MIDAMERICAN ENERGY CO, 8-K, 1996-02-20

MIDAMERICAN ENERGY CO
8-K, 1996-02-20

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<PAGE>
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): February 20, 1996

MidAmerican Energy Company
------------------------------------------------------
(Exact name of registrant as specified in its charter)

Iowa 1-11505 42-1425214
---------------- ------------ --------------
(State or other (Commission (IRS Employer
jurisdiction of File Number) Identification No.)
incorporation)

666 Grand Avenue, P. O. Box 657 Des Moines, Iowa 50303
------------------------------------------------ ----------
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 515/242-4300

<PAGE>
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS.

EXHIBIT NUMBER EXHIBIT

27 Financial Data Schedule

99.1 Financial information of MidAmerican Energy Company including
management's discussion and analysis of financial condition and
results of operations; consolidated statements of income, cash
flows and retained earnings for the years ended December 31,
1995, 1994 and 1993; consolidated balance sheets and
consolidated statements of capitalization as of December 31, 1995
and 1994; notes to the consolidated financial statements; report
of the independent public accountants; report of management; and
supplemental financial and statistical data.

<PAGE>

SIGNATURES

Pursuant to the requirements 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.

MIDAMERICAN ENERGY COMPANY

/s/ Paul J.Leighton
____________________________________
Paul J. Leighton
Vice President and Secretary

February 20, 1996

<PAGE>

EXHIBIT INDEX

EXHIBIT NO. DESCRIPTION

27 Financial Data Schedule

<PAGE>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
consolidated balance sheet of MidAmerican Energy Company as of December
31, 1995, and the related consolidated statements of income and cash flows
for the twelve months ended December 31, 1995, and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,654,549
<OTHER-PROPERTY-AND-INVEST> 826,496
<TOTAL-CURRENT-ASSETS> 409,808
<TOTAL-DEFERRED-CHARGES> 420,520
<OTHER-ASSETS> 212,148
<TOTAL-ASSETS> 4,523,521
<COMMON> 801,227
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 430,589
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,225,715
50,000
89,945
<LONG-TERM-DEBT-NET> 1,403,322
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 184,800
<LONG-TERM-DEBT-CURRENT-PORT> 65,295
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,504,444
<TOT-CAPITALIZATION-AND-LIAB> 4,523,521
<GROSS-OPERATING-REVENUE> 1,723,644
<INCOME-TAX-EXPENSE> 67,984<F1>
<OTHER-OPERATING-EXPENSES> 1,422,512
<TOTAL-OPERATING-EXPENSES> 1,422,512
<OPERATING-INCOME-LOSS> 301,132
<OTHER-INCOME-NET> 12,077<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 312,792
<TOTAL-INTEREST-EXPENSE> 114,402
<NET-INCOME> 130,823
8,059
<EARNINGS-AVAILABLE-FOR-COMM> 122,764
<COMMON-STOCK-DIVIDENDS> 118,828
<TOTAL-INTEREST-ON-BONDS> 80,133
<CASH-FLOW-OPERATIONS> 381,672
<EPS-PRIMARY> 1.22
<EPS-DILUTED> 1.22
<FN>
<F1>Tag 37 includes operating and nonoperating income taxes and is excluded
from operating expenses in Tag 39 and on the Consolidated Statement
of Income.
<F2>Tag 41 includes $417,000 of Income from Discontinued Operations, net of
income taxes.
</FN>

</TABLE>

<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

CORPORATE OVERVIEW

MidAmerican Energy Company (the Company or MidAmerican) was formed on
July 1, 1995, as a result of the merger of Iowa-Illinois Gas and Electric
Company (Iowa-Illinois), Midwest Resources Inc. (Resources) and its utility
subsidiary, Midwest Power Systems Inc. (Midwest). Pursuant to the merger,
each outstanding share of preferred and preference stock of the predecessor
companies was converted into one share of a similarly designated series of
MidAmerican preferred stock, no par value. Each outstanding share of common
stock of Resources and Iowa-Illinois was converted into one share and 1.47
shares, respectively, of MidAmerican common stock, no par value.

The Company's utility operations (the Utility) consist of two principal
business units: an electric business unit headquartered in Davenport, Iowa, and
a natural gas business unit headquartered in Sioux City, Iowa. The Company's
corporate headquarters, which includes various staff functions, is in Des
Moines, Iowa. InterCoast Energy Company (InterCoast) and Midwest Capital Group,
Inc. (Midwest Capital) are the nonregulated subsidiaries of the Company and are
headquartered in Des Moines. InterCoast conducts various nonregulated
activities of the Company, while Midwest Capital functions as a regional
business development company in the utility service territory.

Management anticipates that the merger will permit the Company to derive
benefits from more efficient and economic use of the combined facilities and
resources of its predecessors. Savings from avoided costs and cost reductions
are estimated to total in excess of $500 million over the next 10 years.
Although the Company began realizing some benefits of the merger in 1995,
additional benefits and savings will be realized in 1996 and future years. As
discussed below, the Company has incurred significant costs related to
consummation of the merger, business restructuring and work force reduction.

The merger is being accounted for as a pooling-of-interests, and the
Consolidated Financial Statements included in this Annual Report are presented
as if the merger was consummated as of the beginning of the earliest period
presented. Portions of the following discussion provide information related to
material changes in the Company's financial condition and results of operations
between the periods presented, based on the combined historical information of
the predecessor companies. It is not necessarily indicative of what would have
occurred had the merger actually been consummated at the beginning of the
earliest period.

In January 1996, the Company's Board of Directors approved the formation
of a holding company structure. The holding company would have two wholly
owned subsidiaries consisting of MidAmerican (utility operations) and
InterCoast. Midwest Capital would remain a subsidiary of MidAmerican. The
Board of Directors and management believe a holding company structure will
provide a more flexible organization better designed to operate in a more
competitive environment. Consummation of the holding company structure is
subject to approval by holders of a majority of the outstanding shares of the
Company's common stock. In addition, certain orders must be received from
the Illinois Commerce Commission (ICC), the Iowa Utilities Board (IUB), the
Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory
Commission (NRC). Subject to such approvals, each share of MidAmerican common
stock will be exchanged for one share of the holding company's common stock.
It is management's intent, if possible, to complete the formation of the
holding company and share exchange by the end of 1996.

-1-

<PAGE>

RESULTS OF OPERATIONS

EARNINGS

The following tables provide a summary of the earnings contributions of the
Company's operations for the past three years:
<TABLE>
<CAPTION>
1995 1994 1993
------ ------ ------
<S> <C> <C> <C>
Earnings (in millions)
Utility operations............... $124.5 $110.6 $125.5
Nonregulated operations.......... (2.1) 15.2 13.8
Income (loss) from
discontinued operations........ 0.4 (5.6) (3.8)
------ ------ -------
Consolidated earnings............ $122.8 $120.2 $135.5
------ ------ -------
------ ------ -------

Earnings Per Common Share
Utility operations............... $1.24 $1.12 $1.29
Nonregulated operations.......... (0.02) 0.16 0.14
Income (loss) from
discontinued operations........ - (0.06) (0.04)
------ ------ -------
Consolidated earnings............ $1.22 $1.22 $1.39
------ ------ -------
------ ------ -------
</TABLE>

Earnings per share for 1995 were unchanged compared to 1994. Increases in
the gross margins of utility electric and natural gas operations favorably
affected earnings for 1995. Gross margin is the amount of revenues remaining
after deducting electric fuel costs or the cost of gas sold, as appropriate.
Decreases in nuclear operations and maintenance costs also favorably affected
earnings. Merger-related costs and write-downs of certain nonregulated assets
had a significant adverse affect on 1995 earnings.

The increases in utility gross margins were due primarily to electric and
gas service rate increases filed prior to the merger. Recent rate activity is
discussed in greater detail later in this section. A portion of the rate
increases relate directly to increases in certain operating expenses. The gross
margin for electric operations, net of the increase in directly-related
operating expenses, contributed $0.26 per share more to earnings in 1995 than
in 1994. In addition to increases in electric rates, increased sales due to hot
weather in the third quarter of 1995, though offset somewhat by less extreme
temperatures in the heating season, resulted in a 3% increase in electric retail
sales for 1995 compared to 1994. The gross margin for gas operations, net of
the increase in directly-related operating expenses, contributed $0.07 per share
more to earnings in 1995 than in 1994. An increase in retail natural gas sales
also contributed to the improved gross margin due to colder temperatures in the
fourth quarter of 1995 compared to 1994.

As part of the process of merging the operations of MidAmerican's
predecessors, the Company developed a restructuring plan which includes employee
incentive early retirement, relocation and separation programs. The
restructuring plan, which was completed in 1995, resulted in the elimination of
over 700 positions. During 1995 the Company recorded $33.4 million of
restructuring costs which included the Company's estimate of the remaining
amount of such costs to be incurred. These costs are primarily reflected in
Other Operating Expenses in the Consolidated Statements of Income.

-2-
<PAGE>

In addition, the Company incurred nonrecurring costs to accomplish
consummation of the merger. These "transaction costs," which are included in
Other Non-Operating Income, in the Consolidated Statements of Income, totalled
$4.6 million in 1995 and $4.5 million in 1994.

In total, restructuring and transaction costs reduced 1995 earnings by
$0.24 per share, while transaction costs reduced 1994 earnings by $0.05 per
share.

Write-downs of certain assets of the Company's nonregulated subsidiaries
reduced 1995 earnings by approximately $10.2 million, or $0.10 per share. The
pre-tax amount of the write-downs, which is included in Other Non-Operating
Income, in the Consolidated Statements of Income, reflects other-than-temporary
declines of $18.0 million in the value of those nonregulated investments. The
investments are primarily alternative energy projects.

Earnings for 1994 decreased $15.3 million from the 1993 level due
primarily to merger transaction costs in 1994 and recognition of an $11.5
million aftertax gain on the exchange of gas service territory in 1993.

