gypsum products.
MidAmerican Energy also conducts a number of nonregulated business activities.
For the year ended December 31 , 2004, MidAmerican Energy derived 53% of its gross operating revenues from its regulated
electric business, 37% from its regulated gas business and 10% from its nonregulated business activities. For.2003 and 2002
the corresponding percentages were 54% electric, 36% gas and 10% nonregulated; and 61 % electric, 31 % gas and 8%
nonregulated, respectively.
Electric Operations
For the year ended December 31 , 2004, regulated electric sales by MidAmerican Energy by customer class were as follows:
20% were to residential customers 14% were to small general service customers, 27% were to large general service
customers, 5% were to other customers, and 34% were wholesale sales. For the year ended December 31 , 2004, regulated
electric sales by MidAmericanEnergy by jurisdiction were as follows: 89% to Iowa, 10% to Illinois and 1 % to South Dakota.
The annual hourly peak demand on MidAmerican Energy s electric system usually o~curs as a result of air conditioning use
during the cooling season. In August 2003, MidAmerican Energy reached a record hourly peak demand of 3 935 MW. For
2004, MidAmerican Energy recorded an hourly peak demand of 3 894 MW on July 20.
PacifiCorp
Exhibit No. II, page 6 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
The following table sets out certain information concerning MidAmerican Energy s power generation facilities based upon
summer 2004 accreditation and expected accredited generating capacity of projects recently completed or under construction:
Facility
Net
Capacity Net MW
eratin ect (1)Owned (2)Fuel Location eration
Steam Electric Generating Facilities:
Council Bluffs Energy Center 'Units 1 & 2 133 133 Coal Iowa 1954, 1958
Council Bluffs Energy Center Unit 3 690 546 Coal Iowa 1978
Louisa Generation Station 700 616 Coal Iowa 1983
Neal Generation Station Units 1 & 2 435 435 Coal Iowa 1964, 1972
Neal Generation Station Unit 3 515 371 Coal Iowa 1975
Neal Generation Station Unit 4 644 261 Coal Iowa 1979
Ottumwa Generation Station 715 372 Coal Iowa 1981
Riverside Generation Station --ill --ill Coal Iowa 1925-
Total steam electric generating facilities 967 869
Other Facilities:
Combustion Turbines (3)116 116 Gas/Oil Iowa 1969-2003
Quad Cities Generating Station 748 437 Nuclear Illinois 1974
Portable Power Modules Oil Iowa 2000
Moline Water Power --1.--1.Hydro Illinois 1970
Total other facilities 923 612
Total accredited generating capacity 890 4.481
Pro1ects Recently Completed or Under Construction:
Greater Des Moines Energy Center (3)190 190 Gas Iowa 2004
Council Bluffs Energy Center Unit 4 790 479 Coal Iowa 2007
Northern Iowa Wind Power Wind Iowa 2005
Total projects recently completed or
under construction 033 722
(1)MidAmerican Energy operates all such power generation facilities other than Quad Cities Generating Station and
Ottumwa Generation Station.
(2)Represents accredited net generating capability from the summer of 2004 and the expected accredited generating
capacity of projects recently completed or under construction. Actual MW may vary depending on operating
conditions and plant design for operating projects. Net MW Owned indicates ownership of accredited capacity for
the summer of 2004 as approved by the Mid-Continent Area Power Pool ("MAPP"
(3)The Greater Des Moines Energy Center project was completed in two phases. Commercial operation in the simple
cycle mode began in May 2003, resulting in 327 MW (included in "Other Facilities Combustion Turbines
above) of accredited capacity throughout 2004. Commercial operation of the combined cycle mode began in
December 2004 and additional accredited capacity is expected to be 190 MW.
MidAmerican Energy s total accredited net generating capability in the summer of 2004 was 4 897 MW. Accredited net
generating capability represents the amount of generation available to meet the requirements on MidAmerican Energy
system and consists of MidAmerican Energy-owned generation of 4 481 MW and the net amount of capacity purchases and
sales of 416 MW. The actual amount of generation capacity available at any time may be less than the accredited capability
due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service
for inspection, maintenance, refueling, modifications or other reasons.
MidAmerican Energy anticipates a continuing increase in demand for electricity from its regulated customers. To meet
anticipated demand and ensure adequate electric generation in its service territory, MidAmerican Energy recently completed
, a"""""UIJ-IExhibit No. 11, page 7 of 130
CASE NO. PAC-O5-Witness: Patrick J. Goodman
its combined cycle combustion turbine project and is currently constructing the 790 MW (expected accreditation) super-
critical-temperature, coal-fired Council Bluffs Energy ,Center Unit No.4 ("CBEC Unit 4") and a 310 MW (nameplate rating)
wind power project in Iowa. The projects will provide service to regulated retail electricity customers. MidAmerican Energy
has obtained regulatory approval to include the Iowa portion of the actual costs of the generation projects in its Iowa rate base
as long as actual costs do not exceed the agreed caps that MidAmerican Energy has deemed to be reasonable. If the caps are
exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the caps, subject to
regulatory review. Wholesale sales may also be made from the projects to the extent the power is not immediately needed for
regulated retail service. MidAmerican Energy expects to invest approximately $1.1 billion in the CBEC Unit 4 and wind
generation projects, of which $350.4 million has been invested through December 31 2004.
MidAmerican Energy recently completed work on its Greater Des Moines Energy Center, a natural gas-fired, combined cycle
plant located near Pleasant Hill, Iowa. Construction of the plant was completed in two phases. Commer.cial' operation of the
simple cycle mode began on May 5, 2003, and continued through most of 2004, providing 327 MW of accredited capacity in
the summer of 2004. Commercial operation of the combined cycle mode began on December 16, 2004. The additional
accredited capacity from the completion of the second phase is expected to be 190 MW. MidAmerican Energy expects the
total cost of the Greater Des Moines Energy Center to be under the $357.0 million cost cap established by the Iowa Utilities
Board ("IUB"
MidAmerican Energy is currently constructing the CBEC Unit 4, a 790 MW (based on expected accreditation) super-critical-
temperature, low-sulfur coal-fired plant. MidAmerican Energy will operate the plant and hold an undivided ownership
interest as a tenant in common with the other owners of the plant. MidAmerican Energy s ownership interest is 60.67%
equating to 479 MW of output. MidAmerican Energy expects its share of the estimated cost of the project, including
transmission facilities, to be approximately $737.0 million, excluding allowance for funds used during construction.
Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large
base-load plants in Iowa. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy
Development, Inc. ("Mitsui") for the engineering, procurement and construction of the plant. On September 9, 2003,
MidAmericanEnergy began construction of the plant, which it expects to be completed in the summer of 2007. On
December 29, 2004 MidAmerican Energy received an order from the IUB approving construction of the associated
transmission facilities and is proceeding with construction.
The second electric generating project currently under construction consists of wind power facilities located at two sites in
north central Iowa totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for wind
power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The current projected
accredited capacity for these wind power facilities is approximately 53 MW. MidAmerican Energy will own and operate
these facilities, which are expected to cost approximately $323.0 million, including transmission facilities ,and excluding the
allowance for funds used during construction. As of December 31 , 2004, wind turbines totaling 160.5 MW at one of the sites
were completed and in service. Completion of the remaining turbines is expected by the middle of 2005. On January 31
2005, the IUB approved ratemaking principles related to expanding the wind power project. An additional 50 MW of
capacity, based on the nameplate rating, is expected to be constructed at the sites in 2005 at an estimated cost of
$63.0 million.
MidAmerican Energy is interconnected with Iowa utilities and utilities in neighboring states and is party to an electric
generation and transmission pooling agreement administered by the MAPP. The MAPP is a voluntary association of electric
utilities doing business in Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba
and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory
agencies and independent power producers. The MAPP facilitates operation of the transmission system, is responsible for the
safety and reliability of the bulk electric system, and has responsibility for administration of the. MAPP's Open-Access
Transmission Tariff.
Each MAPP participant is required to maintain for emergency purposes a net generating capability reserve of at least 15%
above its system peak demand. MidAmerican Energy s reserve margin at peak demand for 2004 was approximately 26%.
MidAmerican Energy believes it has adequate electric capacity reserve through 2010, including capacity provided by the
generating projects discussed above. However, significantly higher-than-normal temperatures during the cooling season
could cause MidAmerican Energy s reserve to fall below the 15% minimum. If MidAmerican Energy fails to maintain the
appropriate reserve, significant penalties could be contractually imposed by the MAPP.
Paci fi Corp
Exhibit No. II, page 8 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
MidAmerican Energy s transmission system connects its generating facilities with distribution substations and interconnects
with 14 other transmission providers in Iowa and five adjacent states. Under normal operating conditions, MidAmerican
Energy s transmission s.ystem has adequate capacity to deliver energy to MidAmerican Energy s distribution system and to
export and import energy with other interconnected systems.
Gas Operations
MidAmerican Energy is engaged in the procurement, transportation, storage and distribution of natural gas for customers in
the midwest region of the United States. MidAmerican Energy purchases natural gas from various suppliers, transports it
from the production area to MidAmerican Energy's service territory under contracts with interstate pipelines, stores it in
various storage facilities to manage fluctuations in system demand and seasonal pricing, and distributes it to customers
through MidAmerican Energy s distribution system.
MidAmerican Energy sells natural gas and transportation services to end-use, or retail, customers and natural gas to other
utilities, marketers and municipalities. MidAmerican Energy also transports through its distribution system natural gas
purchased independently by a number of end-use customers. During 2004, 45% of total gas delivered through MidAmerican
Energy s system for end-use customers was under gas transportation services.
For the year ended December 31, 2004, regulated gas sales, excluding transportation throughput, by MidAmerican Energy by
customer class were as follows: 40% were to residential customers, 20% were to small general service customers, 2% were to
large general service customers and 38% were wholesale sales. For the year ended December 31, 2004, regulated gas sales,
excluding transportation throughput, by MidAmerican Energy by jurisdiction were as follows: 78% to Iowa, 11 % to South
Dakota, 10% to Illinois and 1% to Nebraska.
There are seasonal variations in MidAmerican Energy s gas business that are principally due to the use of natural gas for
heating. In general, 45-55% of MidAmerican Energy s regulated gas revenue is reported in the months of January, February,
March and December.
MidAmerican Energy purchases gas supplies from producers and third party marketers. To ensure system reliability, a
geographically diverse supply portfolio with varying terms and contract conditions is utilized for the gas supplies.
MidAmerican Energy attempts to optimize the value of its regulated assets by engaging in wholesale sales transactions. IUB
and South Dakota Public Utilities Commission ("SDPUC") rulings have allowed MidAmerican Energy to retain 50% of the
respective jurisdictional margins earned on wholesale sales of natural gas, with the remaining 50% being returned to
customers through the purchased gas adjustment clause discussed below.
MidAmerican Energy has rights to firm pipeline capacity to transport gas to its service territory through direct interconnects
to the pipeline systems of Northern Natural Gas (an affiliate company), Natural Gas Pipeline Company. of America
NGPL"), Northern Border Pipeline Company ("Northern Border ) and ANR Pipeline Company ("ANR"). At times, the
capacity available through MidAmerican Energy s finn capacity portfolio may exceed the demand on MidAmerican
Energy s distribution system. Finn capacity in excess of MidAmerican Energy s system needs can be resold to other
companies to achieve optimum use of the available capacity. Past IUB and SDPUC rulings have allowed MidAmerican
Energy to retain 30% of the, respective jurisdictional margins earned on the resold capacity, with the remaining 70% being
returned to customers through the purchased gas adjustment clause.
MidAmerican Energy is allowed to recover its cost of gas from all of its regulated gas customers through purchased gas
adjustment clauses. Accordingly, MidAmerican Energy s regulated gas customers retain the risk associated with the market
price of gas. MidAmerican Energy uses several strategies to reduce the market price risk for its gas customers, including the
use of storage gas and peak shaving facilities, sharing arrangements to share savings and costs with customers and short-term
and long-term financial and physical gas purchase agreements.
MidAmerican Energy utilizes leased gas storage to meet peak day requirements and to manage the daily changes in demand
due to changes in weather. The storage gas is typically replaced during the summer months when the demand for gas has
historically been lower than during the heating season. In addition, MidAmerican En~rgy also utilizes three liquefied natural
gas ("LNG") plants and two propane-air plants to meet peak day demands in the winter. The storage and peak shaving
facilities reduce MidAmerican Energy s dependence on gas purchases during the volatile winter heating season.
PacifiCorp
Exhibit No. 11, page 9 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
In 1995, the IUB gave initial approval of MidAmerican Energy s Incentive Gas Supply Procurement Program. In November
2004, the IUa extended the program through October 31 , 2006. Under the program, as amended, MidAmerican Energy is
required to file with the IUB every six months a comparison of its gas procurement costs to an index-based reference price. If
MidAmerican Energy s cost of gas for the period is less or greater than an established tolerance band around the reference
price, then MidAmerican Energy shares a portion of the savings or costs with customers. A similar program is currently in
effect in South Dakota through October 31 , 2005. Since the implementation of the program, MidAmerican Energy has
successfully achieved and shared savings with its natural gas customers.
On February 2, 1996, MidAmerican Energy had its highest peak-day delivery of 1 143,026 Dth. This peak-day delivery
consisted of 88% traditional sales service and 12% transportation service of customer-owned gas. As of January 31, 2005
MidAmericanEnergy s 2004/2005 winter heating season peak-day delivery of 997 058 Dth was reached on January 14
2005. This peak-day delivery included 76% traditional sales service and 24% transportation service.
Kern River
Business
Kern River, an indirect wholly-owned subsidiary of MEHC, owns an interstate natural gas transportation pipeline system
comprising 1 679 miles of pipeline, with an approximate design capacity of 1 755 575 Dth per day, extending from supply
areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. In 2003, a 717 mile expansion project
2003 Expansion Project"), which was placed in service on May 1 , 2003, increased the design capacity of Kern River
pipeline system by 885 575 Dth per day to its current 1 755 575 Dth per day.
Kern River s pipeline consists of two sections: the mainline section and the common facilities. Kern River owns the entire
mainline section, which extends from the pipeline s point of origination near Opal, Wyoming through the Central Rocky
Mountains area into Daggett, California. The mainline section consists of the original 682 miles of 36-inch pipeline
, '
628
miles of 36-inch loop pipeline related to the 2003 Expansion Project and 68 miles of various laterals that connect to the
mainline.
The common facilities consist of a 219-mile section of original pipeline that extends from the point of interconnection with
the mainline in Daggett to Bakersfield, California and an additional 82 miles related to the 2003 Expansion Project. The
common facilities are jointly owned by Kern River (approximately 76.8% as of December 31, 2004) and Mojave Pipeline
Company ("Mojave ), a wholly owned subsidiary of El Paso Corporation ("EI Paso ) (approximately 23.2% as of
December 31, 2004), as tenants-in-common. Kern River s ownership percentage in the common facilities will increase or
decrease pursuant to subsequently completed expansions by the respective joint owners. Kern River has exclusive rights to
approximately 1 570 500 Dth per day of the common facilities' capacity, and Mojave has exclusive rights to 400 000 Dth per
day of capacity. Operation and maintenance of the common facilities are the responsibility of Mojave Pipeline Operating
Company, an affiliate of Mojave.
Transportation Service Agreements
As of December 31 , 2004, Kern River had under contract 1 661 575 Dth per day of capacity under long-term firm gas
transportation service agreements under which the pipeline receives natural gas on behalf of shippers at designated receipt
points, transports the gas on a firm basis up to each shipper s maximum daily quantity and delivers thermally equivalent
quantities of gas at designated delivery points. Each shipper pays Kern River the aggregate amount specified. in its long-term
firm gas transportation service agreement and Kern River s tariff, with such amount consisting primarily of a fixed monthly
reservation fee based on each shipper s maximum daily quantity and a commodity charge based on the actUal amount of gastransported.
With respect to Kern River s mainline facilities in existence prior to the 2003 Expansion Project, at December 31 2004, Kern
River had 27 long-term firm gas transportation service agreements with 16 shippers, for a total of 848,949 Dth per day of
capacity. All but one of these long-term firm gas transportation service agreements expires on or before April 30, 2017.
Several of these shippers are major oil and gas companies, or affiliates of such companies. These shippers also include
electric generating companies, energy marketing and trading companies, and a gas distribution utility which provides services
in Nevada and California.
t"aC1J1Lorp
Exhibit No. 11, page 10 of 130
CASE NO. P AC-05-
Witness: Patrick J. Goodman
With respect to Kern River s 2003 Expansion Project, at December 3 I, 2004, Kern River had 19 long-term firm gas
transportation service agreements with 16 shippers, for a total of 8 I 2 626 Dth per day of capacity from the pipeline s point of
origination near Opal, Wyoming to delivery points primarily in California. Approximately 83% of the 2003 Expansion
Project's capacity is contracted for 15 years, with 14 of the long-term firm gas transportation service agreements expiring on
April 30, 2018. The remaining 17% of capacity is contracted for 10 years, with five long-term firm gas transportation service
agreements expiring on April 30, 2013. Over 95% of the 2003 Expansion Project's capacity has primary delivery points in
California, with the flexibility to access secondary delivery points in Nevada and Utah.
Northern Natural Gas
Business
Northern Natural Gas, an indirect wholly-owned subsidiary of MEHC, owns one of the largest interstate natural gas pipeline
systems in the United States. It reaches from Texas to Michigan s Upper Peninsula and is engaged in the transmission and
storage of natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users
and other end users. Northern Natural Gas operates approximately 16,500 miles of natural gas pipelines with a design
capacity of 4.4 Bcf per day. Based on a review of relevant industry data, the Northern Natural Gas system is believed to be
the largest single pipeline in the United States as measured by pipeline miles and the ninth largest as measured by throughput.
Northern Natural Gas' revenue is derived from the interstate transportation and storage of natural gas for third parties. Except
for small quantities of natural gas owned for system operations, Northern Natural Gas does not own the natural gas that is
transported through its system. Northern Natural Gas' transportation and storage operations are subject to a Federal Energy
Regulatory Commission ("FERC") regulated tariff that is designed to allow it an opportunity to recover its costs together
with a regulated return on equity.
Northern Natural Gas' system consists of two distinct but operationally integrated markets. Its traditional end-use and
distribution market area is at the northern end of the system, including delivery points in Michigan, Illinois, Iowa, Minnesota
Nebraska, Wisconsin and South Dakota, which Northern Natural Gas refers to as the Market Area, and the natural gas supply
and service area is at the southern end of the system, including Kansas, Oklahoma, Texas and New Mexico, which Northern
Natural Gas refers to as the Field Area. Northern Natural Gas' Field Area is interconnected with many interstate and
intrastate pipelines in the national grid system. A majority of Northern Natural Gas' capacity in both the Market Area and the
Field Area is dedicated to Market Area customers under long-term firm transportation contracts. Approximately 70% of
Northern Natural Gas' firm transportation contracts extend beyond 2007.
Northern Natural Gas' pipeline system transports natural gas primarily to end-user and local distribution markets in the
Market Area. Customers consist of local distribution companies ("LDCs ), municipalities, other pipeline companies, gas
marketers and end-users. While eight large LDCs account for the majority of Market Area volumes, Northern Natural Gas
also serves numerous small communities through these large LDCs as well as municipalities or smaller LDCs and directly
serves several large end-users. In 2004, approximately 85% of Northern Natural Gas' revenue was from capacity charges
under firm transportation and storage contracts and approximately 80% of that revenue was from LDCs. In 2004
approximately 71% of Northern Natural Gas' revenue was generated from Market Area customer contracts.
The Field Area of Northern Natural Gas' system provides access to natural gas supply from key production areas including
the Hugoton, Permian and Anadarko Basins. In each of these areas, Northern Natural Gas has numerous interconnecting
receipt and delivery points, with volumes received in the Field Area consisting of both directly connected supply and
volumes from interconnections with other pipeline systems. In addition, Northern Natural Gas has the ability to aggregate
processable natural gas for deliveries to various gas processing facilities.
In the Field Area, customers holding transportation capacity consist of LDCs, marketers, producers, and end-users. The
majority of Northern Natural Gas' Field Area firm transportation is provided to Northern Natural Gas' Market Area firm
customers under long-term firm transportation contracts with such volumes supplemented by volumes transported on
interruptible basis or pursuant to short-term firm ,contracts. In 2004, approximately 19% of Northern Natural Gas' revenue
was generated from Field Area customer transportation contracts.
Northern Natural Gas' storage services are provided through the operation of one underground storage field in Iowa, two
underground storage facilities in Kansas and one LNG storage peaking unit each at Gamer, Iowa and Wrenshall, Minnesota.
The three underground natural gas storage facilities and Northern Natural Gas' two LNG storage peaking units have a total
working storage capacity of approximately 59 Bcf and over 1.3 Bcf per day of peak day deliverability.These storage
PacifiCorp
Exhibit No. II , page II of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
facilities provide Northern Natural Gas with operational flexibility for the daily balancing of its system and providing
services to customers for meeting their year-round loadswing requirements. In 2004, approximately 10% of Northern Natural
Gas' revenue was generated from storage services;
Northern Natural Gas' system is characterized by significant seasonal swings in demand, which provide opportunities to
deliver high value-added services. Because of its location and multiple interconnections with other interstate and intrastate
pipelines, Northern Natural Gas is able to access natural gas from both traditional production areas, such as the Hugoton
Permian and Anadarko Basins, as well as growing supply areas such as the Rocky Mountains through Trailblazer Pipeline
Company, Pony Express Pipeline and Colorado Interstate Gas Pipeline Company ("Colorado Interstate ), and from Canadian
production areas through Northern Border, Great Lakes Gas Transmission Limited Partnership ("Great Lakes ) and Viking
Gas Transmission Company ("Viking ). As a result of Northern Natural Gas' geographic location in the middle of the United
States and its many interconnections with other pipelines, Northern Natural Gas augments its stead~ end-user and LDC
revenue by taking advantage of opportunities to provide intennediate transportation through pipeline interconnections for
customers in other markets including Chicago, Illinois, other parts of the Midwest and Texas.
Kern River and Northern Natural Gas Competition
Each of Kern River and Northern Natural Gas has several customers who account for greater than 10% of its revenue. The
loss of any one or more of these, if not replaced, could have a material adverse effect on Kern River s and Northern Natural
Gas' respective businesses.
Pipelines compete on the basis of cost (including both transportation costs and the relative costs of the natural gas they
transport), flexibility, reliability of service and overall customer service. Industrial end-users often have the ability to choose
from alternative fuel sources in addition to natural gas, such as fuel oil and coal. Natural gas competes with other fonDS of
energy, including electricity, coal and fuel oil, primarily on the basis of price. Legislation and governmental regulations, the
weather, the futures market, production costs, and other factors beyond the control of Kern River and Northern Natural Gasinfluence the price of natural gas.
Kern River competes with various interstate pipelines and its shippers in serving the southern California, Las Vegas, Nevada
and Salt Lake City, Utah market areas, in order to market any unutilized or unsubscribed capacity. Kern River provides its
customers with supply diversity through pipeline interconnections with Northwest Pipeline, Colorado Interstate, Overland
Trail Pipeline, and Questar Pipeline. These interconnections, in addition to the direct interconnections to natural gas
processing facilities, allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming,
Utah and the Western Canadian Sedimentary Basin.
Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin into the intrastate
California market, which enables its customers to avoid paying a "rate stack" (i., additional transportation costs attributable
to the movement from one or more interstate pipeline systems to an intrastate system within California). Kern River believes
that its rate structure and access to upstream pipelines/storage facilities and to economic Rocky Mountain gas reserves
increases its competitiveness and attractiveness to end-users. Kern River believes it is advantaged relative to other competing
interstate pipelines because itS relatively new pipeline can be expanded at comparatively lower costs and will require
significantly less capital expenditure to comply with the Pipeline Safety Improvement Act of 2002 ("PSIA") than other
systems. Kern River s levelized rate structures under expansion rates and settlement r~tes also provide customers with greater
rate certainty. Kern River s market position depends to a significant degree, however, on the availability and favorable price
of gas produced in the Rocky Mountain area, an area that in recent years has attracted considerable expansion of pipeline
capacity serving markets other than California and Nevada. In addition, Kern River s 2003 Expansion Project relies
substantially on long-tenD transportation service agreements with several electric generation companies, who face significant
competitive and financial pressures due to, among other things, the financial stress of energy markets and apparent over-
building of electric generation capacity in California and other markets.
Northern Natural Gas has been able to provide cost competitive service because of its access to a variety of relatively low
cost gas supply basins, its cost control measures and its relatively high load factor throughput, which lowers the cost per unit
of transportation. Although Northern Natural Gas has experienced pipeline system bypass affecting a small percentage of its
market, to date Northern Natural Gas has been able to more than offset any load lost to bypass in the Northern Natural Gas
Market Area through expansion projects.
t'aCIttLorp
Exhibit No. 11 , page 12 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
Major competitors in the Northern Natural Gas Market Area include ANR, Northern Border and NGPL. Other competitors
include Great Lakes and Viking. In the Field Area, Northern Natural Gas competes with a large number of other competitors.
Particularly in the Field Area, a significant amount of Northern Natural Gas' capacity is used on an interruptible or short-term
basis. In summer months, Northern Natural Gas' Market Area customers often release significant amounts of their unused
firm capacity to other shippers, which released capacity competes with Northern Natural Gas' short-tenD or interruptible
services.
Although Northern Natural Gas will need to aggressively compete to retain and build load, Northern Natural Gas believes
that current and anticipated changes in its competitive environment have created opportunities to serve existing customers
more efficiently and to meet 'certain growing supply needs. While LDCs ' peak day growth is driven by population growth
and alternative fuel replacement, new off-peak demand growth is being driven primarily by power and ethanol plant
expansion. Off-peak demand growth is important to Northern Natural Gas as this demand can generally be satisfied with little
or no requirement for the construction of new facilities. Northern Natural Gas has been successful in competing for a
significant amount of the increased demand related to the construction of new power and ethanol plants. Over the last five
years, Northern Na~al Gas has contracted approximately 281 mmcf per day of finD volume on its system from such new
facilities, of which approximately 262 mmcfper day is currently in service and approximately 19 mmcfper day is scheduled
to begin service in 2005.
Pipeline Development Project
MEHC and a subsidiary, Alaska Gas Transmission Company, LLC ("Alaska Gas ), are two of several other parties
including existing producers of oil from Alaska s North Slope, involved in a competitive selection process to develop and
construct a proposed 745-mile natural gas pipeline which would be subject to FERC regulation and would extend from the
North Slope area near Prudhoe Bay, Alaska south to the Alaska-Yukon border near Beaver Creek, Alaska. The State of
Alaska is expected to select a 'preferred party for the project by the end of the second quarter of 2005. If either MEHC or
Alaska Gas are selected, further approvals, including from FERC, would be required and significant development and
construction risk would remain with respect to the pipeline project.
CE Electric UK
Business
CE Electric UK, an indirect wholly-owned subsidiary ofMEHC, owns, primarily, two companies that distribute electricity in
the United Kingdom, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity, collectively,
are the third largest electricity distribution business in the United 'Kingdom, serving more than 3.7 million customers in an
area of approximately 10,000 square miles.
Electricity Distribution
Northern Electric s and Yorkshire Electricity's operations consist primarily of the distribution of electricity in the United
Kingdom. Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and
distribute it to their customers' premises using their network of transfonners, switchgear and cables. Substantially all of the
end users in Northern Electric s and Yorkshire Electricity's distribution service areas are connected to the Northern Electric
and Yorkshire Electricity networks and electricity can only be delivered through their distribution system, thus providing
Northern Electric and Yorkshire Electricity with distribution volume that is relatively stable from year to year. Northern
Electric and Yorkshire Electricity charge fees for the use of the distribution system to the suppliers of electricity. The
suppliers, which purchase electricity from generators and sell the electricity to end-user customers, use Northern Electric
and Y orkshireElectricity' s distribution networks pursuant to an industry standard "Use of System Agreement", which
Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective
distribution areas. One such supplier, Innogy Holdings pic ("Innogy ) and certain of its affiliates, represented approximately
47% of the total revenues of Northern Electric and Yorkshire Electricity in 2004. The fees that may be charged by Northern
Electric and Yorkshire Electricity for use of their distribution systems are controlled by a fonnula prescribed by the United
Kingdom s electricity regulatory body that limits increases (and may require decreases) based upon the rate of inflation in the
United Kingdom and other regulatory action.
PacifiCorp
Exhibit No. 11 , page 13 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
At December 31 , 2004, Northern Electric s and Yorkshire Electricity's electricity distribution network (excluding service
connections to consumers) on a combined basis included approximately 33 000 kilometers of overhead lines and
approximately 64 000 kilometers of underground cables. In addition to the circuits referred to above, at December 31 , 2004
Northern Electric s and Yorkshire Electricity's distribution facilities also included approximately 58 000 transfonners and
approximately 750 primary substations. Substantially all substations are owned, with the balance being leased from third
parties, most of which have remaining tenDS of at least 10 years.
Utility Services
Integrated Utility Services Limited, CE Electric UK's indirect wholly-owned subsidiary, is an engineering contracting
company whose main business is providing electrical connection services on behalf of Northern Electric s and Yorkshire
Electricity's distribution businesses and providing electrical infrastructUre contracting services to third parties.
Gas Exploration and Production
CalEnergy Gas (Holdings) Limited ("CE Gas ), CE Electric UK's indirect wholly-owned subsidiary, is a gas exploration and
production company that is focused on developing integrated upstream gas projects in Australia, the United Kingdom and
Poland. Its upstream gas business consists of exploration, development and production projects, resulting in the sale of gas tothird parties.
In Australia, CE Gas has construction and development projects in the Bass, Otway and Perth Basins. The Yolla construction
project in the Bass Basin is a gas and gas liquids project in which CE Gas holds a 20% interest. The project, operated by
Origin Energy of Australia, is nearing completion and includes an approximately 145 kilometer subsea pipeline across the
Bass Strait off southern Victoria. The Bass Project is expected to be fully operational in 2005. The gas from the project will
be sold to Origin Energy s retail affiliate, the liquefied petroleum gas will be sold to Elgas Limited, the largest marketer of
liquefied petroleum gas in AuStralia, and the condensate will be sold to The Shell Company of Australia Limited. Also iri the
Bass Basin, CE Gas holds a 23.5% interest in the Trefoil discovery. This gas and gas liquids discovery was drilled in late
2004 and the commercial development potential is currently under evaluation. The Otway project, in which CE Gas holds
6% interest, is operated by Woodside of Australia. This project received construction approval during 2004. Construction has
now commenced with first production expected in 2006. Further prospecting in the three Otway Basin exploration pennits in
which CE Gas holds a 6% interest continues to be investigated. CE Gas also has a one-third interest in pennit EP 437 in the
onshore northern Perth Basin. The pennitting process for this project was successfully completed in 2004.
In the United Kingdom, CE Gas continues to retain its 5% interest in the Victor Field, which is a gas field located in the
North Sea, and during 2004, successfully applied for, and was granted, a new exploration pennit in which CE Gas has
I 00% interest.
In Poland, CE Gas retains its development interest in the Polish Trough. CE Gas, together with its joint venture partners FX
Energy and the Polish Oil and Gas Company, has drilled the Zaniemysl #3 well in the Fences I Concession. This resulted in a
commercial gas discovery early in 2004 in which CE Gas holds a 24.5% interest. This discovery is currently being developed
and it is anticipated that the field will be on production in early 2006.
CalEnergy Generation-Foreign
Business
The CalEnergy Generation-Foreign platfonn consists of MEHC's indirect ownership of the Upper Mahiao, Mahanagdong
and Malitbog projects, which are geothennal power plants located on the island of Leyte in the Philippines, and the Casecnan
project, a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in
the Philippines. Each plant possesses an operating margin that allows for production in excess of the amount listed below.
Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters
under nonnal operating conditions.
PacifiCorp
Exhibit No. II, page 14 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
The following table sets out certain information concerning CalEnergy Generation-Foreign s non-utility power projects in
operation as of December 31 2004:
Facility
Net Power
Capacity Net MW Contract Purchaser!
Project(l)(MW)(Z)Owned(Z)Fuel Expiration Guarantor(J)
Upper Mahiao 119 119 Geo 2006 PNOC-EDCIROP
Mahanagdong 155 150 Geo 2007 PNOC-EDCIROP
Malitbog 216 216 Geo 2007 PNOC-EDCIROP
Casecnan (4)150 150 Hydro 2021 NINROP
Total International
Projects ill
(1)All projects are located in the Philippines, are governed by contracts which are mainly payable in U.S. dollars and
carry political risk insurance.
(2)Actual MW may vary depending on operating, geothermal reservoir and water flow conditions, as well as plant
design. Facility Net Capacity (MW) represents the contract capacity for the facility. Net MW Owned indicates
current legal ownership, but, in some cases, does not reflect the current allocation of distributions.
(3)Philippine National Oil Company-Energy Development Corporation ("PNOC-EDC"), Republic of the Philippines
ROP"), and National Irrigation Administration ("NIA"). NIA also pays CE Casecnan Water and Energy
Company, Inc. ("CE Casecnan ), an indirect subsidiary of MEHC, for the delivery of water and electricity by CE
Casecnan. Separate sovereign undertakings of the ROP support PNOC-EDC's and NIA's respective obligations for
each project.
(4)Net MW Owned of approximately 150 MW is subject to repurchase rights of up to 15% of the project by an initial
minority shareholder and a dispute with the other initial minority shareholder regarding an additional 15% of the
project. Refer to "Item 3. Legal Proceedings" of this Form 10-K for additional information.
The Upper Mahiao project is a 119 net MW geothermal power project owned and operated by CE Cebu Geothermal Power
Company, Inc. ("CE Cebu ), a Philippine corporation that is 00% indirectly owned by MEHC. On June 18, 2006, the end of
the ten-year cooperation period, the Upper Mahiao facility will be transferred toPNOC-EDC at no cost on an "as-" basis.
The Upper Mahiao project takes geothermal steam and fluid, provided by PNOC-EDC at no cost, and converts its thermal
energy into electrical energy which is sold to PNOC-EDC on a "take-or-pay" basis, which in turn sells the power to the
National Power Corporation C'NPC"), the government-owned and controlled corporation that is the primary supplier of
electricity in the Philippines, for distribution on the island of Cebu. PNOC-EDC pays CE Cebu a fee based on the plant
capacity. Pursuant to an amendment to the Upper Mahiao energy conversion agreement entered into on August 31, 2003, CE
Cebu and PNOC-EDC agreed that the plant capacity for purposes of the fee would equal the contractually specified level of
118.5 MW. PNOC-EDC also pays CE Cebu a fee based on the electricity actually delivered to PNOC-EDC (approximately
5% of total contract revenue). Payments under the Upper Mahiao agreement are denominated in U.S. dollars, or computed in
S. dollars and paid in pesos at the then-current exchange rate, except for the energy fee. PNOC-EDC's payment
requirements, and its other obligations under the Upper Mahiao agreement, are supported by the ROP through a performanceundertaking.
The Mahanagdong project is a 155 net MW geothermal power project owned and operated by CE Luzon Geothermal Power
Company, Inc. ("CE Luzon ), a Philippine corporation of which MEHC indirectly owns 100% of the common stock. Another
industrial company owns an approximate 3% preferred equity interest in the Mahanagdong project. The Mahanagdong
project sells 100% of its capacity to PNOC-EDC, which in turn sells the power to the NPC for distribution on the island ofLuzon.
~ a'-JlI'-Vlp
Exhibit No. 11, page 15 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
The terms of the Mahanagdong energy conversion agreement are substantially similar to those of the Upper Mahiao
agreement. On July 25, 2007, the end of the ten year cooperation period, the Mahanagdong facility will be transferred
PNOC-EDC at no cost on an "as-" basis. PNOC-EDC pays CE Luzon a fee based on the plant capacity. Pursuant to an
amendment to the Mahanagdong energy conversion agreement entered into on August 31 , 2003, CE Luzon and PNOC-EDC
agreed that the plant capacity would equal the contractually specified level, which declines from approximately 155 MW in
2004 to approximately 153 MW in the last year of the cooperation period. The capacity fees are approximately 970/0 of total
revenue at the contractually agreed capacity levels and the energy fees are approximately 3% of such total revenue. PNOC-
EDC's payment requirements, and its other obligations under the Mahanagdong agreement, are supported by the ROP
through a performance undertaking.
The Malitbog project is a 216 net MW geothermal project owned and operated by Visayas Geothermal Power Company
VGPC"), a Philippine general partnership that is indirectly wholly owned by MEHC. VGPC sells 100% of its capacity on
substantially the same basis as described above for the Upper Mahiao project to PNOC-EDC, which sells the power to theNPC for distribution on the islands of Cebu and Luzon.
The electrical energy produced by the facility is sold to PNOC-EDC on a "take-or-pay" basis. These capacity payments
equal 100% of total revenue. Pursuant to an amendment to the Malitbog energy conversion agreement entered into on
August 31, 2003, VGPC and PNOC-EDC agreed that the plant capacity would equal the contractually specified level of 216
MW. A substantial majority of the capacity payments are required to be made by PNOC-EDC in U.S. dollars. The portion of
capacity payments payable to PNOC-EDC in pesos is expected to vary over the term of the Malitbog project energy
conversion agreement from 10% ofVGPC's revenue in the early years of the cooperation period to 23% ofVGPC's revenue
at the end of the cooperation period. Payments made in pesos will generally be made to a peso-denominated account and will
be used to pay peso-denominated operation and maintenance expenses with respect to the Malitbog project and Philippine
withholding taxes, if any, on the Malitbog project's debt service. The ROP has entered into a performance undertaking,
which provides that all of PNOC-EDC's obligations pursuant to the Malitbog energy conversion agreement carry the full
faith and credit of, and are affirmed and guaranteed by, the ROP. The Malitbog energy conversion agreement ten year
cooperation period expires on July 25, 2007, at which time the facility will be transferred to PNOC-EDC at no cost on an "
" basis. '
The Casecnan project is a combined irrigation and hydroelectric power generation project. The Casecnan project consists
generally of diversion structures in the Casecnan and Taan rivers that capture and divert excess water in the Casecnan
watershed by means of concrete, in-stream diversion weirs and transfer that water through a transbasin tunnel of
approximately 23 kilometers. During the water transfer, the elevation differences between the two watersheds allows
electrical energy to be generated at an approximately ISO MW rated capacity power plant, which is located in an
underground powerhouse cavern at the end of the transbasin water tunnel. A tailrace discharge tunnel then delivers water to
the existing underutilized water storage reservoir at Pantabangan, providing additional water for irrigation and increasing the
potential electrical generation at two existing downstream hydroelectric facilities of NPC. Once in the reservoir at
Pantabangan, the water is under the control ofNIA.
CE Casecnan owns and operates the Casecnan project under the terms of the Project Agreement between CE Casecnan and
NIA, which was modified by a Supplemental Agreement between CE Casecnan and NIA effective on October IS, 2003 (the
Supplemental Agreement"
).
CE Casecnan will own and operate the project for a 20-year cooperation period which
commenced on December 11 , 2001 , the start of the project's commercial operations, ~fter which ownership and operation of
the project will be transferred to NIA at no cost on an "as-" basis. The Casecnan project is dependant upon sufficient
rainfall to generate electricity and deliver water. The seasonality of rainfall patterns and the variability of rainfall from year to
year, all of which are outside the control of CE Casecnan, have a material impact on the amounts of electricity generated and
water delivered by the Casecnan project. Rainfall has historically been highest from June through December and lowest from
January through May. The contractual terms for water delivery fees and variable energy fees (described below) can produce
significant variability in revenue between reporting periods. Summarized below are significant provisions of the ProjectAgreement as modified by the Supplemental Agreement.
. ~_...~v.t'
Exhibit No.1), page 16 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Under the Supplemental Agreement, CE Casecnan is paid a fee for the delivery of water and a fee for the generation of
electricity. With respect to water deliveries, the water delivery fee is payable in a fixed monthly payment based upon an
average annual water delivery of 801.9 million cubic meters, pro-rated to approximately 66.8 million cubic meters per month
multiplied by the applicable per cubic meter rate through December 25, 2008. For each contract year starting from
December 25, 2003 and ending on December 25, 2008, a water delivery credit (deferred revenue) is computed equal to
801.9 million cubic meters minus the greater of actual water deliveries or 700.0 million cubic meters - the minimum
threshold. The water delivery credit at the end of the contract year is available to be earned in the succeeding contract years
ending December 25, 2008. The cumulative water delivery credit at December 25, 2008, if any, shall be amortized from
December 25 2008 through December 25, 2013. Accordingly, in recognizing revenue, the water delivery fees are recorded
each month pro-rated to approximately 58.3 million cubic meters per month until the minimum threshold ha~ been reached
for the contract year. Subsequent water delivery fees within the contract year are based on actual water delivered.
With respect to electricity, CE Casecnan is paid a guaranteed energy delivery fee each month equal to the product obtained
by multiplying 19 GWh times $0.1596 per kWh. The guaranteed energy delivery fee is payable regardless of the amount
energy actually generated and delivered by CE Casecnan in any month. NIA also pays CE Casecnan an excess energy
delivery fee, which is a variable amount based on actual electrical energy, if any, delivered in each month in excess of 19
GWh multiplied by (i) $0.1509 per kWh through the end of2008 and (ii) commencing in 2009, $0.1132 (escalating at 1% per
annum thereafter) per kWh, provided that any deliveries of energy in excess of 490 GWh but less than 550 GWh per year are
paid for at a rate of 1.3 pesos per kWh and deliveries in excess of 550 GWh per year are at no cost to NIA. Within each
contract year, no variable energy fees are payable until energy in excess of the cumulative 19 GWh per month for the contract
year to date has been delivered. If the Casecnan project is not dispatched up to 150 MW whenever water is available, NIA
will pay for energy that could have been generated but was not as a result of such dispatch constraint.
The ROP has provided a Perfonnance Undertaking under which NIA's obligations under the Project Agreement, as
, supplemented by the Supplemental Agreement, are guaranteed by the full faith and credit of the ROP. The Project Agreement
and the Perfonnance Undertaking provide for the resolution of disputes by binding arbitration in Singapore under
international arbitration roles.
In connection with the signing of the Supplemental Agreement, CE Casecnan received written confirmation from the Private
Sector Assets and Liabilities Management Corporation that the issues with respect to the Casecnan project that had been
raised by the interagency review of independent power producers in the Philippines or that may have existed with respect to
the project under certain provisions of the Electric Power Industry Refonn Act of 2001 ("EPIRA"), which authorized the
ROP to seek to renegotiate certain contracts such as the Project Agreement, have been satisfactorily addressed by theSupplemental Agreement.
PacifiCorp
Exhibit No. II , page 17 of 130CASE NO. PAC-05-Witness: Patrick J. Goodman
CalEnergy Generation-Domestic
Business
The subsidiaries comprising the Company s CalEnergy Generation-Domestic platform own interests in 15 operating non-
utility power projects in the United States. The following table sets out certain infonnation concerning CalEnergy
Generation,;,Domestic s non-utility power projects in operation as of December 31, 2004:
Facility Power
Net,Net Purchase
Capacity Agreement Power
eratin ect Owned(1)Fuel Location Expiration Purchaser(l)
Cordova 537 537 Gas Illinois 2017 EI Paso
Salton Sea I Geo California 2017 Edison
Salton Sea II Geo California 2020 Edison
Salton Sea III Geo California 2019 Edison
Salton Sea IV Geo California 2026 Edison
Salton Sea V Geo California Varies Various
Vulcan Geo California 2016 Edison
Elmore Geo California 2018 Edison
Leathers Geo California 2019 ' Edison
Del Ranch Geo California 2019 Edison
CE Turbo Geo California Varies Various
Saranac 240 Gas New York 2009 NYSE&G
Power Resources 212 106 Gas Texas 2005 ONEOK
Yuma Gas Arizona 2024 SDG&E
Roosevelt Hot
Springs --1J -11 Geo Utah 2020 UP&L
Total Domestic
Operating Projects 232
(1)Represents nominal net generating capability (accredited for Cordova and contract capacity for most others). Actual
MW may vary depending on operating and reservoir conditions and plant design. Net MW Owned indicates current
legal ownership, but, in some cases, does not reflect the current allocation of partnership distributions.
(2)El Paso; Southern California Edison Company ("Edison
);
New York State Electric & Gas Corporation
NYSE&G"); ONEOK Energy, Marketing and Trading Company, L.P. ("ONEOK"); San Diego Gas & Electric
Company ("SDG&E"); and Utah Power & Light Company ("UP&L"
Cordova Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). CalEnergy
Generation Operating Company, an indirect wholly owned subsidiary of MEHC, operates the Cordova Project which
commenced commercial operations in June 2001. Cordova Energy entered into a power purchase agreement with a unit of EI
Paso, under which EI Paso will purchase all of the capacity and energy from the project until December 31 , 2019. The
contract year under the power purchase agreement extends from May 15th in a year to May 14th in the subsequent year. For
each contract year, Cordova Energy has an option to recall from EI Paso 50% of the output of the Cordova Project, reducing
EI Paso s purchase obligation to 50% of the output during such contract year. Cordova Energy exercised such option for the
contract year ended May 14, 2004, and the recalled output was sold to MidAmerican Energy. Cordova Energy did not
exercise the recall option for the contract year which commenced on May 15, 2004, and EI Paso is required to purchase 100%
of the capacity and energy from the project for the current contract year and, subject to future exercises of the recall option
for the remainder of the term of the power purchase agreement. The Company is aware there have been public
announcements that El Paso s financial condition has deteriorated as a result of, among other things, reduced liquidity and
will continue to monitor the situation.
MEHC has a 50% ownership interest in CE Generation, LLC ("CE Generation ) whose affiliates currently operate ten
geothermal plants in the Imperial Valley in California (the "Imperial Valley Projects ). The Imperial Valley Projects include
the "Salton Sea Projects" consisting of the Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V projects
and the "Partnership Projects" consisting of the Vulcan, Elmore, Leathers, Del Ranch and CE Turbo projects.