UTILITY OPERATING REVENUES

ELECTRIC:

A combination of factors contributed to the $73.0 million increase in
electric operating revenues for 1995.

Various increases in retail electric rates contributed to the increase in
electric revenues. In October 1994 and January 1995, the Company implemented
rate increases for Iowa energy efficiency cost recovery filings which allow a
total increase in electric revenues of $31.7 million over a four-year period.
In August 1995, the Company began collection of $18.6 million over a four-year
prospective period related to another energy efficiency cost recovery filing.
In connection with an Iowa electric rate filing, the Company began collecting in
January 1995 interim rates representing an increase of $13.6 million in annual
electric revenues. A final rate increase in the proceeding, representing an
increase of $20.3 million in annual electric revenues, was effective in August
1995. The new rates include a component for the recovery of other
postretirement employee benefit (OPEB) costs on an accrual basis instead of the
pay-as-you-go basis previously used. Approximately $8 million of the $20.3
million increase in annual revenues relates to additional expensing of OPEB
costs. Increases in revenues due to OPEB and energy efficiency costs have an
immaterial impact on net income due to corresponding increases in operating
expenses.

An 11% increase in retail sales of electricity for the 1995 third quarter
compared to the 1994 third quarter was the main cause of the increase in
electric retail sales for 1995. The increase in sales was primarily the result
of warmer temperatures which, measured in cooling degree days, were 56% warmer
in the 1995 third quarter than in the comparable 1994 quarter.

The Company has been allowed current recovery from most of its electric
utility customers for fuel and purchased power costs through energy adjustment
clauses (EACs). As the cost of energy to serve those customers fluctuates,
revenues fluctuate accordingly with no impact on gross margin or net income. In
1995, the average energy cost per unit decreased 4.5%. As a result, 1995
revenues collected through the EACs decreased compared to 1994.

Revenues from sales for resale accounted for $21.2 million of the increase
in electric revenues. Sales for resale volumes increased 53% for 1995 compared
to 1994. Greater availability of nuclear generating facilities in 1995
increased the amount of energy available for sales for resale. Coal delivery
uncertainties also limited the

-3-

<PAGE>

Company's sales for resale activity in 1994. Sales for resale have a lower
margin than other sales and, accordingly, increases in related revenues do
not increase net income as much as increases in retail revenues.

The Company is a 25% owner in Quad-Cities Nuclear Power Station (Quad-
Cities Station), which is jointly owned and operated by Commonwealth Edison.
The Company also purchases 50% of the energy of Cooper Nuclear Station (Cooper),
which is owned and operated by Nebraska Public Power District (NPPD), through a
power purchase agreement which terminates in 2004. NPPD took Cooper out of
service on May 25, 1994. Pending satisfaction of the concerns of the NRC,
Cooper remained out of service until February 1995 when it returned to service
following NRC approval to restart. In May 1995, the Company filed a lawsuit
seeking unspecified damages from NPPD related to the 1994-95 Cooper outage. In
June 1995, the NRC removed Cooper and the Quad-Cities Station from its list of
adversely trending plants.

Total electric operating revenues for 1994 increased $18.7 million compared
to 1993. Electric retail revenues increased $38.2 million in 1994 compared to
1993. The increase in retail revenues was partially offset by a decrease of
approximately $20 million in sales for resale revenues. As discussed above,
outages at Cooper in 1994 and coal delivery uncertainties limited the Company's
sales for resale activity. An increase in retail sales, due mostly to increased
sales to general service customers, was the primary cause of the increase in
retail revenues. An increase in the cost of energy per unit sold also increased
revenues through the EACs in 1994. Rate increases also contributed to the
increase in electric revenues for 1994 compared to 1993 as discussed below.

In July 1993, the Company implemented electric rates for some of its Iowa
customers designed to increase annual electric revenues by $6.8 million. Also
in July 1993, an annual electric rate increase in Illinois of $9.6 million
became effective.

GAS:

Gas operating revenues for 1995 decreased $32.4 million compared to 1994.
A reduction in revenues collected through the purchased gas adjustment clauses
(PGAs) was the primary cause of the decrease in revenues. This was due to a
significant decrease in the average cost of gas per unit sold. Variations in
revenues collected through the PGAs reflecting changes in the cost of gas and
volumes sold do not affect gross margin or net income.

An increase in sales and rates offset part of the impact of lower PGA
revenues. In January 1995, the Company implemented a gas service rate increase
resulting from findings in an Iowa energy efficiency cost recovery filing which
allows an increase in gas revenues of $6.7 million over a four-year period. In
October 1994, the Company began collecting interim rates for an Iowa gas rate
filing representing an increase of $8.2 million in annual gas revenues. A final
rate increase of $10.6 million in annual gas revenues was effective in August
1995. Approximately $2.5 million of the $10.6 million increase in annual
revenues relates to the recovery of OPEB costs on an accrual basis. Increases
in revenues due to OPEB and energy efficiency costs have an immaterial impact on
net income due to corresponding increases in operating expenses. Retail sales
of natural gas increased slightly due to a 4% increase in residential sales.
This was due mostly to colder weather in the fourth quarter of 1995.

Gas operating revenues for 1994 decreased $47.0 million compared to 1993
due to a decrease in retail natural gas sales. Temperatures, measured in
heating degree days, decreased considerably in 1994 compared to 1993, resulting
in the decrease in retail sales. In addition, an exchange of gas service
territories in the third quarter of 1993 resulted in a decrease in natural gas
customers. A reduction in revenues collected through the PGAs also contributed
to the decrease in retail revenues. The effect of rate increases partially
offset the decrease in revenues due to reduced sales volumes and PGA revenues.

-4-
<PAGE>

UTILITY OPERATING EXPENSES

Changes in the cost of electric fuel, energy and capacity (collectively,
Energy Costs) reflect fluctuations in generation levels and mix, fuel cost, and
energy and capacity purchases. Energy Costs for 1995 increased 8% compared to
1994 due primarily to a 13% increase in total electric sales. The increase in
Energy Costs as a result of greater sales of electricity was partially offset by
a 5% decrease in the average Energy Cost per unit. Energy Costs for 1994
decreased 2% compared to 1993 due primarily to the reduction in sales for
resale. The decrease due to reduced sales of electricity was partially offset
by a 7% increase in the average Energy Cost per unit. Part of the fluctuation
in the average Energy Cost per unit was due to the changes in the availability
of nuclear generation throughout the three-year period.

Cost of gas sold for 1995 decreased compared to 1994 due to a 15% decrease
in the average cost of gas per unit sold. Cost of gas sold decreased in 1994
compared to 1993 due primarily to a 9% decrease in sales which was due in part
to a gas property exchange.

Other operating expenses increased $45.5 million in 1995 compared to 1994
due primarily to costs related to the restructuring plan discussed in the
opening section of Results of Operations. Utility operating expenses include
$31.9 million of the $33.4 million total restructuring costs. As discussed
above, 1995 expenses also include increases from deferred energy efficiency and
OPEB costs. The increases for 1995 were partially offset by an $8.6 million
reduction in nuclear operations costs. Expenses for 1994 were reduced by $3.0
million due to capitalizing previously expensed energy efficiency costs to
comply with the IUB regulation of these costs.

Other operating expenses in 1994 increased $13.5 million compared to 1993.
Increased nuclear operations costs related to extended outages at Cooper and
Quad-Cities Station during 1994 contributed to the increase. The increase in
nuclear costs was partially offset by the adjustment to energy efficiency costs
mentioned above.

Maintenance expenses decreased $15.9 million in 1995 compared to 1994.
Quad-Cities Station maintenance expenses decreased $5.5 million due in part to
the 1994 outage. The timing of power plant maintenance and a reduction in
various distribution maintenance accounted for much of the remaining variation
between years.

Depreciation expense increased compared to each prior year due primarily to
additions to utility plant in service.

NONREGULATED OPERATING REVENUES

Revenues for the Company's nonregulated subsidiaries decreased $7.8 million
for 1995 compared to 1994. A decrease in real estate revenues and reduced
revenues due to the impact of the sale of a telecommunications subsidiary in
early 1995 accounted for most of the decrease. Revenues from the Company's oil
and gas production subsidiary were basically unchanged with increases in gas
production volumes and oil prices offsetting decreases due to lower prices for
natural gas. A 16% decrease in sales volumes for a nonregulated retail natural
gas marketing subsidiary resulted in a $13.9 million decrease in nonregulated
gas revenues for 1995. This decrease was offset by $14.2 million in revenues of
a wholesale natural gas marketing firm acquired in December 1995.

Revenues for 1994 increased $36.3 million compared to 1993 due primarily to
a $33.4 million increase in revenues from retail sales of natural gas. The
increase in retail natural gas sales and revenues for 1994 is attributable
primarily to the purchase of the assets of an existing nonregulated natural gas
business in January 1994. Higher production volumes reflecting additional
acquired reserves and successful drilling results also contributed to the
increase in revenues for 1995.

-5-

<PAGE>

NONREGULATED OPERATING EXPENSES

Cost of sales includes expenses directly related to sales of oil, natural
gas and real estate. The factors discussed above for revenues, including
natural gas sales volumes, lower gas prices and reduced real estate sales, also
affected the variances in cost of sales for the years 1993 through 1995. Cost
of sales for the newly acquired natural gas firm also contributed to the
increase in 1995 compared to 1994.

Other nonregulated expenses increased $3.0 million for 1995 compared to
1994. The 1995 amount includes $1.5 million of expenses for the Company's
restructuring plan. The $5.7 million increase in 1994 compared to 1993 was due
primarily to expenses of the natural gas marketing business acquired in January
1994.

REALIZED GAINS AND LOSSES ON SECURITIES, NET

Realized gains and losses on securities decreased $6.9 million for 1995
compared to 1994. The decrease resulted primarily from the sale of a single
holding in 1994 which generated a $5.9 million pre-tax gain. During 1993,
InterCoast realized significant gains on some of its investments in marketable
securities due to the impact of favorable market conditions.

NON-OPERATING INCOME - OTHER, NET

The adjustments to nonregulated investments discussed at the beginning of
Results of Operations were the primary cause of the decrease in Other, Net, for
1995 compared to 1994. In addition, merger transaction costs reduced Other, Net
in 1995 and 1994. A gain on the sale of an investment in a leveraged lease in
1994 also contributed to the comparative decrease for 1995 compared to 1994.
Gains totalling $8.5 million on the sales of a partnership interest in a gas
marketing organization and a telecommunication subsidiary in 1995 partially
offset the decreases. The decrease from 1993 to 1994 is due primarily to an
$18.5 million pre-tax gain on the exchange of natural gas service territories in
1993.

INTEREST CHARGES

Increased interest on long-term debt in 1995 compared to 1994 was due
primarily to the issuance of $60 million of 7.875% Series of mortgage bonds in
November 1994. The decrease in interest on long-term debt from 1993 to 1994
reflects refinancing of several series of long-term debt at lower interest rates
in 1993.

DISCONTINUED OPERATIONS

In 1994, the Company announced its intent to divest its construction
subsidiaries and recognized the anticipated loss on disposal. The sale of
certain assets of one of the subsidiaries was completed in December 1994, and
the sale of the other construction subsidiary was completed in March 1995.
Settlement of a construction receivable in the second quarter of 1995 resulted
in $0.4 million of income in 1995.

PREFERRED DIVIDENDS

The decrease in the preferred dividend requirement for 1995 compared to
1994 was due mostly to the redemption of three series of outstanding preferred
shares in December 1994.

-6-
<PAGE>

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, debt retirement, dividends, construction expenditures
and other capital requirements.

For 1995, the Company had net cash provided from operating activities of
$382 million and net cash used of $320 million and $54 million for investing and
financing activities, respectively.

INVESTING ACTIVITIES

Utility construction expenditures, including allowance for funds used
during construction (AFUDC), Quad-Cities Station nuclear fuel purchases and
Cooper capital improvements, were $191 million for 1995. The decrease from the
1994 total of $212 million reflects the Company's efforts to limit construction
expenditures.

Forecasted utility construction expenditures for 1996 are $166 million
including AFUDC. The 1996 plan includes $35 million for Cooper capital
improvements and Quad-Cities Station nuclear fuel purchases and construction
expenditures. For the years 1996 through 2000, the Company forecasts $818
million for utility construction expenditures, $154 million of which is for
nuclear expenditures. The Company presently expects that all utility
construction expenditures for 1996 through 2000 will be met with cash generated
from utility operations, net of dividends.

In general, decommissioning of a nuclear facility means to safely remove
the facility from service and restore the property to a condition allowing
unrestricted use. During 1995, the Utility contributed approximately $9 million
to an external trust established for the investment of funds for decommissioning
the Quad-Cities Station. Based on information presently available, the Utility
expects to contribute $45 million to the trust during the period 1996 through
2000. The funds are invested predominately in investment grade municipal, and
U.S. Treasury, bonds. In addition, approximately $9 million of the 1995
payments made under the power purchase contract with NPPD were for
decommissioning funding related to Cooper. The Cooper costs are reflected in
Other Operating Expenses in the Consolidated Statements of Income. Based on
NPPD estimates, the Utility expects to pay approximately $54 million for Cooper
decommissioning during the period 1996 through 2000. NPPD invests the funds in
instruments similar to those of the Quad-Cities Station trust fund. The
Company's obligation for Cooper decommissioning may be affected by the actual
plant shutdown date and the status of the power purchase contract at that time.
The Company currently recovers Quad-Cities Station decommissioning costs charged
to Illinois customers through a rate rider on customer billings. Cooper and
Quad-Cities Station decommissioning costs charged to Iowa customers are included
in base rates, and increases in those amounts must be sought through the normal
ratemaking process. Refer to Note 4(d) of Notes to Consolidated Financial
Statements (Notes) for additional details regarding decommissioning.

Capital expenditures of nonregulated subsidiaries were $56 million for
1995. Capital expenditures of nonregulated subsidiaries depend upon the
availability of suitable investment opportunities and other factors. For 1996,
such expenditures are forecasted to be approximately $85 million, primarily
related to InterCoast.

InterCoast invests in a variety of marketable securities which it holds for
indefinite periods of time. For 1995, InterCoast had net cash outflows of $67
million from its marketable securities investment activities. In the
Consolidated Statements of Cash Flows, the lines Purchase of Securities and
Proceeds from Sale of Securities consist primarily of the gross amounts of these
activities, including realized gains and losses on investments in marketable
securities.

-7-
<PAGE>

FINANCING ACTIVITIES

The Utility currently has authority from the FERC to issue short-term debt
in the form of commercial paper and bank notes aggregating $400 million. As of
December 31, 1995, the Utility had bank lines of credit of $250 million to
provide short-term financing for utility operations. In January 1996, the
Utility entered into a $250 million revolving credit facility agreement to
replace those lines of credit. The Utility's commercial paper borrowings, which
totalled $185 million at December 31, 1995, are currently supported by the
revolving credit facility. The Utility also has lines of credit and revolving
credit facilities which are dedicated to provide liquidity for its obligations
under outstanding pollution control revenue bonds that are periodically
remarketed.

In January 1995, $12.75 million of floating rate pollution control
refunding revenue bonds due 2025 were issued. Proceeds from this financing were
used to redeem $12.75 million of collateralized pollution control revenue bonds,
5.8% Series, due 2007.

The Utility has $347 million of long-term debt maturities and sinking fund
requirements for 1996 through 2000, $1 million of which matures in 1996.

The Utility is currently considering several long-term financing options
for 1996. Proceeds from those issuances would be used to reduce commercial
paper outstanding and to refinance higher cost securities.

As of December 31, 1995, the Utility had the capability to issue
approximately $1.3 billion of mortgage bonds under the current Midwest
indenture. The Utility does not expect to issue additional debt under the Iowa-
Illinois indenture, but may if necessary.

During the first six months of 1995, Resources and Iowa-Illinois sold
original issue shares of common stock through certain of their employee stock
purchase and dividend reinvestment plans. On a MidAmerican share basis,
1,065,240 shares of common stock were issued. The Company has the necessary
authority to issue up to 6,000,000 shares of common stock through its
Shareholder Options Plan (the Company's dividend reinvestment and stock
purchase plan). Since the effective date of the merger, the Company has used
open market purchases of its common stock rather than original issue shares to
meet share obligations under its Employee Stock Purchase Plan and the
Shareholder Options Plan. The Company currently plans to continue using open
market purchases to meet share obligations under these plans.

Subsequent to the consummation of the merger, the Utility made a $55
million equity contribution to InterCoast. In addition, nonregulated businesses
not related to regional business development were transferred from Midwest
Capital to InterCoast. The equity contribution was then used to extinguish
Senior Notes and variable interest rate Notes Payable, thus eliminating several
financial relationships between the Company's utility and nonregulated
operations.

One support agreement remains between the Utility and Midwest Capital
related to a performance guarantee by Midwest Capital of a joint venture turnkey
engineering, procurement and construction contract for a cogeneration project.
The project received preliminary acceptance from the owner in 1995, which
pursuant to the construction contract, eliminates the potential for liquidated
damages being incurred related to the project. Midwest Capital also has $25
million of long-term debt outstanding at December 31, 1995, that matures in 1996
and is supported by a guarantee from the Utility. In addition, Midwest Capital
has a $25 million line of credit with the Utility.

During the third quarter of 1995, InterCoast entered into a $64 million
unsecured revolving credit facility agreement which matures in 1998. The
facility was used primarily to refinance maturing Senior Notes. InterCoast also
has a $110 million unsecured revolving credit facility agreement which matures
in 1999.

-8-

<PAGE>

Borrowings under these agreements may be at a fixed rate, floating rate or
competitive bid rate basis. All borrowings under these agreements are
without recourse to the Utility. At December 31, 1995, InterCoast had $130
million of debt outstanding under these two revolving credit facility
agreements.

In addition, InterCoast has entered into two floating rate to fixed
interest rate swaps each in the amount of $32 million. The interest rate swaps
have fixed rates of 5.97% and 6.00%, respectively, and are for three-year and
two-year terms, respectively, with an optional third year on the latter.

InterCoast's aggregate amounts of maturities and sinking fund requirements
for long-term debt outstanding at December 31, 1995, are $39 million for 1996
and $287 million for the years 1996 through 2000. Amounts due in 1996 are
expected to be refinanced with debt instruments.

On January 24, 1996, the Company's Board of Directors declared a quarterly
dividend on common shares of $0.30 per share payable March 1, 1996. The
dividend represents an annual rate of $1.20 per share.

OPERATING ACTIVITIES

The Utility is subject to regulation by several utility regulatory
agencies. The operating environment and the recoverability of costs from
utility customers are significantly influenced by the regulation of those
agencies. The Company anticipates that changes in the utility industry will
create a more competitive environment. Although these anticipated changes may
create opportunities, they will also create additional challenges and risks for
utilities. The Company is evaluating strategies that will assist it in a more
competitive environment.

A possible consequence of competition in the utility industry is the
discontinued applicability of Statement of Financial Accounting Standards (SFAS)
No. 71. SFAS 71 sets forth accounting principles for all, or a portion, of a
company's operations that are regulated and meet certain criteria. For
operations that meet the criteria, SFAS 71 allows, among other things, the
deferral of costs that would otherwise be expensed when incurred. The Company's
electric and gas utility operations are currently subject to the provisions of
SFAS 71. Should the utility industry become more competitive as presently
anticipated, the Company will reexamine the applicability of SFAS 71. If a
portion of the Company's utility operations no longer meets the criteria of SFAS
71, the Company could be required to eliminate from its balance sheet assets and
liabilities related to those operations that resulted from actions of its
regulators (i.e., regulatory assets and liabilities). A material adjustment to
earnings in the appropriate period could result from the discontinuance of SFAS
71. Refer to Note (1)(c) of Notes for a discussion of regulatory assets.