PacitiCorp
Exhibit No. II , page 18 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Each of the Imperial Valley Projects, excluding the Salton Sea V and CE Turbo projects, sells electricity to Edison pursuant
to a separate Standard Offer No.4 Agreement ("S04 Agreement") or a negotiated power purchase agreement. Each power
purchase agreement is independent of the others, and the perfonnance requirements specified within one such agreement
apply only to the project subject to the agreement. The power purchase agreements provide for capacity payments, capacity
bonus payments and energy payments. Edison makes fixed annual capacity payments and capacity bonus payments to the
applicable projects to the extent that capacity factors exceed certain benchmarks. The price for capacity is fixed for the life of
the S04. Agreements and is significantly higher in the months of June through September.
Energy payments under the onginal S04 Agreements were based on the cost that Edison avoids by purchasing energy from
the project instead of obtaining the energy from other sources voided Cost of Energy ). In June and November 200 1, the
Imperial Valley Projects (except the Salton Sea IV, Salton Sea V and CE Turbo projects), which receive Edison s Avoided
Cost of Energy, entered into agreements that provide for amended energy payments under the S04 Agreements. The
amendments provide for fixed energy payments per kWh in lieu of Edison s Avoided Cost of Energy. The fixed energy
payment was 25 cents per kWh from December 1 , 2001 through April 30, 2002 and is 37 cents per kWh commencing
May 1, 2002 for a five-year period. Following the five-year period, the energy payments revert back to Edison s Avoided
Cost of Energy.
For the years ended December 31 , 2004, 2003 and 2002, Edison s average Avoided Cost of Energy was cents per kWh
5.4 cents per kWh and 3.5 cents per kWh, respectively. Estimates of Edison s future Avoided Cost of Energy vary
substantially from year to year primarily based on the future cost of natural gas.
On May 20, 2003, Salton Sea Power LLC ("Salton Sea Power ) entered into a power sales agreement with Riverside. Under
the tenDS of the agreement, Salton Sea Power sells up to 20 MW of energy generated from the Salton Sea V project
Riverside. Sales under the agreement commenced June 1 2003 and will terminate May 31 , 2013.
Pursuant to 33-year power sales agreements, the Salton Sea V and CE Turbo projects had sold a portion of their net output to
CalEnergy Minerals LLC ("Minerals ) for the Zinc Recovery Project's full electrical energy requirements. The agreements
provide for energy payments based on the market rates available to the Salton Sea V and CE Turbo projects, adjusted for
wheeling costs. On September 10, 2004, Minerals ceased operations of the Zinc Recovery Project. Accordingly, except for
sales during the dismantling and decommissioning phases of the Zinc Recovery Project, no further sales to Minerals are
expected. The Salton Sea V project sells its remaining output and the CE Turbo project sells its available power under the
transaction agreement as described in the next paragraph.
Pursuant to a transaction agreement dated January 29, 2003, the Salton Sea V project and the CE Turbo project began selling
available power to TransAlta USA Inc. ("TransAlta ) on February 12, 2003 based on percentages of the Dow Jones SP-
Index. The transaction agreement shall continue until the earlier of (a) 30 days following a written notice of tennination and
(b) any other termination date mutually agreed to by the parties. No such notice of termination has been given by either party.
The Saranac project is a 240 net MW natural gas-fired cogeneration facility located in Plattsburgh, New York owned by the
Saranac Partnership, which is indirectly owned by subsidiaries of CE Generation, ArcLight Capital Holdings and General
Electric Capital Corporation., The Saranac project has entered into a IS-year power purchase agreement with NYSE&G, 15-
year steam purchase agreements with Georgia-Pacific Corporation and Pactiv Corporation and a IS-year natural gas supply
contract with Coral Energy to supply 100% of the Saranac project's fuel requirements. Each of the power purchase
agreement, the steam purchase agreements and the natural gas supply contract contains rates that are fixed for the respective
contract tenDS and expire in 2009.
The Power Resources project is a 212 net MW natural gas-fired cogeneration project owned by Power Resources Ltd.
Power Resources ), an indirect wholly-owned subsidiary of CE Generation. On August 5,2003, Power Resources entered
into a Tolling Agreement with ONEOK. The agreement commenced October 1 , 2003 and expires December 31 2005. Under
the tenDS of the agreement, Power Resources, as an exempt wholesale generator ("EWG"), sells its electricity and capacity to
ONEOK for a fixed amount per kW-month plus a variable operating and maintenance fee per MWh. In addition, ONEOK
pays annual turbine start-up costs.
The Yuma project is a 50 net MW natural gas-fired cogeneration project in Yuma, Arizona owned by Yuma Cogeneration
Associates ("YCA"), providing its electricity to SDG&E under an existing 30-year power purchase contract which
commenced in May 1994 the ("Yuma PPA"). MEHC has guaranteed all of the obligations ofYCA under the Yuma PPA or
PacifiCorp
Exhibit No. 11 , page 19 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
any other agreement with SDG&E relating to or arising out of the Yuma PP A. YCA also has executed steam sales contracts
with Queen Carpet, Inc. to act as its thennal host.
The Roosevelt Hot Springs project is a geothennal steam field which supplies geothermal steam to a 23 net MW power plant
owned by UP&L located on the Roosevelt Hot Springs property under a 30-year steam sales contract expiring in 2020. The
Company obtained a cash prepayment under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam
produced by the steam field. MEHC guarantees the perfonnance of this subsidiary and must make certain penalty payments
to UP&L if the steam produced does not meet certain quantity and quality requirements.
Zinc Recovery Project
Indirect wholly-owned subsidiaries of MEHC, own the rights to commercial quantities of extractable mmerals from elements
in solution in the geothennal brine and fluids utilized at the Imperial Valley Projects and a zinc recovery plant constructed
near the Imperial Valley Projects designed to recover zinc from the geothennal brine through an ion exchange, solvent
extraction, electrowinning and casting process (the "Zinc Recovery Project"
The Zinc Recovery Project began limited production during December 2002 and continued limited production until
September 10, 2004. Efforts to increase production had continued since the Zinc Recovery Project was placed in service with
an emphasis on process modification. Management had been assessing the long-term economic viability of the Zinc
Recovery Project in light of continuing cash flow deficits and operating losses and the efforts to increase production, and had
continued to evaluate the expected impact of the planned improvements to the extraction process during the third quarter
2004. Furthennore, management had been exploring other operating alternatives, such as establishing strategic partnerships
and consideration of ceasing operations of the Zinc Recovery Project.
On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project. In connection with
ceasing operations, the Zinc Recovery Project's ass,ets are being dismantled and sold and certain employees of the operator of
the Zinc Recovery Project have been paid one-time termination benefits. Implementation of a disposal plan began in
September 2004 and will continue in 2005. Refer to Note 3 of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" of this Form 10-K for additional discussion regarding the Company
discontinued operations.
Development Projects
MEHC's indirect wholly-owned subsidiary, CE Obsidian Energy LLC ("Obsidian ), is evaluating the development of a 185
net MW geothennal facility in the Imperial Valley in California. Substantially all of the output of the facility would be sold to
the Imperial Irrigation District ("lID") pursuant to a power purchase agreement. TransAlta is currently funding 50% of the
development costs of this project. Significant development and construction risk remains with this project.
HomeServices
Business
HomeServices is the second largest full-service residential real estate brokerage fi~ in the United States. In addition to
providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services
including mortgage originations, mortgage banking, title and closing services and other related services. HomeServices
currently operates in 18 states under the following brand names: Carol Jones REAL TORS, CBSHOME Real Estate
Champion Realty, Edina Realty Home Services, Esslinger-Wooten-Maxwell REALTORS, First Realty/GMAC, HOME Real
Estate, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential California Realty, Prudential
Carolinas Realty, RealtySouth, Rector-Hayden REALTORS, Reece & Nichols, Semonin REALTORS and Woods Bros.
Realty. HomeServices generally occupies the number one or number two market share position in each of its major markets
based on aggregate closed transaction sides. HomeServices' major markets consist of the following metropolitan areas:
Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California; Kansas City, Kansas; Kansas City, Missouri;
Des Moines, Iowa; Omaha and Lincoln, Nebraska; Binningham and Auburn, Alabama; Tucson, Arizona; Winston-Salem and
Charlotte, North Carolina; Louisville and Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia; Miami, Florida and
Springfield, Missouri.
raClJlLorp
Exhibit No. 11, page 20 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Acquisitions
In 2004, HomeServices separately acquired six real estate companies for an aggregate purchase price of $30.7 million, net of
cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2003, these real estate
companies had combined revenue of $95.7 million, on approximately 15,000 closed sides representing $3.2 billion of sales
volume. In 2003, HomeServices separately acquired four real estate companies for an aggregate purchase price of
$36.7 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31
2002, these real estate companies had combined revenue of $102.9 million on approximately 16,000 closed sides
representing $3.6 billion of sales volume.
Regulatory Matters
General Regulation
The Company s operating platforms are subject to a number of federal, state, local and international regulations.
MidAmerican Energy
MidAmerican Energy is subject to comprehensive regulation by the FERC as well as utility regulatory agencies in Iowa
Illinois and South Dakota that significantly influences the operating environment and the recoverability of costs from utility
customers. Except for Illinois, that regulatory environment has to date, in general, given MidAmerican Energy an exclusive
right to serve electricity customers within its service territory and, in turn, the obligation to provide electric service to those
customers. In Illinois, all customers are free to choose their electricity provider and MidAmerican Energy has an obligation to
serve customers at regulated rates that leave MidAmerican Energy s system, but later choose to return. To date, there has
been no significant loss of customers from MidAmerican Energy s existing regulated Illinois rates.
In conjunction with the March 1999 approval by the IUB of the MidAmerican Energy acquisition and March 2000
affirmation as part of the Company s acquisition by a private investor group, MidAmerican Energy committed to the IUB
use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common
equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level
decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval of the IUB of a reasonable
utility capital structure if MidAmerican Energy s common equity level decreases below 42% of total capitalization, unless
the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the
IUB if MidAmerican Energy s equity level decreases to below 39%, even if the decrease is due to circumstances beyond the
control ofMidAmerican Energy. If MidAmerican Energy s common equity level were to drop below the required thresholds
MidAmerican Energy s ability to issue debt could be restricted.
With the elimination of its energy adjustment clause in Iowa in 1997, MidAmerican Energy is financially exposed to
movements in energy prices. Although MidAmerican Energy believes it has sufficient generation under typical operating
conditions for its retail electric needs, a loss of adequate generation by MidAmerican Energy requiring the purchase of
replacement power at a time of high market prices could subject MidAmerican Energy to losses on its energy sales.
Under three settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate ("OCA") and
other intervenors, approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric rates prior
to 2012 unless its Iowa jurisdictional electric return on equity for any year falls below 10%. Prior to filing for a general
increase in electric rates, MidAmerican Energy is required to conduct 30 days of good' faith negotiations with the signatories
to the settlement agreements to attempt to avoid a general increase in such rates. As a party to the settlement agreements, the
OCA has agreed not to request or support any decrease in MidAmerican Energy s Iowa electric rates prior to January 1
2012. The settlement agreements specifically allow the IUBto approve or order electric rate design or cost of service rate
changes that could result in changes to rates for specific customers as long as such changes do not result in an overall
increase in revenues for MidAmerican Energy. The settlement agreements also each provide that portions of revenues
associated with Iowa retail electric returns on equity within specified ranges will be recorded as a regulatory liability.
Under the first settlement agreement, which was approved by the IUB on December 21, 200 I, and is effective through
December 31 , 2005, an amount equal to 50% of revenues associated with returns on equity between 12% and 14%, and
83.33% of revenues associated with returns on equity above 14%, in each year is recorded as a regulatory liability. The
second settlement agreement, which was filed in conjunction with MidAmerican Energy s application for ratemaking
principles on its wind power project and was approved by the IUB on October 17, 2003, provides that during the period
PacifiCorp
Exhibit No. 11 , page 21 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
January 1 2006 through December 31 2010, an amount equal to 40% of revenues associated with returns on equity between
11.75% and 13%, 50% of revenues associated with returns on equity between 13% and 14%, and 83.3% of revenues
associated with returns on equity above 14%, in each year will be recorded as a regulatory liability.
The third settlement agreement was approved by the IUB on January 31,2005, in conjunction with MidAmerican Energy
proposed expansion of its wind power project by up to 90 MW. This settlement extended through 2011 MidAmerican
Energy s commitment not to seek a general increase in electric rates unless its Iowa jurisdictional electric return on equity
falls below 10%. It also extended the revenue sharing mechanism through 2011. In addition, the OCA agreed to commit not
to seek any decrease in Iowa electric base rates to become effective before January 1 , 2012. The total capacity added as the
result of the wind expansion project is currently projected to be 50 MW.
The regulatory liabilities created by the three settlements are recorded as a regulatory charge in depreciation and amortization
expense when the liability is accrued. Additionally, interest expense is accrued on the portion of the regulatory liability
balance recorded in prior years. The regulatory liabilities created for the years through 2010 are expected to be reduced
they are credited against plant in service in amounts equal to the allowance for funds used during construction associated
with generating plant additions. As a result of the credit applied to generating plant balances from the reduction of the
regulatory liabilities, future depreciation will be reduced.
Illinois bundled electric rates are frozen until 2007, subject' to certain exceptions allowing for increases, at which time
bundled rates may be increased or decreased by the Illinois Commerce Commission. Illinois law provides that, through 2006,
Illinois earnings above a computed level of return on common equity are to be shared equally between regulated retail
electric customers and MidAmerican Energy. MidAmerican Energy s computed level of return on common equity is based
on a rolling two-year average of the Monthly Treasury Long-Term Average Rate, as published by the Federal Reserve
System, plus a premium of 8.5% for 2000 through 2004 and a premium of 12.5% for 2005 and 2006. The two-year average
above which sharing must occur for 2004 is 13.57%. The law allows MidAmerican Energy to mitigate the sharing of
earnings above the threshold return on common equity through accelerated recovery of electric assets.
The FERC has undertaken several measures to increase competition in the markets for wholesale electric energy, including
efforts to foster the development of regional transmission organizations ("RTO") in its Order No. 2000 issued December
1999 and its July 2002 proposed rulemaking that would implement a standard market design ("SMD") for wholesale electric
markets.
If implemented, the FERC's July 2002 proposed rule for SMD would require sweeping changes to the use and expansion of
the interstate transmission and wholesale bulk power systems in the United States. However, it is unclear when or even
whether the FERC will issue a final rule and what form the fmal rule would ultimately take. In response to significant
criticism of its proposed rule, the FERC subsequently indicated that it had changed its proposal and would adopt a flexible
approach to SMD that would accommodate regional differences. Any final rule on SMD or similar FERC action could
impact the costs of MidAmerican Energy s electricity and transmission products. Such FERC action could directly or
indirectly influence how transmission services are priced, the availability of transmission services, how transmission services
are obtained and market prices for electricity in markets in which MidAmerican Energy buys and sells electricity. Although
MidAmerican Energy is not presently a member of an RTO, two RTOs - Midwest Independent System Operator and PJM
Interconnection - are directly interconnected with MidAmerican Energy s transmission facilities. MidAmerican Energy
cannot predict what impact, if any, the evolution of these RTOs, or others, may have on how wholesale electricity is bought
and sold, as well as the geographic scope of the wholesale marketplace in which MidAmerican Energy buys or sells
electricity.
On June 3, 2004, the FERC's Division of Operational Investigations of the Office of Market Oversight and Investigations
informed MidAmerican Energy that it was commencing an audit to determine whether and how MidAmerican Energy and its
subsidiaries and affiliates are complying with (1) requirements of the standards of conduct and open access same-time
information system of the FERC's regulations, (2) codes of conduct, and (3) transmission practices.' The FERC has
coinmenced several such audits of utilities in 2003 and 2004. The audit is on-going, and MidAmerican Energy expects it to
be completed within the first half of 2005. MidAmerican Energy does not expect the outcome of this issue to have a material
effect on its results of operations, financial position or cash flows.
On July 13, 2004, the FERC issued an order requiring MidAmerican Energy to conduct a study to determine whether
MidAmerican Energy or its affiliates possess generation market power. MidAmerican Energy is being required to show the
absence of generation market power in order to be allowed to continue to sell wholesale electric power at market-based rates.
PacifiCorp
Exhibit No. II, page 22 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
The FERC order is intended to have MidAmerican Energy conform to what has become the FERC's general practice for
utilities given authorization to make wholesale market-based sales. Under this general practice, utilities authorized to make
market-based electric sales must submit a new market power study to the FERC every three years. In accordance with the
FERC order, MidAmerican Energy s market-based sales became subject to refund beginning November 1, 2004, and will
remain so until the matter is resolved. MidAmerican Energy does not expect the outcome of this issue to have a material
effect on its results of operations, financial position or cash flows.
Kern River and Northern Natural Gas
Kern River and Northern NatUral Gas are subject to regulation by various federal and state agencies. As own~s of interstate
natural gas pipelines, Northern Natural Gas' and Kern River s rates, services and operations are subject to regulation by the
FERC. The FERC administers, among other things, the Natural Gas Act and the Natural Gas Policy Act of 1978.
Additionally, interstate pipeline companies are subject to regulation by the United States Department of Transportation
DOT") pursuant to the Natural Gas Pipeline Safety Act of 1968 ("NGPSA"), which establishes safety requirements in the
design, construction, operations and maintenance of interstate natural gas transmission facilities.
The FERC has jurisdiction over, among other things, the construction and operation of pipelines and related facilities used in
the transportation, storage and sale of natural gas in interstate commerce, including the modification or abandonment of such
facilities. The FERC also has jurisdiction over the rates and charges and terms and conditions of service for the transportation
of natural gas in interstate commerce.
Kern River s tariff rates were designed to give it an opportunity to recover all actually and prudently incurred operations and
maintenance costs of its pipeline system, taxes, interest, depreciation and amortization and a regulated equity return. Kern '
River s rates are set using a "levelized cost-of-service" methodology so that the rate is constant over the contract period. This
is achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases.
Kern River was required to file a general rate case no later than May 1 , 2004 pursuant to the terms of its 1998 FERC Docket
No. RP99-274 rate case settlement. Kern River filed its rate case on April 30, 2004, which supports a revenue increase of
$40.1 million representing a 13% increase from its existing cost of service and a proposed overall cost of service of
$347.4 million. Since its last rate case, Kern River has increased the capacity of its system from 724 500 Dth per day to
755 575 Dth per day ata cost of approximately $1.3 billion resulting in a total rate base of approximately $1.8 billion. The
rate increase became effective on November 1, 2004, subject to refund, and the FERC set a procedural order with a hearing
scheduled for March 2005.
On February 10, 2005, Kern River received notice from the Office of Market Oversight and Investigations of the FERC that
it is instituting a non-public audit to determine Kern River s compliance with the FERC's standards of conduct in regards to
communications with any of Kern River s marketing and energy affiliates. The time period of the audit generally covers
September 22, 2004, to the present although some questions cover time periods from November 25, 2003. Kern River
understands that virtually all interstate pipelines are expected to be audited by the FERC in 2005. Kern River believes it is in
compliance with the standards of conduct in all material respects and the outcome of this audit is not expected to have a
material effect on Kern River s results of operations, financial position or cash flows.
Northern Natural Gas has implemented a straight fixed variable rate design which provides that all fixed costs assignable to
firm capacity customers, including a return on equity, are to be recovered through fixed monthly demand or capacity
reserVation charges which are not a function of throughput volumes.
On May 1, 2003, Northern Natural Gas filed a request for increased rates with the FERC. The rate increase is primarily
attributable to four main cost areas: the capital investment made by Northern Natural Gas in the five years since its last rate
case, an increase in Northern Natural Gas' depreciation rates , increased return on equity, and changes in the level of contract
entitlement. The rate filing provides evidence in support of a $71 million increase to Northern Natural Gas' annual revenue
requirement. However, Northern Natural Gas chose to effectuate only $55 million of the increase. Northern Natural Gas' new
rates went into effect November 1 , 2003, subject to refund.
Additionally, on January 30, 2004, Northern Natural Gas filed with the FERC to increase its revenue requirement by an
incremental $30 million to that requested in the May 1 , 2003 filing. The increased revenue requirement is primarily
attributable to ongoing pipeline integrity initiative costs that Northern Natural Gas has undertaken since the May 1, 2003 rate
filing. The FERC suspended the rate increase until August 1 , 2004 and consolidated the 2003 and 2004 rate cases due to the
PacifiCorp
Exhibit No. J J. page 23 of J 30
CASE NO. PAC-05-
Witness: Patrick J. Goodman
similarity of issues in both cases and the updated costs. On July 29 2004, Northern Natural Gas notified the FERC that, in
furtherance of settlement negotiations, Northern Natural Gas was not putting the rate increase into effect on August 1 , 2004
but reserved its statutory right to put the suspended rates into effect at a later date. Northern Natural Gas' implemented the
new rates on November 1 2004, subject to refund.
On February 16, 2005, Northern Natural Gas reached a tentative agreement with the majority of its customers to settle the
consolidated rate cases. Definitive tenDS of the settlement must be agreed by all settling parties and must then be documented
in a settlement agreement which must be agreed to by all settling parties. Thereafter, the settlement must be certified by the
presiding administrative law judge and approved by the FERC. The tenDS of the agreement in principle provide for an annual
revenue increase of $48 million for the period November 1, 2003 through October 31, 2004, $53 million for the period
November 1 , 2004 through October 31 , 2005, $58 million for the period November 1, 2005 through October 31, 2006, and
$62 million beginning November 1 , 2006. As a result of the settlement, Northern Natural Gas will be required to refund an
amount generally reflecting the difference between the rate increases implemented on November 1 , 2003 and November 12004 and the fmal settled revenue amounts.
Additional proposals and proceedings that might affect the interstate pipeline industry are considered from time to time
Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any new proposals might be
implemented or, if so, how Kern River and Northern Natural Gas might be affected.
Other United States Regulation
The Public Utility Regulatory Policies Act of 1978, as amended ("PURPA") and the Public Utility Holding Company Act of
1935, as amended ("PUHCA"), are two of the laws (including the regulations thereunder) that affect MEHC and certain of its
subsidiaries' operations. PURPA provides to qualified facilities ("QF") certain exemptions from federal and state laws and
regulations, including organizational, rate and financial regulation. PUHCA extensively regulates and restricts the activities
of registered public utility holding companies and their subsidiaries. Any legislation altering PUHCA or PURP A, if adopted
could adversely impact the Company s existing domestic projects.
The Company is currently exempt from regulation under all provisions of PUHCA,except the provisions that regulate the
acquisition of securities of public utility companies, based on the intrastate exemption in Section 3(a)(1) ofPUHCA. In order
to maintain this exemption, MEHC and each of its public utility subsidiaries from which it derives a material part of its
income (currently only MidAmerican Energy) must be predominantly intrastate in character and organized in and carry on
MEHC's and MidAmerican Energy s respective utility operations substantially in MidAmerican Energy state of
organization (currently Iowa). Except for MidAmerican Energy s generating plant assets, the majority of the Company
domestic power plant operations and all of its foreign utility operations are not public utilities within the meaning of PUHCA
as a result of their status as QFs under PURPA (with the Company s ownership interest therein limited to 50%), EWGs or
foreign utility companies, or are otherwise exempted from the definition of "public utility" under PUHCA. Although the
Company believes that it will continue to qualify for exemption from additional regulation under PUHCA, it is possible that
as a result of the expansion of its public utility operations, loss of exempt status by one or more of its domestic power plants
or foreign utilities, or amendments to PUHCA or the interpretation of PUHCA, the Company could become subject to
additional regulation under PUHCA in the future. There can be no assurances that such regulation would not have a material
adverse effect on the Company.
In the event the Company was unable to avoid the loss of QF status for one or more of its affiliate s facilities, such an event
could result in tennination of a given project's power sales agreement and a default under the project subsidiary s project
financing agreements, which, in the event of the loss of QF status for one or more facilities, could have a material adverse
effect on the Company.
Regulatory requirements applicable in the future to nuclear generating facilities could adversely affect the results of
operations ofMEHC and MidAmerican Energy, in particular. The Company is subject to certain generic risks associated with
utility nuclear generation, including risks arising from the operation of nuclear facilities and the storage, handling and
disposal of high-level and low-level radioactive materials; risks of a serious nuclear incident; limitations on the amounts and
types of insurance commercially available in respect of losses that might arise in connection with nuclear operations; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their
licensed lives. The Nuclear Regulatory Commission ("NRC") has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generating facilities. Revised safety requirements promulgated by the
PacifiCorp
Exhibit No. 11, page 24 of 130
CASE NO. P AC-O5-Witness: Patrick J. Goodman
NRC have, in the past, necessitated substantial capital expenditures at nuclear plants, including the Quad Cities units, in
which MidAmerican Energy has an ownership interest, and additional such expenditures could be required in the future.
Pipeline Safety Regulation
The Company s pipeline operations are subject to regulation by the DOT under the NGPSA relating to design, installation
testing, construction, operation and management of its pipeline system. The NGPSA requires any entity that owns or operates
pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and
to comply with such plans. The Company s pipeline operations conduct internal audits of their facilities every four years,
with more frequent reviews ' of those it deems of higher risk. The DOT also routinely audits these pip~line facilities.
Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis.
The aging pipeline infrastructure in the United States has led to heightened regulatory and legislative scrutiny of pipeline
safety and integrity practices. The NGPSA was amended by the Pipeline Safety Act of 1992 to require the DOT's Office of
Pipeline Safety to consider protection of the environment when developing minimum pipeline safety regulations. In addition,
the amendments require that the DOT issue pipeline regulations concerning, among other things, the circumstances under
which emergency flow restriction devices should be required, training and qualification standards for personnel involved in
maintenance and operation, and requirements for periodic integrity inspections, as well as periodic inspection of facilities in
navigable waters which could pose a hazard to navigation or public safety. In addition, the amendments narrowed the scope
of its gas pipeline exemption pertaining to underground storage tanks under the Resource Conservation and Recovery Act.
The Company believes its pipeline operations comply in all material respects with the NGPSA.
The PSIA requires major new programs in the areas of operator qualification, risk analysis and integrity management. The
PSIA requires the periodic inspection or testing of pipelines in areas where the potential consequences of a gas pipeline
accident may be significant or may do considerable harm to people and their property, which are referred to as High
Consequence Areas. Pursuant to the PSIA, the DOT promulgated a major new final rule, effective February 14, 2004, that
requires interstate pipeline operators to: develop comprehensive integrity management programs, identify applicable threats
to pipeline segments that could impact High Consequence Areas, assess these segments, and provide ongoing mitigation and
monitoring. The Company believes its pipeline operations comply in all material respects with the PSIA.
CE Electric UK
Since 1990, the electricity generation, supply and distribution industries in Great Britain have been privatized, and
competition has been introduced in generation and supply. Electricity is produced by generators, transmitted through the
national grid transmission system and distributed to customers by the fourteen Distribution License Holders ("DLHs ) in
their respective distribution service areas~
Under the Utilities Act 2000, the public electricity supply license created pursuant to the Electricity Act 1989 was replaced
by two separate licenses-the electricity distribution license and the electricity supply license. When the relevant provision of
the Utilities Act 2000 became effective on October 1 , 2001, the public electricity supply licenses formerly held by Northern
Electric pic ("NE") and Yorkshire Electricity Group pIc ("YE") were split so that separate subsidiaries held licenses for
electricity distribution and electricity supply. In order to comply with the Utilities Act 2000 and to facilitate this license
splitting, NE and YE (and each of the other holders of the former public electricity supply licenses) each made a statutory
transfer scheme that was approved by the Secretary of State for Trade and Industry. These schemes provided for the transfer
of certain assets and liabilities to the licensed subsidiaries. This occurred on October 1, 2001 , a date set by the Secretary of
State for Trade and Industry. As a consequence of these schemes, the electricity distribution businesses of NE and YE were
transferred to Northern Electric and Yorkshire Electricity, respectively. Northern Electric and Yorkshire Electricity are each
holders of an electricity distribution license. The residual elements of the electricity supply licenses were transferred to
Innogy in connection with the sale of NE's electricity and gas supply business to Innogy and the purchase by NE of YE'
electricity distribution business from Innogy on September 21 , 2001 (the "Yorkshire Swap
).
Each of the DLHs is required to offer terms for connection to its distribution system and for use of its distribution system to
any person. In providing the use of its distribution system, a DLH must not discriminate between users, nor may its charges
differ except where justified by differences in cost.
Most of the revenue of the DLHs in the United Kingdom is controlled by a distribution price control formula which is set out
in the license of each DLH. It has been the practice of the Office of Gas and Electricity Markets ("Of gem ) (and its
PacifiCorp
Exhibit No. 11 , page 25 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
predecessor body, the Office of Electricity Regulation), to review and reset the formula at five year intervals, although the
formula may be further reviewed at other times at the discretion of the regulator. Any such resetting of the fonnula requires
the consent of the DLH. If the DLH does not consent to the formula reset, it is reviewed by the United Kingdom
competition authority, whose recommendations can then be given effect by license modifications made by Of gem.
The current fonnula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where
RPI means the Retail Price Index, reflecting the average of the 12-month inflation rates recorded for each month in the
previous July to December period. The Xd factor in the fonnula was established by Of gem at the price control review
effective in April 2000 (and through March 31, 2005, will continue to be set) at 3%. The formula also takes account of a
variety of other factors including the changes in system electrical losses, the number of customers connected and the voltage
at which customers receive the units of electricity distributed. The distribution price control formula determines the
maximum average price per unit of electricity distributed (in pence per kWh) which a DLH is entitled to charge. The
distribution price control fonnula permits DLHs to receive additional revenue due to increased distribution of units and the
increase in the number of end users. The price control does not seek to constrain the profits of a DLH from year to year. It is
a control on revenue that operates independently of most of the DLH's costs. During the term of the price control, cost
savings or additional costs have a direct impact on income and cash flow.
The procedure and methodology adopted at a price control review is at the reasonable discretion of Of gem. Generally,
Of gem s judgment of the future allowed revenue of licensees has been based upon, among other things:
the actual operating costs of each of the licensees;
the operating costs which each of the licensees would incur if it were as efficient as, in Ofgem s judgment, the
most efficient licensees;
the regulatory value to be ascribed to each of the licensees' distribution network assets;
the allowance for depreciation of the distribution network assets of each of the licensees;
the rate of return to be allowed on investment in the distribution network assets by all licensees; and
the financial ratios of each of the licensees and the license requirement for each licensee to maintain an
investment grade status.
As a result of the review concluded in 1999, the allowed revenue of Northern Electric s distribution business was reduced by
24%, in real tenns, and the allowed revenue of Yorkshire Electricity's distribution business was reduced by 23%, in real
terms, with effect from April 1, 2000.
Of gem s process of reviewing each DLH's existing price control formula, with a revised formula for each DLH (including
Northern Electric and Yorkshire Electricity) to take effect from April 1 , 2005 for an expected period of five years was
recently completed. As a result of the review, the allowed revenue of Northern Electric s distribution business was reduced
by 4%, in real terms, and the allowed revenue of Yorkshire Electricity's distribution business was reduced by 9%, in real
terms, with effect from April 1, 2005. The Xd factor was set at zero. Of gem indicated that during the period 2005 to 2010, the
retention of the benefits of any out-performance from the operating cost assumptions made by Of gem in setting the new price
control may depend on the successful implementation of revised cost reporting guidelines to be prescribed by Of gem and
applied by all DLHs. In settingthe allowed revenue of Northern Electric and Yorkshire Electricity (and all other DLHs) with
effect from April 1 , 2005, Of gem made a specific allowance for an amount in respect of each DLH's pension costs.
With effect from April 1, 2005, a number of incentive schemes operate to encourage DLHs to provide an appropriate quality
of service. Payments in respect of each failure to meet a prescribed standard of service are set out in regulations. The
aggregate payments that may be due is uncapped, although payments are excused in certain force majeure circumstances. In
stonn conditions the obligations relating to the period within which supplies should be restored are relaxed and the overall
annual exposure under the restoration standard in storm conditions is limited to 2% of a DLH's allowed revenue. There also
is a discretionary reward scheme of up to a ;(1 million per annum, and other incentive schemes pursuant to which a DLH'
allowed revenue may increase by up to 3.3% or decrease by up to 3.5% in any year.
Under the Utilities Act 2000, the Gas and Electricity Markets Authority ("GEM A") is able to impose financial penalties on
license holders who contravene (or have in the past contravened) any of their license duties or certain oftheir duties under the
Electricity Act 1989 or who are failing (or have in the past failed) to achieve a satisfactory performance in relation to the
individual standards of performance prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed
10% of the licensee s revenue.
PacifiCorp
Exhibit No. 11 , page 26 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Ca/Energy Generation-Foreign
In June 2004, Philippine President Gloria Macapagal-Arroyo was re-elected for a six-year term, through June 2010. President
Macapagal-Arroyo has announced a plan to pursue policies targeting balanced economic growth, strong market-based
industry, and poverty alleviation. In connection with those policies, the Philippine Department of Energy has announced an
energy plan focused on attaining a l 00 percent electrification level throughout the Philippines, further developing and
utilizing renewable energy sources for power and electrification, and enhancing private sector participation in all energy
activities.
The Philippine Congress has ' passed EPIRA, which is aimed at restructuring the Philippine power industry" privatizing the
NPC and introducing a competitive electricity market, among other initiatives. The implementation of EPlRA may have an
impact on the Company s future operations in the Philippines and the Philippines power industry as a whole, the effect of
which is not yet determinable or estimable.
In connection with an interagency review of approximately 40 independent power project contracts in the Philippines
pUrsuant to EPIRA, in 2003 the Casecnan project (together with four other unrelated projects) had reportedly been identified
as raising legal and financial questions and, with those projects, had been prioritized for renegotiation. As part of the
Supplemental Agreement, CE Casecnan received written confirmation trom the Private Sector Assets and Liabilities
Management Corporation that the issues with respect to the Casecnan project that had been raised by the interagency review
of independent power producers in the Philippines or that may have existed with respect to the project under certain
provisions of EPlRA, which authorized the ROP to seek to renegotiate certain contracts such as the Project Agreement, have
been satisfactorily addressed by the Supplemental Agreement. MEHC's indirect subsidiaries' Leyte Projects also had
reportedly been identified as raising financial questions. In connection with the entering into of amendments to the energy
conversion agreement for each of the Leyte Projects with PNOC-EDC, the Company believes that any issues raised by the
interagency review of independent power producers in the Philippines with respect to the Leyte Projects have been resolved.
Ca/Energy Generation-Domestic
Each of the domestic power facilities in the CalEnergy Generation-Domestic platform, excluding Cordova Energy and Power
Resources, meets the requirements promulgated under PURP A to be a QF. QF status under PURP A provides two primary
benefits. First, regulations under PURP A exempt QFs from PUHCA, the FERC rate regulation under the Federal Power Act
and the state laws concerning rates of electric utilities and financial and organization regulations of electric utilities. Second,
the FERC's regulations promulgated under PURPA require that (1) electric utilities purchase electricity generated by QFs,
the construction of which commenced on or after November 9, 1978, at a price based on the purchasing utility's Avoided
Cost of Energy, (2) electric utilities sell back-up, interruptible, maintenance and supplemental power to QFs on a non-
discriminatory basis, and (3) electric utilities interconnect with QFs in their service territories. There can be no assurance that
the QF status of such CalEnergy Generation - Domestic facilities will be maintained.
Cordova Energy and Power Resources are exempt from regulation under PUHCA because they are EWGs. PUHCA provides
that a EWG is not considered to be an electric utility company. A EWG is permitted to sell capacity and electricity in the
wholesale markets, but not in the retail markets.
If an EWG is subject to a "material change" in facts that might affect its continued eligibility for EWG status, within 60 days
of such material change, the EWG must (1) file a written explanation of why the material change does not affect its EWG
status, (2) file a new application for EWG status, or (3) notify the FERC that it no longer wishes to maintain EWG status.
HomeServices
HomeServices is subject to regulations promulgated by the U.S. Department of Housing and Urban Development ("HUD"
as well as regulatory agencies in the states within which it operates that significantly influence its operating environment. On
July 29, 2002, HUD issued a proposed regulation under the Real Estate Settlement and Procedures Act.("RESPA") HUD has
characterized the proposal as "fundamentally changing the way in which payments to mortgage brokers are recorded and
reported to consumers
" "
significantly" improving the disclosure of settlement costs. on the Good Faith Estimate making it
finDer and more usable, and "removing regulatory barriers to allow guaranteed packages of settlement services and
mortgages to be made available to consumers." The proposal was submitted to the Office of Management and Budget on
December 16, 2003, and was voluntarily withdrawn by HUD on March 22, 2004. The House Committee on Financial
Services, the Senate Committee on Banking, Housing and Urban Affairs and HUD each has indicated that refonning the
PacifiCorp
Exhibit No. I I , page 27 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
RESPA regulation is a priority in 2005. It is unknown whether a proposed rule will be introduced or finalized in 2005.
Accordingly, the Company is presently unable to quantify the likely impact of any proposed rule, if issued.
Environmental Regulation
Domestic
The Company s domestic operations are subject to a number of federal, state and local environmental and environmentally
related laws and regulations affecting many aspects of its present and future operations in the United States. Such laws and
regulations generally require the Company s domestic operations to obtain and comply with a wide variety of licenses,
permits and other approvals. The Company believes that its operating power facilities and gas pipeline operations are
currently in material compliance with all applicable federal, state and local laws and regulations. However, no guarantee can
be given that in the future the Company s domestic operations will be in material compliance with all applicable
environmental statutes and regulations or that all necessary pennits will be obtained or approved. In addition, the
construction of new power facilities and gas pipeline operations is a costly and time-consuming process requiring a multitude
of complex environmental pennits and approvals prior to the start of construction that may create the risk of expensive delays
or material impainnent of project value if projects cannot function as planned due to changing regulatory requirements or
local opposition. The Company cannot provide assurance that existing regulations will not be revised or that new regulations
will not be adopted or become applicable to it which could have an adverse impact on its capital or operating costs or its
operations.
Clean Air Standards
MidAmerican Energy s generating facilities are subject to applicable provisions of the Clean Air Act and related air quality
standards promulgated by the United States Environmental Protection Agency ("EP A"). The Clean Air Act provides the
framework for regulation of certain air emissions and permitting and monitoring associated with those emissions.
MidAmerican Energy believes it is in material compliance with current air quality requirements.
The EP A has in recent years implemented more stringent national ambient air quality standards for ozone and new standards
for fine particulate matter. These standards set the minimum level of air quality that must be met throughout the United
States. Areas that achieve the standards, as determined by ambient monitoring, are characterized as being in attainment of the
standard. Areas that fail to meet the standard are designated as being nonattainment areas. Generally, once an area has been
designated as a nonattainment area, sources of emissions in the area that contribute to the failure to achieve the ambient air
quality standards are required to make emissions reductions. The EP A has concluded that the entire State of Iowa is in
attainment of the ozone standards and the fine particulate standards.
On December 4, 2003, the EP A announced the development of its Interstate Air Quality Rule, now known as the Clean Air
Interstate Rule, a proposal to require coal-burning power plants in 29 states, including Iowa, and the District of Columbia to
reduce emissions of sulfur dioxide ("S02 ) and nitrogen oxides ("NOx ) in an effort to reduce ozone and fine particulate
matter in the Eastern United States. It is likely that MidAmerican Energy s coal-burning facilities will be impacted by this
proposal.
In December 2000, the EP A concluded that mercury emissions from coal-fired gene~ating stations should be regulated. The
EP A is currently considering two regulatory alternatives that would reduce emissions of mercury from coal-fired utilities.
One of these alternatives would require reductions of mercury from all coal-fired facilities greater than 25 MW through
application of Maximum Achievable Control Technology with compliance assessed on a facility basis. The other alternative
would regulate the mercury emissions of coal-fired facilities that pose a health hazard through a market based cap-and-trade
mechanism similar to the S02 allowance system. The EP A is currently under a deadline to finalize the mercury reduction ruleby March 2005.
The Clean Air Interstate Rule or the mercury reduction rule could, in whole or in part, be superseded or made more stringent
by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal ,level,
including the "Clear Skies Initiative " and other pending legislative proposals that contemplate 70% to 90% reductions of
S02, NOx and mercury, as well as possible new federal regulation of carbon dioxide and other gasses that may affect global
climate change.
PacJtiCorp
Exhibit No. 11, page 28 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
Depending on the outcome of the final Clean Air Interstate Rule and the mercury reduction rule or any superseding
legislation by Congress, MidAmerican Energy may be required to install control equipment on its generating stations,
purchase emission allowances or decrease the number of hours during which its generating stations operate. However, until
final regulatory or legislative action is taken, the impact of the regulations on MidAmerican Energy cannot be predicted.
MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be
required to meet emissions reductions as contemplated by the EP A. In accordance with an Iowa law passed in 200 I
MidAmerican Energy has on file with the IUB its current multi-year plan and budget for managing S02 and NOx from its
generating facilities in a cost-effective manner. The plan, which is required to be updated every two years, provides specific
actions to be taken at each coal-fired generating facility and the related costs and timing for each action. On, July 17, 2003,
the ruB issued an order that affinned an administrative law judge s approval of the initial plan filed on April I , 2002, as
amended. On October 4 2004, the ruB issued an order approving MidAmerican Energy s second biennial plan as revised in
a settlement MidAmerican Energy entered into with the Iowa Consumer Advocate Division of the Department of Justice.
That plan covers the time period from April 1, 2004 through December 31 2006. Neither ruB order resulted in any changes
to electric rates for MidAmerican Energy. The effect of the orders is to approve the prudence of expenditures made consistent
with the plans. Pursuant to an unrelated rate settlement agreement approved by the ruB on October 17, 2003, if prior to
January 1 , 2011, capital and operating expenditures to comply with environmental requirements cumulatively exceed
$325.0 million, then MidAmerican Energy may seek to recover the additional expenditures from customers. At this time
MidAmerican Energy does not expect these capital expenditures to exceed such amount.
Under the New Source Review ("NSR") provisions of the Clean Air Act, a utility is required to obtain a pennit from the EP
or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated
pollutant or (2) making a physical or operational change to an existing facility that potentially increases emissions, unless the
changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general
projects subject to NSR regulations are subject to pre-construction review and pennitting under the Prevention of Significant
Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of
regulated pollutants must undergo a Best Available Control Technology analysis and evaluate the most effective emissions
controls. These controls must be installed in order to receive a pennit. Violations of NSR regulations, which may be alleged
by the EP A, states and environmental groups, among others, potentially subject a utility to material expenses for fines and
other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental
environmental proj ects.
In recent years, the EP A has requested from several utilities infonnation and support regarding their capital projects for
various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the
NSR and the New Source Perfonnance Standards of the Clean Air Act. In December 2002 and April 2003, MidAmerican
Energy received requests from the EP A to provide documentation related to its capital projects from January 1 , 1980, to April
2003 for a number of its generating plants. MidAmerican Energy has submitted information to the EP A in responses to these
requests, and there are currently no outstanding data requests pending from the EP A. MidAmerican Energy cannot predict the
outcome of these requests at this time. However, on August 27, 2003, the EPA announced changes to its NSR rules that
clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. The EPA
concluded equipment that is repaired, maintained or replaced with an expenditure not greater than 20 percent of the value of
the source will not trigger the NSR provisions of the Clean Air Act. A number of states and local air districts challenged the
EPA's clarification of the NSR rule and a panel of the U.S. Circuit Court of Appeals for the District of Columbia Circuit
issued an order on December 24, 2003, staying the EPA's implementation of its clarifications of the equipment replacement
rule. On July 1 , 2004, the EP A published a notice of stay of the final equipment replacement rule in the Federal Register
consistent with the judicial stay. Additionally, on the same date, the EP A published a Notice of Reconsideration and Request
for Comment on the equipment replacement rule in response to the Petitioners' legal challenges. Until such time as the EPA
takes final action on the equipment replacement rule, the previous rules without the clarified exemption remain in effect.
Nuclear Regulation
MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad
Cities Station Units 1 and 2. Exelon Generation Company, LLC ("Exelon Generation ) is the operator of Quad Cities Station
and is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.
The NRC regulations control the granting of permits and licenses for the construction and operation of nuclear generating
stations and subject such stations to continuing review and regulation. On October 29, 2004, the NRC granted renewed
PacifiCorp
Exhibit No. 11, page 29 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
licenses for both Quad Cities Station Unit 1 and Unit 2 that provide for operation until December 14, 2032, which is in effect
a 20-year extension of the licenses. The NRC review and regulatory process covers, among other things, operations,
maintenance, and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses
and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of
such licenses.
Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines
there are deficiencies in state, local or utility emergency preparedness plans relating to such, facility, and the deficiencies are
not corrected. Exelon Generation has advised MidAmerican Energy that an emergency, preparedness plan for Quad Cities
Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans
relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.
The NRC also regulates the decommissioning of nuclear power plants including the planning and funding for the eventual
decommissioning of the plants. In accordance with these regulations, MidAmerican Energy submits a report to the NRC
every two years providing reasonable assurance that funds will be available to pay the costs of decommissioning its share of
Quad Cities Station.