The Energy Policy Act (EPAct) was enacted in 1992. This law promotes
competition in the wholesale electric power market. The FERC has taken action
to establish rules and policies in compliance with provisions of the EPAct
through a Notice of Proposed Rulemaking issued March 29, 1995. The Company has
been active in providing filed, written comments with the FERC in an effort to
shape new transmission policies in ways that will best serve the interests of
its customers and shareholders. In conjunction with the Merger, the Company
submitted an open access transmission tariff in 1994 which was accepted for
filing by the FERC in June 1995.

Legislation enacted by the State of Illinois in 1995 allows public
utilities to file for regulatory approval of nontraditional rate design.
Alternative forms of rate design may include price caps, flexible rate
structures and other modifications of the cost-based method currently used to
determine rates for electric and gas services. The Company is evaluating its
options in light of the new legislation. If appropriate, the Company may file a
request in 1996 for alternate rate design in Illinois.

In 1992, the FERC issued Order No. 636, directing a restructuring by
interstate pipeline companies for their natural gas sales and transportation
services. The unbundling of pipeline services increased the Company's access

-9-
<PAGE>

to supply options and its supply responsibilities. Certain transition costs
incurred by interstate natural gas pipelines for their compliance with Order
636 will be paid to the pipeline companies over the next several years. The
Company's Consolidated Balance Sheet as of December 31, 1995, includes a $41
million noncurrent liability and regulatory asset recorded for transition
costs. The Company may incur other transition costs in conjunction with
future purchases of gas, but does not expect these billings to have a
material impact on the cost of gas. The Company is currently recovering
costs related to Order 636 from its customers.

Electric and gas utilities in Iowa are required to spend approximately 2%
and 1.5%, respectively, of their annual Iowa jurisdictional revenues on energy
efficiency activities. In October 1994 and in January 1995, the Company began
collecting over a four-year prospective period $19.7 million and $18.7 million,
respectively, related to prior energy efficiency cost recovery filings. A
recent district court ruling was issued which affirmed in all respects the IUB
decisions allowing such recovery. In another cost recovery filing, the IUB
issued an order approving the collection over a four-year prospective period of
$18.6 million. Collection related to this filing began August 8, 1995. As of
December 31, 1995, the Company had approximately $68 million of energy
efficiency costs deferred on its Consolidated Balance Sheet for which recovery
will be sought in future energy efficiency filings.

The United States Environmental Protection Agency (EPA) and state
environmental agencies have determined that contaminated wastes remaining at
certain decommissioned manufactured gas plant facilities may pose a threat to
the public health or the environment if such contaminants are in sufficient
quantities and at such concentrations as to warrant remedial action.

The Company is evaluating 26 properties which were, at one time, sites of
gas manufacturing plants in which it may be a potentially responsible party
(PRP). The purpose of these evaluations is to determine whether waste materials
are present, whether such materials constitute an environmental or health risk,
and whether the Company has any responsibility for remedial action. The
Company's present estimate of probable remediation costs for these sites is $21
million. This estimate has been recorded as a liability and a regulatory asset
for future recovery through the regulatory process. Refer to Note (4)(b) of
Notes for further discussion of the Company's environmental activities related
to manufactured gas plant sites and cost recovery.

Although the timing of potential incurred costs and recovery of such cost
in rates may affect the results of operations in individual periods, management
believes that the outcome of these issues will not have a material adverse
effect on the Company's financial position or results of operations.

The Clean Air Act Amendments of 1990 (CAA) were signed into law in November
1990. The Company has five jointly owned and five wholly owned coal-fired
generating stations, which represent approximately 65% of the Company's electric
generating capability.

Two of the Company's coal-fired generating units were subject to the
requirements of the CAA beginning in 1995. These units were given a set number
of allowances by the EPA. Each allowance permits the units to emit one ton of
sulfur dioxide. The Company has completed most of the modifications necessary
to one unit to burn low-sulfur coal and to install nitrogen oxides controls and
an emissions monitoring system. Under proposed regulations, the second unit
will require additional capital expenditures to reduce emissions of nitrogen
oxides.

The Company's other coal-fired generating units are not materially affected
by the provisions of the CAA. Due to the use of low-sulfur western coal, the
Company does not anticipate the need for additional capital expenditures to
lower sulfur dioxide emission rates to ensure that allowances allocated by the
federal government are not exceeded. While the Company estimates that
sufficient emission allowances have been allocated on a system-wide basis for
its units to operate at the capacity factors needed to meet system energy

-10-
<PAGE>

requirements, additional purchases of allowances may be necessary to meet
desired sales for resale levels. By the year 2000, some Company coal-fired
generating units will be required to install controls to reduce emissions of
nitrogen oxides. Essentially all utility generating units are subject to CAA
provisions which address continuous emission monitoring, permit requirements and
fees, and emission of toxic substances. Based on currently proposed CAA
regulations, the Company does not anticipate its remaining construction costs
for the installation of low nitrogen oxides burner technology and emissions
monitoring system upgrades to exceed $16 million.

ACCOUNTING ISSUES

In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS
No. 121 regarding accounting for asset impairments. This statement, which will
be adopted by the Company in the first quarter of 1996, requires the Company to
review long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of such assets may not be
recoverable. SFAS 121 also requires rate-regulated companies to recognize an
impairment for regulatory assets that are not probable of future recovery.
Adoption of SFAS 121 is not expected to have a material impact on the Company's
results of operations or financial position at the time of adoption.

The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry, including
those of the Company, regarding the recognition, measurement and classification
of nuclear decommissioning costs in the financial statements. In response to
these questions, the FASB has added a project to its agenda to review the
accounting for closure and removal costs, including decommissioning of nuclear
power plants. If current electric utility industry accounting practices for
such decommissioning are changed, the annual provision for decommissioning could
increase relative to 1995, and the total estimated cost for decommissioning
could be recorded as a liability with recognition of an increase in the cost of
related nuclear power plant. The Company has not determined what impact, if
any, it would have on the Company's operation and financial position.

In October 1995, the FASB issued SFAS No. 123 regarding stock-based
compensation plans. SFAS 123, which is effective for reporting periods
beginning January 1, 1996, allows for alternative methods of adoption. The
Company does not expect the accounting provisions or alternative disclosure
provisions of SFAS 123 to have a material impact on the Company's results of
operations.

-11-

<PAGE>

MIDAMERICAN ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
------------------------------------
1995 1994 1993
---------- ---------- ----------
(In thousands, except per share amounts)
<S> <C> <C> <C>
OPERATING REVENUES
Electric utility $1,094,647 $1,021,660 $1,002,970
Gas utility 459,588 492,015 538,989
Nonregulated 169,409 177,235 140,976
---------- ---------- ----------
1,723,644 1,690,910 1,682,935
---------- ---------- ----------
OPERATING EXPENSES
Utility:
Cost of fuel, energy and capacity 230,261 213,987 217,385
Cost of gas sold 279,025 326,782 366,049
Other operating expenses 399,648 354,190 340,720
Maintenance 85,363 101,275 101,601
Depreciation and amortization 158,950 154,229 150,822
Property and other taxes 96,350 94,990 93,238
---------- ---------- ----------
1,249,597 1,245,453 1,269,815
---------- ---------- ----------
Nonregulated:
Cost of sales 128,685 130,621 96,656
Other 44,230 41,230 35,568
---------- ---------- ----------
172,915 171,851 132,224
---------- ---------- ----------
1,422,512 1,417,304 1,402,039
---------- ---------- ----------

OPERATING INCOME 301,132 273,606 280,896
---------- ---------- ----------

NON-OPERATING INCOME
Interest income 4,485 4,334 5,805
Dividend income 16,954 17,087 17,601
Realized gains and losses on securities, net 688 7,635 7,915
Other, net (10,467) 4,316 20,842
---------- ---------- ----------
11,660 33,372 52,163
---------- ---------- ----------
INTEREST CHARGES
Interest on long-term debt 110,505 105,753 111,065
Other interest expense 9,449 6,446 5,066
Allowance for borrowed funds (5,552) (3,955) (2,186)
---------- ---------- ----------
114,402 108,244 113,945
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES 198,390 198,734 219,114
INCOME TAXES 67,984 62,349 71,409
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS 130,406 136,385 147,705

INCOME (LOSS) FROM DISCONTINUED OPERATIONS 417 (5,645) (3,854)
---------- ---------- ----------
NET INCOME 130,823 130,740 143,851
PREFERRED DIVIDENDS 8,059 10,551 8,367
---------- ---------- ----------
EARNINGS ON COMMON STOCK $ 122,764 $ 120,189 $ 135,484
---------- ---------- ----------
---------- ---------- ----------
AVERAGE COMMON SHARES OUTSTANDING 100,401 98,531 97,762
---------- ---------- ----------
---------- ---------- ----------
EARNINGS PER COMMON SHARE
Continuing operations $ 1.22 $ 1.28 $ 1.43
Discontinued operations - (0.06) (0.04)
---------- ---------- ----------
Earnings per average common share $ 1.22 $ 1.22 $ 1.39
---------- ---------- ----------
---------- ---------- ----------

</TABLE>

The accompanying notes are an integral part of these statements.

- 12 -

<PAGE>

MIDAMERICAN ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
AS OF DECEMBER 31
------------------------------
1995 1994
---------- ----------
(In thousands)
<S> <C> <C>
ASSETS
UTILITY PLANT
Electric $3,881,699 $3,765,004
Gas 695,741 663,792
---------- ----------
4,577,440 4,428,796
Less accumulated depreciation and
amortization 2,027,055 1,885,870
---------- ----------
2,550,385 2,542,926
Construction work in progress 104,164 101,252
---------- ----------
2,654,549 2,644,178
---------- ----------

POWER PURCHASE CONTRACT 212,148 221,998
---------- ----------

INVESTMENT IN DISCONTINUED OPERATIONS - 15,249
---------- ----------

CURRENT ASSETS
Cash and cash equivalents 41,216 33,778
Receivables, less reserves of $2,296 and
$2,099, respectively 261,105 212,902
Inventories 85,235 92,248
Other 22,252 19,035
---------- ----------
409,808 357,963
---------- ----------

INVESTMENTS 826,496 752,428
---------- ----------

OTHER ASSETS 420,520 423,958
---------- ----------

TOTAL ASSETS $4,523,521 $4,415,774
---------- ----------
---------- ----------

CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see accompanying statement)

Common shareholders' equity $1,225,715 $1,204,112
Preferred shares, not subject to
mandatory redemption 89,945 89,955
Preferred shares, subject to
mandatory redemption 50,000 50,000
Long-term debt (excluding current portion) 1,403,322 1,398,255
---------- ----------
2,768,982 2,742,322
---------- ----------

CURRENT LIABILITIES
Notes payable 184,800 124,500
Current portion of long-term debt 65,295 72,872
Current portion of power purchase contract 13,029 12,080
Accounts payable 142,759 110,175
Taxes accrued 81,898 91,653
Interest accrued 30,635 30,659
Other 57,000 54,473
---------- ----------
575,416 496,412
---------- ----------

OTHER LIABILITES
Power purchase contract 112,700 125,729
Deferred income taxes 746,574 725,665
Investment tax credit 95,041 100,871
Other 224,808 224,775
---------- ----------
1,179,123 1,177,040
---------- ----------
TOTAL CAPITALIZATION AND LIABILITIES $4,523,521 $4,415,774
---------- ----------
---------- ----------

</TABLE>

The accompanying notes are an integral part of these statements.

- 13 -
<PAGE>

MIDAMERICAN ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
------------------------------
1995 1994 1993
-------- -------- -------
(In thousands)
<S> <C> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 130,823 $ 130,740 $ 143,851
Adjustments to reconcile net income to net
cash provided:
Depreciation, depletion and amortization 202,542 198,049 193,199
Net increase in deferred income taxes and
investment tax credit, net 10,278 36,926 1,935
Amortization of other assets 20,047 9,731 5,447
Capitalized cost of real estate sold 1,744 3,723 5,737
Loss (income) from discontinued operations (417) 5,645 3,854
Gain on sale of assets and long-term investments (1,050) (6,409) (25,428)
Other-than-temporary decline in value of
investments and other assets 17,971 1,791 2,939
Impact of changes in working capital, net of
effects from discontinued operations (19,075) (9,270) 20,066
Other 18,809 10,624 (7,746)
-------- -------- -------
Net cash provided 381,672 381,550 343,854
-------- -------- -------

NET CASH FLOWS FROM INVESTING ACTIVITIES
Utility construction expenditures (190,771) (211,669) (215,081)
Quad-Cities Nuclear Power Station
decommissioning trust fund (8,636) (9,044) (7,918)
Deferred energy efficiency expenditures (35,841) (28,221) (24,104)
Nonregulated capital expenditures (56,162) (52,609) (86,505)
Purchase of securities (164,521) (113,757) (197,490)
Proceeds from sale of securities 94,493 142,307 205,767
Proceeds from sale of assets and other
investments 34,263 6,433 55,582
Other investing activities, net 7,060 (7,957) 13,716
-------- -------- -------
Net cash used (320,115) (274,517) (256,033)
-------- -------- -------

NET CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid (126,892) (125,065) (122,410)
Issuance of long-term debt, net of issuance cost 12,750 180,410 796,897
Retirement of long-term debt, including
reacquisition cost (110,351) (102,472) (895,900)
Issuance of preferred shares, net of
issuance cost - - 68,140
Reacquisition of preferred shares, including
reacquisition cost (9) (20,142) (32,629)
Increase (decrease) in InterCoast Energy Company
unsecured revolving credit facility 95,000 (9,500) 44,500
Issuance of common shares 15,083 27,760 -
Net increase (decrease) in notes payable 60,300 (48,535) 52,791
-------- -------- -------
Net cash used (54,119) (97,544) (88,611)
-------- -------- -------

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 7,438 9,489 (790)
CASH AND CASH EQUIVALENTS AT BEGINNING
OF PERIOD 33,778 24,289 25,079
-------- -------- -------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 41,216 $ 33,778 $ 24,289
-------- -------- -------
-------- -------- -------

ADDITIONAL CASH FLOW INFORMATION:
Interest paid, net of amounts capitalized $ 116,843 $ 105,004 $ 111,133
-------- -------- -------
-------- -------- -------
Income taxes paid $ 88,863 $ 38,195 $ 54,346
-------- -------- -------
-------- -------- -------

</TABLE>

The accompanying notes are an integral part of these statements.

-14-
<PAGE>

MIDAMERICAN ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

AS OF DECEMBER 31
--------------------------------
1995 1994
------------ ------------
(In thousands,
except share amounts)
<S> <C> <C>
COMMON SHAREHOLDERS' EQUITY
Common shares, no par; 350,000,000 shares authorized;
100,751,713 and 99,686,636 shares outstanding, respectively $ 801,227 $ 786,420
Retained earnings 430,589 426,683
Valuation allowance, net of income taxes (6,101) (8,991)
------------ ------------
1,225,715 44.3% 1,204,112 43.9%
------------ ---- ------------ -----
PREFERRED SHARES (100,000,000 shares authorized)
Cumulative preferred shares outstanding; not subject to
mandatory redemption:
$3.30 Series, 49,523 and 49,622 shares, respectively 4,952 4,962
$3.75 Series, 38,320 shares 3,832 3,832
$3.90 Series, 32,630 shares 3,263 3,263
$4.20 Series, 47,369 shares 4,737 4,737
$4.35 Series, 49,950 shares 4,995 4,995
$4.40 Series, 50,000 shares 5,000 5,000
$4.80 Series, 49,898 shares 4,990 4,990
$1.7375 Series, 2,400,000 shares 58,176 58,176
Cumulative preferred shares outstanding; subject to
mandatory redemption:
$5.25 Series, 100,000 shares 10,000 10,000
$7.80 Series, 400,000 shares 40,000 40,000
------------ ------------
139,945 5.0% 139,955 5.1%
------------ ---- ------------ -----
LONG-TERM DEBT
Mortgage bonds:
5.875% Series, due 1997 22,000 22,000
Adjustable Rate Series, due 1997 (8.8% and 7.6%, respectively) 25,000 25,000
5.05% Series, due 1998 50,000 50,000
6.25% Series, due 1998 75,000 75,000
7 .875% Series, due 1999 60,000 60,000
6% Series, due 2000 35,000 35,000
6.75% Series, due 2000 75,000 75,000
8.15% Series, due 2001 40,000 40,000
7.125% Series, due 2003 100,000 100,000
7.70% Series, due 2004 60,000 60,000
7% Series, due 2005 100,000 100,000
7.375% Series, due 2008 75,000 75,000
8% Series, due 2022 50,000 50,000
7.45% Series, due 2023 30,000 30,000
8.125% Series, due 2023 100,000 100,000
6.95% Series, due 2025 50,000 50,000
Pollution control revenue obligations:
5.15% to 5.75% Series, due periodically through 2003 10,984 11,544
5.8% Series, due 2007 (secured by first mortgage bonds) - 12,750
5.95% Series, due 2023 (secured by general mortgage bonds) 29,030 29,030
Variable Rate Series-
Due 2016 and 2017 (5.0% and 5.7%, respectively) 37,600 37,600
Due 2023 (secured by general
mortgage bonds, 5.05% and 5.55%, respectively) 28,295 28,295
Due 2023 (5.1% and 5.6%, respectively) 6,850 6,850
Due 2024 (5.25% and 5.1%, respectively) 34,900 34,900
Due 2025 (5.1%) 12,750 -

</TABLE>

The accompanying notes are an integral part of these statements.

-15-
<PAGE>

MIDAMERICAN ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

AS OF DECEMBER 31
--------------------------------
1995 1994
------------- -----------
(In thousands)
<S> <C> <C>
LONG-TERM DEBT (CONTINUED)
Notes:
9% to 15% Series, due annually through 1996 $ - $ 22
8.75% Series, due 2002 240 240
6.4% Series, due 2003 through 2007 2,000 2,000
Obligation under capital lease 2,218 2,356
Unamortized debt premium and discount, net (4,126) (4,706)
---------- ----------
Total utility 1,107,741 1,107,881
---------- ----------
Subsidiaries:
Notes -
9.30% Series, due 1995 and 1996 - 9,000
8.7% Series, due annually through 1996 - 25,508
Adjustable Rate Series, due semiannually through 1996 - 13,100
10.20% Series, due 1996 and 1997 30,000 60,000
9.87% Series, due annually through 1997 - 11,664
7.34% Series, due 1998 20,000 20,000
7.76% Series, due 1999 45,000 45,000
8.52% Series, due 2000 through 2002 70,000 70,000
9% Series, due annually through 2000 - 489
8% Series, due annually through 2004 581 613
Borrowings under unsecured revolving credit facility (6.3%) 64,000 -
Borrowings under unsecured revolving credit facility
(6.4% and 6.6%, respectively) 66,000 35,000
---------- ----------
Total Subsidiaries 295,581 290,374
---------- ----------
1,403,322 50.7% 1,398,255 51.0%
---------- ----- ---------- ------
TOTAL CAPITALIZATION $2,768,982 100.0% $2,742,322 100.0%
---------- ----- ---------- ------
---------- ----- ---------- ------

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

YEARS ENDED DECEMBER 31
----------------------------------------
1995 1994 1993
-------- -------- --------
(In thousands, except per share amounts)
<S> <C> <C> <C>
BEGINNING OF YEAR $426,683 $421,358 $400,621
-------- -------- --------
NET INCOME 130,823 130,740 143,851
-------- -------- --------
DEDUCT (ADD):
(Gain) loss on reacquisition of preferred shares (5) 312 672
Dividends declared on preferred shares 8,064 10,141 8,350
Dividends declared on common shares of $1.18, $1.17 and
$1.17 per share, respectively 118,828 114,924 114,060
Other 30 38 32
-------- -------- --------
126,917 125,415 123,114
-------- -------- --------

END OF YEAR $430,589 $426,683 $421,358
-------- -------- --------
-------- -------- --------

</TABLE>

The accompanying notes are an integral part of these statements.