Under the Nuclear Waste Policy Act of 1982 ("NWPA"), the U.S. Department of Energy ("DOE") is responsible for the
selection and development of repositories for, and the pennanent disposal of, spent nuclear fuel and high-level radioactive
wastes. Exelon Generation, as required by the NWP A, signed a contract with the DOE under which the DOE was to receive
spent nuclear fuel and high-level radioactive waste for disposal beginning not later than January 1998. The DOE did not
begin receiving spent nuclear fuel on the scheduled date, and remains unable to receive such fuel and waste. The earliest the
DOE currently is expected to be able to receive such fuel and waste is 2010. The costs to be incurred by the DOE for disposal
activities are being financed by fees charged to owners and generators of the waste. In 2004, Exelon Generation reached a
settlement with the DOE concerning the DOE's failure to begin accepting spent nuclear fuel in 1998. As a result, Quad Cities
Station will be billing the DOE, and the DOE will be obligated to reimburse the station for all station costs incurred due to
the DOE's delay. Exelon Generation has infonned MidAmerican Energy that existing on-site storage capability at Quad
Cities Station is sufficient to pennit interim storage in 2005. For Quad Cities Station, Exelon Generation has begun to
develop an interim spent fuel storage installation ("ISFSI") at Quad Cities Station to store spent nuclear fuel in dry casks in
order to free space in the storage pool. The first pad at the ISFSI is expected to facilitate storage of casks to support
operations at Quad Cities Station until at least 2017. Exelon Generation has completed the bulk of the construction work on
the first pad and expects the first cask loading to take place in 2005. In the 2017 to 2022 timeframe, Exelon Generation plans
to add a second pad to the ISFSI to accommodate storage of spent nuclear fuel through the end of operations at Quad Cities
Station.
MidAmerican Energy has established trusts for the investment of funds collected for nuclear decommissioning associated
with Quad Cities Station. Electric tariffs currently in effect include provisions for annualized collection of estimated
decommissioning costs at Quad Cities Station. In Iowa, estimated Quad Cities Station decommissioning costs are reflected in
base rates. MidAmerican Energy s cost related to decommissioning funding in 2004 was $8.3 million.
United Kingdom
CE Electric UK's businesses are subject to extensive regulatory requirements with respect to the protection of the
environment.
The United Kingdom government introduced new contaminated land legislation in April 2000 that requires local
governmental authorities to put in place a program for investigating land in their area in order to identify contamination.
Local authorities (and the Environment Agency where controlled waters are affected) can enforce remedial action where such
contamination of land poses a threat to the greater environment. If the "person" who contaminated the land cannot be foundthe land owner will be held responsible.
The UK local authorities have not identified any CE Electric UK sites that require any action under these regulations. CE
Electric UK evaluations of three potential sites confinn this conclusion. A project with an environmental remediation
company is in progress at one of these sites where there is an agreement to reduce pockets of localized contamination to an
acceptable standard.
- u
Exhibit No. 11, page 30 of 130
CASE NO. P AC-OS-
Witness: Patrick J. Goodman
The Environmental Protection Act (Disposal of PCB's and other Dangerous Substances) Regulations 2001 were introduced
on May 5, 2000. The regulations required that transformers containing over 50 parts per million of PCB's and other
dangerous substances be registered with the Environment Agency. Transformers containing 500 parts per million had to be
de-contaminated by December 31 , 2000. As of December 31 , 2004, CE Electric UK had 360 transformers containing
between 50 and 500 parts per million of such substances registered with the Environment Agency and is 'continuing with its
sampling, labeling and registration program. CE Electric UK believes it is in compliance and these regulations are not
expected to have a material impact on the Company.
The 1998 Groundwater Regulations seek to prevent listed hazardous substances from entering groundwater and strengthens
the United Kingdom Environment Agency s powers to require additional protective measures, especiaUy in areas of
important groundwater supplies. Mineral oils and hydrocarbons are included in the list of more tightly controlled substances
List I substances ). This affects the high voltage fluid filled electricity cable network incorporating an insulating fluid that
is currently in List I. The existing voluntary Operating Code of Practice, as agreed between the Environment Agency and
companies in the electricity industry, is undergoing revision to address the regulatory changes. The existing voluntary
Operating Code of Practice is, and any revised Operating Code of Practice will be, incorporated into the operating practices
of Northern Electric and Yorkshire Electricity. Any revisions which are made are not expected to have a material impact on
the Company.
The Oil Storage Regulations became effective in 2002 and require the phased introduction of secondary containment
measures (bunding) for all above ground oil storage locations where the capacity is more than 200 liters. The primary
containers must be in sound condition, leak free, and positioned away from vehicle traffic routes. The secondary containment
must be impermeable to water and oil (without drainage valve) and be subject to routine maintenance. The capacity of the
bund must be sufficient to hold up to 110% of the largest stored vessel or 25% of the maximum stored capacity, whichever is
the greater. On March 1 2002, these regulations came into effect for all new oil storage facilities. On September 1 2003, the
regulations became effective for existing storage facilities at "significant risk" (i.e. within 10 meters ofa water course), and
on September 1 , 2005, the regulations come into effect for all remaining storage facilities. A detailed study of the impacts has
been carried out and a plan of action prepared to ensure compliance. The Company expects that the cost of compliance with
the remaining provisions of such regulations will not have a material impact.
The Electricity Act 1989 obligates either the United Kingdom Secretary of State or the Director General of Electric Supply to
take into account the effect of electricity generation, transmission and supply activities on the physical environment when
approving applications for the construction of overhead power lines. The Electricity Act requires CE Electric UK to consider
the desirability of preserving natural beauty and the conservation of natural and man-made features of particular interest
when it formulates proposals for development in connection with certain of its activities. CE Electric UK mitigates the effects
its proposals have on natural and man-made features and administers an environmental assessment when it intends to lay
cables, construct overhead lines or carry out any other development in connection with its licensed activities. The Company
expects thatthe cost of compliance with these obligations and the mitigation thereof will not have a material impact.
CE Electric UK's policy is to carry out its activities in such a manner as to minimize the impact of its works and operations
on the environment, and in accordance with environmental legislation and good practice. There have not been any significant
regulatory environmental compliance issues and there are no material legal or administrative proceedings pending against CE
Electric UK with respect to any environmental matter.
Environmental laws and regulations in the United Kingdom currently have, and future modifications may increasingly have
the effect of requiring modification ofCE Electric UK's facilities and increasing its operating costs.
Philippines
On June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act of 1999. The related implementing rules and
regulations were adopted in November 2000. The law as written would require the Leyte Projects to comply with a maximum
discharge of 200 grams of hydrogen sulfide per gross MWb of output by June 2004. On November 13, 2002, the Secretary
of the Philippine Department of Environment and Natural Resources issued a Memorandum Circular ("MC") designating
geothermal areas as "special airsheds." PNOC-EDC has advised the Leyte Projects that the MC exempts the Mahanagdong
and Malitbog plants from the need to comply with the point-source emission standards of the Clean Air Act. CE Cebu and
PNOC-EDC have constructed a gas dispersion facility for the Upper Mahiao project which is designed to ensure compliance
with the emission standards of the Clean Air Act. The gas dispersion project was put into commercial operation in December2003.
PacifiCorp
Exhibit No. 11, page 31 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
Employees
At December 31,2004, the Company employed approximately 11 540 people, of which approximately 3,900 are covered by
union contracts. MidAmerican Energy s union contract with International Brotherhood of Electrical Workers locals 109 and
499 expires February 28, 2006, and covers approximately 1 700 employee members.
Item 2. Properties.
The Company s utility properties consist of physical assets necessary and appropriate to render electric and gas service in its
service territories. Electric property consists primarily of generation, transmission and distribution facilities and related
rights-of-way. Gas property consists primarily of distribution plants, natural gas pipelines, related right&-Of-way,compressor
stations and meter stations. It is the opinion of management that the principal depreciable properties owned by the Company
are in good operating condition and well maintained. Pursuant to separate financing agreements, substantially all or most
the properties of each subsidiary (except CE Electric UK and Northern Natural Gas) are pledged or encumbered to support or
otherwise provide the secwity for their own project or subsidiary debt. See Notes 6 and 23 of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary Data" of this Form 10-K for additional
information about the Company s properties.
MidAmerican Energy
MidAmerican Energy s most significant properties are its electric generation facilities. Refer to the MidAmerican Energy
discussion in "Item 1. Business" of this Fonn 10-K for additional infonnation about MidAmerican Energy s generation
facilities.
The electric transmission system of MidAmerican Energy at December 31, 2004, included 918 miles of345-kV lines and
128 miles of 161-kV lines. MidAmerican Energy electric distribution system included approximately 222 300
transformers and 382 substations at December 31 , 2004.
Gas property consists primarily of natural gas mains and services pipelines, meters and related distribution equipment
including feeder lines to communities served from natural gas pipelines owned by others. The gas distribution facilities of
MidAmerican Energy at December 31 , 2004, included approximately 21 548 miles of gas mains and services pipelines.
Kern River and Northern Natural Gas
At December 31 2004, Kern River s pipeline consisted of two distinguishable sections: the mainline section and the common
facilities. The mainline section consists of the original 682 miles of 36-inch pipeline, 628 miles of 36-inch loop pipeline
related to the 2003 Expansion Project and 68 miles of various laterals that connect to the mainline, and extends from the
pipeline s point of origination near Opal, Wyoming through the Central Rocky Mountains area into Daggett, California and is
owned entirely by Kern River. The common facilities consist of the 219-mile section of original pipeline that extends from
the point of interconnection with the mainline in Daggett to Bakersfield, California and an additional 82 miles related to the
2003 Expansion Project. The common facilities are jointly owned by Kern River (currently approximately 76.8%) and
Mojave (currently approximately 23.2%) as tenants-in-common.
At December 31,2004, Northern Natural Gas' system was comprised of approximately 7 300 miles of mainline transmission
pipelines and approximately 9 200 miles of lateral pipelines. Northern Natural Gas ' storage services are provided through the
operation of three underground storage fields, in Redfield, Iowa, and Lyons and Cunningham, Kansas. Northern Natural Gas
three underground natural gas storage facilities and two LNG storage peaking units have a total storage capacity of
approximately 59 Bcf. Northern Natural Gas' two LNG liquefaction/vaporization facilities are located near Gamer , Iowa and
Wrenshall, Minnesota with storage capacity of 2 Bcf each.
The right to construct and operate the pipelines across certain property was obtained through negotiations and through the
exercise of the power of eminent domain, where necessary. Kern River and Northern Natural Gas continue to have the power
of eminent domain in each of the states in which they operate their respective pipelines, but they do not have the power of
eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa
Indian Reservation, all facilities are located within a utility corridor that is reserved to the United States Department of
Interior, Bureau of Land Management.
dl;UJ\-Orp
Exhibit No. II , page 32 of 130CASE NO. PAC-05-Witness: Patrick J. Goodman
With respect to real property, each of the pipelines falls into two basic categories: (1) parcels that are owned in fee, such as
certain of the compressor stations, measurement stations and district office sites; and (2) parcels where the interest derives
from leases, easements, rights-of-way, pennits or licenses from landowners or governmental authorities pennitting the use
such land for the construction, operation and maintenance of the pipelines.
MEHC believes that Kern River and Northern Natural Gas each have satisfactory title to all of the real property making up
their respective pipelines in all material respects.
CE Electric UK
At December 31, 2004, Northern Electric s and Yorkshire Electricity's electricity distribution networks (excluding service
connection to consumers) on a combined basis included approximately 33,000 kilometers of overhead lines and
approximately 64 000 kilometers of underground cables. In addition to the circuits referred to above, at December 31 , 2004
Northern Electric s and Yorkshire Electricity's distribution facilities also included approximately 58,000 transformers and
approximately 750 primary substations.
Other Properties
At December 31 2004, MEHC's most significant physical properties, other than those owned by MidAmerican Energy, Kern
River, Northern Natural Gas and CE Electric UK, are its current interests in operating power facilities and its plants under
construction and related real property interests, as well as leases of office space for its residential real estate brokerage
operations. See "Item I. Business" of this Form 10-K for further detail.
Item 3. Legal Proceedings. .
In addition to the proceedings described below, the Company is currently party to various items of litigation or arbitration in
the normal course of business, none of which are reasonably expected by the Company to have a material adverse effect on
its financial position, results of operations or cash flows.
Pipeline Litigation
In 1998, the United States Department of Justice infonned the then current owners of Kern River and Northern Natural Gas
that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the
False Claims Act against such entities and certain of their subsidiaries including Kern River and Northern Natural Gas.
Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the
False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified
amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys' fees and costs. On
April 9, 1999, the United States Department of Justice announced that it declined to intervene in any of the Grynberg qui tam
cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the
District of Colorado. On October 21 , 1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam cases
including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District
Wyoming for pre-trial purposes. Motions to dismiss the complaint, filed by various defendants including Northern Natural
Gas and The Williams Companies, Inc. ("Williams ), which was the fonner owner of Kern River, were denied on May 18
2001. On October 9, 2002, the United States District Court for the District of Wyoming dismissed Grynberg s royalty
valuation claims. On November 19, 2002, the United States District Court for the District of Wyoming denied Grynberg
motion for clarification and dismissed his royalty valuation claims. Grynberg appealed this dismissal to the United States
Court of Appeals for the Tenth Circuit and on May 13, 2003 , the Tenth Circuit Court dismissed his appeal. Motions to
Dismiss based on various jurisdictional grounds were filed on June 4, 2004. Grynberg tiled his brief and other pleadings in
opposition to the Motions to Dismiss on October 22, 2004. In connection with the purchase of Kern River from Williams in
March 2002, Williams agreed to indemnify MEHC against any liability for this claim; however, no assurance can be given as
to the ability of Williams to perfonn on this indemnity should it become necessary. No such indemnification was obtained in
connection with the purchase of Northern Natural Gas in August 2002. The Company. believes that the Grynberg cases filed
against Kern River and Northern Natural Gas are without merit and that Williams, on behalf of Kern River pursuant to its
indemnification, and Northern Natural Gas, intend to defend these actions vigorously.
.t'acttlCorp
Exhibit No. I), page 33 of )
CASE NO. PAC-05-Witness: Patrick J. Goodman
On June 8 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as
defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens
County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999.
The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of
natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. In November 2001, Kern
River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B andl2B
of the Kansas Rules of Civil Procedure. The court denied this motion. In January 2002, Kern River and most of the
coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions.
The plaintiffs filed for certification of the plaintiff class on September 16, 2002. On January 13, 2003, oral arguments were
heard on coordinating defendants' opposition to class certification. On April 10 , 2003, the court entered an order denying the
plaintiffs' motion for class certification. On May 12 , 2003, the plaintiffs filed a motion for leave to file a fourth amended
petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The court granted the motion for leave
amend on July 28 2003. Kern River was not a named defendant in the amended complaint and has been dismissed from the
action. Northern Natural Gas filed an answer to the fourth amended petition on August 22, 2003. Class discoveryis ongoing.
Williams has agreed to indemnify MEHC against any liability associated with Kern River for this claim; however, no
assurance can be given as to the ability of Williams to perfonn on this indemnity should it become necessary. Northern
Natural Gas anticipates joining with other defendants in contesting certification of the plaintiff class. Kern River and
Northern Natural Gas believe that this claim is without merit and that Kern River s and Northern Natural Gas' gas
measurement techniques have been in accordance with industry standards and their tariffs.
Similar to the June 8, 2001 matter referenced above, the plaintiffs in that matter have filed a new companion action against a
number of parties, including Northern Natural Gas but excluding Kern River, in a Kansas state district court for damages for
mismeasurement of British thennal unit content, resulting in lower royalties. The action was filed on May 12, 2003, shortly
after the state district court dismissed the plaintiffs' third amended petition in the original litigation which sought to certify a
nationwide class. The new companion action which seeks to certify a class of royalty owners in Kansas, Colorado and
Wyoming, tracking the fourth amended petition in the action referenced above, was not served until August 4, 2003. A
motion to dismiss was filed on August 25, 2003. On October 9, 2003, the state district court denied the motion to dismiss;
Northern 'Natural Gas filed its answer on November 6, 2003. Class discovery is ongoing. Northern Natural Gas anticipates
joining with other defendants in contesting certification of the plaintiff class. Northern Natural Gas believes that this claim is
without merit and that Northern Natural Gas' gas measurement techniques have been in accordance with industry standards
and its tariff.
Natural Gas Commodity Litigation
MidAmerican Energy is one of dozens of companies named as defendants in a January 20, 2004 consolidated class action
lawsuit filed in the U.S. District Court for the Southern District of New York. The suit alleges that the defendants have
engaged in unlawful manipulation of the prices of natural gas futures and options contracts traded on the New York
Mercantile Exchange ("NYMEX") during the period January I, 2000 to December 31 , 2002. MidAmerican Energy is
mentioned as a company that has engaged in wash trades on Enron Online (an electronic trading platfonn) that had the effect
of distorting prices for gas trades on the NYMEX. The plaintiffs to the class action do not specify the amount of alleged
damages. At this time, MidAmerican Energy does not believe that it has any material exposure in this lawsuit.
The original complaint in this matter, Cornerstone Propane Partners, L.P. v. Relian~, et al. ("Cornerstone ), was filed on
August 18, 2003 in the United States District Court, Southern District of New York naming MidAmerican Energy and
MEHC. On October 1 , 2003, a second complaint Roberto, E. Calle Gracey, et al. ("Calle Gracey J, was filed in the same
court but did not name MidAmerican' Energy or MEHC. On November 14, 2003, a third complaint Dominick Viola
Viola J. et aI., was filed in the same court and named MidAmerican Energy and MEHC as defendants. On November 19
2003, an Order of Voluntary Dismissal Without Prejudice of MEHC was entered by the court dismissing MEHC from the
Cornerstone and Viola complaints. On December 5, 2003, the court entered Pretrial Order No., which among other
procedural matters, ordered the consolidation of the Cornerstone, Calle Gracey and Viola complaints and permitted plaintiffs
to file an amended complaint in this matter. On January 20, 2004, plaintiffs filed In Re: Natural Gas Commodity Litigation
the amended complaint reasserting their previous allegations. On February 19, 2004, MidAmerican Energy filed a Motion to
Dismiss and joined with several other defendants to file a joint Motion to Dismiss. The plaintiffs filed a response on May 19
2004, contesting both Motions to Dismiss. On September 24, 2004, the pending Motions to Dismiss were denied. On
October 14, 2004, the plaintiffs filed an amended consolidated class action complaint reasserting their previous allegations.
On January 25, 2005, the plaintiffs filed their motion for class certification. MidAmerican Energy will continue to coordinate
with the other defendants and vigorously defend the allegations against it.
Philippines
PacifiCorp
Exhibit No. II, page 34 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro
forma financial projections of the Casecnan project prepared following commencement of commercial operations, in
February 2002, MEHC's indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the minority stockholder, LaPrairie
Group Contractors (International) Ltd. ("LPG"), that MEHC's ownership interest in CE Casecnan had increased to 100%
effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of
the State of California, City and County of San Francisco against among others, CE Casecnan Ltd. and MEHC. On
January 21 , 2004, CE Casecnan Ltd. and LPG entered into a status quo agreement pursuant to which the parties agreed to set
aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further
actions with respect to such distribution without at least 15 days prior notice to LPG. Accordingly, 15%'oftheCE Casecnan
dividend distributions declared in 2004, totaling $15.9 million, was set aside by CE Casecnan in an unsecured CE Casecnan
account and is shown as restricted cash and short-term investments and other current liabilities in the accompanying
consolidated balance sheet included in "Item 8. Financial Statements and Supplementary Data" of this Form 10-K. The court
is currently expected to rule on the first phase of the litigation before the end of the first quarter of 2005. The impact, if any,
of this litigation on the Company cannot be determined at this time.
Mirant Americas Energy Marketing ("Mirant") Claim
Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract (90 000
Dth per day) with Kern River (the "Mirant Agreement") and provided a letter of credit equivalent to 12 months of reservation
charges as security for its obligations under the Mirant Agreement. In July 2003, Mirant filed for Chapter 11 bankruptcy
protection and continued to perform under the Mirant Agreement post-bankruptcy. In October 2003, Mirant informed Kern
River that it would not renew its letter of credit and Kern River drew on the letter of credit and held the proceeds thereof
$14.8 million, as cash collateral. Effective December 18, 2003, Mirant rejected the Mirant Agreement pursuant to procedures
under the Bankruptcy Code and paid all post-petition amounts then due and owing under the Mirant Agreement through
December 18, 2003. On January 13 2004, Kern River filed a proof of claim with the bankruptcy court for an aggregate total
amount of $210.2 million (the "Kern River Claim
),
which Kern River believed was secured to the extent of the
$14.8 million in proceeds received from the letter of credit and held as a cash security deposit. The claims underpinning the
proof of claim arise from damages caused by Mirant's rejection of the MirantAgreement. On May 25, 2004, the bankruptcy
court issued an order permitting Kern River to apply 100% of the $14.8 million cash security deposit to its claim for
damages. On October 12 2004, Mirant raised an objection to the Kern River Claim asserting, among other things, that Kern
River had not included a discount adjustment or mitigation to the claim. On November 11 , 2004, Kern River filed an
amended proof of claim of$138.8 million, reflecting discounting, mitigation and other adjustments, and which excludes the
$14.8 million already received by Kern River. Kern River can not determine at this time if it will collect any portion of the
balance of the Kern River Claim or be able to remarket the rejected Mirant Agreement capacity.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
Paci fi Corp
Exhibit No. II , page 35 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
PART II
Item S. Market for Registrant's Common Equity and Related Stockholder Matters.
Since March 14, 2000, MEHC's equity securities have been owned by Berkshire Hathaway, Walter Scott, Jr. (together with
certain of his family members and family trusts and corporations), David L. Sokol and Gregory E. Abel and have not been
registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly
held or traded.
Item 6. Selected Financial Data.
The following table sets forth selected financial data, which should be read in conjunction with the Company s consolidated
financial statements and the related notes to those statements included in "Item 8. Financial Statements and Supplementary
Data" and with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
appearing elsewhere in this Form 10-K. The selected financial data as of and for the years ended December 31 , 2004, 2003
2002 and 2001, and as of December 31 2000 and for the period from March 14 2000 through December 31, 2000, have been
derived from the Company s historical consolidated financial statements. The selected financial data from January 1 , 2000
through March 13,2000, have been derived from MEHC (Predecessor)'s historical consolidated financial statements.
2004 '
Year Ended December 31,2003 2002(1) 2001 (2)
(Amounts in millions)
March 14
2000
through
December 31,
2000(3)
MEHC
(Predecessor)
January 1,
2000
through
March 13,
2000(4)
Stateme~t of Operations
Data:
Operating revenue
Income from continuing
operati ons
Loss from discontinued
operations, net of taxCS)
Net income
537.
$ 5 965.$ 4 795.$ 4 696.$3,918.$ 1 056.4
442.397.4 148.4 84.1 51.4
(27.1)(17.4)(5.(2.(0.
415.380.142.81.3 51.3
$ 6 553.4
(367.
$ 170.
Balance Sheet Data:
Total assets $19 903.$19 145.$18,434.$12 994.$11 960.4 N/A
Parent company senior
debt(6)772.777.323.4 834.5 830.N/A
Parent company
subordinated debtC6)585.772.1 N/A
Company-obligated
mandatory redeemable
preferred securities of
subsidiary trusts 063.4 788.786.N/A
Subsidiary and project
debtC6)304.674.077.754.398.N/A
Subsidiary-obligated
mandatorily redeemable
preferred securities of
subsidiary trusts 100.100.N/A
Preferred securities of
subsidiaries 89.92.93.3 121.145.N/A
Total stockholders' equity $ 2,971.$ 2 771.4 $ 2 294.$ 1 708.$ 1 576.4 N/A
PacifiCorp
Exhibit No. 11 , page 36 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
(1)Reflects the acquisitions of Kern River on March 27, 2002 and Northern Natural Gas on August 16, 2002.
(2)Reflects the Yorkshire Swap on September 21, 2001 and includes $15.2 million of after-tax income related to the sale
of the Northern Electric electricity and gas supply business, the sale of the Telephone Flat Project, the sale of Western
States Geothennal, the transfer of Bali Energy Ltd. shares, and the Teesside Power Limited ("TPL") asset valuation
impainnent charge.
(3)
(4)
Reflects the Teton Transaction on March 14 2000.
Includes $7.6 million of expenses related to the Teton Transaction.
(5)Reflects MEHC's decision to cease operations of the Zinc Recovery Project effective September 10, 2004, which
resulted in a non-cash, after-tax impainnent charge of $340.3 million being recorded to write-off the Zinc Recovery
Project, rights to quantities of extractable minerals, and allocated goodwill (collectively, the "Mineral Assets ). The
charge and related activity of the Mineral Assets, including the reclassification of such activity for the years ended
December 31 2003,2002 and 2001 and for the periods January 1 , 2000 through March 13,2000 and March 14, 2000
through December 31, 2000, are classified separately as discontinued operations.
(6)Excludes current portion.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in combination with the selected financial data and the conSolidated
financial statements included in Items and herein.
General
The Company s operations are organized and managed on seven distinct platfonns: MidAmerican Energy, Kern River
Northern Natural Gas, CE Electric UK (which includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-
Foreign, CalEnergy Generation-Domestic, and HomeServices.
The Company owns and operates a combined electric and natural gas utility company in the United States, two natural gas
pipeline companies in the United States, two electricity distribution companies in the United Kingdom, a diversified portfolio
of domestic and international independent power projects and the second largest residential real estate brokerage finD in the
United States.
The Company s principal energy subsidiaries generate, transmit, store, distribute and supply energy. The Company s electric
and natural gas utility subsidiaries currently serve approximately 4.4 million electricity customers and approximately 680 000
natural gas customers. Its natural gas pipeline subsidiaries operate interstate natural gas transmission systems with
approximately 18,300 miles of pipeline in operation and peak delivery capacity of 6.4 Bcf of natural gas per day. The
Company has interests in 6,777 net owned MW of power generation facilities in operation and under construction, including
203 net owned MW in facilities that are part of the regulated return asset base of its electric utility business and 1 574 net
owned MW in non-utility power generation facilities. Substantially all of the non-utility power generation facilities have
long-tenD contracts for the sale of energy and/or capacity from the facilities.
. U""&I~V' II
Exhibit No. 11 , page 37 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Executive Summary
The following significant events and changes, as discussed in more detail herein, highlight some factors that affect the
comparability of our financial results, for the years ended December 31 , 2004, 2003 and 2002, respectively:
On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project, effective
immediately. Based on this decision, a non-cash, after-tax impainnent charge of $340.3 million has been recorded to
. write-off the Mineral Assets.
In December 2004, MidAmerican Energy placed into service the second phase of its 327 MW natural gas-fired
combined cycle generating plant. The plant is the first of three electric generating 'projects to be completed by
MidAmerican Energy. MidAmerican Energy expects to invest approximately $1.1 billion in the two remaining
projects through 2007. Both projects are currently under construction and $350.4 million of the $1.1 billion had been
invested through December 31, 2004.
The Company made significant investments in its natural gas pipeline business by acquiring Kern River in March
2002 for $419.7 million, net of cash acquired, and Northern Natural Gas in August 2002 for $882.7 million, net of
cash acquired, and completing the 2003 Expansion Project in May 2003 at a total cost of $1.2 billion. These
pipelines serve major markets in the midwest and western United States.
HomeServices separately acquired 13 real estate companies throughout 2004, 2003 and 2002. Operating revenue has
grown from $1.1 billion in 2002 to $1.8 billion in 2004.
CE Electric UK. operates mainly in Great Britain and the majority. of its transactions are in Pounds Sterling. The
weighted average ratio of U.S. Dollars to Pounds Sterling was 1.84, 1.64 and 1.49 during each of the years ended
December 31, 2004, 2003 and 2002, respectively, which continues to produce positive revenue and profit
comparisons on a year over year basis.
Both Kern River and Northern Natural Gas have filed for rate increases with the FERC and have hearings scheduled
in 2005. New rates for Northern Natural Gas' May 2003 rate case went into effect on November 1 2003, subject to
refund. New rates for the Northern Natural Gas' January 2004 and Kern River s April 2004 rate cases each went
into effect on November 1 , 2004, subject to refund. Additionally, Of gem completed the process of reviewing the
existing price control fonnula for Northern Electric and Yorkshire Electricity in November 2004. As a result of the
review, the allowed revenue of Northern Electric s and Yorkshire Electricity's distribution businesses will
reduced by 4% and 9%, respectively, in real tenDs, effective April 1 , 2005.
CE Casecnan reached an arbitration settlement with the NIA effective during the fourth quarter of 2003. As part of
the settlement, NIA paid CE Casecnan $17.7 million plus Philippines pesos of 39.9 million (approximately
$0.7 million) and delivered a ROP $97.0 million 8.375% Note due in 2013. In exchange, CE Casecnan agreed to
modify certain provisions of the project agreement, the most significant being the elimination of the tax
compensation portion of the water delivery fee and modification of the threshold volume of water used to calculate
the guaranteed water delivery fee. In January 2004, CE Casecnan exercised its right to put the note and received
$99.2 million (representing par plus accrued interest) from the ROP.
On November 23, 2004, Northern Natural Gas sold its stipulated general, unsecured claim of $249.0 million against
Enron Corp. ("Enron ) to a third party investor for $72.2 million and recorded the proceeds received as other
income in 2004.
In the fourth quarter of 2004, CE Generation recorded a $16.8 million charge as a result of the partial impainnent of
the carrying value of the Power Resources project.
In February 2004, MEHC issued $250.0 million of 5.00% senior notes due February 15 2014. The proceeds from
these issuances were used to satisfy a demand made by MEHC's affiliate, Salton Sea Funding Corporation
Funding Corporation ), for the amount remaining on MEHC's guarantee of Funding Corporation s 7.475% Senior
Secured Series F Bonds ("Series F Bonds ) and for, other general corporate purposes. In October 2004
MidAmerican Energy issued $350.0 million of 4.65% medium-tenD notes due October 2014, which were used forgeneral corporate purposes.
PacifiCorp
Exhibit No. II. page 3.8 of 130
CASE NO. P AC-O5-
Witness: Patrick J. Goodman
Results of Operations for the Year Ended December 31, 2004 and the Year Ended December 31, 2003
The following table summarizes net income for the years ended December 31 (in millions):
2004 2003
Income from continuing operations before income tax expense, minority interest
and preferred dividends of subsidiaries and equity income:
MidAmerican Energy
Kern River
Northern Natural Gas
CE Electric UK
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other
Income from continuing operations before income tax expense, minority interest
and preferred dividends of subsidiaries and equity income
Income tax expense
Minority interest and preferred dividends of subsidiaries
Income from continuing operations before equity income
Equity income
Income from continuing operations
Loss from discontinued operations, net of tax benefits
Net income available to common and preferred stockholders
267.
142.
218.
325.
165.
3.1
111.9
235.
271.
133.
127.
288.
177.
90.
090.
----illb2)
799.
265.
13.
520.
16.
537.
$ 170.
857.
270.3
183.
404.4
38.
442.
(27.1.)
415.
The $367.6 million loss from discontinued operations, net of tax benefits, for the year ended December 31 , 2004 included a
$340.3 million non-cash impairment charge recognized in connection with ceasing operations of the Company s Zinc
Recovery Project and a $27.1 million loss from operations, net of tax, of the Zinc Recovery Project.
Income from continuing operations for the year ended December 31, 2004, increased $95.1 million, or 21.5%, to
$537.8 million compared with $442.7 million for the same period in 2003.
Equity income for the year ended December 31 2004, decreased $21.4 million to $16.9 million compared with $38.3 million
for the same period in 2003. CE Generation recorded a $16.8 million charge as a result of the partial impairment of the
carrying value of the Power Resources project Additionally, HomeServices' mortgage joint ventures had lower income due
to lower refinancing activity.
Minority interest and preferred dividends for the year ended December 31, 2004, decreased $169;9million to $13.3 million
from $183.2 million for the same period in 2003. The decrease was due to the Company s adoption, as of October 1 2003, of
FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities
" ("
FIN 46R") related to certain finance
subsidiaries. The adoption required the decoilsolidation of certain finance subsidiaries, which resulted in the amounts
previously classified as mandatorily redeemable preferred securities of subsidiary trusts being reclassified as parent company
subordinated debt in the Company s consolidated balance sheet at December 31, 2003. The adoption also required that
amounts previously recorded in minority interest and preferred dividends of subsidiaries be recorded as interest expense in
the Company s consolidated statements of operations, prospectively. In accordance with the requirements of FIN 46R, no
amounts prior to adoption, on October 1 , 2003, have been reclassified. The amount remaining in minority interest and
preferred dividends of subsidiaries related to these mandatorily redeemable preferred securities of subsidiary trusts for the
nine-month period ended September 30, 2003, was $170.2 million.
Income tax expense for the year ended December 31 2004, decreased $5.3 million to $265.0 million from $270.3 million for
the same period in 2003. The effective tax rate was 33.2% and 31.5% for the years ended December 31 , 2004 and 2003,
respectively. The increase in the effective tax rate in 2004 was mainly due to the effect pf the $170.2 million of tax deductible
interest on subordinated debt not included in income from continuing operations before income tax expense, minority interest
and preferred dividends of subsidiaries and equity income in 2003, partially offset by the $24.4 million tax payment made in
connection with the NIA arbitration settlement at CE Casecnan in 2003, and the settlement by CE Electric UK of various
positions with the Inland Revenue department and a change in the State of Iowa s income tax laws in 2004.
PacifiCorp
Exhibit No. II , page 39 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and
equity income decreased $58.7 million, or 6.8%, to $799.2 million in 2004 from $857.9 million in 2003. The decrease was
due to the following:
Reportable Segments
Corporate
. Kern River s pre-tax earnings were $8.9 million higher due to the completion of the 2003 Expansion Project in May
2003, partially offset, by lower capitalized interest in connection with completing the expansion. In 2004, Kern River
collected $14.8 million on its claim for damages against Mirant for the rejection by Mirant Qf its finn gas
transportation contract. The income was largely offset by revenue lost related to the rejection of the agreement.
Northern Natural Gas' pre-tax earnings were $90.7 million higher due to a $72.2 million pre-tax gain on the sale of
the Emon Note Receivable -and improved results associated with the May 2003 rate case which resulted in higher
rates commencing November 1 2003.
CE Electric UK's pre-tax earnings were $37.2 million higher primarily from the approximately $34.0 million
favorable earnings impact of the continued weakness of the U.S. dollar relative to the British pound, partially offset
by the $8.9 million gain from the sale of a local operational and dispatch facility at Northern Electric in 2003.
CalEnergy Generation-Foreign s pre-tax earnings were $11.9 million lower in 2004 compared to 2003. In 2003
CE Casecnan recorded $31.9 million of income in connection with the settlement of its arbitration with the NIA.
That gain was partially offset by the settlement of various disputes which the Leyte Projects had with PNOC-EDC
which resulted in the reversal of accrued revenue totaling $11.3 million. In 2004, CE Casecnan had lower revenue as
a result of its contract arbitration settlement, which was fully offset by higher revenue at the Leyte Projects due to
price indices and lower interest expense on the repayment of project debt. Also in 2004, CalEnergy Generation-
Foreign earned higher interest income on affiliate loans of$8.7million.
Pre-tax earnings at HomeServices were $21.9 million higher due to higher average home sales prices and
acquisitions not included in the comparable 2003 period.
The Company s adoption of FIN 46R, as previously described, required that amounts previously recorded in
minority interest and preferred dividends of subsidiaries be recorded as interest expense in the Company
consolidated statements of operations prospectively. As a result, the charges for interest expense related to securities
of the Company s finance subsidiaries increased by $147.1 million to $196.9 million in 2004 from $49.8 million in
2003.
During June 2003, the Company sold its investment in Williams Cumulative Convertible Preferred Stock. As a
result, 2003 pre-tax earnings included $32.6 million from the gain on the sale and dividend income.
The Companys corporate interest expense increased $11.5 million primarily as a result of the issuance of the
$250.0 million of 5.00% senior notes in February 2004.
Revenue
PacifiCorp
Exhibit No. ) ), page 40 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Operating revenue for the year ended December 31 , 2004 increased $587.8 million or 9.9% to $6,553.4million from
965.6 million for the same period in 2003. The following table summarizes operating revenue by segment for the yearsended December 31 (in millions):
Year Ended December 31,2004 2003
Operating revenue:
MidAmerican Energy
Kern River
Northern Natural Gas
CE Electric UK
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other
Total operating revenue
$ 2 701.7
316.
544.
936.
307.4
39.
1.756.4
601.
$ 6.553~
$ 2,600.
260.
486.
830.
326.
45.
476.
025.
(59.
$ 5.965.
MidArnerican Energy s operating revenue for the year ended December 31, 2004, increased $101.5 million, or 3.9%, to
701.7 million. Regulated and non-regulated natural gas revenue increased $53.8 million, or 4.8%, to $1 166.5 million
mainly due to higher prices for natural gas purchased for regulated customers, which is passed directly to the customer, and
regulated wholesale volumes. Average natural gas prices increased 7.4% from 2003 to 2004. These price increases were
partially offset by lower regulated retail and non-regulated volumes. Regulated and non-regulated electric revenue increased
$49.8 million, or 3., to $1 518.9 million mainly due to higher regulated retail and non-regulated volumes as well as prices
of wholesale sales. These increases were partially offset by lower regulated wholesale volumes and regulated retail prices.
Operating revenue at Kern River and Northern Natural Gas is principally derived by providing finn or interruptible
transportation services under long-tenn gas transportation service agreements. Northern Natural Gas also derives part of its
revenue from storing gas. Kern River s operating revenue for the year ended December 31 2004, increased $55.9 million, or
21.5%, to $316.1 million primarily due to the transportation fees earned in connection with the 2003 Expansion Project
which began operations May 1 , 2003. Northern Natural Gas' operating revenue , which reflects the impact of the new rates
beginning November 1 2004 and 2003, and higher gas and liquid sales, increased $57.9 million, or 11.9%, to $544.8 million
for the year ended December 31 , 2004.
CE Electric UK's operating revenue for the year ended December 31, 2004, increased $106.4 million, or 12.8%, to
$936.4 million primarily as a result of the weaker U.S. dollar. Additionally, CE Electric UK experienced increased revenue atits contracting business.
Operating revenue for CalEnergy Generation~Foreign for the year ended December 31, 2004, decreased $19.0 million, or
8%, to $307.4 million primarily due to lower water delivery fees in connection with the NIA arbitration settlement at CE
Casecnan effective in the fourth quarter of 2003, partially offset by higher energy fees due to increased generation on higher
water flows in 2004.
HomeServices' operating revenue for the year ended December 31 , 2004, consisting mainly of commission revenue from real
estate brokerage transactions, increased $279.8 million, or 18., to $1 756.4 million. The increase is due primarily to
growth at existing businesses of $154.7 million due primarily to higher average home sales prices and acquisitions not
included in the comparable 2003 period totaling $125.1 million. During the year ended December 31, 2004, HomeServices
participated in $59.8 billion of transactions, an increase of$I1.2 billion from 2003. About 24% of the increase came from the
six acquisitions made during the year.
PacifiCorp
Exhibit No. II, page 41 of 130
CASE NO. P AC-05-
Witness: Patrick J. Goodman
Costs and expenses
Cost of sales for the year ended December 31, 2004, increased $351.4 million, or 14.6%, to $2 751.9 million from
400.5 million for the same period in 2003. HomeServices' cost of sales, consisting primarily of commissions on real estate
brokered transactions, increased $211.8 million due to higher commission expense on incremental sales at existing business
uriits and acquisitions not included in the comparable 2003 period. MidAmerican Energy s costs of sales increased
$87.4 million due mainly to an increase in the per unit cost of natural gas, higher regulated wholesale natural gas, regulated
retail electric and non-regulated electric volumes, partially offset by lower regulated retail and non-regulated natural gas
volumes. Northern Natural Gas' cost of sales increased $18.9 million due to higher gas and liquid sales. CE Electric UK'
cost of sales increased $16.7 million mainly due to increased activity at its contracting business and the wea~er U.S. dollar,
partially offsetby lower exit charges from the National Grid Company at both Northern Electric and Yorkshire Electricity.
Operating expenses for the year ended December 31 , 2004, increased $125.6 million, or 8.3%, to $1 637.9 million from
512.3 million for the same period in 2003. HomeServices' operating expenses, consisting mainly of compensation,
marketing and other administrative costs, increased $44.8 million due mainly to acquisitions not included in the comparable
2003 period. MidArnerican Energy s operating expenses increased $40.3 million due mainly to higher generation
maintenance costs, Quad Cities Station expenses, and transmission expenses. CE Electric UK's operating expenses increased
$39.3 million, mainly due to higher pension costs and the weaker U.S. dollar in 2004, and a gain on the sale of a local
operational dispatch facility in 2003. Kern River s operating expenses increased $16.4 million due to the commencement
operations of the 2003 Expansion Project. CalEnergy Generation-foreign s operating expenses decreased $12.5 million
mainly due to lower legal and other costs in 2004.
Depreciation and amortization for the year ended December 31 , 2004, increased $35.3 million to $638.2 million from
$602.9 million for the same period in 2003. Kern River s expense increased $16.5 million due to the completion of the 2003
Expansion Project. Northern Natural Gas' expense increased $15.2 million due to higher depreciation rates consistent with
the filed rate case. CE Electric UK's expense increased $12.7 million primarily due to the weaker U.S. dollar. Partially
offsetting these increases was a decrease in MidArnerican Energy s expense of $14.6 million due primarily to a decrease in
regulatory expense related to its revenue sharing arrangements.
Other income and expense
Interest expense for the year ended December 31 2004, increased $142.2 million to $903.2 million from $761.0 million for
the same period in 2003. On October 1, 2003, the Company adopted fIN 46R related to certain finance subsidiaries. The
adoption required that amounts previously recorded in minority interest and preferred dividends of subsidiaries be recorded
as interest expense in the accompanying consolidated statement of operations, prospectively. for the year ended
December 31, 2004 and the three-month period ended December 31, 2003, the Company has recorded $196.9 million and
$49.8 million, respectively, of interest expense related to these finance subsidiaries. In accordance with the requirements of
FIN 46R, no amounts prior to adoption on October 1 , 2003 have been reclassified. The amount included in minority interest
and preferred dividends of subsidiaries related to these finance subsidiaries for the nine-month period ended September 30,
2003, was $170.2 million. Other interest expense decreased $4.9 million. The Company incurred lower interest expense of
$42.9 million due mainly to the Company s scheduled redemption of$215.0 million of 6.96% senior notes in September
2003, redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust securities in June 2003, and
reductions in subsidiary project debt. The Company incurred additional interest e~pense, totaling $38.0 million, on the
Company s debt issuances of $450.0 million of 3.5% senior notes in May 2003 and $250.0 million of 5.0% senior notes in
February 2004 and the effects of the weaker U.S. dollar.
Capitalized interest for the year ended December 31 , 2004, decreased $10.5 million to $20.0 million from $30.5 million for
the same period in 2003. The decrease was mainly due to the discontinuance of capitalizing interest on Kern River s 2003
Expansion Project, partially offset by increased construction activity at MidAmerican Energy s generation projects.
Interest and dividend income for the year ended December 31 , 2004, decreased $9.0 million to $38.9 million from
$47.9 million for the same period in 2003. The decrease was mainly due to dividend income received in 2003 from the
Company s investment in Williams Cumulative Convertible Preferred Stock that was sold in June 2003, partially offset by
higher interest income at CE Electric UK resulting from higher cash balances.
Other income for the year ended December 31 , 2004, increased $31.6 million to $128.2 million from $96.6 million for the
same period in 2003. In 2004, the Company recognized a $72.2 million gain on Northern Natural Gas' sale of the EnroD Note
J"aCITILorp
Exhibit No. 11, page 42 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
Receivable and a $14.8 million gain on amounts collected by Kern River on its claim for damages against Mirant. In 2003,
the Company recognized a $31.9 million gain in connection with the NIA arbitration settlement and a $13.8 million gain on
the sale of Williams Cumulative Convertible Preferred Stock. Additionally, the allowance for equity funds used during
construction for the year ended December 31 2004, decreased $6.2 million due primarily to the completion of Kern River
expansion in 2003.
Results of Operations for the Year Ended December 31,2003 and the Year Ended December 31,2002
The following table summarizes net income for the years ended December 31 (in millions):
20022003
Income from continuing operations before income tax expense, minority interest
and preferred dividends of subsidiaries and equity income:
MidAmerican Energy
Kern River
Northern Natural Gas
CE Electric UK
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other
, Income from continuing operations before income tax expense, minority interest
and preferred dividends of subsidiaries and equity income
Income tax expense
Minority interest and preferred dividends of subsidiaries
Income from continuing operations before equity income
Equity income
Income from continuing operations
Loss from discontinued operations, net of tax benefits
Net income available to common and preferred stockholders
271.4
133.
127.
288.
177.
2.1
90.
090.
238.
60.
42.
266.
147.
(1.
61.2
, 817.
--L1!W
857.
270.3
183.
404.4
38.
442.
(27.1.)
631.
111.
163.
356.
40.
397.4
---D..W
The loss from discontinued operations, net of tax benefits, for the year ended December 31, 2003, was $27.1 million as
compared to $17.4 million for 2002 and consists of losses from the operation of the Company s Zinc Recovery Project.
Income from continuing operations for the year ended December 31, 2003, increased $45.3 million, or 11.4%,
$442.7 million compared with $397.4 million for the same period in 2002.
Equity income for the year ended December 31 2003, decreased $2.2 million to $38.3 million compared with $40.5 million
for the same period in 2003. Equity income from non-regulated generation equity investments decreased $16.6 million '
$14.8 million from $31.4 million in 2002 mainly due to the expiration of a contract at the Power Resources project and a
charge associated with an equity investment. Equity income from HomeServices for the year ended December 31, 2003
increased $14.8 million to $23.6 million primarily due to increased refinancing activity at mortgage joint ventures.