-16-

<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

(a) MERGER:

On July 1, 1995, Iowa-Illinois Gas and Electric Company (Iowa-Illinois),
Midwest Resources Inc. (Resources) and Midwest Power Systems Inc. (Midwest)
merged to form MidAmerican Energy Company (MidAmerican or Company). The
merger was accounted for as a pooling-of-interests and the financial
statements included herein are presented as if the companies were merged as
of the earliest period shown. MidAmerican is a utility company with two
wholly owned nonregulated subsidiaries: InterCoast Energy Company
(InterCoast) and Midwest Capital Group, Inc. (Midwest Capital).

Each outstanding share of preferred and preference stock of the predecessor
companies was converted into one share of a similarly designated series of
MidAmerican preferred stock, no par value. Each outstanding share of common
stock of Resources and Iowa-Illinois was converted into one share and 1.47
shares, respectively, of MidAmerican common stock, no par value.

Resources' operating revenues and net income for the six months prior to
the merger were $534.2 million and $37.7 million, respectively.
Iowa-Illinois' operating revenues, as reclassified to include nonregulated
revenues in operating revenues consistent with MidAmerican's presentation,
and net income for the six months prior to the merger were $298.9 million and
$27.1 million, respectively.

(b) CONSOLIDATION POLICY AND PREPARATION OF FINANCIAL STATEMENTS:

The accompanying Consolidated Financial Statements include the Company and
its wholly owned nonregulated subsidiaries, InterCoast and Midwest Capital. All
significant intercompany transactions have been eliminated.

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results
may differ from those estimates.

The Company's utility operations are subject to the regulation of the Iowa
Utilities Board (IUB), the Illinois Commerce Commission (ICC), the South Dakota
Public Utilities Commission, and the Federal Energy Regulatory Commission
(FERC). The Company's accounting policies and the accompanying Consolidated
Financial Statements conform to generally accepted accounting principles
applicable to rate-regulated enterprises and reflect the effects of the
ratemaking process.

-17-

<PAGE>

The Company's utility operations are subject to the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation. The following regulatory assets, primarily
included in Other Assets in the Consolidated Balance Sheets, represent probable
future revenue to the Company because these costs are expected to be recovered
in charges to utility customers (in thousands):

<TABLE>
<CAPTION>
1995 1994
<S> <C> <C>
Deferred income taxes. . . . . . . . . $144,257 $139,577
Energy efficiency costs. . . . . . . . 101,541 72,694
Debt refinancing costs . . . . . . . . 44,370 47,879
FERC Order 636 transition costs. . . . 40,824 56,608
Retirement benefit costs . . . . . . . 15,354 18,287
Environmental costs. . . . . . . . . . 23,076 23,535
Unamortized costs of retired plant . . 11,618 10,824
Enrichment facilities decommissioning. 8,970 9,807
Other . . . . . . . . . . . . . . . 7,396 10,479
-------- --------
Total . . . . . . . . . . . . . . $397,406 $389,690
-------- --------
-------- --------
</TABLE>

(d) REVENUE RECOGNITION:

Revenues are recorded as services are rendered to customers. The Company
records unbilled revenues, and related energy costs, representing the estimated
amount customers will be billed for services rendered between the meter-reading
dates in a particular month and the end of such month. Accrued unbilled
revenues are $61.0 million and $65.6 million at December 31, 1995 and 1994,
respectively, and are included in Receivables on the Consolidated Balance
Sheets.

The majority of the utility's electric and gas sales are subject to
adjustment clauses. These clauses allow the utility to adjust the amounts
charged for electric and gas service as the costs of gas, fuel for generation or
purchased power change. The costs recovered in revenues through use of the
adjustment clauses are charged to expense in the same period.

(e) DEPRECIATION AND AMORTIZATION:

The Company's provisions for depreciation and amortization for its utility
operations are based on straight-line composite rates. The average depreciation
and amortization rates for the years ended December 31 were as follows:

1995 1994 1993

Electric . . . . . . . . . . . . . . . . 3.9% 3.8% 3.8%
Gas . . . . . . . . . . . . . . . . 3.7% 3.6% 3.9%

Utility plant is stated at original cost which includes overhead costs,
administrative costs and an allowance for funds used during construction.

The cost of repairs and minor replacements is charged to maintenance
expense. Property additions and major property replacements are charged to
plant accounts. The cost of depreciable units of utility plant retired or
disposed of in the normal course of business is eliminated from the utility
plant accounts and such cost, plus net removal cost, is charged to accumulated
depreciation.

-18-

<PAGE>

An allowance for the estimated annual decommissioning costs of the
Quad-Cities Nuclear Power Station (Quad-Cities) equal to the level of funding is
included in depreciation expense. See Note 4(d) for additional information
regarding decommissioning costs.

(f) INVESTMENTS:

Investments, managed primarily through the Company's nonregulated
subsidiaries, include the following amounts as of December 31 (in thousands):

<TABLE>
<CAPTION>
1995 1994
<S> <C> <C>
Investments:
Marketable securities . . . . . . . $270,162 $199,514
Oil and gas properties. . . . . . . 160,831 142,378
Equipment Leases. . . . . . . . . . 90,729 123,603
Nuclear decommissioning trust fund. 64,781 49,432
Energy projects . . . . . . . . . . 44,741 51,150
Special-purpose funds . . . . . . . 47,046 34,767
Real estate . . . . . . . . . . . . 65,232 72,721
Corporate owned life insurance. . . 22,743 18,832
Non-public preferred stock. . . . . 14,372 24,451
Coal transportation equipment . . . 10,216 11,616
Communications. . . . . . . . . . . 16,332 4,793
Other . . . . . . . . . . . . . . . 19,311 19,171
-------- --------
Total investments. . . . . . . . . . . $826,496 $752,428
-------- --------
-------- --------
</TABLE>

Marketable securities generally consist of preferred stocks, common stocks
and mutual funds held by InterCoast.

On January 1, 1994, the Company adopted SFAS No. 115, Accounting for Certain
Investments in Debt and Equity Securities. Under this statement, investments in
marketable securities classified as available-for-sale are reported at fair
value with net unrealized gains and losses reported as a net of tax amount in
Other Common Shareholders' Equity until realized.

Investments in marketable securities that are classified as held-to-maturity
are reported at amortized cost. An other-than-temporary decline in the value of
a marketable security is recognized through a write-down of the investment to
earnings.

Investments held by the nuclear decommissioning trust fund for the Quad-
Cities units are classified as available-for-sale and are reported at fair value
with net unrealized gains and losses reported as adjustments to the accumulated
provision for nuclear decommissioning.

(g) OIL AND GAS:

The Company uses the full cost method of accounting for oil and gas
activities. Under the full cost method, all acquisition, exploration and
development costs are capitalized and amortized over the estimated production
from proved oil and gas reserves. Under the full cost method, net capitalized
costs may not exceed the present value of proved reserves as determined under
rules of the Securities and Exchange Commission.

-19-

<PAGE>

(h) CONSOLIDATED STATEMENTS OF CASH FLOWS:

The Company considers all cash and highly liquid debt instruments purchased
with a remaining maturity of three months or less to be cash and cash
equivalents for purposes of the Consolidated Statements of Cash Flows.

Net cash provided (used) from changes in working capital, net of effects from
discontinued operations and exchange of assets was as follows (in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Receivables . . . . . . . . . . $(48,203) $13,152 $ 149
Inventories. . . . . . . . . . . 7,013 8,427 (2,067)
Other current assets . . . . . . (3,217) 5,876 605
Accounts payable . . . . . . . . 32,584 (19,329) 13,741
Interest accrued . . . . . . . . (24) (362) (374)
Taxes accrued. . . . . . . . . . (9,755) (19,270) 9,338
Other current liabilities. . . . 2,527 2,236 (1,326)
-------- -------- -------
Total . . . . . . . . . . . . $(19,075) $ (9,270) $20,066
-------- -------- -------
-------- -------- -------
</TABLE>

During 1993, the Company exchanged its Minnesota gas properties, with a book
value of $52 million, for gas distribution properties in South Dakota, with an
appraised fair value of $32 million, and $38 million cash. A pre-tax gain on
the transaction of $18 million was recorded.

(i) ACCOUNTING FOR LONG-TERM POWER PURCHASE CONTRACT:

Under a long-term power purchase contract with Nebraska Public Power District
(NPPD), expiring in 2004, the Company purchases one-half of the output of the
778-megawatt Cooper Nuclear Station (Cooper). The Consolidated Balance Sheets
include a liability for the Company's fixed obligation to pay 50% of NPPD's
Nuclear Facility Revenue Bonds and other fixed liabilities. A like amount
representing the Company's right to purchase power is shown as an asset.

-20-

<PAGE>

Capital improvement costs for new property, including carrying costs, are
being deferred, amortized and recovered in rates over the term of the NPPD
contract. Capital improvement costs for property replacements, including
carrying costs, are being deferred, amortized and recovered in rates over a
five-year period.

The fuel cost portion of the power purchase contract is included in Cost of
Fuel, Energy and Capacity on the Consolidated Statements of Income. All other
costs the Company incurs in relation to its long-term power purchase contract
with NPPD are included in Other Operating Expenses on the Consolidated
Statements of Income.

See Notes 4(c), 4(d) and 4(e) for additional information regarding the power
purchase contract.

(j) STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 121:

In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS
No. 121 regarding accounting for asset impairments. This statement, which will
be adopted by the Company in the first quarter of 1996, requires the Company to
review long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. SFAS No. 121 also requires rate-regulated companies to recognize
an impairment for regulatory assets for which future recovery is not probable.
Adoption of SFAS No. 121 is not expected to have a material impact on the
Company's results of operations or financial position at the time of adoption.

(k) STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 123:

In October 1995, the FASB issued SFAS No. 123 regarding accounting for stock-
based compensation plans. This statement, which is effective for reporting
periods beginning January 1, 1996, allows for alternative methods of adoption.
The Company does not expect the accounting provisions or the alternative
disclosure provisions of SFAS No. 123 to have a material impact on the Company's
results of operations.

(2) LONG-TERM DEBT:

The Company's sinking fund requirements and maturities of long-term debt and
preferred stock for 1996 through 2000 are $65 million, $80 million, $209
million, $171 million and $134 million, respectively.

The interest rate on the Company's Adjustable Rate Series Mortgage Bonds is
reset every two years at 160 basis points over the average yield to maturity of
10-year Treasury securities. The rate was reset in 1995.

The Company's Variable Rate Pollution Control Revenue Obligations bear
interest at rates that are periodically established through remarketing of the
bonds in the short-term tax-exempt market. The Company, at its option, may
change the mode of interest calculation for these bonds by selecting from among
several alternative floating or fixed rate modes. The interest rates shown in
the Consolidated Statements of Capitalization are the weighted average interest
rates as of December 31, 1995 and 1994. The Company maintains dedicated
revolving credit facility agreements or renewable lines of credit to provide
liquidity for holders of these issues.

Substantially all the former Iowa-Illinois utility property and franchises,
and substantially all of the former Midwest electric utility property in Iowa,
is pledged to secure mortgage bonds.

InterCoast's unsecured Notes are issued in private placement transactions.
All Notes are issued without recourse to MidAmerican.

InterCoast has $64 million and $110 million unsecured revolving credit
facility agreements, which mature in 1998

-21-

<PAGE>

and 1999, respectively. Borrowings under these agreements may be on a fixed
rate, floating rate or competitive bid rate basis. InterCoast has entered
into two floating rate to fixed interest rate swaps, each in the amount of
$32 million. The interest rate swaps have fixed rates at 5.97% and 6.00%,
respectively, and are for three-year and two-year terms, respectively, with
an optional third year on the latter. All InterCoast borrowings are without
recourse to MidAmerican.

(3) JOINTLY OWNED UTILITY PLANT:

Under joint plant ownership agreements with other utilities, the Company had
undivided interests at December 31, 1995, in jointly owned generating plants as
shown in the table below.

The dollar amounts below represent the Company's share in each jointly owned
unit. Each participant has provided financing for its share of each unit.
Operating Expenses on the Consolidated Statements of Income include the
Company's share of the expenses of these units (dollars in millions).

<TABLE>
<CAPTION>
Nuclear Coal fired
------------ -------------------------------------------------
Council
Quad-Cities Neal Bluffs Neal Ottumwa Louisa
Units Unit Unit Unit Unit Unit
No. 1 & 2 No. 3 No. 3 No.4 No. 1 No. 1
---------- ------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
In service date 1972 1975 1978 1979 1981 1983
Utility plant in service $200.4 $111.7 $286.5 $155.8 $202.2 $526.0
Accumulated depreciation $ 70.6 $ 64.8 $138.8 $ 78.9 $ 89.3 $204.3
Unit capacity-MW 1,539 515 675 624 716 700
Percent ownership 25.0% 72.0% 79.1% 40.6% 52.0% 88.0%

</TABLE>

(4) COMMITMENTS AND CONTINGENCIES:

(a) CAPITAL EXPENDITURES:

Utility construction expenditures for 1996 are estimated to be $166 million,
including $17 million for Quad-Cities nuclear fuel and $9 million for Cooper
capital improvements. Capital expenditures for nonregulated subsidiaries depend
upon the availability of investment opportunities and other factors. During
1996, such expenditures are estimated to be approximately $85 million.

(b) ENVIRONMENTAL MATTERS:

The United States Environmental Protection Agency (EPA) and the state
environmental agencies have determined that contaminated wastes remaining at
certain decommissioned manufactured gas plant (MGP) facilities may pose a threat
to the public health or the environment if such contaminants are in sufficient
quantities and at such concentrations as to warrant remedial action.

The Company is evaluating 26 properties which were, at one time, sites of gas
manufacturing plants in which it may be a potentially responsible party (PRP).
The purpose of these evaluations is to determine whether waste materials are
present, whether such materials constitute an environmental or health risk, and
whether the Company has any responsibility for remedial action. The Company is
currently conducting field investigations at five sites and has completed
investigations at three sites. In addition, the Company is currently removing
contaminated soil at three sites, and has completed removals at two sites. The
Company is continuing to evaluate several sites to determine the future
liability, if any, for conducting site investigations or other site activity.

-22-

<PAGE>

The Company's present estimate of probable remediation costs for the sites
discussed above is $21 million. This estimate has been recorded as a liability
and a regulatory asset for future recovery. The Illinois Commerce Commission
has approved the use of a tariff rider which permits recovery of the actual
costs of litigation, investigation and remediation relating to former MGP sites.
The Company's present rates in Iowa provide for a fixed annual recovery of MGP
costs. The Company intends to pursue recovery of the remediation costs from
other PRPs and its insurance carriers.

The estimate of probable remediation costs is established on a site specific
basis. The costs are accumulated in a three-step process. First, a
determination is made as to whether the Company has potential legal liability
for the site and whether information exists to indicate that contaminated wastes
remain at the site. If so, the costs of performing a preliminary investigation
are accrued. Once the investigation is completed and if it is determined
remedial action is required, the best estimate of remediation costs is accrued.
If necessary, the estimate is revised when a consent order is issued.

The estimated recorded liabilities for these properties are based upon
preliminary data. Thus, actual costs could vary significantly from the
estimates. The estimate could change materially based on facts and
circumstances derived from site investigations, changes in required remedial
action and changes in technology relating to remedial alternatives. In
addition, insurance recoveries for some or all of the costs may be possible, but
the liabilities recorded have not been reduced by any estimate of such
recoveries.

Although the timing of potential incurred costs and recovery of such costs in
rates may affect the results of operations in individual periods, management
believes that the outcome of these issues will not have a material adverse
effect on the Company's financial position or results of operations.

Payments to NPPD cover one-half of the fixed and operating costs of Cooper
(excluding depreciation but including debt service) and the Company's share of
nuclear fuel cost (including nuclear fuel disposal) based on energy delivered.
The debt service portion is approximately $1.5 million per month for 1996 and is
not contingent upon the plant being in service. In addition, the Company pays
one-half of NPPD's decommissioning funding related to Cooper.

The debt amortization and Department of Energy (DOE) enrichment plant
decontamination and decommissioning component of the Company's payments to NPPD
were $12.0 million, $10.8 million and $9.9 million and the net interest
component was $4.6 million, $5.4 million and $5.7 million each for the years
1995, 1994 and 1993, respectively.

The Company's payments for the debt principal portion of the power purchase
contract obligation and the DOE enrichment plant decontamination and
decommissioning payments are $13.0 million, $13.6 million, $14.3 million, $15.0
million and $15.8 million for 1996 through 2000, respectively, and $54.0
million for 2001 through 2004.

(d) DECOMMISSIONING COSTS:

Based on site-specific decommissioning studies that include decontamination,
dismantling, site restoration and dry fuel storage cost, the Company's share of
expected decommissioning costs for Cooper and Quad-Cities, in 1995 dollars, is
$420 million. In Illinois, nuclear decommissioning costs are included in
customer billings through a mechanism that permits annual adjustments. Such
costs are reflected as base rates in Iowa tariffs.

For purposes of developing a decommissioning funding plan for Cooper, NPPD
assumes that decommissioning costs will escalate at an annual rate of 4%.
Although Cooper's operating license expires in 2014, the funding plan assumes
decommissioning will start in 2004, the currently anticipated plant shutdown
date.

-23-

<PAGE>

As of December 31, 1995, the Company's share of funds set aside by NPPD in
internal and external accounts for decommissioning was $49.4 million. In
addition, the funding plan also assumes various funds and reserves currently
held to satisfy NPPD Bond Resolution requirements will be available for plant
decommissioning costs after the bonds are retired in early 2004. The funding
schedule assumes a long-term return on funds in the trust of 6% annually.
Certain funds will be required to be invested on a short-term basis when
decommissioning begins and are assumed to earn at a rate of 4% annually. NPPD
is recognizing decommissioning costs over the expected service life of the
plant, and 50% of the costs are included as a component of the Company's power
purchased costs. During each of the years 1995, 1994 and 1993, $8.9 million of
the Company's power purchased costs were for Cooper decommissioning and are
included in Other Operating Expenses in the Consolidated Statements of Income.
Earnings from the internal and external trust funds, which are recognized by
NPPD as the owner of the plant, are tax exempt and serve to reduce future
funding requirements.

The Company has established an external trust for the investment of funds for
decommissioning the Quad-Cities units. The total accrued balance as of December
31, 1995, was $64.8 million and is included in Other Liabilities and a like
amount is reflected in Investments and represents the value of the assets held
in the trust.

The Company's provision for depreciation includes costs for Quad-Cities
nuclear decommissioning of $8.6 million, $9.1 million and $7.9 million for
1995, 1994 and 1993, respectively. The provision charged to expense is equal to
the funding that is being collected in rates. The decommissioning funding
component of the Company's Illinois tariffs assumes that decommissioning costs,
related to the Quad-Cities unit, will escalate at an annual rate of 5.3% and the
assumed annual return on funds in the trust is 6.5%. The Quad-Cities
decommissioning funding component of the Company's Iowa tariffs assumes that
decommissioning costs will escalate at an annual rate of 6.3% and the assumed
annual return on funds in the trust is 6.5%. Earnings on the assets in the
trust fund were $2.5 million, $2.2 million and $2.0 million for 1995, 1994 and
1993.