Minority interest and preferred dividends for the year ended December 31 , 2003, increased $19.7 million to $183.2 million
from $163.5 million for the same period in 2002. As previously described, the Company was required to adopt, as of
October 1, 2003, FIN 46R related to certain finance subsidiaries. The adoption required that amounts previously recorded in
minority interest and preferred dividends of subsidiaries be recorded as interest expense in the Company s consolidated
statements of operations prospectively. In accordance with the requirements of FIN 46R, no amounts prior to adoption, on
October 1 , 2003, have been reclassified. The amount remaining in minority interest and preferred dividends of subsidiaries
related to these securities increased $22.5 million to $170.2 million for the nine-month period ended September 30, 2003,
from $147.7 million for the year ended December 31 , 2002. Mandatorily redeemable preferred securities of subsidiary trusts
were issued in 2002 to finance the acquisitions of both Kern River and Northern Natw:al Gas.
Income tax expense for the year ended December 31 2003, increased $159.0 million to $270.3 million from $111.3 million
for the same period in 2002. The effective tax rate was 31.5% and 17.6% for the years ended December 31 , 2003 and 2002
respectively. The increase in the effective tax rate was primarily due to increased tax expense on foreign income including
- ---.._~.Exhibit No. 11 , page 43 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
the incremental tax expense of $24.4 million in connection with the CE Casecnan NIA arbitration settlement proceeds. The
2002 effective tax rate was unusually low as the Company recognized tax benefits of $35.7 million in connection with the
execution of the TPL restructuring agreement at CE Electric UK.
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and
equity income increased $226.2 million, or 35.8%, to $857.9 million in 2003 from $631.7 million in 2002. The increase was
due to the following:
Reportable Segments
Corporate
Pre-tax earnings at MidAmerican Energy were higher by $32.6 million. The reportable segment earned higher
regulated Iowa electric income as it benefited from the first phase of the Greater Des Moines Energy Center
beginning operation in May 2003 , higher equity funds used during the construction of its electric generation
projects, and certain non-recurring items, including lower fuel costs resulting from a contract restructuring and the
settlement of a bankruptcy claim.
Kern River, acquired in March 2002, and Northern Natural Gas, acquired in August 2002, had higher pre-tax
earnings of $73.0 million and $84.4 million, respectively, due mainly to the inclusion of the acquisitions for a full-
year of operations in the Company s consolidated results and the completion of Kern River s 2003 Expansion
Project.
CE Electric UK's pre:"tax earnings were higher by $21.9 million. Approximately $20.0 million of the increase
resulted from higher distribution revenue at Yorkshire Electricity, $18.5 million was due to the earnings benefit of
the continued weakness of the U.s. dollar relative to the British pound, $11.3 million related to lower costs primarily
achieved from economies of scale with Northern Electric and Yorkshire Electricity, $14.4 million was a result of the
gain and lower interest costs associated with a bond redemption, $8.9 million related to the gain on sale of a local
operational and dispatch facility at Northern Electric, and $7.0 million for rebates received from the National Grid
Company. These increases were partially offset by the sale of several of its north sea, natural gas assets resulting in a
pre-tax gain of $54.3 million.
Pre-tax earnings at CalEnergy Generation-Foreign were higher by $29.7 million. In 2003, CE Casecnan recorded
$31.9 million of other income in connection with the settlement of its arbitration with the NIA. The 2003 gain was
partially offset by the settlement of various disputes which the Leyte Projects had with PNOC-EDC, which resulted
in the reversal of accrued revenue totaling $11.3 million. The other significant difference in 2003 was the decrease
in financial expense of $1 0.6 million due to repayment of debt and lower variable interest rates.
HomeServices' pre-tax earnings were higher by $28.8 million due to acquisitions made throughout 2002 and 2003
and due to growth from higher home prices and higher mortgage refinancing activity at existing companies.
The Company s adoption of FIN 46R, as previously described, required that amounts previously recorded in minority
interest and preferred dividends of subsidiaries be recorded as interest expense in the Company s consolidated
statements of operations prospectively. The charge to interest expense related to securities of the Company s finance
subsidiaries was $49.8 million in 2003 and $ - million in 2002.
Revenue
PacifiCorp
Exhibit No. II, page 44 of I 30
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
Operating revenue for the year ended December 31, 2003 increased $1 170.4 million or 24.4% to $5,965.6 million from
795.2 million for the same period in 2002. The following table summarizes operating revenue by segment for the years
ended December 31 (in millions):
Operating revenue:
MidAmerican Energy
Kern River
Northern Natural Gas
CE Electric UK
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other
Total operating revenue
Year Ended December 31,2003 2002
$ 2,600.
260.
486.
830.
326.4
45.
1.476.
025.
(59.
$ 5.965.
$ 2,240.
127.
178.
795.4
326.3
38.
1.138.
844.
MidAmerican Energy s operating revenue for the year ended December 31; 2003, increased $359.3 million, or 16.0%, to
600.2 million. MidAmerican Energy s regulated and non-regulated gas revenue for the year ended December 31 , 2003
increased $308.4 million to $1 112.7 million from $804.3 million in 2002 mainly due to higher prices for gas purchased for
regulated customers which is passed directly to the customer. Average gas prices increased 59.9% or $2.24 per Dth from
2002 to 2003. Regulated electric revenue for the year ended December 31 2003 increased $44.6 million to $1 398.0 million
from $1,353.4 million for the same period in 2002 mainly due to higher prices of wholesale sales during 2003.
Operating revenue at both pipelines is principally derived by providing finD or interruptible transportation services under
long-tenD gas transportation service agreements. Northern Natural Gas also derives part of its revenue from storing gas. Kern
River s operating revenue for the year ended December 31 , 2003, increased $132.9 million to $260.2 million. The increase
was primarily due to the transportation fees earned in connection with the 2003 Expansion Project which began operations
May 1 , 2003, and to a lesser degree, the inclusion of its operations for all of 2003. Northern Natural Gas' operating revenue
for the year ended December 31, 2003, increased $308.8 million to $486.9 million. Northern Natural Gas was acquired on
August 16, 2002. The increase in its operating revenue relates to the timing of that acquisition and inclusion of its operations
for all'of2003.
CE Electric UK's operating revenue for the year ended December 31 , 2004, increased $34.6 million, or 4.4%, to
$830.0 million. The increase was a result of the weaker U.S. dollar, higher distribution revenue and higher revenue at its
contracting business. This was partially offset by lower revenue caused by the sale of CE Gas assets in 2002.
HomeServices' operating revenue for the year ended December 31 , 2003, consisting mainly of commission revenue from real
estate brokerage transactions, increased $338.3 million, or 29.7%, to $1,476.6 million. The increase was due to acquisitions
made throughout 2002 and 2003 and $91.3 million due to growth at existing companies. During the year ended December 31
2003, HomeServices participated in $48.6 billion of transactions, an increase of $11.7 billion from 2002. About 23% of the
increase came from the four acquisitions made during the year.
Costs and expenses
Cost of sales for the year ended December 31 , 2003 increased $5565 million, or 30.2%, to $2 400.5 million from
844.0 million for the same period in 2002. MidAmerican Energy s cost of sales for the year ended December 31 , 2003
increased $345.6 million, or 34.9%, to $1,334.5 million from $988.9 million for the same period in 2002. MidAmerican
Energy s regulated and non-regulated gas cost of sales for the year ended December 31 , 2003 increased $291.1 million to
$878.1 million from $587.0 million in 2002 mainly due to the increase in per unit cost of gas discussed in operating revenue.
Electric cost of sales increased $51.0 million in 2003 primarily due to the reclassification of costs for energy purchased under
the Cooper Nuclear Station restructured contract between MidAmerican Energy and the Nebraska Public Power District
which expired in December 2004. Prior to August 1 , 2002, the date of the restructuring, only fuel costs for energy purchased
- --...~v.Exhibit No. II, page 45 of 130
CASE NO. P AC-05-Wit~~s: Patrick J. Goodman
from Cooper Nuclear Station were classified as a cost of sales. Consistent with the restructured contract, other costs under the
contract are classified as operating expenses. Following the restructuring, all costs for energy and capacity purchased under
the contract were included in cost of sales consistent with the new power purchase contract. Operating expenses decreased
accordingly.
HomeServices' cost of sales, consisting primarily of commissions on real estate brokerage transactions, increased
$235.6 million for the year ended December 31 2003, or 30.7%, to $1 003.2 million from $767.6 million for the same period
in 2002. Cost of sales increased $106.7 million due to acquisitions made during 2002 and 2003. The remainder of
HomeServices' increase was due to growth of existing companies totaling $128.9 million.
Operating expenses for the year ended December 31, 2003 increased $209.5 million, or 16.-1 %, to $1 512.3 million from
302.8 million for the same period in 2002. An increase of $146.6 million was due to Northern Natural Gas, which was
owned for the entire period in 2003. Increased operating expenses at HomeServices were $78.8 million, primarily due to the
impact of acquisitions and increased compensation expenses. These increases were partially offset by lower operating
expenses at CE Electric UK of $39.6 million, mainly due to the sale of the retail business in 2002 and a gain on the sale of a
local operational dispatch facility in 2003, and lower operating expenses at MidAmerican Energy of $19.5 million primarily
due to the restructuring of the Cooper contract.
Depreciation and amortization for the year ended December 31, 2003 increased $72.8 million, or 13.7%, to $602.9 million
from $530.1 million for the same period in 2002. An increase of $34.6 million was due to Northern Natural Gas, which was
owned for the entire period in 2003. Increased depreciation at Kern River was $19;6 million mainly due to the completion of
the 2003 Expansion Project and the inclusion of Kern River s operations for the entire period. Increased depreciation of
$11.6 million at MidAmerican Energy due to higher utility plant depreciation and increased depreciation of $8.2 million at
CE Electric UK due to a weaker U.S. dollar and an increased asset base, partially offset by the CE Gas asset sale in 2002.
In 2002, CE Gas executed the sale of several of its assets and recorded a pre-tax gain of $54.3 million, which included a write
off of non-deductible goodwill of $49.6 million. Refer to Note 5 of Notes to Consolidated Financial Statements included in
Item 8. 'Financial Statements and Supplementary Data" of this Fonn 10-K for additional infonnation regarding the assetsales.
Other Income and Expense
Interest expense for the year ended December 31 , 2003 increased $128.9 million to $761.0 million from $632.1 million for
the same period in 2002. The increase was mainly due to interest on parent company subordinated debt which was
$49.8 million for the quarter and year ended December 31 2003. This amount represents the interest recorded on the parent
company subordinated debt for the period from October I , 2003, the date the Company adopted FIN 46R, through
December 31, 2003. Prior to the adoption of FIN 46R, the parent company subordinated debt was classified as company-
obligated mandatorily redeemable preferred securities of subsidiary trusts. Costs associated with those instruments, prior to
the adoption of FIN 46R, were classified as minority interest and preferred dividends of subsidiaries in the accompanying
consolidated statements of operations. The remaining $79.1 million increase resulted from additional interest expense totaling
$38.9 million on MEHC's debt issuances of $700.0 million in October 2002 and $450.0 million in May 2003, increased
interest expense of $32.5 million at Northern Natural Gas primarily due to a full year of ownership and increased interest
expense at Kern River of $32.2 million due to additional borrowings related to the 2003 Expansion Project and a full year of
ownership. The increases were partially offset by decreased interest, totaling $27.9 million, due to the combination of the
June 2003 redemption of the Yorkshire Electricity securities, reductions in CalEnergy Generation-Foreign project debt
MEHC's revolving credit facility and the retirement of MEHC's 6.96% Senior Notes.
Capitalized interest for the year ended December 31, 2003 increased $7.1 million to $30.5 million. The increase was mainly
due to Kern River s 2003 Expansion Project and increased construction activity at MidAmerican Energy s generation
projects.
Interest and dividend income for the year ended December 31, 2003 decreased $8.1 million to $47.9 million from
$56.0 million for the same period in 2002. The decrease was primarily due to lower , income at CE Electric UK. of
$9.9 million due to lower cash balances partially offset by higher dividend income on the investment in Williams Cumulative
Convertible Preferred Stock totaling $4.7 million and interest earned on higher corporate cash balances available during
2003.
- ------Exhibit No. )), page 46 of ) 30CASE NO. PAC-05-Witness: Patrick J. Goodman
Other income for the year ended December 31 , 2003, increased $56.4 million to $96.6 million from $40.2 million for the
same period in 2003. In 2003, the Company recognized a $31.9 million gain in connection with the NIA arbitration
settlement and a $13.8 million gain on the sale of Williams Cumulative Convertible Preferred Stock. Additionally, the
allowance for equity funds used during construction for the year ended December 31, 2003, increased $7.3 million due
primarily to the construction of Kern River s expansion in 2003.
Other expense for the year ended December 31 , 2003, decreased $22.7 million to $5.9 million from $28.6 million for the
same period in 2002. In 2002, MidAmerican Energy recorded an impairment of its investment in airplane leases and other
non-regulated investments of $21.7 million.
Liquidity and Capital Resources
The Company has available a variety of sources of liquidity and capital resources, both internal and external. These resources
provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The
Company may from time to time seek to retire its outstanding securities through cash purchases in the open market, privately
negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the
Company s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Each of MEHC's direct or indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other
subsidiaries. Pursuant to separate financing agreements at each subsidiary, the assets of each subsidiary may be pledged or
encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should ,not be assumed
that any asset of any subsidiary of MEHC will be available to satisfy the obligations of MEHC or any of its other
subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to
applicable law and the terms of financing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise
distributed or contributed to MEHC or affiliates thereof.
The Company s cash and cash equivalents were $960.9 million at December 31 , 2004 compared to $660.2 million at
December 31, 2003. In addition, the Company recorded separately, in restricted cash and short-term investments and in
deferred charges and other assets, restricted cash and investments of$I64.5 million and $119.5 million at December 31 , 2004
and 2003, respectively. The restricted cash balance for both periods is comprised primarily of amounts deposited in restricted
accounts which are reserved for the service of debt obligations, customer deposits held in escrow, custody deposits and
unpaid dividends declared obligations.
Cash Flows from
The Company generated cash flows from operations of $1 424.6 million for the year ended December 31, 2004, compared
with $1,217.9 million for the same period in 2003 . The increase was mainly due to greater income from continuing
operations and a tax refund as a result of a 2003 net operating loss from accelerated depreciation. Also contributing to the net
increase in cash flows from operations were changes in working capital, partially offset by lower distributions from equity
investments.
Cash Flows from Investing Activities
Cash flows used in investing activities for the years ended December 31 , 2004 and 2003 were $1 029.7 million and
003.2 million, respectively. Capital expenditures, construction and other development costs for the years ended
December 31 , 2004 and 2003 were $1 179.4 million and $1 219.4 million, respectively. In addition to the capital
expenditures, contributing to the increase of cash flows used in investing activities was $288.8 million of proceeds from the
sale of convertible preferred securities in 2003, partially offset by the receipt of the proceeds of the put of the ROP Note, and
sale of the Enron Note Receivable claim, as described below.
Put of ROP Note and Receipt of Cash
On January 14, 2004, CE Casecnan exercised its right to put the ROP Note to the ROP and, in accordance with the terms of
the put option, CE Casecnan received $99.2 million (representing $97.0 million par value plus accrued interest) from the
ROP on January 21, 2004.
Sale of Enron Note Receivable and Receipt of Cash
t'aCltlCOrp
Exhibit No. II , page 47 of 130
CASE NO. P AC-O5-
Witness: Patrick J. Goodman
Northern Natural Gas had a note receivable of approximately $259.0 million (the "Enron Note Receivable ) with Enroll. As a
result of Enron filing for bankruptcy on December 2, 2001, Northern Natural Gas filed a bankruptcy claim against Enron
seeking to recover payment of the Enron Note Receivable. As of December 31 2001 , Northern Natural Gas had written-off
the note. By stipulation, Enron and Northern Natural Gas agreed to a value of $249.0 million for the claim and received
approval of the stipulation from Enron s Bankruptcy Court on August 26, 2004. On November 23, 2004, Northern Natural
Gas sold its stipulated general, unsecured claim against Enron of $249.0 million to a third party investor for $72.2 million
which was recorded as other income in the fourth quarter of 2004.
Capital Expenditures, Construction and Other Development Costs
Capital expenditures, construction and other development costs were $1 310.3 for the year ended December 31, 2004
compared with $1 179.8 million for the same period in 2003. The following table summarizes the expenditures by business
segment (in millions):
Year Ended December 31,2004 2003
Capital expenditures:
MidAmericanEnergy
Kern River
Northern Natural Gas
CE Electric UK
, CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Segment capital expenditures
Corporate/other
Total capital expenditures
$ 633.
26.
138.
334.
1.3
20.
160.
18.
$ 346.
433.
104.4
301.9
18.
219.
0.1
LlJ.lM
Forecasted capital expenditures, construction and other development costs for fiscal 2005 are approximately $1.3 billion~
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews.
The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital
expenditures relating to operating projects, consisting mainly of recuning expenditures, were $778.3 million for the year
ended December 31,2004. Construction and other development costs were $401.0 million for the year ended December 31
2004. These costs consist mainly of expenditures for large scale, generation projects as follows:
MidAmerican Energy
MidAmerican Energy anticipates a continuing increase in demand for electricity from its regulated customers. To meet
anticipated demand and ensure adequate electric generation in its service tenitory, MidAmerican Energy recently completed
its combined cycle combustion turbine project and is currently constructing the 790 MW CBEC Unit 4 and a 310 MW
(nameplate rating) wind power project in Iowa. A 50 MW (nameplate rating) expan~ion of the wind power project is also
expected to be constructed in 2005. The projects will provide service to regulated retail electricity customers.
MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual costs of the generation
projects in its Iowa rate base as long as actual costs do not exceed the agreed caps that MidAmerican Energy has deemed to
be reasonable. If the caps are exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures
above the caps, subject to regulatory review. Wholesale sales may also be made from the projects to the extent the power is
not immediately needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.1 billion in the
CBEC Unit 4 and wind generation projects currently under construction, of which $350.4 million has been invested through
December 31, 2004.
MidAmerican Energy recently completed work on its Greater Des Moines Energy Center, a natural gas-fired, combined cycle
unit located near Pleasant Hill, Iowa. Construction of the plant was completed in two phases. Commercial operation of the
simple cycle mode began on May 5, 2003, and continued through most of 2004, providing 327 MW of accredited capacity in
PacifiCorp
Exhibit No. 11, page 48 of 130
CASE NO. P AC-05-
Witness: Patrick J. Goodman
the summer of 2004. Commercial operation of the combined cycle mode began on December 16, 2004. The additional
accredited capacity from completion of the second phase is expected to be 190 MW. MidAmerican Energy expects the total
cost of the Greater Des Moines Energy Center to be under the $357.0 million cost cap established by the IUB.
MidAmerican Energy is currently constructing the CBEC Unit 4, a 790 MW (based on expected accreditation) super-critical..
temperature, low-sulfur coal-fired plant. MidAmerican Energy will operate the plant and hold an undivided ownership
interest as a tenant in common with the other owners of the plant. MidAmerican Energy s ownership interest is 60.67%,
equating to 479 MW of output. MidAmerican Energy expects its share of the estimated cost of the project, including
transmission facilities, to be approximately $737.0 million, excluding allowance for funds used during construction.
Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large
base-load plants in Iowa. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui for engineering,
procurement and construction of the plant. On September 9, 2003, MidAmerican Energy began construction of the plant
which it expects to be completed in the summer of 2007. On December 29, 2004, MidAmerican Energy received an order
from the IUB approving construction of the associated transmission facilities and is proceeding with construction.
The second electric generating project currently under construction consists of wind power facilities located at two sites in
north central Iowa totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for wind
power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The current projected
accredited capacity for these wind power facilities is approximately 53 MW. MidAmerican Energy will own and operate
these facilities, which are expected to cost approximately $323.0 million, including transmission facilities and excluding the
allowance for funds using during construction. As of December 31, 2004, wind turbines totaling 160.5 MW at one of the sites
were completed and in service. Completion of the remaining turbines is expected by the middle of 2005. On January 31
2005, the IUB approved ratemaking principles related to expanding the wind power project. An additional 50 MW of
capacity, based on nameplate rating, is expected to be constructed at the sites in 2005 at an estimated cost of $63.0 million.
MidAmerican Energy s total accredited net generating capability in the summer of 2004 was 4 897 MW. Accredited net
generating capability represents the amount of generation available to meet the requirements on MidAmerican Energy
system and consists of MidAmerican Energy-owned generation of 4 481 MW and the net amount of capacity purchases and
sales of 416 MW. The actual amount of generation capacity available at any time may be less than the accredited capability
due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service
for inspection, maintenance, refueling, modifications or other reasons.
HomeServices' Acquisitions
In 2004, HomeServices separately acquired six real estate companies for an aggregate purchase price of $30.7 million, net of
cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2003, these real estate
companies had combined revenue of $95.7 million on approximately 15,000 closed sides representing $3.2 billion of sales
volume. These purchases were financed using HomeServices' cash balances. In 2003, HomeServices separately acquired four
real estate companies for an aggregate purchase price of $36.7 million, net of cash acquired, plus working capital and certain
other adjustments. For the year ended December 31 , 2002, these real estate companies had combined revenue of
$102.9 million on approximately 16 000 closed sides representing $3.6 billion of sales volume. Additionally in 2004
HomeServices paid an eamout of $6.0 million based on 2004 financial perfonnance measures. These purchases were
financed using HomeServices' cash balances and revolving credit facility.
Cash Flows from Financing Activities
Cash flows used in financing activities for the year ended December 31 , 2004 were $122.8 million. During 2004, the
Company used cash for financing activities, totaling $747.9 million ' primarily for repayments of subsidiary and parent
company obligations, including $136.4 million of cash flows from discontinued operations, and generated cash from
financing activities, totaling $625.1 million, from the issuance of subsidiary, project and parent company debt. Cash flows
used in financing activities for the year ended December 31, 2003 were $426.3 million. During 2003, the Company used cash
for financing activities, totaling $2 033.2 million, primarily for repayments of subsidiary obligations and parent company
debt and the retirement of preferred securities of subsidiary trusts, and generated cash from financing activities, totaling
606.9 million, from the issuance of subsidiary, project and parent company debt.
ra\,;J11\..,UljJ
Exhibit No. 11 , page 49 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Recent Debt Issuances, Redemptions and Stock Transactions
On February 12, 2004, MEHC completed the sale of $250 million in aggregate principal amount of its 5.00% senior notes
due February IS, 2014. The proceeds were used to satisfy a demand made by its affiliate, Funding Corporation, for
$136.4 million, the amount remaining on MEHC's guarantee of Funding Corporation s Series F Bonds, and for other general
corporate purposes.
On March 1, 2004, Funding Corporation completed the redemption of an aggregate principal amount of $136.4 million of its
Series F Bonds, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest
to the date of redemption. A demand was also made on MEHC for the full amount remaining on MEHC's guarantee of the
Series F Bonds in order to fund the redemption. MEHC made the requisite payment and, as a result, it has no further liability
with respect to its guarantee. The payment was included in cash flows from discontinued operations.
On October I, 2004, MidAmerican Energy issued $350.0 million of 4.65% medium-term notes due October 1 , 2014. The
proceeds were used for general corporate purposes.
In 2004, the Company made the required $100.0 million payment on its 11.00% parent company subordinated debt. The
payments on subsidiary and project debt made in 2004 consisted of the maturity of CE Electric UK's 6.853% senior notes,
totaling $117.1 million, and regularly scheduled principal payments on project term loans.
On January 6, 2004, the Company purchased a portion of the shares of common stock owned by the Company s chairman
and chief executive officer, for an aggregate purchase price of $20.0 million.
Current Maturities of Long-Term Debt
The Company s current portion of long-term debt increased $644.7 million to $1 145.6 million at December 31 , 2004, from
$500.9 million at December 31, 2003, due mainly to $260.0 million of 7.23% parent company senior notes becoming due in
the third quarter of 2005, and, pursuant to a call option exercised in February 2005, at a cost of $17.5 million, a subsidiary of
CE Electric UK purchased, and then cancelled, its Variable Rate Reset Trust Securities, due in 2020, at a par value of
;(155.0 million. Accordingly, the Company has included the entire principal amount of these securities in its current portion
of long-tenD debt in the accompanying consolidated balance sheet. The Company plans to use existing cash and future debt
issuances to repay these obligations.
Restricted Cash and Short-Term Investments
During the year ended December 31 , 2004, CE Casecnan increased its restricted cash related to obligations for debt service
and unpaid dividends declared. Additionally, Northern Natural Gas increased its restricted cash related to custody deposits.
Piscontinueq Oyerations - Zinc Recovery Project and Mineral Assets
Indirect wholly-owned subsidiaries of MEHC, own the rights to commercial quantities of extractable minerals from elements
in solution in the geothermal brine and fluids utilized at the Imperial Valley Projects and a zinc recovery plant constructed
near the Imperial Valley Projects designed to recover zinc from the geothermal brine through an ion exchange, solvent
extraction, electrowinning and casting process.
The Zinc Recovery Project began limited production during December 2002 and continued limited production until
September 10, 2004. Efforts to increase production had continued since the Zinc Recovery Project was place in service with
an emphasis on process modification. Management had been assessing the long-term economic viability of the Zinc
Recovery Project in light of continuing cash flpw deficits and operating losses and the efforts to increase production, and had
continued to evaluate the expected impact of the planned improvements to the extraction process during the third quarter of
2004. Furthennore, management had been exploring other operating alternatives, such as establishing strategic partnerships
and consideration of ceasing operations of the Zinc Recovery Project.
On September 10, 2004 management made the decision to cease operations of the Zinc Recovery Project, effective
immediately. Based on this decision, a non-cash, after-tax impairment charge of $340.3 million has been recorded to write-off
the Mineral Assets.
t'acltlCOrp
Exhibit No. 11, page 50 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
. --
In connection with' ceasing operations, the Zinc Recovery Project's assets are being dismantled and sold and certain
employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. Cash expenditures of
approximately $4.1 million, consisting of pre-tax disposal costs, tennination benefit costs and property taxes, were made
through December 31 , 2004. The Company expects to make additional cash expenditures of pre-tax disposal costs and
property taxes of approximately $1.6 million. Substantially all of such costs are expected to relate to disposal activities, and a
portion of the disposal costs is expected to be offset by proceeds from sales of the Zinc Recovery Project's assets. These costs
are recognized in the period in which the related liability is incurred. Salvage proceeds will be recognized in the period
earned. Implementation of a disposal plan began in September 2004 and will continue in 2005. The Company also expects to
receive approximately $55 million in future tax benefits.
The operating losses from discontinued operations before income taxes during the years ended December 31, 2004, 2003 and
2002 were $42.7 million, $46.4 million and $29.1 million, respectively. 1\
Credit Ratings Risks
Debt and preferred securities of the Company may be rated by nationally recognized credit rating agencies. Assigned credit
ratings are based on each rating agency s assessment of the rated company s ability to, in general, meet the obligations of its
debt or preferred securities; The credit ratings are not a recommendation to buy, sell or hold securities, and there is no
assurance that a particular credit rating will continue for any given period of time. Other than the agreements discussed
below, the Company does not have any credit agreements that require tennination or a material change in collateral
requirements or payment schedule in the event ofa downgrade in the credit ratings of the respective company s securities.
In conjunction with its wholesale marketing and trading activities, MidAmerican Energy must meet credit quality standards
as required by counterparties. MidAmerican Energy has energy trading agreements that, in accordance with industry practice,
either specifically require it to maintain investment grade credit ratings or provide the right for counterparties to demand
adequate assurances" in the event of a material adverse change in MidAmerican Energy s creditworthiness. If one or more
of MidAmerican Energy s credit ratings decline below investment grade, MidAmerican Energy may be required to post cash
collateral, letters of credit or other similar credit support to facilitate ongoing wholesale marketing and trading activities. As
of December 31 , 2004, MidAmerican Energy estimated potential collateral requirements totaled approximately
$151.0 million. MidAmerican Energy s collateral requirements could fluctuate considerably due to seasonality, market price
volatility, and a loss of key MidAmerican Energy generating facilities or other related factors.
Yorkshire Power Group Limited ("YPGL"), a subsidiary of CE Electric UK, entered into certain currency rate swap
agreements for its Yankee Bonds with three large multi-national financial institutions. The swap agreements effectively
convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the $281.1 million of the 6.496% Yankee Bonds
outstanding at December 31 2004, the agreements extend until February 25,2008 and convert the U.S. dollar interest rate to
a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31,
2004 was $96.1 million based on quotes from the counterparties to these instruments and represents the estimated amount
that the Company would expect to pay if these agreements were tenninated. Certain of these counterparties have the option to
tenninate the swap agreements and demand payment of the fair value of the swaps if YPGL's credit ratings from the three
recognized credit rating agencies decline below investment grade. As of December 31, 2004, YPGL's credit ratings from the
three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment
requirements would have been approximately $44.8 million.
Inflation
Inflation has not had a significant impact on the Company s costs.
n1~JJJ\...Urp
Exhibit No. II, page 51 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Obligations and Commitments
The Company has contractual obligations and commercial commitments that may affect its financial condition. Contractual
obligations to make future payments arise from parent company and subsidiary long-term debt and notes payable, preferred
equity securities, operating leases and power and fuel purchase contracts. Other obligations arise from unused lines of credit
and letters of credit. Material obligations as of December 31, 2004 are as follows (in millions):
Total
Payments Due By Periodsc:: 2-3 4-1 Year, Years Years
;;:.5
Years
Contractual Cash Obligations:
Parent company senior debt 032.260.550.$ 1,000.$ 1,222.
Parent company subordinated debt 774.4 188.468.468.649.
Subsidiary and project debt 190.4 885.695.844.765.
Preferred securities of subsidiaries 89.89.
Interest payments on long-tenD debt(l)588.811.9 417.056.302.
Coal, electricity and natural gas contract
commitments (2)668.173.255.122.118.
Operating leases (2)375.70.121.0 78.104.
Deferred costs on construction contracts (3)152.3 152.3
Total contractual cash obligations $ 20.870.$2.389.4 659.$ 3.570.$11.251.7
Total
Commitment Expiration per Periodc:: 2-3 4-
1 Year Years Years
;;:.5
Years
Other Commercial Commitments:
Unused parent company revolving lines of credit
Parent company letters of credit
Unused subsidiary lines of credit
Total other commercial commitments
$ 30.
71.1
144.
$ 246.
30.
71.1
144.
$ 216.30.
(1)Excludes interest payments on variable rate long-term debt.
(2)The coal, electricity and natural gas contract commitments and operating leases are not reflected on the consolidated
balance sheets.
(3)MidAmerican Energy is allowed to defer up to $200.0 million in payments to Mitsui under its engineering,
procurement and construction contract to build the CBEC Unit 4, which is expected to be complete in the summer of
2007.
The Company has other types of commitments that are subject to change and relate primarily to the items listed below. For
additional infonnation, refer, where applicable, to the respective referenced note of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data" of this Form 10-
Construction expenditures (see Note 6)
Asset retirement obligations (see Note 10)
Debt service reserve guarantees (see Note 14)
Nuclear decommissioning costs (see Note 21)
Residual guarantees on operating leases (see Note 21)
Off-Balance Sheet Arrangements
PacitiCorp
Exhibit No. 11, page 52 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
The Company has certain investments that are accounted for under the equity method in accordance with accounting
principles generally accepted in the United States of America ("GAAP"). Accordingly, an amount is recorded on the
Company s balance sheet as an equity investment and is increased or decreased for the Company s pro-rata share of earnings
or losses, respectively, less any dividend distribution from such investments.
As of December 31, 2004, the Company s investments which are accounted for under the equity method had $861.3 million
of debt and $40.2 million in outstanding letters of credit. As of December 31, 2004, the Company s pro-rata share of such
debt and outstanding letters of, credit, which is all non-recourse to MEHC, was $430.3 million and $20.1 million
respectively.
MEHC is generally not required to support the debt service obligations of its equity investments. However, default with
respect to this non-recourse debt could result in a loss of invested equity.
New Accounting Pronouncements
In December 2003, the F ASB issued FIN 46R, which served to clarify guidance in F ASB Interpretation No. 46
Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" ("FIN 46"). The
Company adopted and applied the provisions of FIN 46R, related to certain finance subsidiaries, as of October 1, 2003. The
adoption required the deconsolidation of certain finance subsidiaries, which resulted in the amounts previously classified as
mandatorily redeemable preferred securities of subsidiary trusts, in the amount of $1.9 billion, being reclassified to parent
company subordinated debt in the accompanying consolidated balance sheets. In addition, amounts previously recorded as
minority interest and preferred dividends of subsidiaries are now recorded as interest expense in the accompanying
consolidated statements of operations prospectively. For the year ended December 31 , 2004, and the three-month period
ended December 31, 2003, the Company has recorded $196.9 million and $49.8 million, respectively, of interest expense
related to these securities. In accordance with the requirements of FIN 46R, no amounts prior to adoption of FIN 46R on
October 1, 2003 have been reclassified. The amounts included in minority interest and preferred dividends of subsidiaries
related to these securities for the nine-month period ended September 30,2003, and the year ended December 31 2002, were
$170.2 million and $147.7 million, respectively. The Company adopted the provisions of FIN 46R related to non-special
purpose entities in the first quarter of 2004. The Company considered the provisions of FIN 46R for all subsidiaries and their
related power purchase, power sale, or tolling agreements. Factors considered in the analysis include' the duration of the
agreements, how capacity and energy payments are determined, source and payment terms for fuel, as well as responsibility
and payment for operating and maintenance expenses. As a result of these considerations, the Company has determined its
power purchase, power sale and tolling agreements do not represent significant variable interests. Accordingly, the Company
concluded that it is appropriate to continue to consolidate the power plant projects with ownership interests greater than 50%
and not to consolidate the power plants from which it purchases power.
In December 2004, the FASB issued Statement of Financial Accounting Standards ("SFAS") No. 123R, "Share-Based
Payment" ("SFAS 123R"), which replaces SFAS No. 123, "Accounting for Stock-Based Compensation " and supersedes
Accounting Principles Board Opinion No. 25
, "
Accounting for Stock Issued to Employees SFAS 123R establishes
standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services
primarily focusing on the accounting for transactions in which an entity obtains employee services in share-based payment
transactions. SFAS 123R requires entities to measure compensation costs for all share-based payments, including stock
options, at fair value and expense such payments over the service period. Since MEHC is considered a nonpublic entity under
the criteria of SF AS 123R, this standard is effective for annual periods beginning after December 15, 2005. Adoption of this
standard will not have an effect on the Company s financial position, results of operations or cash flows as all of the
Company s outstanding stock options were fully vested at the date of issuance of SFAS 123R.Modifications to outstanding
stock options after the effective date of the standard may result in additional compensation expense pursuant to the provisions
of SF AS 123R
ri11.;111'-V1P
Exhibit No. 11, page 53 of 130
CASE NO. P AC-05-
Witness: Patrick J. Goodman
.--
Critical Accounting Policies
The preparation of financial statements and related documents in conformity with GAAP requires management to make
judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and
accompanying notes. Note 2 to the consolidated financial statements for the year ended December 31 , 2004 included in this
annual report describes the significant accounting policies and methods used in the preparation of the consolidated financial
statements. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment
of long-lived assets, contingent liabilities, accrued pension and post-retirement expense and revenue. Actual results could
differ from these estimates. The following critical accounting policies are impacted significantly by judgments, assumptions
and estimates used in the preparation of the consolidated financial statements.
Accounting for the Effects of Certain Types of Regulation
MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the
provisions of SFAS No. 71, .Accounting for the Effects of Certain Types of Regulation ("SFAS 71"), which differs in
certain respects from the application of GAAP by non-regulated businesses. In general, SF AS 71 recognizes that accounting
for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to
defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that
through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly,
MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs, which will be amortized over
various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a
result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.
A possible consequence of deregulation of the regulated energy industry is that SF AS 71 may no longer apply. If portions of
the Company s regulated energy operations no longer meet the criteria of SFAS 71, the Company could be required to write
off the related regulatory assets and liabilities from its balance sheet, and thus a material adjustment to earnings in that period
could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation legislation.
The Company continues to evaluate the applicability of SF AS 71 to its regulated energy operations and the recoverability of
these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment.
Impairment of Long-Lived Assets and Goodwill
The Company s long-lived assets consist primarily of properties, plants and equipment. Depreciation is computed using the
straight-line method based on economic lives or regulatorily mandated recovery periods. The Company believes the useful
lives assigned to the depreciable assets, which generally range from 3 to 87 years, are reasonable.
The Company periodically evaluates long-lived assets, including properties" plants and equipment, when events or changes in
circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering
event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its
carrying amount. The recoverable amount is the esti~ated net future cash flows that the Company expects to recover from
the future use of the asset, undiscounted and without interest, plus the asset's residual value on disposal. Where the
recoverable amount of the long-lived asset is less than the carrying value, an impairment loss would be recognized to write
down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset.
The estimate of cash flows arising from future use of the asset that are used in the impairment analysis requires judgment
regarding what the Company would expect to recover from future use of the asset. Any changes in the estimates of cash
flows arising from future use of the asset or the residual value of the asset on disposal based on changes in the market
conditions, changes in the use of the asset, management's plans, the determination of the useful life of the asset and
technology changes in the industry could significantly change the calculation of the fair value or recoverable amount of the
asset and the resulting impairment loss, which could significantly affect the results of operations. The determination of
whether impainnent has occurred is primarily based on an estimate of undiscounted cash flows attributable to the assets, as
compared to the carrying value of the assets. An impairment analysis of generating facilities requires estimates of possible
future market prices, load growth, competition and many other factors over the lives of the facilities. A resulting impairment
loss is highly dependent on these underlying assumptions.
. ",","l---Vl P
Exhibit No. 11, page 54 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
.--
The provisions of SFAS No. 142
, "
Goodwill and Other Intangible Assets
" ("
SF AS 142"), which establishes the accounting
for acquired goodwill and other intangible assets, and provides that goodwill and indefinite-lived intangible assets will not be
amortized, requires allocating goodwill to each reporting unit and testing for impainnent using a two-step approach. The
goodwill impainnent test is perfonned annually or whenever an event has occurred that would more likely than not reduce
the fair value of a reporting unit below its'carrying amount. The Company completed its annual review pursuant to SF AS 142
for its reporting units as of October 31 , 2004, primarily using a discounted cash flow methodology. No impainnent was
indicated as a result of these assessments.
Contingent Liabilities
The Company establishes accruals for estimated loss contingencies, such as environmental, legal and regulatory matters
when it is management's assessment that a loss is probable and the amount of the loss can be reasonably. 'estimated. Revisions
to contingent liabilities are recorded in the period in which different facts or infonnation become known or circumstances
change that affect the previous assumptions with respect to the likelihood or amount of loss. Accruals for contingent
liabilities and subsequent revisions are reflected in income when accruals are recorded or as regulatory treatment dictates.
Accruals for contingent liabilities are based upon management's assumptions and estimates, and advice of legal counselor
other third parties regarding the probable outcomes of the matter. Should the outcomes differ from the assumptions and
estimates, revisions to the estimated accruals for contingent liabilities would be required.
Accrued Pension and Postretirement Expense
Pension and postretirement costs are accrued throughout the year based on results of an annual study perfonned by external
actuaries. In addition to the benefits granted to employees, the timing of the cost of these plans is impacted by assumptions
used by the actuaries, including assumptions provided by MEHC for the discount rate and long-tenD rate of return on assets.
Both of these factors require estimates and projections by management and can fluctuate from period to period. Actual
returns on assets are significantly affected by stock and bond markets, over which management has little control. The interest
rate at which projected benefits are discounted significantly affects amounts expensed. Refer to Note 22 of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" of this Fonn 10-K for
additional disclosures regarding the Company s pension and post retirement commitments.
Income Taxes
The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax
basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse.
Based on existing regulatory precedent, MidAmerican Energy is not allowed to recognize deferred income tax expense
related to certain temporary differences resulting from accelerated tax depreciation and other property related basis
differences. For these differences, MidAmerican Energy establishes deferred tax liabilities and regulatory assets on the
consolidated balance sheets since MidAmerican Energy is allowed to recover the increased tax expense when thesedifferences turn around.
The Company has not provided U.S. deferred income taxes on its currency translation adjustment or the cumulative earnings
of international subsidiaries that have been detennined by management to be reinvested indefinitely. These earnings related
to ongoing operations and were approximately $1.5 billion at December 31 2004. Because of the availability of U.S. foreign
tax credits, it is not practicable to detennine the U.S. federal income tax liability that would be payable if such earnings were
not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to
remit those earnings.
The calculation of current and deferred income taxes requires management to apply judgment relating to the application of
complex tax laws or related interpretations and uncertainties related to the outcome of tax audits. Changes in such factors
may result in changes to management's estimates, which could require the Company to adjust its currently recorded tax
assets and liabilities and record additional income tax expense or benefits.
PacltiCorp
Exhibit No. 11, page 55 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
.--
Revenue Recognition
Revenue is recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end
of the period. The Company records unbilled revenue representing the estimated amounts customers will be billed for
services rendered between the meter reading dates in a particular month and the end of that month.
Where billings result in an overrecovery of United Kingdom distribution business revenue against the maximum regulated
amount,- revenue is deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from
revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery ismade.
Revenue from the transportation and storage of gas is recognized based on contractual terms and the related volumes. Kern
River and Northern Natural Gas are subject to the FERC's regulations and, accordingly, certain revenue collected may be
subject to possible refunds upon final orders in pending rate proceedings. Kern River and Northern Natural Gas record
revenue which is subject to refund based on their best estimate of the final outcome of these proceedings and other third party
regulatory proceedings, advice of counsel and estimated total exposure, as well as collection and other risks. The estimate of
the refund is recorded in other current liabilities in the accompanying consolidated balance sheets.
Revenue ftom water and energy delivery is recorded on the basis of the contractual minimum guaranteed water delivery
threshold for the respective contract year. If and when cumulative deliveries within a contract year exceed the minimum
threshold, additional revenue is recognized. Revenue from long-term electricity contracts is recorded at the lower of the
amount billed or the average ofthe contract, subject to contractual provisions at each project.
Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when title has
transferred from seller to buyer. Title fee revenue from real estate transactions and related amounts due to the title insurer are
recognized at the closing, which is when consideration is received. Fees related to loan originations are recognized at the
closing, which is when services have been provided and consideration is received. To the extent the estimated amount differs
from the actual amount, revenue will be affected.
Item 7 Quantitative and Qualitative Disclosures About Market Risk.
The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To
manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments.
Senior management provides the overall direction, structure, conduct and control of the Company s risk management
activities, including the use of financial derivative instruments, authorization and communication of risk management
policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate
systems for recording, monitoring and reporting the results of transactional and risk management activities.
Interest Rate Risk
At December 31, 2004, the Company had fixed-rate long-term debt of $11 503.4 million in aggregate principal amount and
having a fair value of $12 416.2 million. These instruments are fixed-rate and therefore do not expose the Company to the
risk of earnings loss due to changes in market interest rates. However, the fair value 9f these instruments would decrease by
approximately $396.0 million if interest rates were to increase by 10% from their levels at December 31, 2004. In general
such a decrease in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of
these instruments prior to their maturity.
At December 31, 2003, the Company had fixed-rate long-term debt of $11 ,369.4 million in aggregate principal amount and
having a fair value of $12 015.1 million. These instruments were fixed-rate and therefore did not expose the Company to the
risk of earnings loss due to changes in market interest rates.
At December 31 2004, the Company had floating-rate obligations of $493.4 million that expose the Company to the risk of
increased interest expense in the event of increases in short-term interest rates. These obligations are not hedged. If the
floating rates were to increase by 1 %, the Company s consolidated interest expense for unhedged floating-rate obligations
would increase by approximately $0.4 million each month in which such increase continued based upon December 31 , 2004
principal balances.
PacihCorp
Exhibit No. II , page 56 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
. --
At December 31, 2003, the Company had floating-rate obligations of $459.8 million that exposed the Company to the risk
increased interest expense in the event of increases in short-term interest rates. These obligations were not hedged.
Currency Exchange Rate Risk
CE Electric UK entered into currency rate swap agreements for its Senior Notes with large multi-national financial
institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling for
$237.0 million of 6.995% Senior Notes outstanding at December 31 , 2004. The agreements extend until maturity on
December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of
these swap agreements at December 31,2004 and 2003 was $35.7 million and $16.0 million, respectively, based on quotes
from the counterparty to these instruments and represents the estimated amount that the Company would expect to pay ifthese agreements were terminated.
A subsidiary of CE Electric UK entered into certain currency rate swap agreements for its Yankee Bonds with three large
multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate
in Sterling for $281.1 million of 6.496% Yankee Bonds outstanding at December 31 , 2004. The agreements extend until
maturity on February 25, 2008 and convert the U. S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to
7.345%. The estimated fair value of these swap agreements at December 31, 2004 and 2003 was $96.1 million and $62.
million, respectively, based on quotes from the counterparties to these instruments and represents the estimated amount that
the Company would expect to pay if these agreements were terminated.
A 10% devaluation of the U.S. dollar versus Sterling from the value at December 31 2004 would increase the amount owed
by the Company if these swap agreements were terminated by approximately $69.9 million.
Derivatives
As' of December 31, 2004, MidAmerican Energy held derivative instruments used for non-trading and trading purposes with
the following fair values (in thousands):
Contract TVDe
Maturity
in 2005
Non-trading:
Regulated electric assets
Regulated electric (liabilities)
Regulated gas assets
Regulated gas (liabilities)
Regulated weather (liabilities)
Nonregulated electric assets
Nonregulated electric (liabilities)
Nonregulated gas assets
Nonregulated gas (liabilities)
Total
260
(10,057)
973
(21 921)
495)
957
(1,158)
937
(6.606)
(31.11 0
Trading:
Nonregulated gas assets
Nonregulated gas (liabilities)
Total
Maturity
in 2006-
431
817)
798
I!!!!!
$ 2 691
(14 874)
771
(21 921)
495)
329
372)
856
993 993
( 41Q)--1lQQ)(53..Q)
563 --1lQQ)463
Total MidAmerican Energy assets
Total MidAmerican Energy (liabilities)
372
(214)
919
t'aclttcorp
Exhibit No. 11 , page 57 of 130
CASE NO. PAC-05-
~it~.:~s: Patrick J. Goodman
Item 8. Financial Statements and Supplementary Data.
Report of Independent Registered Public Accounting Finn
Consolidated Balance Sheets as of December 31 , 2004 and 2003
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Statements of Stockholders' Equity for the Years Ended December 31 , 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the Years Ended December 31 , 2004, 2003 and 2002
Notes to Consolidated Financial Statements
PacltJcorp
Exhibit No. 11, page 58 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
.--
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
MidAmerican Energy Holdings Company
Des Moines, Iowa
We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company and subsidiaries
(the "Company ) as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders
equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the
consolidated financial statement schedules listed in the Index at Item 15. These financial statements aoo financi~l statement
schedules are the responsibility of the Company s management. Our responsibility is to express an opinion on the financial
statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perfonn the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company s internal control over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of
MidAmerican Energy Holdings Company and subsidiaries as of December 31 , 2004 and 2003, and the results of their
operations and their cash flows for each of the three years in the period ended December 31 , 2004, in conformity with
accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial
statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present
fairly in all material respects the infonnation set forth therein.
As discussed in Notes 2 and 10 to the consolidated financial statements, the Company changed its accounting policy for asset
retirement obligations and for variable interest entities in 2003.
/s/Deloitte & Touche LLP
Des Moines, Iowa
February 25, 2005
raCIIU...orp
Exhibit No. II , page 59 of 130
CASE NO. PAC-05-
~it~~~s: Patrick J. Goodman
MID AMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands)
As of December 31,2004 2003
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash and short-tenD investments
Accounts receivable, net of allowance for doubtful accounts of $26 033
and $26,004
Inventories
Other current assets
Total current assets
Properties, plants and equipm~nt, net
Goodwill
Regulatory assets
Other investments
Equity investments
Deferred charges and other assets
Total assets
960,903 660,213
129,316 55,281
695,761 666 063
125,079 123,301
278.219 348.618
2.189.278 1.853.476
11,607 264 11,180 979
306,751 305,643
451 830 512,549
236,258 228,896
210 430 234 370
901.751 829.039
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable
Accrued interest
Accrued property and other taxes
Other liabilities
Short-term debt
Current portion of long-tenD debt
Current portion of parent company subordinated debt
Total current liabilities
Other long-term accrued liabilities
Parent company senior debt
Parent company subordinated debt
Subsidiary and project debt
Deferred income taxes
Total liabilities
Deferred income
Minority interest
Preferred securities of subsidiaries
410 319 345,237
197,813 189,635
166,639 112 823
532,160 420 294
090 036
145,598 500 941
188.543 100.000
650.162 1.716.966
171 616 961 695
771 957 777,878
585,810 772 146
304 923 674 640'
1.281.833 1.299.082
766 301 202
443 201
119 754
89,540 145
Commitments and contingencies (Note 21)
Stockholders' equity:
Zero coupon convertible preferred stock authorized 50 000 shares, no par
value; 41 263 shares issued and outstanding
Common stock authorized 60,000 shares, no par value; 9,081 and 9,281
shares issued and outstanding at December 31, 2004 and 2003, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss, net
Total stockholders' equity
Total liabilities and stockholders' equity
950,663
156 843
971.159
957,277
999,627
771.445
The accompanying notes are an integral part of these financial statements.
MID AMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands)
Operating revenue
Costs and expenses:
Cost of sales
Operating expense
Depreciation and amortization
Gain on CE Gas asset sale (Note 5)
Total costs and expenses
Operating income
Other income (expense):
Interest expense
Capitalized interest
Interest and dividend income
Other income
Other expense
Total other income (expense)
Income from continuing operations before income tax expense,
minority interest and preferred dividends of subsidiaries and
equity income
Income tax expense
Minority interest and preferred dividends of subsidiaries
Income from continuing operations before equity income
Equity income
Income from continuing operations
Loss from discontinued operations, net of tax benefits (Note 3)
Net income available to common and preferred stockholders
PacJtICorp
Exhibit No. II, page 60 of t 30
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Year Ended December 31,2004 2003
751 856 400,536 843 955
637 922 512 345\302 780
638,209 602 934 530,078
027 987 515 815 622
525 1.449.815 1.172.711
$ 6.553.
(903,217)
20,040
889
128,205
(726.2QID
799,193
264,986
13.301
520 906
16.861
537,767
$ 5.965.630
(760,956)
30,494
908
643
(5.9U)
857,991
270,276
183.203
404,512
38.224
442 736
(27. ill)
The accompanying notes are an integral part of these financial statements.
2002
795.t79
(632,133)
361
56,037
223
631 638
111 ,278
163.468
356 892
40.520
397,412
--O..U22)
pacltlcorp
Exhibit No. 11, page 61 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
.~~
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31,2004
(Amounts in thousands)
Accumulated
Outstanding Additional Other
Common Common Paid-Retained Comprehensive
Shares Stock Capital Earnin Loss Total
Balance, January 1, 2002 281 $ 1 553 073 $ 223,926 (68,832)'708 167
Net income 380,043 380,043
Other comprehensive income:
Foreign currency translation
adjustment 166,880 166,880
Fair value adjustment on cash flow
hedges, net of tax ofS(10,106)(27 623)(27 623)
Minimum pension liability
adjustment, net of tax of
$(135,707)(313,456)(313,456)
Unrealized losses on securities, net of
tax ofS(I,813)(3,204)(3.204)
Total comprehensive income 202.640
Issuance ofzero-coupon convertible
preferred stock 402,000 402 000
Retirement of stock options 815 (19,960)(19,145)
other equ transactions 621 621
Balance, December 31,2002 281 956 509 584 009 (246 235)294 283
Net income 415,618 415,618
Other comprehensive income:
Foreign currency translation
adjustment 148 58,148
Fair value adjustment on cash flow
hedges, net of tax of$7,202 16,769 16,769
Minimum pension liability
adjustment, net of tax ofS(6 425)(14 989)(14 989)
Unrealized gains on securities, net of
tax ofS566 848 848
Total comprehensive income 476.394
Other equ transactions 768 768
Balance, December 31, 2003 281 957,277 999,627 (185 459)771 445
Net income 170 206 170 206
Other comprehensive income:
Foreign currency translation
adjustment 107,370 107 370
Fair value adjustment on cash flow
hedges, net of tax of $(6,069) (12 270)(12 270)
Minimum pension liability
adjustment, net of tax ofS(19,898)(46 429)(46 429)
Unrealized gains on securities, net of
tax ofS294 441 441
Total comprehensive income 219.318
Common stock purchase (200)(7,010)(12 990)(20 000)
Other e transactions 396 396
Balance, December 31, 2004 081 $ 1 950 663 $ 1,156,843 (136 347)971 159
The accompanying notes are an integral part of these financial statements.
PaCltlCorp
Exhibit No. 11, page 62 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
.--
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
, (Amounts in thousands)
Cash flows from operating activities:
Income from continuing operations
Adjustments to reconcile income from continuing operations to cash flows
from continuing operations:
Distributions less income on equity investments
Gain on other items
Depreciation and amortization
Amortization of regulatory assets and liabilities
Amortization of deferred financing costs
Provision for deferred income taxes
Other
Changes in other items:
Accounts receivable and other current assets
Accounts payable and other accrued liabilities
Deferred income
Net cash flows from continuing operations
Net cash flows from discontinued operations
Net cash flows from operating activities
Cash flows from investing activities:
Capital expenditures relating to operating projects
Construction and other development costs
Proceeds from notes receivable
Acquisitions, net of cash acquired
Proceeds from (purchase of) affiliate notes, net
Sale (purchase) of convertible preferred securities
Other
Net cash flows from continuing operations
Net cash flows from discontinued operations
Net cash flows from investing activities
Cash flows from financing activities:
Proceeds from subsidiary and project debt
Proceeds from parent company senior debt
Repayments of subsidiary and project debt
Repayments of parent company senior and subordinated debt
Net repayment of subsidiary short-term debt
Purchase and retirement of common stock
Proceeds from issuance of trust preferred securities
Proceeds from issuance of preferred stock
Net repayment of parent company revolving credit facility
Repayment of other obligations
Increase in restricted cash and investments
Redemption of preferred securities of subsidiaries
Other
Net cash flows from continuing operations
Net cash flows from discontinued operations
Net cash flows from financing activities
Effect of exchange rate changes
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Y ear Ended December 31,2004 2003 2002
$ 537,767 $ 442 736 $ 397,412
022 40,160 (11,383)
(71,757)(29,264)(47 086)
638,209 602,934 " 530,078
(1,586)(14 363)709
20,875 27,748 28,433
176 591 220,136 (18 020)
16,981 211 356
(43,600)(25 900)(200,760)
171,457 (17,835)78,813
(6.(9.3M)
458,494 245 219 769 713
(27.296) ----D.L.m)
648 217 923 757 726
(778 300)(616;804)(528,950)
(401 090)(602 564)(813 ,348)
169 210
(36,706)(54 263)416,937)
14,118 (32,406)
288 750 (275,000)
148 25.786 189.984
030,620)(991,501)844 251)
966
375,351 157 649 485,349
249,765 449,295 700,000
(368,417)490 986)(393,264)
(100 000)(412 551)
(43,949)(31 750)(472 835)
(20,000)
273 000
402 000
(153,500)
(94 297)
(48,515)024)(41,524)
(2,606)176)(127,908)
462 (424 930)536,059
(U7.297)---MQl)19.175
(426.311.)555.234
28.531 27.364 52.536
390 690 (184 217)457,685
660.213 '844.430 386.745
The accompanying notes are an integral part of these financial statements.
t"aCIJILorp
Exhibit No. 11 , page 63 of 130
CASE NO. PAC-05-
~it~~~s: Patrick J. Goodman
MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Organization and Operations
MidAmerican Energy Holdings Company ("MEHC") and its subsidiaries (together with MEHC, the "Company ) are
organized and managed on seven distinct platforms: MidAmerican Energy Company ("MidAmerican Energy ), Kern River
Gas Transmission Company ("Kern River ), Northern Natural Gas Company ("Northern Natural Gas ), CE Electric UK
Funding ("CE Electric UK") (which includes Northern Electric Distribution Limited ("Northern Electric ) and Yorkshire
Electricity Distribution pic ("'Yorkshire Electricity")), CalEnergy Generation-Foreign (the subsidiaries o~ing the Upper
Mahiao, Malitbog and Mahanagdong Projects (collectively the "Leyte Projects") and the Casecnan project), CalEnergy
Generation-Domestic (the subsidiaries owning interests in independent power projects and related operations) and
HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices ). Through these platfonns, the Company
owns and operates a combined electric and natural gas utility company in the United States, two natural gas pipeline
companies in the United States, two electricity distribution companies in the United Kingdom, a diversified portfolio of
domestic and international independent power projects and the second largest residential real estate brokerage finn in the
United States.
On March 14, 2000, MEHC and an investor group comprising Berkshire Hathaway Inc. ("Berkshire Hathaway ), Walter
Scott, Jr., a director of MEHC, David L. Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel
President and Chief Operating Officer of MEHC, closed on a definitive agreement and plan of merger whereby the investor
group, together with certain of Mr. Scott's family members and family trusts and corporations, acquired all of the outstanding
common stock ofMEHC (the "Teton Transaction
MEHC initially incorporated in 1971 under the laws of the State of Delaware and reincorporated in 1999 in Iowa, at which
time it changed its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.
In these notes to consolidated financial statements, references to "S. dollars
" "
dollars,
" "
$" or "cents" are to the currency
of the United States, references to "pounds sterling," " f.
" "
sterling,
" "
pence" or "" are to the currency of the United
Kingdom and references to "pesos" are to the currency of the Philippines. References to kW means kilowatts, MW means
megawatts, GW means gigawatts, kWh means kilowatt hours, MWh means megawatt hours, GWh means gigawatts hours
kV means kilovolts, mmcf means million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic feet and Dth
means decathenns or one million British thermal units.
Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of MEHC and its wholly-owned subsidiaries except for certain
trusts fonned to hold trust preferred securities. Under Financial Accounting Standards Board ("F ASB") Interpretation No.
46R, "Consolidation of Variable Interest Entities
" ("
FIN 46R") these trusts, by design, are considered variable interest
entities, with no variable interest holder being considered the primary beneficiary, thus requiring the reporting entity to
deconsolidate the trust. Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a
minority interest. Subsidiaries that are 50% owned or less, but where the Company has the ability to exercise significant
influence, are accounted for under the equity method of accounting. Investments where the Company s ability to influence is
limited are accounted for under the cost method of accounting. All inter-enterprise transactions and accounts have been
eliminated. The results of operations of the Company include the Company s proportionate share of results of operations of
entities acquired tTom the date of each acquisition for purchase business combinations.
For the Company s foreign operations whose functional currency is not the U.S. dollar, the assets and liabilities are translated
into U.S. dollars at current exchange rates. Resulting translation adjustments are reflected as other comprehensive income in
stockholders' equity. Revenue and expenses are translated at average exchange rates for the period. Transaction gains and
losses that arise tTom exchange rate fluctuations on transactions denominated in a currency other than the functional currency
are included in the results of operations as incurred.
raCUlLOrp
Exhibit No. )), page 64 of 130
CASE NO. PAC-05-
~it~:~s: Patrick J. Goodman
Reclassifications
Certain amounts in the fiscal 2003 and 2002 consolidated financial statements and supporting note disclosures have been
reclassified to confonn to the fiscal 2004 presentation, including the reclassification of activity as discontinued operations
(see Note 3). Such reclassification did not impact previously reported net income or retained earnings.
Use of Estimates
The preparation of consolidated financial statements in confonnity with accounting principles generally accepted in the
United States of America requires management to make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the
reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Accountingfor the Effects of Certain Types of Regulation
MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the
provisions of Statement of Financial Accounting Standards ("SF AS") No. 71
, "
Accounting for the Effects of Certain Types
of Regulation
" ("
SF AS 71 "), which differs in certain respects from the application of generally accepted accounting
principles by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should
reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs (a
regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making
process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River
and Northern Natural Gas have deferred certain costs, which will be amortized over various future periods. To the e~tent that
collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the
associated regulatory asset or liability is charged or credited to income.
A possible consequence of deregulation of the regulated energy industry is that SF AS 71 may no longer apply.If portions of
the Company s regulated energy operations no longer meet the criteria of SFAS 71 , the Company could be required to write
off the related regulatory assets and liabilities from its consolidated balance sheet, and thus a material adjustment to earnings
in that period could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation
legislation.
The Company continues to evaluate the applicability of SF AS 71 to its regulated energy operations and the recoverability of
these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment.
Consolidated Statements of Cash Flows
The Company, considers all investment instruments purchased with an original maturity of three months or less to be cash
equivalents. Investments other than restricted cash are primarily commercial paper and money market securities. Restricted
cash is not considered a cash equivalent. The supplemental disclosures to the accompanying consolidated statements of cash
flows were as follows (in thousands):
, Year Ended December 31,
2004 2003 2002
Interest paid, net of interest capitalized Income taxes (refunded) paid
Non-cash transaction - ROP note received under NIA Arbitration Settlement
$ 9.
Cash paid for interest for the years ended December 31 , 2003 and 2002 does not include $170,151 and $147 667,
respectively, of interest paid on subordinated debt, which is included in minority interest and preferred dividends of
subsidiaries in the consolidated statements of operations. These amounts were not reclassified pursuant to the FIN 46R.
. ""'U'-VIP
Exhibit No. 11, page 65 of 130
CASE NO. PAC-05-~it~~s: Patrick J. Goodman
Restricted Cash and Investments
The restricted cash and short-tenD investments balance recorded separately in restricted cash and short-tenD investments and
in deferred charges and other assets, was $164.5 million and $119.5 million at December 31, 2004 and 2003, respectively,
and includes commercial paper and money market securities. The balance is mainly composed of amounts deposited in
restricted accounts from which the Company will source its debt service reserve requirements relating to the projects
customer deposits held in escrow, custody deposits, and unpaid dividends declared obligations. The debt service funds are
restricted by their respective project debt agreements to be used only for the related project.
The Company nuclear decolnmissioning trust funds and other marketable securities are classified as available for sale andare accounted for at fair value.
Allowance for Doubtful Accounts
The allowance for doubtful accounts is based on the Company s assessment of the collectibility of payments from its
customers. This assessment requires judgment regarding the outcome of pending disputes, arbitrations and the ability of
customers to pay the amounts owed to the Company.
Inventories
Inventories consist mainly of materials and supplies, coal stocks, gas in storage and fuel oil, which are valued at the lower of
cost, detennined primarily using average cost, or market.
Fair Value of Financial Instruments
The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction
between willing parties, other than in a forced sale or liquidation. Although management uses its best judgment in estimating
the fair value of these financial instruments, there are inherent limitations in any estimation technique. Therefore, the fair
value estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a currenttransaction.
The methods and assumptions used to estimate fair value are as follows:
Short-tenD debt - Due to the short-tenD nature of the short-tenD debt, the fair value approximates the carrying value.
Debt instruments The fair value of all debt instruments has been estimated based upon quoted market prices as
supplied by third-party broker dealers, where available, or at the present value of future cash flows discounted at rates
consistent with comparable maturities with similar credit risks.
Other financial instruments All other financial instruments of a material nature are short-tenD and the fair value
approximates the carrying amount.
Properties, Plants and Equipment, Net
Properties, plants and equipment are recorded at historical cost. The cost of major additions and bettennents are capitalized
while replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are expensed.
Depreciation is computed using the straight-line method based on economic lives or regulatorily mandated recovery periods.
The Company believes the useful lives assigned to the depreciable assets, which generally range from 3 to 87 years, are
reasonable.
Capitalized costs for gas reserves, other than costs of unevaluated exploration projects and projects awaiting development
consent, are depleted using the units of production method. Depletion is calculated based on hydrocarbon reserves of
properties in the evaluated pool estimated to be commercially recoverable and include anticipated future development costs
in respect of those reserves.
ra(;lIlLOrp
Exhibit No. 11, page 66 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
.--
Impairment of Long-Lived Assets
The Company periodically evaluates long-lived assets, including properties, plants and equipment, when events or changes in
circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering
event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its
carrying amount. The recoverable amount is the estimated net future cash flows that the Company expects to recover from
the future use of the asset, undiscounted and without interest, plus the asset's residual value on disposal. Where the
recoverable amount of the long-lived asset is less than the carrying value, an impairment loss would be recognized to write
down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset.
Goodwill
The provisions of SFAS No. 142
, "
Goodwill and Other Intangible Assets
" ("
SFAS 142"), which establishes the accounting
for acquired goodwill and other intangible assets, and provides that goodwill and indefinite-lived intangible assets will not be
amortized, requires allocating goodwill to each reporting unit and testing for impairment using a two-step approach. The
goodwill impairment test is performed annually or whenever an event has occurred that would more likely than not reduce
the fair value of a reporting unit below its carrying amount. The Company completed its annual review pursuant to SF AS 142
for its reporting units as of October 31 , 2004 primarily using a discounted cash flow methodology. No impairment was
indicated as a result ofthese assessments.
Allowance for Funds Used During Construction
Allowance for funds used during construction ("AFUDC") represents the approximate net composite interest cost
borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both
properties, plants and equipment and earnings, it is realized in cash through depreciation provisions included in rates for
subsidiaries that apply SF AS 71. Interest and AFUDC for subsidiaries that apply SF AS 71 are capitalized as a component of
projects under construction and will be amortized over the assets' estimated useful lives.
Deferred Financing Cost
The Company capitalizes costs associated with financings, as deferred financing costs, and amortizes the amounts over the
term of the related financing using the effective interest method.
Contingent Liabilities
The Company establishes accruals for estimated loss contingencies, such as environmental, legal and regulatory matters,
when it is management's assessment that a loss is probable and the amount of the loss can be reasonably estimated.
Income Taxes
The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax
basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse.
Based on existing regulatory precedent, MidAmerican Energy is not allowed to recognize deferred income tax expense
related to certain temporary differences resulting from accelerated tax depreciation and other property related basis
differences. For these differences, MidAmerican Energy establishes deferred tax liabilities and regulatory assets on the
consolidated balance sheets since MidAmerican Energy is allowed to recover the increased tax expense when these
differences turn around.
The Company has not provided U.S. deferred income taxes on its currency translation adjustment or the cumulative earnings
of international subsidiaries that have been determined by management to be reinvested indefinitely. These earnings related
to ongoing operations and were approximately $1.5 billion at December 31 , 2004. Because of the availability of U.S. foreign
tax credits, it is not practicable to determine the U.S. federal income tax liability that would be payable if such earnings were
not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to
remit those earnings.
pacltlCorp
Exhibit No. II , page 67 of 130
CASE NO. PAC-05-
~it~:~s: Patrick J. Goodman
The calculation of current and deferred income taxes requires management to apply judgment relating to the application of
complex tax laws or related interpretations and uncertainties related to the outcome of tax audits. Changes in such factors
may result in changes to management's estimates, which could require the Company to adjust its currently recorded tax
assets and liabilities and record additional income tax expense or benefits.
Revenue Recognition
Revenue is recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end
of the period. The Company records unbilled revenue representing the estimated amounts customers will be billed for
services rendered between the meter reading dates in a particular month and the end of that month.
Where billings result in an overrecovery of United Kingdom distribution business revenue against the maximum regulated
amount, revenue is deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from
revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery is
made.
Revenue from the transportation and storage of gas are recognized based on contractual terms and the related volumes. Kern
River and Northern Natural Gas are subject to the Federal Energy Regulatory Commission s ("FERC") regulations and,
accordingly, certain revenue collected may be subject to possible refunds upon final orders in pending rate proceedings. Kern
River and Northern Natural Gas record revenue which is subject to refund based on their best estimate of the final outcome
these proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as well as
collection and other risks. The estimate of the refund is recorded in other current liabilities in the accompanying consolidated
balance sheets.
Revenue from water and energy delivery is recorded on the basis of the contractual minimum guaranteed water delivery
threshold for the respective contract year. If and when cumulative deliveries within a contract year exceed the minimum
threshold, additional revenue is recognized. Revenue from long-tenn electricity contracts is recorded at the lower of the
amount billed or the average of the contract, subject to contractual provisions at each project.
Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when title has
U'ansferred from seller to buyer. Title fee revenue from real estate transactions and related amounts due to the title insurer are
recognized at the closing, which is when consideration is received. Fees related to loan originations are recognized at the
closing, which is when services have been provided and consideration is received.
Financial Instruments
The Company currently utilizes ' swap agreements and forward purchase agreements to manage market risks and reduce its
exposure resulting from fluctuation in interest rates, foreign currency exchange rates and electric and gas prices. For interest
rate swap agreements, the net cash amounts paid or received on the agreements are accrued and recognized as an adjustment
to interest expense. Gains and losses related to gas forward contracts are deferred and included in the measurement of the
related gas purchases. These instruments are either exchange traded or with counterparties of high credit quality; therefore
the risk of nonperformance by the counterparties is considered to be negligible.
New Accounting Pronouncements
In December 2003, the FASB issued FIN 46R, which served to clarify guidance in FASB Interpretation No. 46,
Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51." The Company
adopted and applied the provisions of FIN 46R, related to certain finance subsidiaries, as of October 1 , 2003. The adoption
required the deconsolidation of certain finance subsidiaries, which resulted in the amounts previously classified as
mandatorily redeemable preferred securities of subsidiary trusts, in the amount of $1.9 billion, being reclassified to parent
company subordinated debt in the accompanying consolidated balance sheets. In addition, amounts previously recorded
minority interest and preferred dividends of subsidiaries are now recorded as interest expense in the accompanying
consolidated statements of operations, prospectively. For the year ended December 31 , 2004, and the three-month period
ended December 31 , 2003, the Company has recorded $196.9 million and $49.8 million, respectively, of interest expense
related to these securities. In accordance with the requirements of FIN 46R, no amounts prior to adoption of FIN 46R on
October 1, 2003 have been reclassified. The amounts included in minority interest and preferred dividends of subsidiaries
related to these securities for the nine-month period ended September 30, 2003 , and the year ended December31, 2002, were
t'aClI1Lorp
Exhibit No. I), page 68 of 130
CASE NO. PAC-05-
~it~~~s: Patrick J. Goodman
$170.2 million and $147.7 million, respectively. The Company adopted the provisions of FIN 46R related to non-special
purpose entities in the first quarter of 2004. The Company considered the provisions of FIN 46R for all subsidiaries and their
related power purchase, power sale, or tolling agreements. Factors considered in the analysis include the duration of the
agreements, how capacity and energy payments are determined, source and payment terms for fuel ' as well as responsibility
and payment for operating and maintenance expenses. As a result of these considerations, the Company has determined its
power purchase, power sale and tolling agreements do not represent significant variable interests. Accordingly, the Company
concluded that it is appropriate to continue to consolidate the power plant projects with ownership interests greater than 50%
and not to consolidate the power plants from which it purchases power.
In December 2004, the FASB issued SFAS No. 123R
, "
Share-Based Payment" ("SF AS 123R"), which replaces SFAS No.
123
, "
Accounting for Stock-Based Compensation " and supersedes Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees." SFAS 123R establishes standards for the accounting for .transactions in which
an entity exchanges its equity instruments for goods or services, primarily focusing on the accounting for transactions in
which an entity obtains employee services in share-based payment transactions. SFAS 123R requires entities to measure
compensation costs for all share-based payments, including stock options, at fair value and expense such payments over the
service period. Since MEHC is considered a nonpublic entity under the criteria of SF AS 123R, this standard is effective for
annual period beginning after December 15, 2005. Adoption of this standard will not have an effect on the Company
financial position, results of operations or cash flows as all of the Company s outstanding stock options were fully vested at
the date of issuance of SF AS 123R. Modifications to outstanding stock options after the effective date of the standard may
result in additional compensation expense pursuant to the provisions of SF AS 123R.
Discontinued Operations - Zinc Recovery Project and Mineral Assets
Indirect wholly-owned subsidiaries of MEHC, own the rights to commercial quantities of extractable minerals from elements
in solution in the geothermal brine and fluids utilized at certain geothermal energy generation facilities located in the Imperial
Valley of California and a zinc recovery plant constructed near the geothermal energy generation facilities designed to
recover zinc from the geothermal brine through an ion exchange, solvent extraction, electrowinning and casting process (the
Zinc Recovery Project"
The Zinc Recovery Project began limited production during December 2002 and continued limited production until
September 10, 2004. Efforts to increase production had continued since the Zinc Recovery Project was placed in service with
an emphasis on process modification. Management had been assessing the long-term economic viability of the Zinc
Recovery Project in light of continuing cash flow deficits and operating losses and the efforts to increase production, and had
continued to evaluate the expected impact of the planned improvements to the extraction process during the third quarter of
2004. Furthermore, management had been exploring other operating alternatives, such as establishing strategic partnerships
and consideration of ceasing operations of the Zinc Recovery Project.
On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project. Based on this
decision, a non-cash, after-tax impairment charge of $340.3 million has been recorded to write-off the Zinc Recovery Project,
rights to quantities of extractable minerals, and allocated goodwill (collectively, the "Mineral Assets"). The charge al1d the
related activity of the Mineral Assets are classified separately as discontinued operations in the accompanying consolidated
statements of operations and include the following (in thousands):
2004
Year Ended December 31.
2003
Total revenue 659
Losses from discontinued operations
Costs of disposal activities, net
Asset impairment charges, including goodwill
Income tax benefits
Loss from discontinued operations, net of tax
$ (42 695)
134)
(532 009)
211.277
$ (46,423)
19.305
1mJW
2002
288
$ (29 059)
11.690
t'aClllLorp
Exhibit No. 11 , page 69 of 130
CASE NO. PAC-05-
~it~~~s: Patrick J. Goodman
In connection with ceasing operations, the Zinc Recovery Project's assets are being dismantled and sold and certain
employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. Cash expenditures of
approximately $4.1 million, consisting of pre-tax disposal costs, termination benefit costs and property taxes, were made
through December 31, 2004. The Company expects to make additional cash expenditures of pre-tax disposal costs and
property taxes of approximately $1.6 million. Substantially all of such costs are expected to relate to disposal activities, and a
portion of the disposal costs is expected to be offset by proceeds from sales of the Zinc Recovery Project's assets. These costs
are recognized in the period in which the related liability is incurred. Salvage proceeds will be recognized in the period
earned. Implementation of a disposal plan began in September 2004 and will continue in 2005. The Company also expects
receive approximately $55 million in future tax benefits.
Acquisitions
HomeServices
In 2004, HomeServices separately acquired six real estate companies for an aggregate purchase price of $30.7 million, net of
cash acquired, plus working capital and certain other adjustments. These purchases were financed using HomeServices' cash
balances.
In 2003, HomeServices separately acquired four real estate, companies for an aggregate purchase price of $36.7 million, net
of cash acquired, plus working capital and certain other adjustments. Additionally in 2004, HomeServices paid an earnout of
$6.0 million based on 2004 financial performance measures. These purchases were financed using HomeServices' cash
balances and revolving credit facility.
In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of $1 06.1 million, net
of cash acquired, plus working capital and certain other adjustments. Additionally in 2003, HomeServices paid an earnout of
$17.6 million based on 2002 financial performance measures. These purchases were financed using HomeServices' cash
balances revolving credit facility and $40.0 million from MEHC, which was contributed to HomeServices as equity.
Kern River
On March 27, 2002, the Company acquired Kern River from The Williams Companies, Inc. ("Williams ). At the date of
acquisition, Kern River owned a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to
markets in California, Nevada and Utah.
The Company paid $419.7 million, net of cash acquired and a working capital adjustment, for Kern River s gas pipeline
business. The acquisition has been accounted for as a purchase business combination. The Company completed the allocation
of the purchase price to the assets and liabilities acquired during 2003. The results of operations for Kern River are included
in the Company s results beginning March 27, 2002.
The recognition of goodwill resulted from various attributes of Kern River s operations and business in general. These
attributes include, but are not limited to:
Opportunities for expansion;
Generally high credit quality shippers contracting with Kern River;
Kern River s strong competitive position;
Exceptional operating track record and state-of-the-art technology;
Strong demand for gas in the Western markets; and
An ample supply of low-cost gas.
There is no assurance that these attributes will continue to exist to the same degree as believed at the time ofthe acquisition.
In connection with the acquisition of Kern River, MEHC issued $323.0 million of II % Company-obligated mandatorily
redeemable preferred securities of a subsidiary trust due March 12, 2012 with scheduled principal payments beginning in
2005 and $127.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway. Each share of preferred
stock is convertible at the option of the holder into one share of the Company s common stock subject to certain adjustments
as described in the MEHC Amended and Restated Articles of Incorporation.
t'aCltILorp
Exhibit No. 11 , page 70 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
.~-
Northern Natural Gas
On August 16, 2002, the Company acquired Northern Natural Gas from Dynegy Inc. Northern Natural Gas is a 16 500-mile
interstate pipeline extending from southwest Texas to the upper Midwest region of the United States.
The Company paid $882.7 million for Northern Natural Gas, net of cash acquired and a working capital adjustment. The
acquisition has been accounted for as a purchase business combination. The Company completed the allocation of the
purchase price to the assets and liabilities acquired during 2003. The results of operations for Northern Natural Gas are
included in the Company s results beginning August 16 2002.
The recognition of goodwill resulted ftom various attributes of Northern Natural Gas' operations and business in general.
These attributes include, but are not limited to:
Generally high credit quality shippers contracting with Northern Natural Gas;
Northern Natural Gas' strong competitive position;
Strategic location in the high demand Upper Midwest markets;
Flexible access to an ample supply of low-cost gas;
Exceptional operating track record; and
Opportunities for expansion.
There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition.
In connection with the acquisition of Northern Natural Gas, MEHC issued $950.0 million of 11 Company-obligated
mandatorily redeemable preferred securities of a subsidiary trust due August 31 , 2011 , with scheduled principal payments
beginning in 2003, to Berkshire Hathaway.
The following pro forma financial' information of the Company represents the unaudited pro forma results of operations as if
the Kern River and Northern Natural Gas acquisitions, and the related financings, had occurred at the beginning of 2002.
These pro forma results have been prepared for comparative purposes only and do not profess to be indicative of the results
of operations which would have been achieved had these transactions been completed at the beginning of the year, nor are the
results indicative of the Company s future results of operations (in millions):
Year Ended
December 31,
2002
Revenue
Income before cumulative effect of change in accounting principle
Net income available to common and preferred shareholders
$ 5 299.4
285.
285.
Dispositions and Other Items
CE Gas Asset Sale
In May 2002, CalEnergy Gas (Holdings) Limited ("CE Gas ), an indirect wholly owned subsidiary of the Company,
executed the sale of several of its U.K. natural gas assets to Gaz de France for approximately $200.0 million ((137.0 million),
which was included in other investing activities in the accompany consolidated statement of cash flows in 2002. CE Gas sold
its interest in four natural gas-producing fields located in the southern basin of the U.K. North Sea (Anglia, Johnston
Schooner and Windermere). The transaction also included the sale of rights in four gas fields (in development/construction)
and three exploration blocks owned by CE Gas. The Company recorded pre-tax and after-tax income of $54.3 million and
$41.3 million, respectively, which includes a write off of non-deductible goodwill of $49.6 million.
paclhLorp
Exhibit No. 11 , page 71 of 130
CASE NO. PAC-05-
~it!1~~s: Patrick J. Goodman
Teesside Power Limited (flTPL
The Company has a 15.4% interest in TPL, which owns and operates a 1,875 MW combined cycle gas-fired power plant.
Enron Corp. ("Enron ), which through its subsidiaries has , a 42.5% interest, previously operated TPL. TPL is now in
administration and administrators have been appointed to run its business and are attempting to find a buyer. The Company
wrote-off its investment in TPL during 2001. Shareholders in TPL had previously utilized TPL's taxable losses with an
obligation to reimburse TPL later in the project's life. In May 2002, TPL executed a restructuring and stabilization agreement
with its lenders. The contract included an agreement between TPL and its shareholders with respect to the waiver of these
repayment obligations. In May 2002, TPL released $35.7 million due to the repayment obligation being waived which is
reflected as a tax benefit in income tax expense in 2002.
Properties, Plants and Equipment, Net
Properties, plants and equipment, net comprise the following at December 31 (in thousands):
Depreciation
Life 2004 2003
10-50 years $ 10 149,818 $ 8,987,158
87 years 566,578 3,470,117
10-30 years'384 660 395,782
30 years 101 472 554,780
30 years 465,297 429 228
10 years 167.150 146.286
15,834,975 14,983 351
(~00.372)
034 603 722,708
572.661 458.271
Utility generation and distribution system
Interstate pipelines' assets
Independent power plants
Mineral and gas reserves and exploration assets
Utility non-operational assets
Other assets
Total operating assets
Accumulated depreciation and amortization
, Net operating assets
Construction in progress
Properties" plants and equipment, net
Investment in CE Generation
The Company holds a 50% interest in CE Generation, LLC ("CE Generation ) and accounts for this interest as an equity
investment. The equity investment in CE Generation at December 31 , 2004 and 2003 was $188.7 million and $209.4 million
respectively. The following is summarized financial information for CE Generation as of and for the years ended
December 31 (in thousands):
Revenue
Income (loss) before cumulative effect of change in
accounting principle
Net income (loss)
Current assets
Total assets
Current liabilities
Long-term debt, including current portion
2004 2003 2002
444 228 $ 487 422 $ 510 082
(3,084)37,341 314
(3,084)874 58,314
124 734 260 551
447 388 708 742
115 153 253 237
722 650 924 565
As part of its annual impairment test, CE Generation determined on December 9, 2004 that a portion of the carrying value of
the Power Resources project's long-lived assets were no longer recoverable. As a result, CE Generation recognized a non-
cash impairment charge of $54.5 million ($33.5 million after tax), in accordance with SFAS No. 144
, "
Accounting for the
Impairment of Long-Lived Assets," to write down the long-lived assets to their fair value. The fair value was determined
based on discounted estimated cash flows from the future use of the long-lived assets. The impairment charge will not result
in any current or future cash expenditures. MEHC's $16.8 million portion of the Power Resources impairment is reflected in
income on equity investments in the accompanying consolidated statement of operations for the year ended December 31
2004.
. ""UJ'-'Ul P
Exhibit No. II, page 72 of 130
CASE NO. PAC-05-
~it~:~s: Patrick J. Goodman
Other Income and Expense
Other income for the years ending December 31 consists of the following (in thousands):
2004 2003 2002
210
889
20,476 26,708 19,366
750
13,750 750
447 317 330
609 183 519
11.713 13.796 258
$ 96.&:U
Gain on Enron note receivable
Gain on CE Casecnan settlement
Allowance for equity ~ds used during construction
Gain on Mirant bankruptcy claim
Gain on Williams preferred stock
Corporate-owned life insurance income
Gain on sale of other assets and investments
Other
Total other income'
Other expense for the years ending December 31 , 2004, 2003 and 2002 was $10.1 million, $5.9 million and $28.6 million,
respectively. In 2002, MidAmerican Energy recorded an impainnent of its investment in airplane leases and other non-
regulated investments of $21.7 million.
Sale of Enron Note Receivable and Receipt of Cash
Northern Natural Gas had a note receivable of approximately $259.0 million (the "Enron Note Receivable ) with Enron. As a,
result of Enron filing for bankruptcy on December 2, 2001 , Northern Natural Gas filed a bankruptcy claim against Enron
seeking to recover payment of the Enron Note Receivable. As of December 31 , 2001 , Northern Natural Gas had written-off
the note. By stipulation, Enron and Northern Natural Gas agreed to a value of $249.0 million for the claim and received
approval of the stipulation from Enron s Bankruptcy Court on August 26, 2004. On November 23, 2004, Northern Natural
Gas sold its stipulated general, unsecured claim against Enron of $249.0 million to a third party investor for $72.2 million
which was recorded as other income in the fourth quarter of 2004.
CE Casecnan Water and Energy Company r"CE Casecnan J Arbitration Settlement
On October 15, 2003 CE Casecnan, an indirect, majority-owned subsidiary of the Company, closed a transaction settling the
arbitration, which arose from a Statement of Claim made on August 19, 2002, by CE Casecnan against the Republic of the
Philippines ("RaP") National Irrigation Administration ("NIA"). As a result of the agreement, CE Casecnan recorded
$31.9 million of other income and $24.4 million of associated income taxes. In connection with the settlement, the NIA
delivered to CE Casecnan a Rap $97.0 million 8.375% Note due 2013 (the "Rap Note ), which contained a put provision
granting CE Casecnan the right to put the Rap Note to the Rap for a price of par plus accrued interest for a 30-day period
commencing on January 14, 2004. The Rap Note is included in other current assets in the accompanying consolidated
balance sheet at December 31 2003.
On January 14, 2004, CE Casecnan exercised its right to put the Rap Note to the Rap and, in accordance with the tenDS of
the put, CE Casecnan received $99.2 million (representing $97.0 million par value plus accrued interest) from the Rap on
January 21 2004.
Mirant Americas Energy Marketing r"Mirant'J Claim
In July 2003, Mirant filed Chapter 11 bankruptcy. On January 13, 2004, Kern River filed a proof of claim with the
bankruptcy court for an aggregate total of $210.2 million, which Kern River believed was secured by the $14.8 million in
proceeds received from its letter of credit and held as a cash security deposit. In May 2004, the bankruptcy court issued an
order pennitting Kern River to apply 100% of the $14.8 million it held in cash collateral to its claim for damages. On
October 12, 2004, Mirant raised an objection to Kern River s claim asserting, among other things, that Kern River had not
included a discount adjustment or mitigation to the claim. On November 11, 2004 . Kern River filed an amended proof of
claim of $138.8 million, reflecting discounting, mitigation and other adjustments. The amended proof of claim excludes the
$14.8 million already received by Kern River. Kern River can not detennine at this time if it will collect any portion of the
balance of the claim or be able to remarket the rejected capacity.
Williams Preferred Stock
~ .......--v. p
Exhibit No. 11 , page 73 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
._~
On March 27, 2002, the Company invested $275.0 million in Williams in exchange for shares of 9'/8% cumulative
convertible preferred stock of Williams. Dividends on Williams preferred stock were received quarterly, commencing July 1
2002. On June 10, 2003, Williams repurchased, for $288.8 million, plus accrued dividends, all of the shares of its 9'/8%
Cumulative Convertible Preferred Stock originally acquired by the Company in March 2002 for $275.0 million. The
Company recorded a pre-tax gain of$13.8 million on the transaction.
Regulatory Assets and Liabilities
The principal components of the Company s regulatory assets and liabilities were as follows as Il()f December 31 (inthousands):
Regulatory assets:
Deferred income taxes, net
Computer systems development costs
System levelized account
Minimum pension liability adjustment
Unrealized loss on regulated hedges
Pipe recoating and reconditioning costs
Asset retirement obligations
Debt refinancing costs
Environmental costs
Nuclear generation assets
Cooper Nuclear Station capital improvement costs
Other
Total
Regulatory liabilities:
Cost of removal accrual
Iowa electric settlement accrual
Asset retirement obligations
Unrealized gain on regulated hedges
Environmental insurance recovery
Nuclear insurance reserve
Other
Total
As of December 31,
Weighted Average
Remaining Life 2004
24 years
7 years
25 years
N/A
1 year
87 years
9 years
7 years
3 years
28 years
Various
24 years
3 years
49 years
2 years
3 years
49 years
Various
$ 160 662
63,637
53,576
136
36,794
406
20,875
365
284
727
21.368
$ 428 719
181 188
53,259
462
599
262
278
2003
$ 138,192
787
109
36,795
248
315
90,556
19,698
13,995
522
314
35.018
$ 408 608
144 418
15,122
781
561
10.250
Of the regulatory assets listed above, only the nuclear generation assets at MidAmerican Energy and the computer systems
development costs, the system levelized account, and the pipe recoating and reconditioning costs at Northern Natural Gas are
included in rate base and earn a return.
The decrease in the asset retirement obligation regulatory asset and the establishment of a related regulatory liability is the
result of a 20-year extension to the operating license of Quad Cities Generating Station and its impact on the timing of related
cash flows. Regulatory liabilities are included in other long-tenD accrued liabilities in the accompanying consolidated balance
sheets.
. ""U I '-'VI 11
Exhibit No. II . page 74 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
.--
10. Asset Retirement Obligations
On January 1 , 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" and recognized a
liability for legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral
pipeline facilities. Concurrent with the recognition of the liability, the estimated cost of the asset retirement obligation
ARO") was capitalized and is being depreciated over the remaining life of the asset. The difference between the ARO
liability, the ARO net asset and amounts recovered from regulated customers to satisfy such liabilities is recorded as
regulatory asset or liability.
The change in the balance of the ARO liability, which is included in other long-term accrued liabilities in the, accompanying
consolidated balance sheets, for the years ended December 31 is summarized as follows (in thousands):
2004 2003
Balance, January 1 '
Revision to nuclear decommissioning ARO liability
Addition for new wind power facilities
Accretion
Balance, December 31
$ 284 007
(120 098)
777
15.877
$ 289,323
(21 902)
16.586
At December 31, 2004, $154.2 million of the ARO liability pertained to the decommissioning of Quad Cities Station. Also, at
December 31 , 2004, $207.5 million of assets reflected in other investments in the accompanying consolidated balance sheet
are restricted for satisfying the Quad Cities Station ARO liability.
The' 2004 revision is a result of a change in the assumed life of Quad Cities Station pursuant to a 20-year extension to the
operating license of the plant by the Nuclear Regulatory Commission ("NRC") in October 2004 and its impact on the timing
of related cash flows. 'The 2003 revision to the nuclear decommissioning ARO liability was due to the results of a
decommissioning study performed by the plant operator.
In addition to the ARO liabilities, MidAmerican Energy has accrued for the cost of removing other electric and gas assets
through its depreciation rates, in accordance with accepted regulatory practices. These accruals are reflected in other long-
tenD accrued liabilities in the accompanying consolidated balance sheets and total $428.7 million and $408.6 million at
December 31 2004 and 2003, respectively.
11. Short-Term Debt
Short-term debt consists of the following at December 31 (in thousands):
2004 2003
$ 48 000MidAmerican Energy commercial paper
HomeServices revolving credit facilitiesOther
Total short-term debt
052
Parent Company Revolving Credit Facilities
In the second quarter of 2003, the Company terminated its $400.0 million credit facility. On June 6, 2003, the Company
closed on a new $100.0 million revolving credit facility which expires on June 6, 2006. The facility supports letters of credit
of which $70.0 million were outstanding at December 31 , 2004. No borrowings were outstanding at December 31, 2004 or
2003. The facility, which was not drawn on during 2004, carries a variable interest rate based on LIBOR and ranged from
02% to 2.255% in 2003.
MidAmerican Energy Short-Term Debt
t'acltJLorp
Exhibit No. ) I, page 75 of 130
CASE NO. PAC-05-
~it~~~,,: Patrick J. Goodman
As of December 31, 2004, MidAmerican Energy has in place a $425.0 million revolving credit facility, which expires on
November 18, 2009, and supports its $304.6 million commercial paper program and its variable rate pollution control
revenue obligations, all of which was available at December 31, 2004. In addition, MidAmerican Energy has a $5.0 million
line of credit which expires on July 1, 2005. There was no commercial paper outstanding at December 31 , 2004, and
commercial paper totaled $48.0 million at December 31 , 2003. MHC Inc., an indirect wholly-owned subsidiary of the
Company, has a $4.0 million line of credit, expiring July 1 , 2005, under which no borrowings were outstanding at
December 31, 2004 or 2003. The commercial paper, bank notes and outstanding line of credit had a weighted average interest
rate of 0.98% at December 31 2003.
HomeServices Revolving Credit Facilities
HomeServices maintains a $125.0 million senior secured revolving credit facility, which expires in November 2005.
Amounts outstanding under this revolving credit facility are secured by a pledge of the capital stock of all of the existing and
future subsidiaries of HomeServices and bear interest, at HomeServices' option, at either the prime lending rate or LIB OR
plus a fixed spread of 1.25% to 2.25%, which varies based on HomeServices' cash flow leverage ratio. The spread was
1.25% at December 31, 2004 and 2003. No borrowings were outstanding at December 31, 2004 or 2003. In addition
HomeServices has in place two mortgage warehouse lines of credit totaling $20.0 million, which expire on March 31, 2005
and October 31 , 2005, and bear interest at LIB OR plus 1.75% and LIBOR plus 2.25%, respectively. The balances
outstanding on these mortgage warehouse lines of credit at December 31 , 2004, totaled $9.1 million. There were no
borrowings outstanding at December 31, 2003. The mortgage warehouse lines of credit had weighted average interest rates of
54% and 4.21%, respectively, at December 31, 2004.
12. Parent Company Senior Debt
Parent company senior debt is unsecured senior obligations of MEHC and consists of the following at December 31 (in
thousand's) :
23% Senior Notes, due 2005
625% Senior Notes, due 2007
63% Senior Notes, due 2007
50% Senior Notes, due 2008
52% Senior Notes, due 2008
7.52% Senior Notes, due 2008 (Series B)
875% Senior Notes, due 2012
00% Senior Notes, due 2014
48% Senior Notes, due 2028
Fair value adjustments and other
Total Parent Company Senior Debt
Less current portion
Total Long-Term Parent Company Senior Debt
2004
$ 260,000
199,403
350,000
449,497
450,000
101,037
499,906
249,797
475 000
(2.
031 957
(260.00.2)
2003
$ 260 000
199,225
350,000
449,373
450,000
101 267
499,898
475,000
777,878
On February 12, 2004, MEHC issued $250.0 million, net of discount, of its 5.00% Senior Notes with a final maturity on
February 15, 2014. The proceeds were used to satisfy a demand made by its affiliate, Salton Sea Funding Corporation
Funding Corporation ), for $136.4 million, the amount remaining on MEHC's guarantee of Funding Corporation s 7.475%
Senior Secured Series F Bonds due November 30, 2018 ("Series F Bonds ), and for other general corporate purposes.
On May 16, 2003, MEHC issued $450.0 million, net of discount, of its 3.50% Senior Notes with a final maturity on May 15
2008. The proceeds were used for general corporate purposes.
13. Parent Company Subordinated Debt
ral:lIl\...UIp
Exhibit No. II, page 76 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
. - ,
MEHC has organized special purpose Delaware business trusts (collectively, the "Trusts ) pursuant to their respective
amended and restated declarations of trusts (collectively, the "Declarations
The financial terms of MEHC's various subordinated debentures held by such Trusts are essentially identical to the
corresponding terms of the mandatorily redeemable preferred securities issued by such Trusts (the "Trust Securities
Pursuant to Preferred Securities Guarantee Agreements (collectively, the "Guarantees ), between MEHC and a trustee,
MEHC has agreed irrevocably to pay to the holders of the Trust Securities, to the extent that the applicable Trust has funds
available to make such payments, quarterly distributions, redemption payments and liquidation payments on the Trust
Securities. Considered together, the undertakings contained in the Declarations, Junior Debentures, Indentures and
Guarantees constitute full and unconditional guarantees on a subordinated basis by MEHC of the Trusts' obligations under
the Trust Securities.
Parent company subordinated debt consists of the following at December 31 (in thousands):
CalEnergy Capital Trust II - 6.25%, due 2012
CalEnergy Capital Trust III - 6.5%, due 2027
MidAmerican Capital Trust I 11 %, due 2010
MidAmerican Capital Trust II 11 %, due 2011
MidAmerican Capital Trust III -11 %, due 2012
Fair value adjustment
Total Parent Company Subordinated Debt
Less current portion
Long-Term Parent Company Subordinated Debt
2004
$ 104,645
269,980
454 772
700 000
323,000
774,353
2003
$ 104,645
269,980
454 772
800 000
323,000
872,146
(100.000)
MEHC owns all of the common securities of the Trusts. The Trust Securities have a liquidation preference of $50 each (plus
accrued and unpaid dividends thereon to the date of payment) and represent undivided beneficial ownership interests in each
of the Trusts. The assets of the Trusts consist solely of Subordinated Debentures of MEHC (collectively, the "Junior
Debentures ) issued pursuant to their respective indentures. The indentures include agreements by MEHC to pay expensesand obligations incurred by the Trusts.
Prior to the Teton Transaction, each Trust Security issued by CalEnergy Capital Trust II and III with a par value of $50 was
convertible at the option of the holder atany time into shares ofMEHC's common stock based on a specified conversion rate.
As a result of the Teton Transaction, in lieu of shares of MEHC's common stock, upon any conversion, holders of Trust
Securities will receive $35.05 for each share of common stock it would have been entitled to receive on conversion.
Distributions on the Trust Securities (and Junior Debentures) are cumulative, accrue from the date of initial issuance and are
payable quarterly in arrears. The Junior Debentures are subordinated in right of payment to all senior indebtedness of the
Company and the Junior Debentures are subject to certain covenants, events of default and optional and mandatory
redemption provisions, all as described in the Junior Debenture indentures.
The indentures relating to the CalEnergy Trusts II and III Trust Securities give MEHC the option to defer the interest
payments due on the respective Junior Debentures for up to 20 consecutive quarters during which time the corresponding
distributions on the respective Trust Securities are deferred (but continue to accumulate and accrue interest). The indentures
relating to the MidAmerican Capital Trust I, II and III Trust Securities give MEHC the option to defer the 11 % interest
payment on the respective Junior Debentures for up to 10 consecutive semi-annual periods during which time the
corresponding 11 distributions on the respective Trust Securities are deferred (but continue to accumulate and accrue
interest at the rate of 13% per annum). In addition, each declaration of trust establishing the MidAmerican Capital Trusts I, II
and III Trust Securities and each of the related subscription agreements contains a provision prohibiting Berkshire Hathaway
and its affiliates, who are the holders of all of the respective Trust Securities issued .by such Trusts, from transferring such
Trust Securities to a non-affiliated person absent an event of default.
14. Subsidiary and Project Debt
J a"'IJ1~UI
Exhibit No. I 1, page 77 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Each of MEHC's direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other
subsidiaries. Pursuant to separate project financing agreements, all or substantially all of the assets of each subsidiary are or
may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should
not be assumed that any asset of any such subsidiary will be available to satisfy the obligations of MEHC or any of its other
such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject
to applicable law and the tenDS of financing arrangements of such parties, be advanced, loaned, paid as dividends or
otherwise distributed or contributed to MEHC or affiliates thereof.
The restrictions on distributions at these separate legal entities include various covenants including, but not limited to
leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2004, the separate legal entities
were in compliance with all applicable covenants. However, Cordova Energy s 537 MW gas-fired power plant in the Quad
Cities, Illinois area (the "Cordova project") is currently prohibited from making distributions by the tenDS of its indenture due
to its failure to meet its debt service coverage ratio requirement.
Long-tenn debt of subsidiaries and projects consists of the following at December 31 (in thousands):
MidAmerican Funding
MidAmerican Energy
CE Electric UK
Kern River
N orthem Natural Gas
CE Casecnan
Leyte Projects
Cordova Funding
Funding Corporation
HomeServices
Other, including fair value adjustments
Total Subsidiary and Project Debt
Less current portion
Total Long- Tenn Subsidiary and Project Debt
2004
700,000
422 527
504 801
214 808
799 614
197,098
105 664
206 663
963
383
190 521
MidAmerican Funding
2003
$ 700 000
128,647
467,214
276 174
799,472
246 458
172 813
214,761
136 384
37,558
(3.900)
175,581
(500.941
The components of MidAmerican Funding s, a wholly owned subsidiary of MEHC, Senior Notes and Bonds consist of the
following at December 31 (in thousands):
339% Senior Notes, due 2009
75% Senior Notes, due 2011
927% Senior Bonds, due 2029
Total MidAmerican Funding
2004
$ 175 000
200 000
, 325.000
2003
$ 175,000
200,000
325.000
MidAmerican Funding may use distributions that it receives from its subsidiaries to make payments on the Notes and Bonds.
These subsidiaries must make payments on their own indebtedness before making distributions to MidAmerican Funding.
These distributions are also subject to utility regulatory restrictions agreed to by MidAmerican Energy in March 1999
whereby it committed to the Iowa Utilities Board ("lUB") to use commercially reasonable efforts to maintain an investment
grade rating on its long-tenD debt and to maintain its common equity level above 42% of total capitalization unless
circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization.
MidAmerican Energy must seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy
common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican
Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy s equity level
decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy.
MidAmerican Energy
Exhibit No. 11, page 78 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
The components of MidAmerican Energy s Mortgage Bonds, Pollution Control Revenue Obligations and Notes consist of thefollowing at December 31 (in thousands):
Mortgage bonds:
7% Series, due 2004
7% Series, due 2005
Pollution control revenue obligations:
1 % Series, due 2007
95% Series, due 2023
Variable rate series:
Due 2016 and 2017 05% and 1.26%
Due 2023 secured by general mortgage bond, 2.05% and 1.26%
Due 2023, 2.05% and 1.26%
Due 2024, 2.05% and 1.26%
Due 2025, 2.05% and 1.26%
Notes:
375% Series, due 2006
5.125% Series, due 2013
65% Series, due 2014
75% Series, due 2031
Obligations under capital lease
Unamortized debt premium and discount, net
Total MidAmerican Energy
2004 2003
55,630
500 500
000 000
030 030
600 37,600
295 295
850 850
900 900
750 750
160 000 160,000
275 000 275,000
350 000
400 000 400,000
524 060
MidAmerican Energy s 7.7% series of mortgage bonds, totaling $55.6 million, matured on May 17, 2004. On October 1,
2004, MidAmerican Energy issued $350.0 million of 4.65% medium-tenn notes due October 1, 2014. The proceeds were
used for general corporate purposes.
On January 14, 2003, MidAmerican Energy issued $275.0 million of 5.125% medium-tenn notes due in 2013. The proceeds
were used to refinance existing debt and for other corporate purposes.
CE Electric UK
The components of CE Electric UK and its subsidiaries' long-tenn debt consist of the following at December 31 (in
thousands):
853% Senior Notes, due 2004
625% Bearer bonds, due 2005
995% Senior Notes, due 2007
6.496% Yankee Bonds, due 2008
Variable Rate Reset Trust Securities, due 2020 (5.88% and 4.39%)
875% Bearer bonds, due 2020
25% Eurobonds, due 2020
25% Sterling Bonds, due 2022
25% Eurobonds, due 2028
CE Gas Credit Facility, 6.36%
Total CE Electric UK
2004 2003
$ 117 112
178,877
236 174
281 149
287 539
178 644
458 187
351 242
352 768
25.522
192 045
237 000
281 113
308,361
191 955
485,654
377 674
378,202
52.797
Exhibit No. II, page 79 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Pursuant to a call option exercised in February 2005, at a cost of $17.5 million, a subsidiary of CE Electric UK purchased,
and then cancelled, its Variable Rate Reset Trust Securities, due in 2020, at a par value of 1:155.0 million. Accordingly, the
Company has included the entire principal amount of these securities in its current portion of long-term debt in the
accompanying consolidated balance sheet at December 31, 2004.
Kern River
The components of Kern River s long-term debt consist of the following at December 31 (in thousands):
676% Senior Notes, due 2016
893% Senior Notes, due 2018
Total Kern River
2004
$ 439,000
775.808
2003
$ 464 000
812.174
On August 13, 2001 , Kern River issued $510.0 million in debt securities. The offering was in the form of $510.0 million of
15-year amortizing Senior Notes bearing a fixed rate of interest of 6.676%. For the Senior Notes, $405.0 million will be
amortized through June 2016, with a final payment of $1 05.0 million to be made on July 31 , 2016.
On May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836.0 million of its
893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the $815.0 million of
outstanding borrowings under Kern River s $875.0 million credit facility. Kern River entered into this credit facility in 2002
to finance the construction of its 717 mile expansion.
Northern Natural Gas
The components of Northern Natural Gas' Senior Notes consist of the following at December 31 (in thousands):
875% Senior Notes, due 2005
75% Senior Notes, due 2008
00% Senior Notes, due 2011
375% Senior Notes, due 2012
Unamortized debt discount
Total Northern Natural Gas
2004
$ 100 000
150 000
250,000
300 000
~ 799.
CE Casecnan
2003
$ 100 000
150 000
250 000
300,000
(528)
799.
On November 27, 1995, CE Casecnan issued $371.5 million of notes and bonds to finance the construction of the CE
Casecnan project. The CE Casecnan Notes and Bonds consist of the following at December 31 (in thousands):
11.45% Senior Secured Series A Notes, due in 2005
11.95% Senior Secured Series B Bonds, due in 2010
Total CE Casecnan
2004
$ 48 750
148.348
2003
$ 91 250
155.208
The CE Casecnan Notes and Bonds are subject to redemption at the Company s option as provided in the Trust Indenture.
The CE Casecnan Notes and Bonds are also subject to mandatory redemption based on certain conditions.
Leyte Projects
The Leyte Projects tenD loans consist of the following at December 31 (in thousands):
Mahanagdong Project 6.92% Tenn Loan, due 2007
Mahanagdong Project 7.60% Tenn Loan, due 2007
Malitbog Project 4.99% and 3.67%, due 2005
Malitbog Project 9.176% Tenn Loan, due 2006
Upper Mahiao Project 5.95% Tenn Loan, due 2006
Total Leyte Projects
2004
$ 51 537
11,428
866
580
24.253
l"acltlCorp
Exhibit No. 11, page 80 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
2003
$ 72 151
, 16 000
378
14,628
43.656
MEHC provides d~bt service reserve letters of credit in amounts equal to the next semi-annual principal and interest
payments due on the loans which were equal to $44.6 million and $40.3 million at December 31, 2004 and 2003,
respectively.
Cordova Funding
On September 10, 1999, Cordova Funding Corporation ("Cordova Funding ), a wholly owned subsidiary of the Company,
closed the $225.0 million aggregate principal amount financing for the construction of the Cordova project. The proceeds
were loaned to Cordova Energy and consist of the following at December 31 (in thousands):
8.48% Senior Secured Bonds, due 2019
64% Senior Secured Bonds, due 2019
79% Senior Secured Bonds, due 2019
82% Senior Secured Bonds, due 2019
07% Senior Secured Bonds, due 2019
Toml CoMova Fundmg
2004
$ 11 716
85,893
28,758
53,384
26.912
2003
$ 12 175
89,260
29,885
55,476
27.965
MEHC has issued a limited guarantee of a specified portion of the final scheduled principal payment on December 15,2019
on the Cordova Funding Senior Secured Bonds in an amount up to a maximum of $37.0 million. MEHC has also issued a
debt service reserve guarantee of which such maximum amount was $13.0 million as of December 31, 2004.
As of December 31 , 2004, Cordova Funding is currently prohibited from making distributions by the tenDS of its indenture
due to its failure to meet its debt service coverage ratio requirement.
Funding Corporation
CalEnergy Minerals LLC ("Minerals ), a wholly-owned indirect subsidiary of MEHC, was one of several guarantors of the
Funding Corporation debt. As a result of a note allocation agreement, Minerals was primarily responsible for
$136.4 million of the Series F Bonds. In 1999, MEHC guaranteed a specified portion of the scheduled debt service on the
Series F Bonds equal to the then current principal amount of $136.4 million and associated interest.
On March 1 , 2004, Funding Corporation completed the redemption of an aggregate principal amount of $136.4 million of the
Series F Bonds, pro ram, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest
to the date of redemption. Funding Corporation also made a demand on MEHC for the full amount remaining on MEHC'
guarantee of the Series F Bonds in order to fund the redemption. MEHC made the requisite payment and, as a result, it has no
further liability with respect to its guarantee. The Company had a non-cash, after-tax loss, recorded in loss from discontinued
operations in the accompanying consolidated statement of operations, of $6.4 million as a result of the redemption of the
Series F Bonds.
HomeServices
PacifiCorp
Exhibit No. 11 , page 81 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
In November 1998, HomeServices issued $35.0 million of 7.12% fixed-rate private placement senior notes due in annual
increments of$5.0 million beginning in 2004. As of December 31 2004 and 2003, the balance of the HomeServices Senior
Notes was $30.0 million and $35.0 million, respectively.
In addition to the senior notes, HomeServices has outstanding capital leases and other long-term debt, with varying interest
rates, totaling $3.0 million and $2.6 million at December 31 2004 and 2003, respectively.
Annual Repayments of Long- term Debt
The annual repayments of parent company, subsidiary and project debt for the years beginning January 1 , 2005 and thereafter
areas follows (in thousands):
Parent Company senior
debt
Parent Company
subordinated debt
MidAmerican Funding
MidAmerican Energy
CE Electric UK
Kern River
Northern Natural Gas
CE Casecnan
Leyte Projects
Cordova Funding
HomeServiees
Other, including purchase
accounting adjustments
Totals
Fair Value
2006 2007
$ 260,000 550,000
188,543 234,021 234,021
018 160,000 000
500,406 720 253,925
784 128 472
99,963
753 36,016 730
63,034 30,037 593
875 500 163
765 000 000
$1,000,000
234 021
294 051
816
150 000
37,730
725
000
$1.798.343
234 021
175,000
913
74,906
13,720
412
000
$ 513.972
Thereafter Total
$ 1 221 957 031,957
649,726 774 353
525,000 700,000
170,509 422 527
441 786 504 801
868 702 214 808
549,651 799,614
149 197,098
105,664
178 988 206 663
198 963
383 383
$ 6637049 $ 11 996831
At December 31, 2004, the Company had fixed-rate long-term debt of $11 ,503.4 million in principal amount and having a
fair value of $12 416.2 million. In addition, at December 31, 2004, the Company had floating-rate obligations of
$493.4 million that expose the Company to the risk of increased interest expense in the event of increases in short-term
interest rates. The fair value of the floating-rate obligations and the short-term debt approximates their carrying amounts.
$1 334 141 $ 545.422 $ 1.167.904
At December 31 2003, the Company had fixed-rate long-term debt of $11 369.4 million in principal amount and having a
fair value of $12 015.1 million. In addition, at December 31 , 2003, the Company had floating-rate obligations of
$459.8 million. The fair value of the floating-rate obligations and the short-term debt approximates their carrying amounts.
Year Ended December 31,
2004 2003 2002
18,794 (48,911)236
862)901 17,476
79.463 88.150 54.586
88.395 50.140 129.298
112 719 141 795 900)
607 833 (13 640)
63.265 67.508 520
176.591 220.136 ---.O..MW26~
15. Income Taxes
Income tax expense on continuing operations consists of the following (in thousands):
Current:
Federal
State
Foreign
Deferred:
Federal
State
Foreign
Total
PacifiCorp
Exhibit No. )), page 82 of ) 30
CASE NO. PAC-05-Witness: Patrick J. Goodman
A reconciliation of the federal statutory tax rate to the effective tax rate on continuing operations applicable to income before
income tax expense follows:
Federal statutory rate
Investment and energy tax credits
State taxes, net of federal tax effect
Equity income
Dividends on preferred securities of subsidiaries
Tax effect of foreign income
Non-recurring items on CE Electric UK, net of tax
effect of foreign income
Dividends received deduction
Effects of ratemaking
Other items, net
Effective tax rate
2004
35.
(0.
2003
35.
(0.
1.8
1.6
(6.
(0.
ad)
33.
(0.
(1.1)
31.
Deferred tax liabilities (assets) consist of the following at December 31 (in thousands):
Properties, plants and equipment, net
Income taxes recoverable through future rates
Employee benefits
Reacquired debt
Fuel cost recoveries
2004
$ 1 700 884
163,108
56,656
877
028
930.553
Minimum pension liability adjustment
Revenue sharing accruals
Accruals not currently deductible for tax purposes
Nuclear reserve and decommissioning
Deferred income
Net operating loss ("NOL") and credit carryforwards
Other
(172 350)
(80,220)
, (54 402)
(27,112)
(34 458)
(267,051 )
----1.llJ.21)
Net deferred income taxes
2002
35.
(0.
1.2
(8.
(4.
(8.3)
(1.
1.0
..lJ.
17.
2003
$ 1 611 744
142 597
005
665
12.864
1.815.875
(147 279)
(64 192)
(55,290)
(35 955)
(37 819)
(161 659)
16.793)
nU'::IIILUIp
Exhibit No. II , page 83 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
At December 31 , 2004, the Company has available unused NOL and credit carryforwards that may be applied against future
taxable income and that expire at various intervals between 2007 and 2024.
16. Preferred Securities of Subsidiaries
The total outstanding cumulative preferred securities of MidAmerican Energy are not subject to mandatory redemption
requirements and may be redeemed at the option of MidAmerican Energy at prices which, in the aggregate, total
$31.1 million. The aggregate total the holders of all preferred securities outstanding at December 31, 2004, are entitled to
upon involuntary bankruptcy is $30.3 million plus accrued dividends. The annual dividend requirements for all preferred
securities outstanding at December 31, 2004, total $1.2 million.
The total outstanding 8.061 % cumulative preferred securities of a subsidiary of CE Electric UK, which are redeemable in the
event of the revocation by the Secretary of State of the subsidiary s electricity distribution license, was $56.0 million as of
Dec~mber 31 2004 and 2003, respectively.
17. Convertible Preferred Stock
In connection with the Kern River acquisition and the purchase of$275.0 million of Williams' preferred stock , MEHC issued
7 million shares of no par, zero-coupon convertible preferred stock valued at $402.0 million to Berkshire Hathaway. In
connection with the Teton Transaction, MEHC issued 34.6 million shares of no par, zero coupon convertible preferred stock
valued at $1 211.4 million. Each share of preferred stock is convertible at the option of the holder into one share ofMEHC'
common stock subject to certain adjustments as described in MEHC's Amended and Restated Articles of Incorporation.
While the convertible preferred stock does not vote generally with the common stock in the election of directors, the
convertible preferred stock gives Berkshire Hathaway the right to elect 20% of MEHC's Board of Directors. The convertible
preferred stock is convertible into common stock only upon the occurrence of specified events, including modification or
elimination of the Public Utility Holding Company Act of 1935 so that holding company registration would not be triggered
by conversion. Additionally, the prior approval of the holders of convertible preferred stock is required for certain
fundamental transactions by MEHC. Such transactions include, among others: (a) significant asset sales or dispositions; (b)
merger transactions; (c) significant business acquisitions or capital expenditures; (d) issuances or repurchases of equity
securities; and (e) the removal or appointment of the Chief Executive Officer.
MEHC's Articles of Incorporation further provide that the convertible preferred shares: (a) are not mandatorily redeemable
by MEHC or at the option of the holder; (b) participate in dividends and other distributions to common shareholders as if
they were common shares and otherwise possess no dividend rights; (c) are convertible into common shares on a 1 for 1
basis, as adjusted for splits, combinations, reclassifications and other capital changes by MEHC; and (d) upon liquidation
except for a de minimus first priority distribution of $1 per share, shared ratably with the shareholders of common stock.
Further, the aforementioned dividend and distribution arrangements cannot be modified without the positive consent of the
preferred shareholders.
18. Stock Transactions
As of December 31 , 2004" there were 2 048 329 options outstanding which are e~ercisable until the end of the tenD on
March 14 2008 at exercise prices ranging from $15.94 to $35.05 per share.
On March 6, 2002, MEHC purchased 800 000 stock options held by Mr. David L. Sokol, its Chainnan and Chief Executive
Officer. The options purchased had exercise prices ranging from $18.50 to $29.01. MEHC paid Mr. Sokol an aggregate
amount of $27.1 million, which is equal to the difference between the option exercise prices and an agreed upon per share
value.
On January 6, 2004, the Company purchased a portion of the shares of common stock owned by Mr. Sokol for an aggregate
purchase price of $20.0 million.
19. Accounting for Derivatives
t'aCIfJLorp
Exhibit No. II , page 84 of 130CASE NO. PAC-05-Witness: Patrick.1, Goodm:m
The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To
manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments.
Senior management provide the overall direction, structure, conduct and control of the Company s risk management
activities, including the use of financial derivative instruments, authorization and communication of risk management
policies and procedures, strategic hedging program and guidelines, appropriate market and credit risk limits, and appropriate
systems for recording, monitoring and reporting the results of transactional and risk management activities.
Currency Exchange Rate Risk
CE Electric UK entered into currency rate swap agreements for its Senior Notes with large mufti-national financial
institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling for
$237.0 million of 6.995% Senior Notes outstanding at December 31 , 2004. The agreements extend until maturity on
December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of
these swap agreements at December 31 2004 and 2003, was $35.7 million and $16.0 million, respectively, based on quotes
from the counterparty to these instruments and represents the estimated amount that the Company would expect to pay
these agreement were tenninated.
A subsidiary of CE Electric UK entered into certain currency rate swap agreements for its Yankee Bonds with three large
multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate
in Sterling for $281.1 million of the 6.496% Yankee Bonds outstanding at December 31, 2004. The agreements extend until
maturity on February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to
345%. The estimated fair value of these swap agreements at December 31 , 2004 and 2003, was $96.1 million and
$62.6 million, respectively, based on quotes from the counterparties to these instruments and represents the estimated amount
that the Company would expect to pay if these agreements were tenninated.
Derivatives
As of December 31 , 2004, MidAmerican Energy held derivative instruments used for non-trading and trading purposes with
the following fair values (in thousands):
Contract Type
Maturity
in 2005
Maturity
in 2006-
Non-trading:
Regulated electric assets
Regulated electric (liabilities)
Regulated gas assets
Regulated gas (liabilities)
, Regulated weather (liabilities)
Nonregulatedelectric assets
Nonregulated electric (liabilities)
Nonregulated gas assets
Nonregulated gas (liabilities)
Total
260
(10 057)
973
(21 ,921 )
495)
957
(1,158)
937
(6.606
--ill..Jl.Q)
431
817)
798
372
(214)
919
(2.069)
Trading:
Nonregulated gas assets
Nonregulated gas (liabilities)
Total
Total
$ 2 691
(14 874)
771
(21 921)
495)
329
372)
856
--D.lJ.12)
993 993
( 4l.Q)---Ll.QQ)(53.Q)
563 ---Ll.QQ)463
(6.
Total MidAmerican Energy assets
Total MidAmerican Energy (liabilities)
PacifiCorp
Exhibit No. II, page 85 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
20. Regulatory Matters
MidAmerican Energy
Under three settlement agreements between MidAmerican Energy, The Iowa Office of Consumer Advocate ("OCA") and
other intervenors approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric rates prior
to 2012 unless its Iowa jwisdictional electric return on equity for any year falls below 10%. Prior to filing for a general
increase in electric rates, MidAmerican Energy is required to conduct 30 days of good faith negotiations with the signatories
to the settlement agreements to attempt to avoid a general increase in such rates. As a party to the settlement agreements the
OCA has agreed not to request or support any decrease in MidAmerican Energy s Iowa electric rates prior to January
2012. The settlement agreements specifically allow the IUB to approve or order electric rate design or cost of service rate
changes that could result in changes to rates for specific customers as long as such changes do not result in an overall
increase in revenues for MidAmerican Energy. The settlement agreements also each provide that portions of revenues
associated with Iowa retail electric returns on equity within specified ranges will be recorded as a regulatory liability.
Under the first settlement agreement, which was approved by the ruB on December 21 , 2001 , and is effective through
December 31, 2005, an amount equal to 50% of revenues associated with returns on equity between 12% and 14%, and
83.33% of revenues associated with returns on equity above 14%, in each year is recorded as a regulatory liability. The
second settlement agreement, which was filed in conjunction with MidAmerican Energy s application for ratemaking
principles on its wind power project and was approved by the IUB on October 17, 2003, provides that during the period
January 1 , 2006 through December 31 , 2010, an amount equal to 40% of revenues associated with returns on equity between
11.75% and 13%, 50% of revenues associated with returns on equity between 13% and 14%, and 83.3% of revenues
associated with returns on equity above 14%, in each year will be recorded as a regulatory liability.
The third settlement agreement was approved by the IUB on January 31 2005, in conjunction with MidAmerican Energy
proposed expansion of its wind power project by up to 90 MW. This settlement extended through 2011 MidAmerican
Energy s commitment not to seek a general increase in electric rates unless its Iowa jurisdictional electric return on equity
falls below 10%. It also extended the revenue sharing mechanism through 2011. In addition, the OCA agreed to commit not
to seek any decrease in Iowa electric base rates to become effective before January 1 , 2012. The total capacity added as the
result of the wind expansion project is currently projected to be 50 MW.
The regulatory liabilities created by the three settlement agreements are recorded as a regulatory charge in depreciation and
amortization expense when the liability is accrued. Additionally, interest expense is accrued on the portion of the regulatory
liability balance recorded in prior years. The regulatory liabilities created for the years through 2010 are expected to be
reduced as they are credited against plant in service in amounts equal to the AFUDC associated with generating plant
additions. As a result of the credit applied to generating plant balances from the reduction of the regulatory liabilities, future
depreciation will be reduced. As of December 31 , 2004 and 2003, the related regulatory liability reflected in the
accompanying consolidated balance sheets was $181.2 million and $144.4 million, respectively. The regulatory liability for
2011 will be credited to customer bills in 2012.
Illinois bundled electric rates are frozen until 2007, subject to certain exceptions allowing for increases, at which time
bundled rates may be increased or decreased by the Illinois Commerce Commission. Illinois law provides that, through 2006
Illinois earnings above a computed level of return on common equity are to be shared equally between regulated retail
electric customers and MidAmerican Energy. MidAmerican Energy s computed level of return on common equity is based
on a rolling two-year average of the Monthly Treasury Long-Term Average Rate, as published by the Federal Reserve
System, plus a premium of 8.5% for 2000 through 2004 and a premium of 12.5% for 2005 and 2006. The two-year average
above which sharing must occur for 2004 is 13.57%. The law allows MidAmerican Energy to mitigate the sharing of
earnings above the threshold return on common equity through accelerated recovery of electric assets.
Kern River
Kern River s tariff rates were designed to give it an opportunity to recover all actually and prudently incurred operations and
maintenance costs of its pipeline system, taxes, interest, depreciation and amortization and a regulated equity return. Kern
River s rates are set using a "levelized cost-of-service" methodology so that the rate is constant over the contract period. This
is achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases.
t'acltlCOrp
Exhibit No. II, page 86 of 130C~SE NO. PAC-05-WItness: Patrick J. Goodman
Kern, River was required to file a general rate case no later than May 1 , 2004 pursuant to the tenns of its 1998 FERC Docket
No. RP99-274 rate case settlement. Kern River filed its rate case on April 30, 2004, which supports a revenue increase of
$40.1 million representing a 13% increase from its existing cost of service and a proposed overall cost of service of
$347.4 million. Since its last rate case, Kern River has increased the capacity of its system from 724 500 Dth per day to
755,575 Dth per day at a cost of approximately $1.3 billion, resulting in a total rate base of approximately $1.8 billion. The
rate increase became effective on November 1 , 2004, subject to refund, and the FERC set a procedural order with a hearing
scheduled for March 2005.
Northern Natural Gas
Northern Natural Gas has implemented a straight fixed variable rate design which provides that all fixed costs assignable to
finn capacity customers, including a return on equity, are to be recovered through fixed monthly"demandor capacity
reservation charges which are not a function ofthroughput volumes.
On May 1 , 2003, Northern Natural Gas filed a request for increased rates with the FERC. The rate increase is primarily
attributable to four main cost areas: the capital investment made by Northern, Natural Gas in the five years since its last rate
case, an increase in Northern Natural Gas' depreciation rates , increased return on equity, and changes in the level of contract
entitlement. The rate filing provides evidence in support of a $71 million increase to Northern Natural Gas' annual revenue
requirement. However, Northern Natural Gas chose to effectuate only $55 million of the increase. Northern Natural Gas' new
rates went into effect November 1 , 2003, subject to refund.
Additionally, on January 30, 2004, Northern Natural Gas filed with the FERC to increase its revenue requirement by an
incremental $30 million to that requested in the May 1 , 2003 filing. The increased revenue requirement is primarily
attributable to ongoing pipeline integrity initiative costs that Northern Natural Gas has undertaken since the May 1, 2003 rate
filing. The FERC suspended the rate increase until August 1, 2004 and consolidated the 2003 and 2004 rate cases due to the
similarity of issues in both cases and the updated costs. On July 29, 2004, Northern Natural Gas notified the FERCthat, in
furtherance of settlement negotiations, Northern Natural Gas was not moving the rate increase into effect on August 1, 2004
but reserved its statutory right to move the suspended rates into effect at a later date. Northern Natural Gas' implemented the
new rates on November 1 , 2004, subject to refund.
On February 16, 2005, Northern Natural Gas reached a tentative agreement with the majority of its customers to settle the
consolidated rate cases. Definitive tenns of the settlement must be agreed by all settling parties and must then be documented
in a settlement agreement which must be agreed to by all settling parties. Thereafter, the settlement must be certified by the
presiding administrative law judge and approved by the FERC. The terms of the agreement in principle provide for an annual
revenue increase of $48 million for the period November 1, 2003, through October 31, 2004, $53 million for the period
November 1 , 2004 through October 31, 2005, $58 million for the period November 1, 2005 through October 31 , 2006, and
$62 million beginning November I, 2006. As a result of the settlement, Northern Natural Gas will be required to refund an
amount generally reflecting the difference between the rate increases implemented on November 1 , 2003 and November 12004 and the final settled revenue amounts.
CE Electric UK
The majority of the revenue of the Distribution License Holder ("DLH") in the United Kingdom is controlled by a
distribution price control fonnula which is set out in the license of each DLH. It has been the practice of the Office of Gas
and Electricity Markets ("Of gem ) (and its predecessor body, the Office of Electricity Regulation), to review and reset the
fonnula at five-year intervals, although the formula may be further reviewed at other times at the discretion of the regulator.
Any such resetting of the fonnula requires the consent of the DLH. If the DLH does not consent to the fonnula reset, it is
reviewed by the United Kingdom s competition authority, whose recommendation can then be given effect by licensemodifications made by Of gem.
The current fonnula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where
RPI means the Retail Price Index, reflecting the average of the 12-month inflation rates recorded for each month in the
previous July to December period. The Xd factor in the fonnula was established 'by Of gem at the price control review
effective in April 2000 (and through March 31 , 2005, will continue to be set) at 3%. The fonnula also takes account of a
variety of other factors including the changes in system electrical losses, the number of customers connected and the voltage
at which customers receive the units of electricity distributed. The distribution price control formula detennines the
maximum average price per unit of electricity distributed (in pence per kWh) which a DLH is entitled to charge. The
t'acltJcorp
Exhibit No. ) 1, page 87 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
distribution price control fonnula pennits DLHs to receive additional revenue due to increased distribution of units and the
increase in the number of end users. The price control does not seek to constrain the profits of a DLH from year to year. It is
a control on revenue that operates independently of most of the DLH's costs. During the term of the price control, cost
savings or additional costs have a direct impact on income and cash flow.
Ofgem s process of reviewing each DLH's existing price control fonnula, with a revised formula for each DLH (including
Northern Electric and Yorkshire Electricity) to take effect from April 1 , 2005 for an expected period of five years, was
recently completed. As a result of the review, the allowed revenue of Northern Electric s distribution business was reduced
by 4%, in real tenns, and the al1owed revenue of Yorkshire Electricity's distribution business was reduced by 9%, in real
tenns, with effect from April '2005. The Xd factor was set at zero. Of gem indicated that during the period 2005 to 2010, the
retention of the benefits of any out-perfonnance from the operating cost assumptions made by Of gem in setting the new price
control may depend on the successful implementation of revised cost reporting guidelines to be prescribed by Of gem and
applied by al1 DLHs. In setting the allowed revenue of Northern Electric and Yorkshire Electricity (and all other DLHs) with
effect from April 1 , 2005, Of gem made a specific allowance for an amount in respect of each DLH's pension costs.
With effect from April I, 2005, a number of incentive schemes operate to encourage DLHs to provide an appropriate quality
of service. Payments in respect of each failure to meet a prescribed standard of service are set out in regulations. The
aggregate payments that may be due is uncapped, although payments are excused in certain force majeure circumstances. In
stonn conditions the obligations relating to the period within which supplies should be restored are relaxed and the overall
annual exposure under the restoration standard in stonn conditions is limited to 2% of a DLH's allowed revenue. There also is
a discretionary reward scheme of up to f1 million per annum, and other incentive schemes pursuant to which a DLH'
allowed revenue may increase by up to 3.3% or decrease by up to 3.5% in any year.
21. Commitments and Contingencies
MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Domestic and
HomeServices have non-cancelable operating leases primarily for computer equipment, office space and rail cars. Rental
payments on non-cancelable operating leases totaled $71.1 million for 2004, $65.8 million for 2003, and $60.1 million for
2002. The minimum payments under these leases are $70.4 million, $64.3 million, $56.7 million, $45.9 million, and
$33.0 million for the years 2005 through 2009, respectively, and $104.7 million for the total of the years thereafter.
MidAmerican Energy
Fuel, Energy and Operating Lease Commitments
MidAmerican Energy has supply and related transportation contracts for its fossil fueled generating stations. As of
December 31 , 2004, the contracts, with expiration dates ranging from 2005 to 2010, require minimum payments of
$83.5 million, $67.4 million, $62.8 million, $22.0 million and $15.8 million for the years 2005 through 2009, respectively,
and $15.5 million for the total of the years thereafter. MidAmerican Energy expects to supplement these coal contracts with
additional contracts and spot market purchases to fulfil1 its future fossil fuel needs. Additionally, MidAmerican Energy has a
supply and transportation contract for a natural gas-fired generating plant. The contract, which expires in 2012, requires
minimum annual payments of $6.2 million.
MidAmerican Energy also has contracts to purchase electric capacity. As of December 31 , 2004, the contracts, with
expiration dates ranging from 2005 to 2028, require minimum payments of $29.1 million, $25.1 million, $27.3 million
$35.8 million and $28.9 million for the years 2005 through 2009, respectively, and $73.9 million for the. total of the years
thereafter.
MidAmerican Energy has various natural gas supply and transportation contracts for its gas operations. As of December 31
2004, the contracts, with expiration dates ranging from 2005 to 2013, require minimum payments of $54.2 million
$35.1 million, $25.2 million, $4.4 million and $2.9 million for the years 2005 through 2009, respectively, and $10.3 million
for the total of the years thereafter.
MidAmerican Energy is the lessee on operating leases for coal railcars that contain guarantees of the residual value of such
equipment throughout the term of the leases. Events triggering the residual guarantees include termination of the lease, loss
of the equipment or purchase of the equipment. Lease terms are for five years with provisions for extensions. As
raCITILOrp
Exhibit No. II, page 88 of 130
CASE NO. PAC-05-
Witne!'!': Patrick J, Goorlm:m
December 31 , 2004~ the maximum amount of such guarantees specified in these leases totaled $30.2 million. These
guarantees are not reflected in the accompanying consolidated balance sheets.
On February 12 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. ("Mitsui") for
engineering, procurement and construction of a 790 MW (based on expected accreditation) coal-fired generating plant
expected to be completed in the summer of 2007. MidAmerican Energy will hold a 60.67% individual ownership interest as a
tenant in common with the other owners of the plant. Under the contract, MidAmerican Energy is allowed to defer payments,
including the other owners' shares, for up to $200.0 million of billed construction costs through the end of the project.
Deferred payments as of December 31, 2004 and 2003, totaled $152.3 million and $23.4 million, respectively, and are
reflected in other long-tenD accrued liabilities in the accompanying consolidated balance sheets.
An asset representing the other owners' share of the deferred payments is reflected in deferred charges and other assets in the
accompanying consolidated balance sheets and totaled $59.9 million and $9.2 million, respectively, as of December 31 2004
and 2003. MidAmerican Energy will bill each of the other owners for its share of the deferred payments when payment is
made to Mitsui.
Air Quality
MidAmerican Energy s generating facilities are subject to applicable provisions of the Clean Air Act and related air quality
standards promulgated by the EP A. The Clean Air Act provides the framework for regulation of certain air emissions and
pennitting and monitoring associated with those emissions. MidAmerican Energy believes it is in material compliance with
current air quality requirements.
The EP A has in recent years implemented more stringent national ambient air quality standards for ozone and new standards
for fine particulate matter. These standards set the minimum level of air quality that must be met throughout the United
States. Areas that achieve the standards, as detennined by ambient monitoring, are characterized as being in attainment of the
standard. Areas that fail to meet the standard are designated as being nonattainment areas. Generally, once an area has been
designated as a nonattainment area, sources of emissions in the area that contribute to the failure to achieve the ambient air
quality standards are required to make emissions reductions. The EP A has concluded that the entire State of Iowa is in
attainment of the ozone standards and the fine particulate standards.
On December 4, 2003, the EP A announced the development of its Interstate Air Quality Rule, now known as the Clean Air
Interstate Rule, a proposal to require coal-burning power plants in 29 states, including Iowa, and the District of Columbia to
reduce emissions of sulfur dioxide ("S02 ) and nitrogen oxides ("NOx ) in an effort to reduce ozone and fine particulate
matter in the Eastern United States. It is likely that MidAmerican Energy s coal-burning facilities will be impacted by this
proposal.
In December 2000, the EP A concluded that mercury emissions from coal-fired generating stations should be regulated. The
EPA is currently considering two regulatory alternatives that would reduce emissions of mercury from coal-fired utilities.
One of these alternatives would require reductions of mercury from all coal-fired facilities greater than 25 MW through
application of Maximum Achievable Control Technology with compliance assessed on a facility basis. The other alternative
would regulate the mercury emissions of coal-fired facilities that pose a health hazard through a market based cap-and-trade
mechanism similar to the S02 allowance system. The EPA is currently under a deadline'to finalize the mercury reduction ruleby March 2005.
The Clean Air Interstate Rule or the mercury reduction rule could, in whole or in part, be superseded or made more stringent
by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level
including the "Clear Skies Initiative " and other pending legislative proposals that contemplate 70% to 90% reductions of
S02, NOx and mercury, as well as possible new federal regulation of carbon dioxide and other gasses that may affect global
climate change.
Depending on the outcome of the final Clean Air Interstate Rule and the mercury reduction rule or any superseding
legislation by Congress, MidAmerican Energy may be required to install control equipment on its generating stations,
purchase emission allowances or decrease the number of hours during which its generating stations operate. However, until
final regulatory or legislative action is taken, the impact of the regulations on MidAmerican Energy cannot be predicted.
. "~III~Vlp
Exhibit No. II , page 89 of 130CASE NO. PAC-O5-Witness: Patrick J. Goodman
MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be
required to meet emissions reductions as contemplated by the United States Environmental Protection Agency ("EP A"). In
accordance with an Iowa law passed in 2001 , MidAmerican Energy has on file with the ruB its current multi-year plan and
budget for managing S02 and NOx from its generating facilities in a cost-effective manner. The plan, which is required to be
updated every two years, provides specific actions to be taken at each coal-fired generating facility and the related costs and
timing for each action. On July 17, 2003, the IUB issued an order that affinned an administrative law judge s approval of the
initial plan filed on April 1, 2002, as amended. On October 4, 2004, the ruB issued an order approving MidAmerican
Energy s second biennial plan as revised in a settlement MidAmerican Energy entered into with the Iowa Consumer
Advocate Division of the DeJ,Jartment of Justice. That plan covers the time period from April ', 2004 through December 31
2006. Neither IUB order resulted in any changes to electric rates for MidAmerican Energy. The effect of the orders is to
approve the prudence of expenditures made consistent with the plans. Pursuant to an unrelated rate settlement agreement
approved by the IUB on October 17, 2003, if prior to January 1, 2011, capital and operating expenditures to comply with
environmental requirements cumulatively exceed $325.0 million, then MidAmerican Energy may seek to recover the
additional expenditures from customers. At this time, MidAmerican Energy does not expect these capital expenditures to
exceed such amount.
Under the New Source Review ("NSR") provisions of the Clean Air Act, a utility is required to obtain a pennit from the EP
or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated
pollutant or (2) making a physical or operational change to an existing facility that potentially increases emissions, unless the
changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general
projects subject to NSR regulations are subject to pre-construction review and pennitting under the Prevention of Significant
Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of
regulated pollutants must undergo a Best A vailtlble Control Technology analysis and evaluate the most effective emissions
controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged
by the EP A, states and environmental, groups, among others, potentially subject a utility to material expenses for fines and
other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental
environmental projects.
In recent years, the EP A has requested from several utilities infonnation and support regarding their capital projects for
various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the
NSR and the New Source Perfonnance Standards of the Clean Air Act. In December 2002 and April 2003, MidAmerican
Energy received requests from the EPA to provide documentation related to its capital projects from January I, 1980, to April
2003 for a number of its generating plants. MidAmerican Energy has submitted infonnation to the EP A in responses to these
requests, and there are currently no outstanding data requests pending from the EP A. ,MidAmerican Energy cannot predict the
outcome of these requests at this time. However, on August 27,2003, the EPA announced changes to its NSR rules that
clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. The EP
concluded equipment that is repaired, maintained or replaced with an expenditure not greater than 20 percent of the value of
the source will not trigger the NSR provisions of the Clean Air Act. A number of states and local air districts challenged the
EPA's clarification of the NSR rule and a panel of the U.S. Circuit Court of Appeals for the District of Columbia Circuit
issued an order on December 24, 2003, staying the EPA's implementation of its clarifications of the equipment replacement
rule. On July 1 , 2004, the EPA published a notice of stay of the final equipment replacement rule in the Federal Register
consistent with the judicial stay. Additionally, on the same date, the EPA published a Notice of Reconsideration and Request
for Comment on the equipment replacement rule in response to the Petitioners' legal challenges. Until such time as the EPA
takes final action on the equipment replacement rule, the previous rules without the clarified exemption remain in effect.
Nuclear Decommissioning Costs
Expected decommissioning costs for Quad Cities Station have been developed based on a site-specific decommissioning
study that includes decontamination, dismantling, site restoration, dry fuel storage cost and an assumed shutdown date. Quad
Cities Station decommissioning costs are included in base rates in Iowa tariffs.
MidAmerican Energy s share of expected decommissioning costs for Quad Cities Station, in 2004 dollars, is $154.0 million
and is the ARO liability for Quad Cities Station. MidAmerican Energy has established trusts for the investment of funds for
decommissioning the Quad Cities Station. The fair value of the assets held in the trusts is reflected in other investments in the
accompanying consolidated balance sheets.
PacifiCorp
Exhibit No. II , page 90 of 130
CASE NO. PAC-05-
Witness: Patrick.t. Goodman
Nuclear Insurance
MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities
Station through a combination of insurance purchased by Exelon Generation Company, LLC ("Exelon Generation ), (the
operator and joint owner of Quad Cities Station), insurance purchased directly by MidAmerican Energy, and the mandatory
industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988. The general types of
coverage are: nuclear liability, property coverage and nuclear worker liability.
Exelon Generation purchases nuclear liability insurance for Quad Cities Station in the maximum available amount of
$300.0 million, which includes coverage for MidAmerican Energy s ownership. In accordance with the Price-Anderson
Amendments Act of 1988, excess liability protection above that amount is provided by a mandatory industry-wide Secondary
Financial Protection program under which the licensees of nuclear generating facilities could be assessed. for liability incurred
due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy
aggregate maximum potential share of an assessment for Quad Cities Station is approximately $50.3 million per incident
payable in installments not to exceed $5.0 million annually.
The property insurance covers property damage, stabilization and decontamination of the facility, disposal of the
decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exe10n
Generation purchased primary and excess property insurance protection for the combined interests in Quad Cities Station
with coverage limits totaling $2.1 billion. MidAmerican Energy also directly purchased extra expense or business
interruption coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage
at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon
Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company
and contain provisions for retrospective premium assessments should tWo or more full policy-limit losses occur in one policy
year. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry
mutual policies for its obligations associated with Quad Cities Station total $8.8 million.
The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an
industry-wide guaranteed-cost policy with an aggregate limit of $300 million for the nuclear industry as a whole, which is in
effect to cover tort claims in nuclear-related industries.
The current Price-Anderson Act expired in August 2002 and is pending congressional action for reauthorization. Its
contingent financial obligations still apply to reactors licensed by the NRC as of its expiration date. It is anticipated that the
Price-Anderson Act will be renewed with increased third party financial protection requirements for nuclear incidents.
Lega/ Matters
In addition to the proceedings described below, the Company is currently party to various items of litigation or arbitration in
the nonnal course of business, none of which are reasonably expected by the Company to have a material adverse effect on
its financial position, results of operations or cash flows.
Ca/Energy Generation-Foreign
Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro
fonna financial projections of the Casecnan project prepared following commencement of commercial operations, in
February 2002, MEHC's indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the minority stockholder, LaPrairie
Group Contractors (International) Ltd. ("LPG"), that MEHC's ownership interest in CE Casecnan ,had increased to 100%
effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of
the State of California, City and County of San Francisco against among others, CE Casecnan Ltd. and MEHC. On
January 21 2004, CE Casecnan Ltd. and LPG entered into a status quo agreement pursuant to which the parties agreed to set
aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further
actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan
dividend distributions declared in 2004, totaling to $15.9 million, was set aside by CE Casecnan in an unsecured CE
Casecnan account and is shown as restricted cash and short-tenD investments and other current liabilities in the
, accompanying consolidated balance sheet. The court is currently expected to rule on the first phase of the litigation before
the end of the first quarter of 2005. The impact, if any, of this litigation on the Company cannot be detennined at this time.
PacifiCorp
Exhibit No. 11, page 91 of 130
CASE NO. PAC-05-
Witness: Patrick J, Goodman
22. Pension and Postretirement Commitments
Domestic Operations
MidAmerican Energy sponsors a noncontriblltory defined benefit pension plan covering substantially all employees of
MEHC and its domestic energy subsidiaries. Benefit obligations under the plan are based on participants' compensation
years of service and age at retirement. Funding to the established trust is based upon the actuarially determined costs of the
plan and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act. The Company
also maintains noncontributo!y, nonqualified defined benefit supplemental executive retirement plans for active and retired
participants.
MidArnerican Energy also sponsors certain postretirement health care and life insurance benefits covering substantially all
retired employees of MEHC and its domestic energy subsidiaries. Under the plans, covered employees may become eligible
for these benefits if they reach retirement age while working for the Company. On July I, 2004, the postretirement benefit
plan was amended for non-union participants. Non-union employees hired July I , 2004, and after will no longer be eligible
for postretirement benefits other than pensions. The amendment establishes retiree medical accounts for participants to which
the Company will make fixed contributions. Participants will use such accounts to pay a portion of their medical premiums
during retirement. The Company retains the right to change these benefits anytime, subject to provisions in its collective
bargaining agreements.
Net periodic pension benefit cost, including supplemental retirement, and postretirement benefit cost included the following
components for MEHC and its domestic energy subsidiaries for the years ended December 31. For purposes of calculating
the expected return on pension plan assets, a market,.related value is used. Market-related value is equal to fair value except
for gains and losses on equity investments which are amortized into market-related value on a straight-line basis over five
years.
Pension Cost Postretirement Cost
2004 2003 2002 2004 2003 2002
(in thousands)
Service cost $ 25,568 $ 24 693 $20,235 $ 7,842 $ 8 175 $ 6,028
Interest cost 159 533 177 15,716 065 13,928
Expected return on plan assets (38 258)(38 396)(38 213)(8,437)008)880)
Amortization of net transition
obligation (792)(2,591)591)283 , II 0 110
Amortization of prior service cost 758 761 729 296 593 425
Amortization of prior year (gain) loss 569 483 482)299 716 385
Regulatory expense 320 639
Net periodic benefit cost $26.65 t
Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate
Rate of compensation increase
2004
75%
00%
2003
75%
00%
2002
75%
00%
2004
, 5.75%
2003
75%
Not applicable
2002
75%
Weighted-average assumptions used to determine net benefit cost for the years ended December 31:
Discount rate
Expected return on plan assets
Rate of compensation increase
2004
75%
00%
00%
2003
75%
00%
00%
2002
50%
00%
00%
2004
75%
00%
2003
75%
00%
Not applicable
2002
50%
00%
Assumed health care cost trend rates at December 31
Health care cost trend rate assumed for next year
Rate that the cost trend rate gradually declines to
Year that the rate reaches the rate it is assumed to remain at
2004
10.00%
00%
2010
- -... __a t'Exhibit No. II, page 92 of 130
CASE NO. PAC-O5-
Witne"c:. PMrirk , ((ontim:m
2003
11.00%
00%
2010
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-
percentage-point change in assumed health care cost trend rates would have the following effects in thousands:
Increase (Decrease) in Expense
One Percentage- One ~rcentage
':'
Point Increase Point Decrease
$ 4 855 $ (3,740)
$ 29,420 $ (24 066)
Effect on total service and interest cost
Effect on postretirement benefit obligation
The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan
assets and the funded status of the aforementioned plans to the net amounts measured and recognized in the accompanying
consolidated balance sheets as of December 31 (in thousands): '
Pension Benefits Postretirement Benefits
2004 2003 2004 2003
551 568 467 773 157 849 122 655
083 044 782 566
733 371
151 105 438 698 15,853
(26.6rn
591.628 551.568 179.375 L..illM2
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year
Employer contributions
Participant contributions
Actual r~tum on plan assets
Benefits paid
Fair value of plan assets at end of year
Reconciliation of benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Participant contributions
Plan amendments
Actuarial (gain) loss
Benefits paid
Benefit obligation at end of year
$ 620 048
568
35,159
805
$ 657.4.Q2
Funded statUs
Amounts not recognized in consolidated balance
sheets:
Unrecognized net (gain) loss
Unrecognized prior service cost
Unrecognized net transition obligation (asset)
Net amount recognized in the consolidated balance
sheets
(65,778)
(34 319)
157
Net amount recognized in the consolidated balance
sheets consists of:
Prepaid benefit cost
Accrued benefit liability
Intangible assets
Regulatory assets
Net amount recognized
(117,357)
653
17.764
$ 593,179
693
533
(5,670)
(26.6rn
$ 620.
(68,480)
297 433 291 441
841 175
716 065
733 371
(19 219)
(33,773)(5,023)
256 297 All
(76,669)$(139,584)
(12 907)768 509
915 5,451
792 641 992
(100 490)
17,367
18.820
(14,260)(13,632)
PacifiCorp
Exhibit No. 11, page 93 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
The portion of the pension projected benefit obligation, included in the table above, related to the supplemental executive
retirement plan was $106.5 million and $105.1 million as of December 31, 2004 and 2003, respectively. The supplemental
executive retirement plan has no assets, and accordingly, the fair value of its plan assets was zero as of December 31, 2004
and 2003. The accumulated benefit obligation for all defined benefit pension plans was $585.4 million and $554.6 million at
December 31, 2004 and 2003, respectively. Of these amounts, the supplemental executive retirement plan accumulated
benefit obligation totaled $102.3 million and $100.5 million for 2004 and 2003, respectively.
Although the supplemental executive retirement plan had no assets as of December 31 , 2004, the Company has Rabbi trusts
that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements. Because
this plan is nonqualified, the cash surrender value of these assets is not included in the plan assets. The cash surrender value
of the Rabbi trust investments was $98.8 million and $88.1 million at December 31, 2004 and 2003, respectively.
Plan Assets
The Company s investment policy for its domestic pension and postretirement plans is to balance risk and return through a
diversified portfolio of high-quality equity and fixed income securities. Equity targets for the pension and postretirement
plans are as indicated in the tables below. Maturities for fixed income securities are managed such that sufficient liquidity
exists to meet near-tenD benefit payment obligations. The plans retain outside investment advisors to manage plan
investments within the parameters outlined by the Company s Pension and Employee Benefits Plans Administrative
Committee. The weighted average return on assets assumption is based on historical perfonnance for the types of assets in
which the plans invest.
The Company s pension plan asset allocations at December 31 2004 and 2003, are as follows:
Percentage of
Plan Assets
at December 312004 2003
Asset Cate20rv
Equity securities
Debt securities
Real estate
Other
Total
71%
22%
--1%
100%
70%
23%
100%
Target
Range
65-75%
20-30%
10%
The Company s postretirement benefit plan asset allocations at December 31 2004, and 2003, are as follows:
Percentage of
Plan Assets
at December 312004 2003
Asset Cate20rv
Equity securities
Debt securities
Other
Total
49%
47%
100
49%
48%
-1%
100%
Target
Range
45-55%
45-55%
10%
PacifiCorp
Exhibit No. II, page 94 of 130
CASE NO. PAC~E-05-
Witness: Patrick J. Goodman
Cash Flows
MidAmerican Energy s expected benefit payments for its pension and postretirement plans for 2005 through 2009 and for the
five years thereafter are summarized below (in thousands):
Pension Benefits Postretirement Benefits
2005 30,670 $ 12 241
2006 728 11,731
2007 972 618
2008 38,092 13,432
2009 339 321
2010-$ 267,549 $ 87,264
Employer contributions to the domestic pension and postretirement plans are currently expected to be $6.6 million and
$15.8 million, respectively, for 2005. The Company s policy is to contribute the minimum required amount to the pension
plan and the amount expensed to its postretirement plans.
The Company sponsors defined contribution pension plans (401(k) plans) covering substantially all domestic employees. The
Company s contributions vary depending on the plan but are based primarily on each participant's level of contribution and
cannot exceed the maximum allowable for tax purposes. Total contributions were $17.1 million, $15.5 million and
$12.0 million for 2004, 2003 and 2002, respectively.
In December 2003, the President signed into law the Medicare Prescription Drug, Improvement and Modernization Act of
2003 ("Medicare Act"). The Medicare Act introduces a prescription drug benefit under Medicare as well as a subsidy to
sponsors of retiree health care plans that provide a benefit to participants that is at least actuarially equivalent to Medicare
Part D. The Medicare Act is expected to ultimately reduce the Company s postretirement costs from what they would have
been absent such changes. Detailed regulations pertaining to the Medicare Act were promulgated in July 2004, resulting in a
$23.8 million reduction in the accumulated postretirement obligation, which has been reflected as an actuarial gain in the
table above. The impact of the Medicare Act on the net periodic postretirement benefit expense will initially be recognized in
2005 in conjunction with the next valuation of the postretirement plans.
United Kingdom Operations
Certain wholly-owned subsidiaries of CE Electric UK participate in the Electricity Supply Pension Scheme (the "UK Plan
which provides pension and other related defined benefits, based on final pensionable pay, to substantially all employees
throughout the electricity supply industry in the United Kingdom.
Net periodic pension benefit cost included the following components for CE Electric UK for the years ended December 31.
For purposes of calculating the expected return on pension plan assets, a market-related value is used. Market-related value is
equal to fair value except for gains and losses on equity investments which are amortized into market-related value on a
straight-line basis over five years.
Pension Cost
2004 2003 2002
100 485 718
73,515 632 56,817
(98,448)(89 124)(85,927)
915 1 ,472 202
742 537
6.463
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of loss
Curtailment loss
Net periodic expense (benefit)
Weighted-average assumptions used to detennine benefit obligations at December 31:
Discount rate
Rate of compensation increase
2004
25%
75%
2003
50%
75%
Weighted-average assumptions used to determine net benefit cost for years ended December 31
Discount rate
Expected return on plan assets
Rate of compensation increase
2004
50%
00%
75%
2003
75%
00%
50%
t'aCJlJLolp
Exhibit No. II , page 95 of 130
CASE NO. PAC-05-
Witness: Patrick j, Goodman
2002
75%
50%
2002
75%
00%
50%
The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan
assets and the funded status of the UK Plan to the net amounts measured and recognized in the accompanying consolidated
balance sheets as of December 31 (in thousands):
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year
Employer contributions
Participant contributions
Actual return on plan assets
Benefits paid
Foreign currency exchange rate changes
Fair value of plan assets at end of year
Reconciliation of benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Participant contributions
Benefits paid
Experience loss and change of assumptions
Foreign currency exchange rate changes
Benefit obligation at end of year
Funded status
Unrecognized net loss
Net amount recognized in the consolidated balance sheets
Amounts recognized in the consolidated balance sheets consist of:
, Prepaid benefit cost
Accrued benefit liability
Intangible assets
Accumulated other comprehensive income
Net amount recognized
Pension Benefits2004 2003
206 216
17,600
417
106,515
(65,265)
93.239
.u .364.722
$ 1 334 587
100
515
417
(65,265)
104 315
105.910
1.5n 579
$ (206 857)
614.182
$ 407,325
(561 988)
16,119
545.869
$ 976,427
391
742
152 246
(57,726)
116.136
$ 1.206.2lQ
$1,102,730
485
62,632
742
(57,726)
890
128.834
$ (128 371)
507.039
$ 378,668
(496,147)
16,604
479.543
The accumulated benefit obligation for the defined benefit pension plan was $1.5 billion and $1.3 billion at December 31,
2004 and 2003, respectively.
The Company recorded a minimum pension liability as of December 31,2004 and 2003 in the amount of $545.9 million and
$479.5 million, respectively. The pension liability is primarily due to the decline in market value of the pension plan assets
during 2002 combined with the effects of lower discount rates and higher rates of compensation increases used to value the
plan liabilities in 2004 and 2003 , as well as, mortality assumption changes which increased the liability. As of
t'acttlcorp
Exhibit No. II, page 96 of 130
CASE NO. P AC-O5-
Witnf"."": PMnc.k J, Clooilman
December 31 2004 and 2003, the minimum pension liability is measured as the amount of the plan s accumulated benefit
obligation that is in excess of the plan s market value of assets at December 31, 2004 and 2003 plus the prepaid asset balance.
A charge equal to the excess was recorded to the Company s stockholders' equity, net of income tax benefits , as a component
of comprehensive loss in the amount of $46.4 million and $27.1 million in 2004 and 2003, respectively. This adjustment does
not impact current year earnings, or the funding requirements of the plan.
Plan Assets
CE Electric UK's investment policy for its pension and postretirement plans is to balance risk and return through a
diversified portfolio of high-quality equity and fixed income securities. Maturities for fixed income securities are managed
such that sufficient liquidity exists to meet near-tenD benefit payment obligations. The plans retain outside investment
advisors to manage plan investments within the parameters outlined by the Benefits Committee of subsidiaries ofCE Electric
UK. The weighted average return on assets assumption is based on historical perfonnance for the types of assets in which theplans invest.
CE Electric UK's pension plan asset allocation consists of the following at December 31:
Percentage of
Plan Assets
at December 312004 2003 Target
Asset Catel!Orv
Equity securities
Debt securities
Real estate
Other
Total
49%
39%
11%
--1%
100%
64%
26%
-1%
100%
50%
40%
10%
100%
Cash Flows
CE Electric UK's expected benefit payments relative to the UK Plan for 2005 through 2009 and for the five years thereafter
are summarized below (in millions):
2005
2006
2007
2008
2009
2010-
$ 67.
67.
67.
68.1
70.
$ 369.
Employer contributions to fund the ongoing liabilities of the UK Plan were approximately $14.7 million in 2004. The
triennial process of valuing the UK Plan s assets and liabilities, which will value the plan assets and liabilities as of
March 31 , 2004, is underway. This valuation will set a revised level of contributions for the next three years. The preliminary
report of the actuaries conducting the valuation showed a funding deficiency of $365.2 million. Based on the preliminary
valuation, CE Electric UK has proposed that its subsidiaries contribute $63.6 million to the UK Plan each year, which amount
includes $42.7 million each year in respect of the existing funding deficiency. The amount in respect of the funding
deficiency has been calculated based on eliminating the funding deficiency over 12 years commencing April 1 , 2005.
Discussions on the appropriate level of contributions continue with the UK Plan trustees in accordance with the UK Plan
rules.
23. Segment Information
PacifiCorp
Exhibit No. 11, page 97 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
The Company has identified seven reportable segments: MidAmerican Energy, Kern River, Northern Natural Gas, CE
Electric UK, CaIEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices. The Company
detennination of reportable segments considers the strategic units under which the Company is managed. The Company
foreign reportable segments include CE Electric UK and CalEnergy Generation-Foreign. The reportable segment financial
infonnation includes all necessary adjustments and eliminations needed to confonn to the Company s significant accounting
policies -including the allocation of goodwill and fair value adjustments relating to acquisitions. Additionally, the activity of
the Company s Mineral Assets, which was previously reported in the CalEnergy Generation-Domestic reportable segment, is
presented as discontinued operations within the accompanying consolidated financial statements. Infonnatiol) related to the
Company s reportable segments is shown below (in thousands).
Operating revenue:
MidArnerican Energy
Kern River
Northern Natural Gas
CE Electric UK
CalEnergy Generation-Foreign
CalEnergy Generation-DomesticHomeServices
Total reportable segments
Corporate/other(l)
Total operating revenue
Depreciation and amortization:
MidArnerican Energy
Kern River
Northern Natural Gas
CE Electric UK
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other(l)
Total depreciation and amortization
Interest expense:
MidArnerican Energy
Kern River
Northern Natural Gas
CE Electric UK
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other(l)
Parent company subordinated debt(2) ,
Total interest expense
Year Ended December 31,
2004 2003 2002
$ 2 701 700 $ 2 600,239 $ 2,240 879
316,131 260,182 127 254
544,822 486 878 178,118
936,364 829,993 795 366
307,395 326,454 326,316
38,960 45,154 38,478
1.756.454 1.476.569 1.138.332
601 826 025 469 844 743
ill)
965.63.Q.
266 409 281 001 269,412
53,250 36,771 17,165
913 716 1 5 1
137,746 125,000 116,792
328 87,928 88,036
721 882 648
20.827 17.560 22.072
645 194 609 858 540 276
(6.(6.924)63~
125 189 123,395 122,561
671 79,272 034
53,100 56,008 ' 23,550
202 067 180,207 189,554
696 59,603 68,338
18,971 19,736 20,043
837 864 256
521 531 522 085 475,336
184 811 189,083 156,797
196.875 49.78876~
Income from continuing operations before income
tax expense, minority interest and preferred
dividends of subsidiaries and equity income:
MidAmerican Energy
Kern River
Northern Natural Gas
CE Electric UK.
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other(1) (2)
Total income from continuing operations before income
tax expense, minority interest and preferred dividends
of subsidiaries and equity income
Income tax expense:
MidAmerican Energy
Kern River
Northern Natural Gas
CE Electric UK.
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
, Total reportable segments
Corporate/ other( 1)
Total income tax expense
Capital expenditures:
MidAmerican Energy
Kern River
Northern Natural Gas
CE Electric UK.
CalEnergy Generation-Foreign
CalEnergy Generation-Domestic
HomeServices
Total reportable segments
Corporate/other(l)
Total capital expenditures
pacltlcorp
Exhibit No. 11, page 98 of 130
CASE NO. PAC-O5-
Witness: Patrick.T. Goodman
2004
Year Ended December 31,
2003 2002
267,838 271 437 238,761
142 643 133,720 60,700
217 981 127 307 882
325 844 288,720 266 755
165,703 177,568 147,936
071 120 (1,155)
111.906 89.981 61.202
234 986 090 853 817,081
799.
336 110 078 99,782
148 319 23,014
423 50,599 16,947
80,211 539 25,245
548 130 924
217 1 ,078 611)
52.996 43.587 28.207
422 879 410,330 220 508
264~27~
633,807 346,449 332 845
26,936 433,125 692 586
138,747 104,400 409
334 458 301 896 222 622
633 497 830
341 619 640)
20.786 18.311 '18.273
160,708 219,297 334 925
18.682 373
- .._, - -, .. - - , -.. -.. ,PacifiCorp
Exhibit No. )), page 99 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
As of December 31,
2004 2003 2002
Total assets:
MidAmerican Energy $ 7,274 999 $ 6 596 849 $ 6,411 143
Kern River 135,265 200,201 797 850
, Northern Natural Gas 200 846 167 621 162 367
CE Electric UK 794 887 038 880 714,459
CalEnergy Generation-Foreign 767,465 951 155 974 852
CalEnergy Generation-Domestic 553 741 113,172 145 456
HomeServices 724 592 567.736 488.324
Total reportable segments 19,451 795 18,635,614 694 451
Corporate/ othet1)767 509.338 740.469
Total assets
Long-lived assets:
MidAmerican Energy $ 3 892 031 $ 3 385 056 $ 3,236 046
Kern River 945,094 976,213 650 387
Northern Natural Gas 491,428 430 475 403 748
CE Electric UK 691,459 227 723 741 277
CalEnergy Generation':'Foreign 520,406 621,674 724 908
CalEnergy Generation-Domestic 256,429 738 296 739,940
HomeServices 827 53.518 45.078
Total reportable segments 856,674 432 955 541 384
Corporate/othet1)(256.S97)
Total long-lived assets
(1)The remaining differences between the segment amounts and the consolidated amounts described as "Corporate/other" relate principal1y to the corporate
functions, including administrative costs, interest expense, corporate cash and related interest income, intersegment eliminations and fair value adjustments
relating to acquisitions.
(2)The Company adopted and applied the provisions of FIN 46R related to certain finance subsidiaries as of October I, 2003. The adoption required amounts
previously recorded in minority interest and preferred dividends of subsidiaries to be recorded as interest expense in the accompanying consolidated
statements of operations. For the year ended December 31 , 2004, and the three-month period ended December 31, 2003, the Company has recorded
$196.9 million and $49.8 million, respectively, of interest expense related to these securities. In accordance with the requirements of FIN 46R, no amounts
prior to adoption of FIN 46R on October I, 2003 have been reclassified. The amounts included in minority interest and prefelTed dividends of subsidiaries
related to these securities for the nine-month period ended September30, 2003, and the year ended December31,2002, were S170.2 million and
$147.7 million, respectively.
PacifiCorp
Exhibit No. 11 , page 100 of 130
CASE NO. P AC-05-
Witne",,: Patrick J Gnonm:ln
The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended
December 31 2004 and 2003 (in thousands):
Northern Cal Energy
MidAmerican Kern Natural CE Electric Generation Home-
Enern River !i!!Domestic Services I!!!!!
Balance, January 1, 2003 149 282 547 414,721 195,321 126,440 339 821 $4,258,132
Goodwill from acquisitions during the year 26,648 26,648
Other goodwill adjustmentsCI)(10.059)353 05.573)66.262 032)(988)20.863
Balance, December 31, 2003 139,223 33,900 379 148 261,583 126,308 365,481 305,643
Goodwill from acquisitions during the year 32,120 120
Impainnent lossesC2)(52 776) (52,776)
Other goodwill adjustmentsCI)(18.098)(24.236)68.208 (1.038)(3.072)21.764
Balance, December 31, 2004 2 121 125 33 900 354912 1 329.791 72 494 394.529 $4.306751
(1)Other goodwill adjustments include income tax, foreign currency translation and purchase price adjustments.
(2)Impainnent losses relate to the write-off of the Mineral Assets - see Note 3.
100
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
PacifiCorp
Exhibit No. 11 , page 101 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
An evaluation was performed under the supervision and with the participation of the Company s management, including the
chief executive officer and chief financial officer, regarding the effectiveness of the design and operation of the Company
disclosure controls and proc(.(dures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of
1934, as amended) as of December 31, 2004. Based on that evaluation, the Company s management, including the chief
executive officer and chief financial officer, concluded that the Company s disclosure controls and procedures were effective.
There have been no significant changes during the fourth quarter of 2004 in the Company s internal controls or in other
factors that could significantly affect internal controls.
Item 9B.Other Information.
None.
101
PacifiCorp
Exhibit No. 11, page 102 of 130
CASE NO. PAC-O5-
Witness: Patrick", Goodman
PART III
Item 10.Directors and Executive Officers of the Registrant.
MEHC's management structure is organized functionally and the CUITent executive officers and directors ofMEHC and their
positions are as follows:
Name Position
David L. Sokol
Gregory E. Abel
Patrick J. Goodman
Douglas L. Anderson
Keith D. Hartje
Chairman of the Board, Chief Executive Officer and Director
President, Chief Operating Officer and Director
Senior Vice President and Chief Financial Officer
Senior Vice President, General Counsel and Corporate Secretary
Senior Vice President, Communications, General Services and Safety
Audit and Compliance
Director
Director
Director
Director
Director
Director
Director
Director
Warren E. Buffett
Walter Scott Jr.
Marc D. Hamburg
W. David Scott
Edgar D. Aronson
John K. Boyer
Stanley J. Bright
Richard R. Jaros
Officers are elected annually by the Board of Directors. There are no family relationships among the executive officers, nor
any aITangements or understanding between any officer and any other person pursuant to which the officer was appointed.
Set forth below is certain information, as of January 1,2005, with respect to each of the foregoing officers and directors:
DAVID L. SOKOL, 48, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been the Chief
Executive Officer since April 19, 1993 and served as President of MEHC from April 19, 1993 until January 21, 1995.
Mr. Sokol has been Chairman of the Board of Directors since May 1994 and a director since March 1991. Formerly, among
other positions held in the independent power industry, Mr. Sokol served as President and Chief Executive Officer of Kiewit
Energy Company, which at that time was a wholly owned subsidiary of Peter Kiewit & Sons , Inc., and Ogden Projects, Inc.
GREGORY E. ABEL, 42, President, Chief Operating Officer and Director. Mr. Abel joined MEHC in 1992 and initially
served as Vice President and Controller. Mr. Abel is a Chartered Accountant and from 1984 to 1992 was employed by Price
Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was responsible for clients in the energyindustry.
PATRICK 1. GOODMAN, 38, Senior Vice President and Chief Financial Officer. Mr. Goodman joined MEHC in 1995 and
served in various accounting positions including Senior Vice President and Chief Accounting Officer. Prior to joining
MEHC, Mr. Goodman was a financial manager for National Indemnity Company, and a senior associate at Coopers &Lybrand.
DOUGLAS L. ANDERSON, 46, Senior Vice President and General Counsel. Mr. Anderson joined MEH~ in February 1993
and has served in various legal positions including General Counsel of the Company s independent power affiliates. From
1990 to 1993, Mr. Anderson was a corporate attorney with Fraser, Stryker in Omaha, NE. Prior to that Mr. Anderson was a
principal in the firm Anderson and Anderson.
KEITH D. HARTJE, 54, Senior Vice President, Communications, General Services and Safety Audit and Compliance.
Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973. In that time, he has held a number
of positions, including General Counsel and Corporate Secretary, District Vice President for southwest Iowa operations, and
Vice President, Corporate Communications.
102
I a\"III'-UI11
Exhibit No. II, page 1 03 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
WARREN E. BUFFEIT, 74, Director. Mr. Buffett, has been a director of MEHC since March 2000. He is Chairman of the
Board and Chief Executive Office of Berkshire Hathaway. Mr. Buffett is a Director of the Coca-Cola Company, the Gillette
Company and The Washington Post Company.
WALTER SCOIT, JR., Director. Mr. Scott has been a director ofMEHC since June 1991. Mr. Scott was the Chairman
and Chief Executive Officer ofMEHC from January 8, 1992 until April 19, 1993. For more than the past five years, he has
been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit
& Sons , Inc. Mr. Scott is a director of Peter Kiewit & Sons , Inc., Berkshire Hathaway, Burlington Resources, Inc.
ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co.Commonwealth Telephone Enterprises, Inc. and RCN
Corporation. Mr. Scott is the father ofW. David Scott.
MARC D. HAMBURG, 55, Director. Mr. Hamburg has been a director of MEHC since March 2000. He has served as Vice
President - Chief Financial Officer of Berkshire Hathaway since October 1 , 1992 and Treasurer since June 1 , 1987, his date
of employment with Berkshire Hathaway.
W. DAVID SCOIT, 43, Director. Mr. Scott has been a director of MEHC since March 2000. Mr. Scott formed Magnum
Resources, Inc., a commercial real estate investment and management company, in October 1994 and has served as its
President and Chief Executive Officer since its inception. Before forming Magnum Resources, Mr. Scott worked for America
First Companies, Cornerstone Banking Group and Peter Kiewit & Sons , Inc. Mr. Scott has been a director of America First
Mortgage Investments, Inc., a mortgage REIT, since 1998. Mr. Scott is the son of Walter Scott Jr.
EDGAR D. ARONSON, 70, Director. Mr. Aronson has been a director of MEHC since 1983. Mr. Aronson founded
EDACO, Inc., a private venture capital company, in 1981 , and has been President of EDACO, Inc. since that time. Prior to
that, Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a General Partner in charge of the
International Department of Salomon Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice
President consecutively in the International Departments of First National Bank of Chicago and Republic National Bank of
New York. He founded the International Department of Salomon Brothers and Hutzler in 1968.
JOHN K. BOYER, 60, Director. Mr. Boyer has been a director of MEHC since March 2000. He is a partner with Fraser,
Stryker, Meusey, Olson, Boyer & Bloch, P.C. where he has practiced from 1973 to present with emphasis on corporate
commercial, federal, state, and local taxation.
STANLEY 1. BRIGHT, 64, Director. Mr. Bright was Chairman and Chief Executive Officer of MidAmerican Energy from
July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a predecessor of MidAmerican
Energy) as Vice President and Chief Financial Officer in 1986, became a director in 1987, President and Chief Operating
Officer in 1990, and Chairman and Chief Executive Officer in 1991.
RICHARD R. JAROS, , Director. Mr. Jaros has been a director of MEHC since March 1991. Mr. Jaros served as President
and Chief Operating Officer of MEHC from January 8, 1992 to April 19, 1993 and as Chairman of the Board from April 19,
1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President and Chief Financial Officer of Peter Kiewit &
Sons , Inc. and President of Kiewit Diversified Group, Inc., which is now Level 3 Communications, Inc. Mr. Jaros serves as
director of Commonwealth Telephone Enterprises, Inc., RCN Corporation and Level 3 Communications, Inc. '
Audit Committee Members and Financial Experts
The audit committee of the Board of Directors is comprised of Messrs. MarcD. Hamburg and Richard R. Jaros. The Board
Directors has determined that Messrs. Hamburg and Jaros qualify as "audit committee financial experts " as defined by
Securities and Exchange Commission Rules, based on their education, experience and background. Mr. Jaros is independent
as that term is used in Item 7(d) (3) (IV) of Schedule 14A under the Exchange Act.
Code of Ethics
MEHC has adopted a code of ethics that applies to its principal executive officer . its principal financial officer, its chief
accounting officer and certain other covered officers. The code of ethics is filed as an exhibit to this annual report on Form
10-K.
103
Item 11.Executive Compensation.
.- C1\.lll~VI jJ
Exhibit No. 11, page 104 of 130
CASE NO, P AC-O5-
Wi tnl".c;;c;; , PMriC'.k.l C'.nnrhn:m
The following table sets forth the compensation of MEHC's Chief Executive Officer and its four other most highly
compensated executive officers who were employed as of December 31, 2004, which MEHC refers to as its Named
Executive Officers. Information is provided regarding its Named Executive Officers for the last three fiscal years during
which they were its executive officers, if applicable.
Year Other
Ended Annual LTIP Other
Name and'PrinciDal Positions Dec. 31 Salary (1)Bonus (1)ComD(2)Payouts ComD(3)
David L. Sokol 2004 $800,000 $ 2,500 000 131 ,644 995
Chairman and Chief 2003 800 000 750 000 141 ,501 1'-9;800
Executive Officer 2002 800 000 750 000 27,232 047 850
Gregory E. Abel 2004 720 000 200 000
President and 2003 700 000 200;000
Chief Operating Officer 2002 540 000 200,000
Patrick J. Goodman 2004 290 000 '295 000
Senior Vice President and 2003 275 000 285 000
Chief Financial Officer 2002 248,000 260,000
Douglas L. Anderson 2004 270 000 240 000
Senior Vice President and 2003 260,000 240 000
General Counsel 2002 200 000 220,000
Keith D. Hartje 2004 180 000 65,000
Senior Vice President,2003 180,000 65,000
Communications, General 2002 180 000 65,000
Services and Safety Audit and
Compliance
(1)
(2)
Includes amounts voluntarily deferredby the executive, if applicable.
80,424
87,162
995
800
857
257 664 88,391
108,631
(16,342)209 970
151 585 77,145
83,703
(7,289)
128,847 774
71,317
(3,015)
Consists of perquisites and other benefits if the aggregate amount of such benefits exceeds the lesser of either
$50 000 or 10% of the total of salary and bonus reported for the Named Executive Officer. The amounts shown
include the personal use of aircraft for 2004 for Mr. Sokol of$100 726 and for Mr. Abel of $73,859.
(3)Consists of the 2004 earnings on the MEHC Long-Term Incentive Partnership Plan (UL TIP") awards not paid out in
2004 and 401(k) plan contributions. For 2004, LTIP earnings on awards not paid out in 2004 were $78 396 for
Mr. Goodman, $67 150 for Mr. Anderson and $44 979 for Mr. Hartje. Messrs. Sokol and Abel are not participants in
the LTIP. Additionally, the amounts shown include company 401(k) contributions for 2004 for Messrs. Sokol, Abel
Goodman and Anderson of $9 995 and for Mr. Hartje of $9,795.
Pursuant to MEHC's Executive Incremental Profit Sharing Plan, Messrs. Sokol and Abel are each eligible to receive a one-
time profit sharing award of $11.25 million, $18.75 million or $37.5 million based upon achieving specified adjusted diluted
earnings per share targets for any calendar year from 2004 through 2007 and continued employment during such time.
Option Grants in Last Fiscal Year
MEHC did not grant any options during 2004.
104
PacifiCorp
Exhibit No. 11, page 105 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Aggregated Option Exercises In Last Fiscal Year And Fiscal Year End Option Values
The following table sets forth the option exercises and the number of securities underlying exercisable and unexercisable
options held by each of its Named Executive Officers at December 31 , 2004.
Name
Shares
Acquired
Exercise Value
Realized
Underlying Unexercised
Options Held (
Exercisable Unexercisable
Value of Unexercised
In-the-money Options
($)~
Exercisable Unexercisable
David Sokol
Gregory E. Abel
Patrick J. Goodman
Douglas L. Anderson
Keith D. Hartje
399,277
649,052
$113,073,927
$ 55 748,672
N/A
N/A
(1)On March 14, 2000, MEHC was acquired by a private investor group. As a privately held company, MEHC has no
publicly traded equity securities. The value shown is based on an assumed fair market value of the stock of $113 per
share as of December 31, 2004, as agreed to by MEHC stockholders.
, Long-Term Incentive Plans - Awards in Last Fiscal Year
Number of Performance or
Shares,Other Period Until
Units or Other Maturation Threshold Target Maximum
Name hts Or Pa out
Patrick J. Goodman N/A December 31, 2008 000 N/A N/A,
Douglas L. Anderson N/A December 31, 2008 40,000 N/A N/A
Keith D. Hartje N/A December 31, 2008 000 N/A N/A
(1)The awards shown in the foregoing table are made pursuant to the LTIP. The amounts shown are dollar amounts
credited to an investment account for the benefit of the named executive officers and such amounts vest equally over
five years (starting with year 2004) with any unvested balances forfeited upon tennination of employment. Vested
balances (including any investment perfonnance profits or losses thereon) are paid to the participant at the time of
tennination. Once an award is fully vested, the participant may elect to defer or receive payment of part or the entire
award. Awards are credited or reduced with annual interest or loss based on a composite of funds or indices.
Because the amounts to be paid out may increase or decrease depending on investment perfonnance, the ultimate
benefits are undetenninable and the payouts do not have a "target" or "maximum" amount.
Compensation of Directors
All directors, excluding Messrs. Sokol, Abel, Buffett and Walter Scott Jr., are paid an annual retainer fee of $24 000 and a fee
of $500 per day for attendance at Board and Committee meetings. Directors who are employees are not entitled to receive
such fees. All directors are reimbursed for their expenses incurred in attending Board meetings.
105
PacitlCorp
Exhibit No. 11, page 106 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Retirement Plans
The MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers (the "SERP"), provides
additional retirement benefits to designated participants, as detennined by the Board of Directors. Messrs. Sokol, Abel
Goodman and Hartje are participants in the SERP. The SERP provides annual retirement benefits up to sixty-five percent of a
participant's Total Cash Compensation in effect immediately prior to retirement, subject to a $1 million maximum retirement
benefit. "Total Cash Compensation" means the highest amount payable to a participant as monthly base salary during the five
years immediately prior to retirement multiplied by 12 plus the average of the participant's last three years awards under an
annual incentive bonus program and special, additional or non-recurring bonus awards, if any, that are required to be included
in Total Cash Compensation pursuant to a participant's employment agreement or approved for inclusion by the Board.
Participants must be credited with five years of service to be eligible to receive benefits under the SERP. Each of the
Company s Named Executive Officers has or will have five years of credited service with the Companyoas of their respective
nonnal retirement age and will be eligible to receive benefits under the SERP. A participant who elects early retirement is
entitled to reduced benefits under the SERP, however, in accordance with their respective employment agreements
Messrs. Sokol and Abel are eligible to receive the maximum retirement benefit at age 47. A survivor benefit is payable to
surviving spouse under the SERP. Benefits from the SERP will be paid out of general corporate funds; however, through a
Rabbi trust, the Company maintains life insurance on the participants in amounts expected to be sufficient to fund the after-
tax cost of the projected benefits. DefelTed compensation is considered part of the salary covered by the SERP.
The SERP benefit will be reduced by the amount of the participant's regular retirement benefit under the MidAmerican
Energy Company Cash Balance Retirement Plan (the "MidAmerican Retirement Plan ), which became effective January I,
1997, and by benefits under the Iowa Resources Inc. and Subsidiaries Supplemental Retirement Income Plan (the "lOR
Supplemental Plan ), as applicable.
Part A of lOR Supplemental Plan provides retirement benefits up to sixty-five percent of a participant's highest annual salary
during the five years prior to retirement reduced by the participant's MidAmerican Retirement Plan benefit. The percentage
applied is based on years of credited service. A participant who elects early retirement is entitled to reduced benefits under
the plan. A survivor benefit is payable to a surviving spouse. Benefits are adjusted annually for inflation. Part B of the lOR
Supplemental Plan provides that an additional one hundred-fifty percent of annual salary is to be paid out to participants at
the rate of ten percent per year over fifteen years, except in the event of a participant's death, in which event the unpaid
balance would be paid to the participant's beneficiary or estate. DefelTed compensation is considered part of the salary
covered by the lOR Supplemental Plan.
The MidAmerican Retirement Plan replaced retirement plans of predecessor companies that were structured as traditional
defined benefit plans. Under the MidAmerican Retirement Plan, each participant has an account, for record keeping purposes
only, to which credits are allocated each payroll period based upon a percentage of the participant's salary paid in the CUlTent
pay period. In addition, all balances in the accounts of participants earn a fixed rate of interest that is credited annually. The
interest rate for a particular year is based on the constant maturity Treasury yield plus seven-tenths of one percentage point.
At retirement, or other tennination of employment, an amount equal to the vested balance then credited to the account is
payable to the participant in the fonn of a lump sum or a fonn of annuity for the entire benefit under the MidAmerican
Retirement Plan.
106
PacifiCorp
Exhibit No. 11, page 107 of 130
CASE NO: PAC-05-
Witness: Patrick J. Goodman
The table below shows the estimated aggregate annual benefits payable under the SERP and the MidAmerican Retirement
Plan. The amounts exclude Social Security and are based on a straight life annuity and retirement at ages 55, 60 and 65.
Federal law limits the amount of benefits payable to an individual through the tax qualified defined benefit and contribution
plans, and benefits exceeding such limitation are payable under the SERP.
Total Cash
Compensation
at Retirement ($)
Estimated Annual Benefit
Age of Retirement
220 000 240,000 260 000
275,000 300 000 325,000
330 000 360 000 390,000
385 000 420 000 455,000
440 000 480,000 520 000
495,000 540 000 585 000
550 000 600 000 650 000
687 500 750 000 812 500
825,000 900 000 975 000
962 500 000 000 000 000
$ 1,000 000 $ 1 000,000 $ 1 000 000
$ 400 000
500 000
600 000
700 000
800 000 '
900 000
000 000
250 000
500 000
750 000
$ 2 000 000 and greater
Employment Agreements
Pursuant to his employment agreement, Mr. Sokol serves as Chairman of MEHC's Board of Directors and Chief Executive
Officer. The employment agreement provides that Mr. Sokol is to receive an annual base salary of not less than $750 000,
senior executive employee benefits and annual bonus awards that shall not be less than $675,000. Subject to an annual
renewal provision, such agreement is scheduled to expire on August 21 , 2005.
The employment agreement provides that MEHC may terminate the employment of Mr. Sokol with cause, in which case
MEHC is to pay to him any accrued but unpaid salary and a bonus of not less than the minimum annual bonus, or due to
death, permanent disability or other than for cause, including a change in control, in which case Mr. Sokol is entitled to
receive an amount equal to three times the sum of his annual salary then in effect and the greater of his minimum annual
bonus or his average annual bonus for the two preceding years, as well as three years of accelerated option vesting plus
continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol
resigns, MEHC is to pay to him any accrued but unpaid salary and a bonus of not less than the annual minimum bonus
unless he resigns for good reason in which case he will receive the same benefits as if he were terminated other than for
cause.
In the event Mr. Sokol has relinquished his position as Chief Executive Officer and is subsequently terminated as Chairman
of the Board due to death, disability or other than for cause, he is entitled to (i) any accrued but unpaid salary plus an amount
equal to the aggregate annual salary that would have been paid to him through the fifth anniversary of the date he commenced
his employment solely as Chairman of the Board, (ii) the immediate vesting of all of his options, and (iii) the continuation of
his senior executive employee benefits (or the economic equivalent thereot) through such fifth anniversary. If Mr. Sokol
relinquishes his position as Chief Executive Officer but offers to remain employed as the Chairman of the Board, he is to
receive a special achievement bonus equal to two times the sum of his annual salary then in effect and the greater of his
minimum annual bonus or his average annual bonus for the two preceding years, as well as two years of accelerated optionvesting.
Under the terms of separate employment agreements with MEHC, each of Messrs. Abel and Goodman is entitled to receive
two years base salary continuation, payments in respect of average bonuses for the prior two years and two years continued
option vesting in the event MEHC terminates his employment other than for cause. If such persons were terminated without
cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be paid approximately $10 650 000, $5,750 000 and
200 000, respectively, without giving effect to any tax related provisions.
107
'-" -, ---...-.---.PacifiCorp
Exhibit No. 11, page 108 of 130
CASE NO. PAC-05-
Witne!';s: Patrick 1 Gonrlman
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters~
The following table sets forth certain infonnation regarding beneficial ownership of the shares of MEHC's common stock
and certain infonnation with respect to the beneficial ownership of each director, its Named Executive Officers and all
directors and executive officers as a group as of January 31 2005.
Name and Address of Beneficial Owner (1)
Common Stock:
Walter Scott, Jr. (3)
David L. Sokol (4)
Berkshire Hathaway (5)
Gregory E. Abel (6)
W. David Scott (7)
Douglas L. Anderson
Edgar D. Aronson
Stanley J. Bright
John K. Boyer
Warren E. Buffett (8)
Patrick J. Goodman
Marc D. ,Hamburg (8)
Richard R. Jaros
Keith D. Hartje
All directors and executive officers as a group (14 persons)
Number of Shares
Beneficially Owned (2)
Percentage
Of Class (2)
000 000
523,482 '
900 942
704 992
624 350
55.06%
14.54%
92%
25%
88%
753,766 77.40%
(1)
(2)
Unless otherwise indicated, each address is c/o MEHC at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309.
Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under
Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficialowner has the right to acquire within 60 days.
(3)Excludes 3 million shares held by family members and family controlled trusts and corporations ("Scott Family
Interests ) as to which Mr. Scott disclaims beneficial ownership. Such beneficial owner s address is 1000 Kiewit
Plaza, Omaha, Nebraska 68131.
(4)
(5)
Includes options to purchase 1 399,277 shares of common stock that are exercisable within 60 days.
Such beneficial owner s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.
(6)Includes options to purchase 649 052 shares of common stock which are exercisable within 60 days. Excludes
041 shares reserved for issuance pursuant to a deferred compensation plan.
(7)Includes shares held by trusts for the benefit of or controlled by W. David Scott. Such beneficial owner s address is
11422 Miracle Hills Drive, Suite 400, Omaha, Nebraska 68154.
(8)Excludes 900 942 shares of common stock held by Berkshire Hathaway of which beneficial ownership of such
shares is disclaimed.
The tenns of MEHC's Zero Coupon Convertible Preferred Stock held by Berkshire Hathaway entitle the holder thereof to
elect two members of its Board of Directors. The Zero Coupon Convertible Preferred Stock does not vote as to the election of
any other members ofMEHC's Board of Directors. Mr. Sokol's employment agreement gives him the right during the tenn
of his employment to serve as a member of the Board of Directors and to designate two additional directors.
108
PacifiCorp
Exhibit No. 11, page 109 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Pursuant to a shareholders agreement, following March 14, 2003, Walter Scott, Jr. or any of the Scott Family Interests are
able to require Berkshire Hathaway to purchase, for an agreed value or an appraised value, any or all of Walter Scott, Jr. '
and the Scott Family Interests' shares of MEHC's common stock, provided that Berkshire Hathaway is then a purchaser of a
type which is able to consummate such a purchase without causing it or any of its affiliates or MEHC or any of its
subsidiaries to become subject to regulation as a registered holding company or a subsidiary of a registered holding company
under PUHCA. Berkshire Hathaway is not currently such a purchaser. The consummation of such a transaction could result
in a change in control with respect to MEHC.
MEHC's Amended and Restated Articles of Incorporation provide that each share of the Zero Coupon Convertible Preferred
Stock is convertible at the option of the holder thereof into one conversion unit, which is one share of its ,common stock
subject to certain adjustments as described in its articles, upon the occurrence of a Conversion Event. A "Conversion Event"
includes (1) any conversion of Zero Coupon Convertible Preferred Stock that would not cause the holder of the shares of
common stock issued upon conversion (or any affiliate of such holder) or the Company to become subject to regulation as a
registered holding company or as a subsidiary of a registered holding company under PUHCA either as a result of the repeal
or amendment ofPUHCA, the number of shares involved or the identity of the holder of such shares and (2) a Company Sale.
A "Company Sale" includes MEHC's involuntary or voluntary liquidation, dissolution, recapitalization, winding-up or
termination and mergers, consolidations or sale of all or substantially all of its assets. The conversion by Berkshire Hathaway
of its shares of Zero Coupon Convertible Preferred Stock into MEHC's common stock could result in a change in control
with respect to beneficial ownership of its voting securities as calculated pursuant to Rule 13d-3(d) under the Securities
Exchange Act.
Item 13.Certain Relationships and Related Transactions.
Under a subscription agreement with MEHC, which expires in March 2007, Berkshire Hathaway has agreed to purchase
under certain circumstances, additional 11 % trust issued mandatorily redeemable preferred securities in the event that certain
outstanding trust preferred securities of MEHC which were outstanding prior to the closing of its acquisition by a private
investor group on March 14 2000 are tendered for conversion to cash by the current holders.
MEHC provided a guarantee in favor of a third party lender in connection with a $1 663 998.75 loan from such lender to its
President, Gregory E. Abel, in March 2000. The loan matures on April 1 , 2010. The proceeds of this loan were used by
Mr. Abel to purchase 47,475 shares ofMEHC's common stock. Such common stock (together with 8 465 additional shares of
common stock owned by Mr. Abel) also secures the loan. The entire original principal amount of the loan and the guarantee
remain presently outstanding.
In order to finance its acquisition of Northern Natural Gas, on August 16, 2002, MEHC sold to Berkshire Hathaway
$950.0 million in aggregate principal amount of the 11 % mandatorily redeemable trust issued preferred securities Series A
of its subsidiary trust, MidAmerican Capital Trust II, due August 31 , 2012. The transaction was a private placement pursuant
to Section 4(1) of the Securities Act and did not involve any underwriters, underwriting discounts or commissions. Scheduled
principal payments began in August 2003. Messrs. Warren E. Buffett and 'Walter Scott, Jr. are members of the Board of
Directors of Berkshire Hathaway. Messrs. Buffett and Marc D. Hamburg are executive officers of Berkshire Hathaway.
On January 6, 2004, MEHC purchased a portion of the shares of common stock owned by Mr. Sokol for an aggregate
purchase price of $20.0 , million.
Compensation Committee Interlocks and Insider Participation
The compensation committee of the Board of Directors is comprised of Messrs. Warren E. Buffett and Walter Scott, Jr.
Mr. Walter Scott, Jr. is a former officer of the Company. See "Certain Relationships and Related Transactions.
109
PacJt1Corp
Exhibit No. 11, page 110 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Item 14.Principal Accountant Fees and Services.
Aggregate fees billed to the Company as a consolidated entity during the fiscal years ending December 31, 2004 and 2003 by
the Company s principal accounting firm, Deloitte & Touche LLP and the member firms of Deloitte Touche Tohmatsu, and
their respective affiliates (collectively, "Deloitte & Touche ), are set forth below. The audit committee has considered
whether the provision of the non-audit services described below is compatible with maintaining the principal accountant'
independence.
Audit Fees (1)
Audit-Related Fees (2)
Tax Fees (3)
All Other Fees (4)
Total aggregate fees billed
Year Ended December 31,2004 2003
(in millions)
$ 3.
0.1
0.4
6 II
(1)Includes the aggregate fees billed for each of the last two fiscal years for professional services rendered by Deloitte
& Touche for the audit of the Company s annual financial statements and the review of financial statements
included in the Company s Form 10-Q or for services that are normally provided by Deloitte & Touche in
connection with statutory and regulatory filings or engagements for those fiscal years.
(2)Includes the aggregate fees billed in each of the last two fiscal years for assurance and related services by Deloitte &
Touche that are reasonably related to the perfonnance of the audit or review of the Company s financial statements.
Services included in this category include audits of benefit plans, due diligence for possible acquisitions and
consultation pertaining to new and proposed accounting and regulatory rules.
(3)Includes the aggregate fees billed in each of the last two fiscal years for professional services rendered by Deloitte &
Touche for tax compliance, tax advice, and tax planning.
(4)Includes the aggregate fees billed in each of the last two fiscal years for products and services provided by Deloitte
& Touche, other than the services reported as "Audit Fees,
" "
Audit-Related Fees " or "Tax Fees
The audit committee reviewed the non-audit services rendered by Deloitte & Touche in and for fiscal 2004 as set forth in the
above table and concluded that such services were compatible with maintaining the principal accountant's independence.
Under the Sarbanes-Oxley Act of 2002, all audit and non-audit services performed by the Company s principal accountant
are approved in advance by the audit committee to assure that such services do not impair the principal accountant'
independence from the Company. Accordingly, the audit committee has an Audit and Non-Audit Services Pre-Approval
Policy (the "Policy ) which sets forth the procedures and the conditions pursuant to which services to be perfonned by the
principal accountant are to be pre-approved. Pursuant to the Policy, certain services described in detail in the Policy may be
pre;.approved on an annual basis together with pre-approved maximum fee levels for such services. The services eligible for
annual pre-approval consist of services that would be included under the categories of Audit Fees, Audit-Related Fees and
Tax Fees. If not pre-approved on an annual basis, proposed services must otherwise be separately approved prior to being
performed by the principal accountant. In addition, any services that receive annual pre-approval but exceed the pre-approved
maximum fee level also will require separate approval by the audit committee prior to being perfonned. The audit committee
may delegate authority to pre-approve audit and non-audit services to any member of the audit committee, but may not
delegate such authority to management.
110
PacifiCorp
Exhibit No. 11. page III of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
PART IV
Item 15.Exhibits and Financial Statement Schedules.
(a)Financial Statements and Schedules
(i)Financial Statements
Financial Statements are included in Item 8 of this Form 10-
(ii)Financial Statement Schedules
See Schedule I on page 112.
See Schedule II on page 115.
Schedules not listed above have been omitted because they are either not applicable, not required or the
information required to be set forth therein is included in the consolidated financial statements or notes thereto.
(b)Exhibits
The exhibits listed on the accompanying Exhibit Index are filed as part of this Annual Report.
(c)Financial statements required by Regulation S-, which are excluded from the Annual Report by Rule 14a-3(b).
Not applicable.
111
MidAmerican Energy Holdings Company
Parent Company Only
Condensed Balance Sheets
As of December 31 , 2004 and 2003
(Amounts in thousands)
ASSETS
Current assets:
Cash and cash equivalents
Investments in and advances to subsidiaries and joint ventures
Equipment, net
Goodwill
Deferred charges and other assets
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and other liabilities
Current portion of senior debt
Current portion of subordinated debt
Total current liabilities
Other long-term accrued liabilities
Notes payable affiliate
Senior debt
Subordinated debt
Total liabilities
Deferred income
Minority interest
Stockholders' equity:
Zero coupon convertible preferred stock authorized 50 000 shares, no par value;
263 shares outstanding
Common stock authorized 60 000 shares, no par value; 9 081 and 9,281 shares
issued and outstanding at December 31 , 2004 and 2003, respectively
Additional paid in capital
Retained earnings
Accumulated other comprehensive loss, net
Total stockholders' equity
Total liabilities and stockholders' equity
2004
$ 349,689
141,843
881
299 560
168.805
J a~JI1'-urp
Exhibit No. 11 , page 112 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goooman
, Schedule I
2003
$ , 328,750
731 915
15,388
370,241
180.331
$ 7.626.625
535 934
260,000
188.543 100.000
504.078 152.934
142 298
000 86,045
771 957 777,878
1.585.810 1. 772.146
972 987 820 301
30,229 916
403 1 ,963
950,663
156 843
971.159
957 277
999,627
771.445
$ 7.626.625
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
112
MidAmerican Energy Holdings Company
Parent Company Only (continued)
Condensed Statements of Operations
For the three years ended December 31 , 2004
(Amounts in thousands)
2004 2003
Revenues:
Equity in undistributed earnings of subsidiary companies and joint
ventures
Dividends and distributions from subsidiary companies and joint
ventures
Interest and other income
Total revenues
PacifiCorp
Exhibit No. II, page 113 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Schedule I
2002
$ 103 176 $ 375,666 $ 250 517
330 678 318 665 351 847
11.713 19.377 778
445.567 713.708 603.142
Costs and expenses:
General and administration
Depreciation and amortization
Interest, net of capitalized interest
Total costs and expenses
Income before income taxes
Income tax benefit
Income before preferred dividends of subsidiaries
Preferred dividends of subsidiaries
Net income available to common and preferred stockholders
30,209
219
399.394
434.822
10,745
0 59.4Ql)
170,206
35,503
225
247.509
288.237
425,471
585 769 '
170.151
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
113
914
271
164.290
201.475
401 667
026.042.)
527 710
147.667
MidAmerican Energy Holdings Company
Parent Company Only (continued)
Condensed Statements of Cash Flows
For the three years ended December 31 , 2004
(Amounts in thousands)
Cash flows from operating activities
Cash flows from investing activities:
Decrease (increase) in advances to and investments in subsidiaries
and joint ventures
Other, net
Net cash flows from investing activities
Cash flows from financing activities:
Purchase and retirement of common stock
Repayment of subordinated debt
Proceeds from senior debt
Repayments of senior debt
Proceeds from issuance of preferred stock
Proceeds from issuance of trust preferred securities
Net repayment of revolving credit facility
Other
Net cash flows from financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Supplemental disclosures:
Interest paid, net of interest capitalized
Income tax receipts
2004
116 167
803
122.970
(20 000)
(100,000)
249,765
(3.32ID
126.437
939
328.750
2003
S (23 354)
228,083
207.052
(198,958)
449 295
(215 000)
(3.
31.423
121
320.629
PacifiCorp
Exhibit No. II, page 114 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Schedule I
2002
Ulli:l!M)
(1,654 755)
1J 657.595)
700 000
402,000
273 000
(153,500)
187.404
318,105
524
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
114
PacifiCorp
Exhibit No. It , page 115 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
Schedule II
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED V ALUA TION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
(Amounts in thousands)
Column A
Description
Column B
Balance at
Beginning
, of Year
Reserves Deducted
From Assets To Which
They Apply:
Reserve for uncollectible
accounts receivable:
Year ended 2004
Year ended 2003
Year ended 2002
$ 26 004
$ 39 742
$ 7,319
Reserves Not Deducted
From Assets
(!):
Year ended 2004
Year ended 2003
Year ended 2002
$ 17,417
$ 10 981
$ 13,631
Column C Column E
Balance
at End
of Year
Charged
Income
Column D
Deductions
Acquisition
Reserves (1)
Other
Accounts
$ 15 304
$ 13 620
$ 27,782 $ 10,142
$ (15 275)
$ (27,358)
$ (5,501)
$ 26 033
$ 26 004
$ 39 742
$ 4 048
$ 10 527
$ 2 798 247
$ (10 617)
$ (4 091)
$ (5 695)
' 10 848
$ 17 417
$ 10 981
(1)
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
Reserves not deducted from assets include estimated liabilities for losses retained by MEHC for workers compensation
public liability and property damage claims.
(2)Acquisition reserves represent the reserves recorded at Kern River and Northern Natural Gas at the date of acquisition.
115
PacifiCorp
Exhibit No. II, page 116 of 130CASE NO. PAC-05-
Witness: Patrick J, Goodmnn
SIGNATURES
Pursuant to the requirements of Section 13 or 15( d) of the Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Des Moines, State of Iowa
on this 28th day of February 2005.
MIDAMERICAN ENERGY HOLDINGS COMPANY
/s/ David L. Sokol.
David L. Sokol
Chainnan of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the Registrant and in the capacities and on the dates indicated.
Sbmature Date
/s/ David L. Sokol.
David L. Sokol
Chainnan of the Board
Chief Executive Officer, and Director
February 28 2005
/s/ Gregory E. Abel.
Gregory E. Abel
President, Chief Operating Officer
and Director
February 28, 2005
/s/ Patrick J. Goodman
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer
February 28 2005
/s/ Edgar D. Aronson
Edgar D. Aronson
Director
February 28, 2005
/s/ Stanley J. Bright.
Stanley J. Bright
Director
February 28, 2005
/s/ Walter Scott, Jr.
Walter Scott, Jr.
Director
February 28 2005
/s/ Marc D. Hamburg
Marc D. Hamburg
Director
February 28,2005
/s/ Warren E. Buffett.
Warren E. Buffett
Director
February 28,2005
116
/s/ John K. Boyer
John K. Boyer
Director
/s/ W. David Scott.
W. David Scott
Director
/s/ Richard R. Jaros
Richard R. Jaros
Director
PacifiCorp
Exhibit No. 11 , page 117 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Shmature Date
February 28, 2005
February 28, 2005
February 28, 2005
By: /s/ Douglas L. Anderson
Douglas L. Anderson
Attorney-in-Fact
February 28, 2005
117
Exhibit No.
3.1
4.1
4.4
yaCIIILorp
Exhibit No. 11 , page 118 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
EXHIBIT INDEX
Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective
March 6, 2002 (incorporated by reference to Exhibit 3.3 to MidAmerican Energy Holdings Company
Annual Report on Form 10-K for the year ended December 31 , 2001).
Bylaws of MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 3.
MidAmerican Energy Holdings Company s Annual Report on Form 10-K/A for the year ended
December 31, 1999). ,I
Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The
Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012
(incorporated by reference to Exhibit 4.1 of MidAmerican Energy Holdings Company s Registration
Statement No. 333-101699 dated December 6 2002).
First Supplemental Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings
Company and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior
Notes due 2012 (incorporated by reference to Exhibit 4.2 of MidAmerican Energy Holdings Company
Registration Statement No. 333-101699 dated December 6, 2002).
Registration Rights Agreement, dated as of October 1 , 2002, by and between MidAmerican Energy Holdings
Company and Credit Suisse First Boston (as Representative for the Initial Purchasers) (incorporated by
reference to Exhibit 4.3 of MidAmerican Energy Holdings Company s Registration Statement No. 333-
101699 dated December 6, 2002).
Indenture for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated as of February 26
1997, between MidAmerican Energy Holdings Company, as issuer, and the Bank of New York, as Trustee
(incorporated by reference to Exhibit 10.129 to MidAmerican Energy Holdings Company s Annual Report
on Form 10-K for the year ended December 31 , 1995).
Indenture, dated as of October 15, 1997, among MidAmerican Energy Holdings Company and IBJ Schroder
Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MidAmerican Energy
Holdings Company s Current Report on Form 8-K dated October 23, 1997).
Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount of $350 000 000
due 2007, dated as of October 28, 1997, among MidAmerican Energy Holdings Company and IBJ Schroder
Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to MidAmerican Energy
Holdings Company s Current Report on Form 8-K dated October 23, 1997).
Form of Second Supplemental Indenture for the 6.96% Senior Notes i~ the principal amount of $215,000 000
due 2003, 7.23% Senior Notes in the principal amount of $260 000 000 due 2005 , 7.52% Senior Notes in the
principal amount of $450 000,000 due 2008, and 8.48% Senior Notes in the principal amount of
$475 000 000 due 2028, dated as of September 22, 1998 between MidAmerican Energy Holdings Company
and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to
MidAmerican Energy Holdings Company s Current Report on Form 8-K dated September 17, 1998.
Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount of $100 000 000
due 2008, dated as of November 13, 1998, between MidAmerican Energy Holdings Company and IBJ
Schroder Bank & Trust Company, as Trustee (incorporated by reference to MidAmerican Energy Holdings
Company s Current Report on Form 8-K dated November 10, 1998).
118
Exhibit No.
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.19
10.
10.
PacifiCorp
Exhibit No. II , page 119 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Indenture
, '
dated as of March 14, 2000, among MidAmerican Energy Holdings Company and the Bank
New York, as Trustee (incorporated by reference to Exhibit 4.9 to MidAmerican Energy Holdings
Company s Annual Report on Form 10-KlA for the year ended December 31 , 1999).
Subscription Agreement, dated as of March 2000 executed by Berkshire Hathaway Inc. (incorporated by
reference to ~xhibit 4.10 to MidAmerican Energy Holdings Company s Annual Report on Form 10-KlA for
the year ended December 31, 1999).
Indenture, dated as of March 12, 2002, between MidAmerican Energy Holdings Company and the Bank of
New York, as Trustee (incorporated by reference to Exhibit 4.11 to MidAmerican Energy Holdings
Company s Annual Report on Fonn 10-K for the year ended December 31,2001).
Subscription Agreement, dated as of March 7, 2002, executed by Berkshire Hathaway Inc. (incorporated by
reference to Exhibit 4.12 to MidAmerican Energy Holdings Company s Annual Report on Form 10-K for the
year ended December 31,2001).
Subscription Agreement, dated as of March 12, 2002, executed by Berkshire Hathaway Inc. (incorporated by
reference to Exhibit 4.13 to MidAmerican Energy Holdings Company s Annual Report on Form 10-K for the
year ended December 31 , 2001).
Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002
(incorporated by reference to Exhibit 4.14 of MidAmerican Energy Holdings Company s Registration
Statement No. 333-101699 dated December 6, 2002).
Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002
(incorporated by reference to Exhibit 4.15 of MidAmerican Energy Holdings Company s Registration
Statement No. 333-101699 dated December 6, 2002).
Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000
(incorporated by reference to Exhibit ,, of MidAmerican Energy Holdings Company s Registration
Statement No. 333-101699 dated December 6,2002).
Indenture, dated as of August 16, 2002, between MidAmerican Energy Holdings Company and the Bank of
New York, as Trustee (incorporated by reference to Exhibit 4.17 of MidAmerican Energy Holdings
Company s Registration Statement No. 333-101699 dated December 6, 2002).
Subscription Agreement, dated as of August 16, 2002, executed by Berkshire Hathaway Inc. (incorporated by
reference to Exhibit 4.18 of MidAmerican Energy Holdings Company s Registration Statement No. 333-
101699 dated December 6, 2002).
Shareholders Agreement, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 of
MidAmerican Energy Holdings Company s Registration Statement No. 333-101699 dated December 2002).
Amended and Restated Employment Agreement between MidAmerican Energy Holdings Company and
David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to MidAmerican Energy
Holdings Company s Annual Report on F OrIn 1 0- KIA for the year ended December 31 , 1999).
Amendment No.1 to the Amended and Restated Employment Agreement between MidAmerican Energy
Holdings Company and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to
MidAmerican Energy Holdings Company s Annual Report on Form 10-KlA for the year ended
December 31, 1999).
119
Exhibit No.
10.3
10.4
10.
10.
10.
10.
10.
10.
10.
10.12
10.
PacifiCorp
ExhibitNo.page 120 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
Non-Qualified Stock Option Agreements of David L. Sokol, dated March 14, 2000 (incorporated by
reference to Exhibit 10.3 of MidAmerican Energy Holdings Company s Registration Statement No. 333-
101699 dated December 6, 2002).
Amended and Restated Employment Agreement between MidAmerican Energy Holdings Company and
Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to MidAmerican Energy
Holdings Company s Annual Report on Form 10-KlA for the year ended December 31 , 1999).
Non-Qualified Stock Option Agreements of Gregory E. Abel, dated March 14, 2000 (incorporated by
reference to Exhibit 10.5 of MidAmerican Energy Holdings Company s Registrationo'Statement No. 333-
101699 dated December 6,2002).
Employment Agreement between MidAmerican Energy Holdings Company and Patrick J. Goodman, dated
Apri121 , 1999 (incorporated by reference to Exhibit 10.5 to MidAmerican Energy Holdings Company
Annual Report on Form 10-KlA for the year ended December 31 , 1999).
125 MW Power Plant-Upper Mahiao Agreement, dated September 6, 1993, between PNOC- Energy
Development Corporation and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant
Upper Mahiao Agreement, dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the
Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant-Upper
Mahiao Agreement, dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to MidAmerican
Energy Holdings Company s AnnualReport on Form 10-K for the year ended December 31 , 1993).
Credit Agreement, dated April 8
, ,
1994 among CE Cebu Geothermal Power Company, Inc., the Banks
thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to MidAmerican Energy Holdings
Company s Annual Report on Form 10-K for the year ended December 31 , 1993).
Credit Agreement, dated as of April 8, 1994, between CE Cebu Geothermal Power Company, Inc., Export-
Import Bank of the United States (incorporated by reference to Exhibit 10.97 to MidAmerican Energy
Holdings Company s Annual Report on Form 10-K for the year ended December 31, 1993).
Pledge Agreement, dated as of April 8, 1994, among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as
Collateral Agent and CE Cebu Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.
to MidAmerican Energy Holdings Company s Annual Report on Form 10-for the year ended
December 31, 1993).
Overseas Private Investment Corporation Contract of Insurance, dated April 8, 1994, between the Overseas
Private Investment Corporation and the Company through its subsidiaries CE International Ltd.
Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to MidAmerican Energy
Holdings Company s Annual Report on Form 10-K for the year ended December 31 , 1993).
180 MW Power Plant-Mahanagdong Agreement, dated September 18, 1993, between PNOC- Energy
Development Corporation and CE Philippines Ltd. and the Company, as amended by the First Amendment to
Mahanagdong Agreement, dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter
Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement, dated March 3
1995 (incorporated by reference to Exhibit 10.1 00 to MidAmerican Energy Holdings Company s Annual
Report on Form 10-K for the year ended December 31 , 1993).
Credit Agreement, dated as of June 30, 1994, among CE Luzon Geothermal Power Company, Inc., American
Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings
Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to MidAmerican Energy
Holdings Company s Annual Report on Form 10-K for the year ended December 31 , 1993).
120
Exhibit No.
10.14
10.
10.16
10.17
10.
10.
10.
10.
10.
10.
10.
pacitiCorp
Exhibit No. I I , page 121 of 130CASE NO. PAC-05-Witness: Patrick J. Goodman
Credit Agreement, dated as of June 30, 1994, between CE Luzon Geothermal Power Company, Inc. and
Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to MidAmerican
Energy Holdings Company s Annual Report on Fonn 10-K for the year ended December 31, 1993).
Finance Agreement, dated as of June 30, 1994, between CE Luzon Geothermal Power Company, Inc. and
Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to MidAmerican
Energy Holdi~gs Company s Annual Report on Fonn 10-K for the year ended December 31, 1993).
Pledge Agreement, dated as of June 30, 1994, among CE Mahanagdong Ltd., Kiewit Energy International
(Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon
Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to MidAmerican Energy
Holdings Company s Annual Report on Form 10-K for the year ended December 31, 1993).
Overseas Private Investment Corporation Contract of Insurance, dated July 29, 1994, between Overseas
Private Investment Corporation and the Company, CE International Ltd., CE Mahanagdong Ltd. and'
American Pacific Finance Company and Amendment No.1, dated August 3, 1994 (incorporated by reference
to Exhibit 10.105 to MidAmerican Energy Holdings Company s Annual Report on Form 10-K for the year
ended December 31, 1993).
231 MW Power Plant-Malitbog Agreement, dated September 10, 1993
, ,
between PNOC- Energy
Development Corporation and Magma Power Company and the First and Second Amendments thereto, dated
December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to
MidAmerican 'Energy Holdings Company s Annual Report on Form IO-K for the year ended December 31
1993 ).
Credit Agreement, dated as of November 10, 1994, among Visayas Power Capital Corporation, the Banks
parties thereto and Credit Suisse, as Bank Agent (incorporated by reference to Exhibit 10.107 to
MidAmerican Energy Holdings Company s Annual Report on Form 10-K for the year ended December 31
1993).
Finance Agreement, dated as of November 10, 1994, between Visayas Geothennal Power Company and
Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to MidAmerican
Energy Holdings Company s Annual Report on Fonn 10-K for the year ended December 31 , 1993).
Pledge and Security Agreement, dated as of November 10, 1994, among Broad Street Contract Services, Inc.
Magma Power Company, Magma Netherlands B.V. and Credit Suisse, as Bank Agent (incorporated by
reference to Exhibit 10.109 to MidAmerican Energy Holdings Company s Annual Report on Fonn 10-K for
the year ended December 31, 1993).
Overseas Private Investment Corporation Contract of Insurance, dated December 21 , 1994, between
Overseas Private Investment Corporation and Magma Netherlands, B.V. (incorporated by reference to
Exhibit 10.110 to MidAmerican Energy Holdings Company s Annual Report on Forml0-K for the year
ended December 31, 1993).
Agreement as to Certain Common Representations, Warranties, Covenants and Other Tenns, dated
November 10, 1994, between Visayas Geothennal Power Company, Visayas Power Capital Corporation
Credit Suisse, as Bank Agent, Overseas Private Investment Corporation and the Banks named therein
(incorporated by reference to Exhibit 10.111 to MidAmerican Energy Holdings Company s 1994 Annual
Report on Fonn 10-K for the year ended December 31, 1993).
Trust Indenture, dated as of November 27, 1995, between the CE Casecnan Water and Energy Company, Inc.
and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water
and Energy Company, Inco's Registration Statement on Fonn S-4 dated January 25, 1996).
121
Exhibit No.
10.
10.
10.
10.
10.
10.
10.
10.32
10.
10.
10.
PacifiCorp
Exhibit No. 11, page 122 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
Amended and Restated Casecnan Project Agreement, dated June 26, 1995, between the National lITigation
Administration and CECasecnan Water and Energy Company Inc. (incorporated by reference to Exhibit 10.
to CE Casecnan Water and Energy Company, Inc.s Registration Statement on Form S-4 dated January 25
1996).
Indenture and First Supplemental Indenture, dated March 11, 1999, between MidArnerican Funding LLC and
IBJ Whitehall Bank & Trust Company and the First Supplement thereto relatiJtg to the $700 million Senior
Notes and Bonds (incorporated by reference to MidAmerican Energy Holdings Company s Annual Report on
Form 10-K for the year ended December 31 , 1998).
General Mortgage Indenture and Deed of Trust, dated as of January 1, 1993, between Midwest Power
Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to
Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31
1992, Commission File No. 1-10654).
First Supplemental Indenture, dated as of January 1 , 1993, between Midwest Power Systems Inc. and
Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b )-2 to the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31 , 1992, Commission
File No. 1-10654).
Second Supplemental Indenture, dated as of January 15, 1993, between Midwest Power Systems Inc. and
Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission
File No. 1-10654).
Third Supplemental Indenture, dated as of May 1 , 1993, between Midwest Power Systems Inc. and Morgan
Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest
Resources Inc. Annual Report on Forml0-K for the year ended December 31 , 1993, Commission File No. I-
10654).
Fourth Supplemental Indenture, dated as of October 1 , 1994, between Midwest Power Systems Inc. and
Hams Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources
Inc. Annual Report on Form 10-K for the year ended December 31 , 1994, Commission File No. 1-10654).
Fifth Supplemental Indenture, dated as of November 1 , 1994, between Midwest Power Systems Inc. and
Hams Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources
Inc. Annual Report on Form 10-K for the year ended December 31 1994, Commission File No. 1-10654).
Sixth Supplemental Indenture, dated as of July 1 , 1995, between Midwest Power Systems Inc. and Harris
Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy
Company Annual Report on Form 10-K for the year ended December 31 , 1995, Commission File No.
11505).
Supplemental Agreement between CE Casecnan Water and Energy Company, Inc. and the Philippines
National Irrigation Administration dated as of September 29, 2003 (incorporated by reference to Exhibit 98.
to MidAmerican Energy Holdings Company s Current Report on Form 8-K dated October 15 2003).
Sixth Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated August 31, 2003, between
PNOC-Energy Development Corporation and CE Luzon Geothermal Power Company, Inc. (incorporated by
reference to Exhibit 10.44 to MidAmerican Energy Holdings Company s Annual Report on Form 10-K for
the year ended December 31 2003).
122
Exhibit No.
10.
10.37
10.
10.
10.40
10.41
10.42
10.43
10.44
10.45
10.46
10.47
PacifiCorp
Exhibit No. 11, page 123 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
Third Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31 , 2003, between PNOC-
Energy Development Corporation and Visayas Geothennal Power Company, Inc. (incorporated by reference
to Exhibit 10.45 to MidAmerican Energy Holdings Company s Annual Report on Fonn 10-K for the year
ended December 31 , 2003).
Seventh Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated August 31, 2003 , between
PNOC-Energy Development Corporation and CE Cebu Geothennal Power Company, Inc. (incorporated by
reference to Exhibit 1 0.46 to MidAmerican Energy Holdings Company s Annual Report on ,Fonn 10-K for
the year ended December 31, 2003).
Fiscal Agency Agreement, dated as of October 15, 2002, between Northern Natural Gas Company and J.P.
Morgan Trust Company, National Association, Fiscal Agent, relating to the $300,000 000 in principal
amount of the 5375% Senior Notes due 2012. (incorporated by reference to Exhibit 10.47 to MidAmerican
Energy Holdings Company s Annual Report on Fonn 10-K for the year ended December 31 2003).
Trust Indenture, dated as of August 13, 2001 , among Kern River Funding Corporation, Kern River Gas
Transmission Company and the JP Morgan Chase Bank, as Trustee, relating to the $510 000 000 in principal
amount of the 6.676% Senior Notes due 2016. (incorporated by reference to Exhibit 10.48 to MidAmerican
Energy Holdings Company s Annual Report on Fonn 10-K for the year ended December 31 2003).
Third Supplemental Indenture, dated as of May 1, 2003, among Kern River Funding Corporation, Kern River
Gas Transmission Company and JPMorgan Chase Bank, as Trustee, relating to the $836 000 000 in principal
amount of the 4.893% Senior Notes due 2018: (incorporated by reference to Exhibit 10.49 to MidAmerican
Energy Holdings Company s Annual Report on Fonn 10-K for the year ended December 31 , 2003).
CalEnergy Company, Inc. Voluntary Deferred Compensation Plan, effective December 1, 1997, First
Amendment, dated as of August 17, 1999, and Second Amendment effective March 14, 2000 (incorporated
by reference to Exhibit 10.50 of MidAmerican Energy Holdings Company s Registration Statement No. 333-
101699 dated December 6, 2002).
MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (incorporated
by reference to Exhibit 10.51 of MidAmerican Energy Holdings Company s Registration Statement No.333-
101699 dated December 6 2002).
MidAmerican Energy C?mpany First Amended and Restated Supplemental Retirement Plan for Designated
Officers dated as of May 10, 1999 (incorporated by reference to Exhibit 10.52 of MidAmerican Energy
Holdings Company s Registration Statement No. 333-101699 dated December 6, 2002).
MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference
to Exhibit 10.6 to MidAmerican Energy Holdings Company s Annual Report on Fonn 10-KlA for the year
ended December 31, 1999).
MidAmerican Energy Holdings Company Restated Deferred Compensation Plan-Board of Directors
(incorporated by reference to Exhibit 10 to MidAmerican Energy Holdings Company s Quarterly Report on
Fonn 10-Q for the quarter ended June 30, 1999).
MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred
Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10.63 to MidAmerican Energy
Holdings Company s Annual Report on Fonn 10-KlA for the year ended December 31, 1999).
Share Sale Agreement, dated as of August 6, 2001, among NPower Yorkshire Limited, Innogy Holdings pIc,
CE Electric UK pIc and Northern Electric pic (incorporated by reference to Exhibit 10.63 of MidAmerican
Energy Holdings Company s Registration Statement No. 333-101699 dated December 6 2002).
123
Exhibit No.
10.48
10.49
10.
10.
10.
10.
10.
10.
10.
10.
10.
PacifiCorp
Exhibit No. 11. page 124 of 130
CASE NO. P AC-05-
Witness: Patrick J. Goodman
Purchase Agreement, dated as of March 7, 2002 among The Williams Companies, Inc., Williams Gas
Pipeline Company, LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and
MidAmerican Energy Holdings Company, KR Holding, LLC, KR Acquisition 1 , LLC and KR Acquisition 2
LLC (incorporated by reference to Exhibit 99.2 to MidAmerican Energy Holdings Company s Current
Report on Fonn 8-K dated March 28, 2002).
MidAmerican Energy Holdings Company Executive Incremental Profit Sharing Plan (incorporated by
reference to Exhibit 10.2 of MidAmerican Energy Holdings Company s Quarterly Report on Fonn 10-Q for
the quarter ended March 31 , 2003.
Purchase and Sale Agreement, dated as of July 28, 2002, between Dynegy Inc., NNGC Holding Company,
Inc. and MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 99.
MidAmerican Energy Holdings Company s Current Report on Fonn 8-K dated July 30, 2002).
Trust Deed between CE Electric UK Funding Company, AMBAC Insurance UK Limited and The Law
Debenture Trust Corporation, p.l.c. dated December 15, 1997 (incorporated by reference to Exhibit 99.1 to
MidAmerican Energy Holdings Company s Current Report on Fonn 8-K dated March 30, 2004).
Insurance and Indemnity Agreement between CE Electric UK Funding Company and AMBAC Insurance
UK Limited dated December 15, 1997 (incorporated by reference to Exhibit 99.2 to MidAmerican Energy
Holdings Company s Current Report on Fonn 8-K dated March 30, 2004).
Supplemental Agreement to Insurance and Indemnity Agreement between CE Electric UK Funding
Company and AMBAC Insurance UK Limited dated September 19, 2001 (incorporated by reference to
Exhibit 99.3 to MidAmerican Energy Holdings Company s Current Report on Fonn 8-K dated March 30
2004).
Fiscal Agency Agreement, dated as of May 4, 1993, among Northern Natural Gas Company, Enron Corp.
and Continental Bank, National Association, Fiscal Agent, relating to the $100,000 000 in principal amount
of the 6.875% Senior Notes due 2005 (incorporated by reference to Exhibit 10.68 to MidAmerican Energy
Holdings Company s Quarterly Report onFonn 10-Q for the quarter ended March 31, 2004).
Fiscal Agency Agreement, dated as of September 4, 1998, between Northern Natural Gas Company and
Chase Bank of Texas, National Association, Fiscal Agent, relating to the $150 000 000 in principal amount
of the 6.75% Senior Notes due 2008 (incorporated by reference to Exhibit 10.69 to MidAmerican Energy
Holdings Company s Quarterly Report on Fonn 10-Q for the quarter ended March 31, 2004).
Fiscal Agency Agreement, dated as of May 24, 1999, between Northern Natural Gas Company and Chase
Bank of Texas, National Association, Fiscal Agent, relating to the $250 000 000 in principal amount of the
00% Senior Notes due 2011(incorporated by reference to Exhibit 10.70 to MidAmerican Energy Holdings
Company s Quarterly Report on Fonn 10-Q for the quarter ended March 31, 2004).
Trust Indenture, dated as of September 10, 1999, between Cordova Funding Corporation and Chase
Manhattan Bank and Trust Company, National Association, Trustee, relating to the $225,000 000 in principal
amount of the 8.75% Senior Secured Bonds due 2019 (incorporated by reference to Exhibit 10.71 to
MidAmerican Energy Holdings Company s Quarterly Report on Fonn 10-Q for the quarter ended March 31
2004).
Indenture, dated as of December 15, 1997, among CE Electric UK Funding Company, The Bank of New
York, as Trustee, and Banque Internationale A Luxembourg S.A., as Paying Agent (incorporated by
reference to Exhibit 10.72 to MidAmerican Energy Holdings Company s Quarterly Report on Fonn 10-Q for
the quarter ended March 31, 2004).
124
Exhibit No.
10.
10.
10.
10.
10.
10.
10.
10.
10.
PacitiCorp
Exhibit No. 11, page 125 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
First Supplemental Indenture, dated as of December 15, 1997, among CE Electric UK Funding Company,
The Bank of New York, Trustee, and Banque Internationale A Luxembourg S., Paying Agent, relating to
the $125 000 000 in principal amount of the 6.853% Senior Notes due 2004 and to the $237 000 000 in
principal amount of the 6.995% Senior Notes due 2007 (incorporated by reference to Exhibit 10.73 to
MidAmerican Energy Holdings Company s Quarterly Report on Fonn 10-Q for the quarter ended March 31
2004).
Trust Deed, dated as of February 4, 1998 among Yorkshire Power Finance Limited, Yorkshire Power Group
Limited and Bankers Trustee Company Limited, Trustee, relating to the f:200 000 000 in principal amount of
the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.74 to MidAmerican Energy
Holdings Company s Quarterly Report on Fonn 10-Q for the quarter ended March 31 , 2004).
First Supplemental Trust Deed, dated as of October 1 , 200 I , among Yorkshire Power Finance Limited
Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the
f:200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to
Exhibit 10.75 to MidAmerican Energy Holdings Company s Quarterly Report on Fonn 10-Q for the quarter
ended March 31, 2004).
Third Supplemental Trust Deed, dated as of October 1 , 2001 , among Yorkshire Electricity Distribution pIc
Yorkshire Electricity Group PLC and Bankers Trustee Company Limited" Trustee, relating to the
f:200 000 000 in principal amount of the 9.25% Bonds due 2020 (incorporated by reference to Exhibit 10.
to MidAmerican Energy Holdings Company s Quarterly Report on Fonn 10-Q for the quarter ended March
, 2004).
Indenture, dated as of February 1 , 1998, and Second Supplemental Indenture, dated as of February 25, 1998
each among Yorkshire Power Finance Limited, Yorkshire Power Group Limited, The Bank of New York
Trustee, and Banque lnternationale du Luxembourg S., Paying Agent, relating to the $300 000 000 in
principal amount of the 6.496% Notes due 2008 (incorporated by reference to Exhibit 10.77 to MidAmerican
Energy Holdings Company s Quarterly Report on Fonn 10-Q for the quarter ended March 31 , 2004).
Indenture, dated as of February 1 2000, among Yorkshire Power Finance 2 Limited, Yorkshire 'Power Group
Limited and The Bank of New York, Trustee (incorporated by reference to Exhibit 10.78 to MidAmerican
Energy Holdings Company s Quarterly Report on Form 10-Q for the quarter ended March 31 , 2004).
First Supplemental Indenture, dated as of February 16, 2000, among Yorkshire Power Finance 2 Limited
Yorkshire Power Group Limited and The Bank of New York, Trustee, relating to the f:155 000 000 in
principal amount of the Reset Senior Notes due 2020 (incorporated by reference to Exhibit 10.79 to
MidAmerican Energy Holdings Company s Quarterly Report on Form 10-Q for the quarter ended March 31
2004).
Trust Agreement, dated as of February 1 , 2000, among Yorkshire Power Group Limited, YPG Holdings LLC
and The Bank of New York, Trustee, relating to the $250 000 000 in principal amount of the 8.25% Pass-
Through Asset Trust Securities due 2005 (incorporated by reference to Exhibit 10.80 to MidArnerican
Energy Holdings Company s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
First Supplemental Trust Deed, dated as of September 27, 2001, among Northern Electric Finance pic
Northern Electric pIc, Northern Electric Distribution Limited and The Law Debenture Trust Corporation
p.1., Trustee, relating to the f:l00,000,000 in principal amount of the 8.625% Guaranteed Bonds due 2005
and to the f:100~000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by
reference to Exhibit 10.81 to MidAmerican Energy Holdings Company s Quarterly Report on Form 10-Q for
the quarter ended March 31 2004).
125
Exhibit No.
10.
10.
10.
10.
14.1
21.1
24.1
31.1
31.2
32.1
32.
PacifiCorp
Exhibit No. 11, page 126 of 130
CASE NO. PAC-O5-
Witness: Patrick J. Goodman
Stock Redemption Agreement, dated as of January 8, 2004, between David L. Sokol and' MidAmerican
Energy Holdings Company (incorporated by reference to Exhibit 10.82 to MidAmerican Energy Holdings
Company s Quarterly Report on Form 10-Q for the quarter ended March 31 , 2004).
Trust Deed, dated as of January 17, 1995, between Yorkshire Electricity Group pIc and Bankers Trustee
Company Limited, Trustee, relating to the f200 000 000 in principal amount of the 9 1/4% Bonds due 2020
(incorporated by reference to Exhibit 10.83 to MidAmerican Energy Holdings Company s Quarterly Report
on Form 10-Q for the quarter ended March 31, 2004).
Master Trust Deed, dated as of October 16, 1995, among Northern Electric Finance pic,Northern Electric pIc
and The Law Debenture Trust Corporation p.1., Trustee, relating to the f 1 00 000,000 in principal amountof
the 8.625% Guaranteed Bonds due 2005 and to the flOO OOO OOO in principal amount of the 8.875%
Guaranteed Bonds due 2020.
MidAmerican Energy Holdings Company Amended and Restated Long-Term Incentive Partnership Plan
dated as of January 1, 2004.
MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial
Officer and Other Covered Officers.
Subsidiaries of the Registrant.
Power of Attorney.
Chief Executive Officer s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Chief Financial Officer s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of2002.
Chief Executive Officer s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Chief Financial Officer s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of2002.
126
EXHIBIT 31.
Pad fiCorp
Exhibit No. 11, page 127 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
, David L. Sokol, certify that:
, I have reviewed this annual report on Fonn 10.:.K of MidAmerican Energy Holdings Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact or ,omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial infonnation included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material infonnation relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period'
in which this report is being prepared;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred
during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting; and
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or
persons perfonning the equivalent function):
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process,summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant's internal control over financial reporting.
Date: February 28, 2005
/s/ David L. Sokol
DavidL. Sokol
Chairman and Chief Executive Officer
EXHIBIT 31.
PacifiCorp
Exhibit No. II , page 128 of 130
CASE NO. PAC-05-Witness: Patrick J. Goodman
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
, Patrick J. Goodman, certify that:
I have reviewed this annual report on Form 10-K of MidAmerican Energy Holdings Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report; 1\
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
Evaluated the effectiveness of the, registrant's disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred
during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting; and
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or
persons perfonning the equivalent function):
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process,
swnmarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant's internal control over financial reporting.
Date: February 28,2005
/s/ Patrick 1. Goodman
Patrick J. Goodman
Senior Vice President and Chief Financial Officer
PacifiCorp
Exhibit No. 11, page 129 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
EXHIBIT 32.
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
, David L. Sokol, Chairman and Chief Executive Officer of MidAmerican Energy Holdings Company (the "Company ), certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of2002, 18 V.C. Section 1350, that to the best of my knowledge:
(1)the Annual Report on Form 10-K of the Company for the annual period ended December 31 , 2004 (the ,Report") fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 V.C. 18m or
18o( d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of the Company.
Dated: February 28, 2005
Isl David L. Sokol
David L. Sokol
Chairman and Chief Executive Officer
PacifiCorp
Exhibit No, II, page 130 of 130
CASE NO. PAC-05-
Witness: Patrick J. Goodman
EXHIBIT 32.
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
, Patrick J. Goodman, Senior Vice President and Chief Financial Officer of MidAmerican Energy Holdings Company (the
Company ), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 D.C. Section 1350, that to the best of my
knowledge:
(1)the Annual Report on Fonn 10-K of the Company for the annual period ended December 31 , 2004 (the "Report") fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 D.C. 18m or
18o( d)); and
(2)the infonnation contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of the Company.
Dated: February 28, 2005
/s/ Patrick 1. Goodman
, Patrick J. Goodman
Senior Vice President and Chief Financial