(e) NUCLEAR INSURANCE:

The Company maintains financial protection against catastrophic loss
associated with its interest in Quad-Cites and Cooper through a combination of
insurance purchased by NPPD (the owner and operator of Cooper) and Commonwealth
Edison (the joint owner and operator of Quad-Cities), insurance purchased
directly by the Company, and the mandatory industry-wide loss funding mechanism
afforded under the Price-Anderson Amendments Act of 1988. The coverage falls
into three categories: nuclear liability, property coverage and nuclear worker
liability.

NPPD and Commonwealth Edison each purchase nuclear liability insurance in the
maximum available amount of $200 million. In accordance with the Price-Anderson
Amendments Act of 1988, excess liability protection above that amount is
provided by a mandatory industry-wide program under which the owners 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, the Company's maximum potential share of such an assessment is $79.2
million per incident, payable in installments not to exceed $10 million
annually.

The property coverage provides for property damage, stabilization and
decontamination of the facility, disposal of the decontaminated material and
premature decommissioning. For Quad-Cities, Commonwealth Edison purchases
primary and excess property insurance protection for the combined interest in
Quad-Cities totalling $2.1 billion. For Cooper, NPPD purchases primary property
insurance in the amount of $500 million. Additionally, commencing December 31,
1995, the Company and NPPD separately purchase coverage for their respective
obligation of $1.125 billion each in excess of the $500 million primary layer
purchased by NPPD. This structure provides that both the Company and NPPD are
covered for their respective 50% obligation in the event of a loss totalling
$2.75 billion. The Company also directly purchases extra expense/business
interruption coverage to cover the cost of replacement power and/or other
continuing costs in the event of a covered accidental outage at Cooper or Quad-
Cities. The coverages purchased directly by the

-24-

<PAGE>

Company, and the primary and excess property coverages purchased by
Commonwealth Edison, 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 the Company for its obligations associated with Cooper and
Quad-Cities combined total $19.4 million.

The master nuclear worker liability coverage is an industry-wide policy with
an aggregate limit of $200 million for the nuclear industry as a whole, which is
in effect to cover tort claims of workers as a result of radiation exposure on
or after January 1, 1988. The Company's share, based on its interest in Cooper
and Quad-Cities, of a maximum potential share of a retrospective assessment
under this program is $3.0 million.

(f) FINANCIAL GUARANTEES:

The Company has letters of credit amounting to $20.4 million and financial
guarantees amounting to $11.3 million which are not reflected in the
consolidated financial statements. Letters of credit and financial guarantees
are conditional commitments issued by, or on behalf of, the Company to secure
performance for a third party. The guarantees are primarily issued to support
private borrowing arrangements and similar transactions.

Management believes that the likelihood of material cash payments by the
Company under these agreements is remote.

(g) COAL AND NATURAL GAS CONTRACT COMMITMENTS:

The Company has entered into coal supply and transportation contracts for its
fossil-fueled generating stations. The contracts, require minimum payments of
$65 million, $45 million, $28 million, $26 million and $16 million for the years
1996 through 2000, respectively, and $28 million for the years thereafter. The
Company expects to supplement these coal contracts with spot market purchases to
fulfill its future fossil fuel needs.

The Company has entered into various natural gas supply and transportation
contracts for its utility operations. The minimum commitments under these
contracts are $98 million, $87 million, $49 million, $26 million and $23 million
for the years 1996 through 2000, respectively, and $96 million for the years
thereafter. During 1993 FERC Order 636 became effective, requiring interstate
pipelines to restructure their services. The pipelines will recover the
transition costs related to Order 636 from the local distribution companies.
The Company has recorded a liability and regulatory asset for the transition
costs which are being recovered by the Company through the purchased gas
adjustment clause. The unrecovered balance recorded by the Company as of
December 31, 1995, was $41 million.

-25-
<PAGE>

(5) COMMON SHAREHOLDERS' EQUITY:

Common shares outstanding changed during the years ended December 31 as shown
in the table below (in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
Amount Shares Amount Shares Amount Shares
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>

Balance, beginning of year . . . $786,420 99,687 $759,120 97,782 $759,610 97,778
Changes due to:
Issuance of common shares. . 15,083 1,065 27,760 1,911 - -
Capital stock expense . . . (276) - (377) - (442) -
Other. . . . . . . . . . . . - - (83) (6) (48) 4
-------- -------- -------- -------- -------- --------
Balance, end of year . . . . . . $801,227 100,752 $786,420 99,687 $759,120 97,782
-------- -------- -------- -------- -------- --------
-------- -------- -------- -------- -------- --------
</TABLE>

(6) RETIREMENT PLANS:

The Company has noncontributory defined benefit pension plans covering
substantially all employees. Benefits under the plans are based on participants'
compensation, years of service and age at retirement.

Funding is based upon the actuarially determined costs of the plans and the
requirements of the Internal Revenue Code and the Employee Retirement Income
Security Act. The utility has been allowed to recover funding contributions in
rates.

Net periodic pension cost includes the following components for the years
ended December 31 (in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Service cost-benefit earned during
the period. . . . . . . . . . . . . $ 9,817 $ 13,241 $ 11,140
Interest cost on projected benefit
obligation. . . . . . . . . . . . . 27,934 26,822 25,431
Decrease in pension costs from actual
return on assets. . . . . . . . . . (63,593) (7,835) (22,149)
Net amortization and deferral. . . . . . . . 32,126 (21,030) (6,075)
One-time charge. . . . . . . . . . . . . . . 15,683 - -
Regulatory deferral of incurred cost . . . . (10,470) (2,871) (2,018)
------- ------- -------
Net periodic pension cost. . . . . . . . . . $ 11,497 $ 8,327 $ 6,329
------- ------- -------
------- ------- -------
</TABLE>

During 1995, the Company incurred a one-time charge of $15.7 million
related to the early retirement portion of its restructuring plan. Of such
cost, $3.0 million was charged to expense and the remaining amount was
deferred for future recovery through the regulatory process.

-26-

<PAGE>

The plan assets are stated at fair market value and are primarily comprised
of insurance contracts, United States government debt and corporate equity
securities. The following table presents the plans' funding status and
amounts recognized in the Company's Consolidated Balance Sheets as of
December 31 (dollars in thousands):

Plans in Which:
-----------------------------------------------------------
Assets Exceed Accumulated Benefits
Accumulated Benefits Exceed Assets
---------------------------- ----------------------------
1995 1994 1995 1994
----------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
Actuarial present value of benefit obligations:
Vested benefit obligation . . . . . . . . . . . $(293,985) $(224,488) $ (32,429) $(18,915)
Nonvested benefit obligation . . . . . . . . . . (7,516) (5,881) (816) (1,744)
----------- ------------ ------------ ------------
Accumulated benefit obligation . . . . . . . . . (301,501) (230,369) (33,245) (20,659)
Provision for future pay increases . . . . . . . (94,633) (66,414) (5,455) (2,357)
----------- ------------ ------------ ------------
Projected benefit obligation . . . . . . . . . . (396,134) (296,783) (38,700) (23,016)
Plan assets at fair value. . . . . . . . . . . . . 385,598 335,809 - -
----------- ------------ ------------ ------------
Projected benefit obligation (greater) less
than plan assets . . . . . . . . . . . . . . . . (10,536) 39,026 (38,700) (23,016)
Unrecognized prior service cost. . . . . . . . . . (15,866) 22,520 2,884 6,896
Unrecognized net loss (gain) . . . . . . . . . . . 29,541 (40,151) 9,431 2,603
Unrecognized net transition asset. . . . . . . . . (21,521) (24,112) - -
Other . . . . . . . . . . . . . . . . . . . . . . - - (6,860) (7,142)
----------- ------------ ------------ ------------
Pension liability recognized in the
Consolidated Balance Sheets . . . . . . . . . . $ (18,382) $ (2,717) $ (33,245) $(20,659)
----------- ------------ ------------ ------------
----------- ------------ ------------ ------------

Assumptions used were:

Discount rate . . . . . . . . . . . . . . . . . . 7.0% 8.5%
Rate of increase in compensation levels. . . . . . 5.0% 5.0%
Expected long-term rate of return on assets. . . . 8.75-9.0% 8.75-9.0%

</TABLE>

The Company currently provides certain health care and life insurance
benefits for retired employees. Under the plans, substantially all of the
Company's employees may become eligible for these benefits if they reach
retirement age while working for the Company. However, the Company retains
the right to change these benefits anytime at its discretion.

In January 1993, the Company adopted SFAS No. 106, Employers Accounting for
Postretirement Benefits Other Than Pensions. The Company began expensing
these costs on an accrual basis for its Illinois customers and certain of its
Iowa customers in 1993 and including provisions for such costs in rates for
these customers. For its remaining Iowa customers, the Company deferred the
portion of these costs above the "pay-as-you-go" amount already included in
rates until recovery on an accrual basis was established in 1995. The
Company is currently amortizing the deferral, expensing the SFAS No. 106
accrual and including provisions for these costs in rates.

-27-

<PAGE>

Net periodic postretirement benefit cost includes the following
components for the year ended December 31 (dollars in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Service cost-benefit earned during the period. . . $ 1,583 $ 2,147 $ 2,252
Interest cost . . . . . . . . . . . . . . . . . 7,185 7,221 8,644
Increase (decrease) in benefit cost from
actual return on assets . . . . . . . . . . . . . (2,090) 894 (468)
Amortization of unrecognized transition
obligation . . . . . . . . . . . . . . . . . . . 5,291 5,442 5,449
Other . . . . . . . . . . . . . . . . . . . . (262) (1,991) 293
One-time charge for early retirement . . . . . . . 4,353 - -
Regulatory recognition of incurred cost. . . . . . 5,140 (6,218) (9,126)
------- ------- -------
Net periodic postretirement benefit cost . . . . . $21,200 $ 7,495 $ 7,044
------- ------- -------
------- ------- -------

</TABLE>

During 1995, the Company recorded a one-time expense of $4.4 million related
to the early retirement portion of its restructuring plan.

The Company has established external trust funds to meet its expected
postretirement benefit obligations. The trust funds are comprised primarily of
guaranteed rate investment accounts and money market investment accounts. A
reconciliation of the funded status of the plan to the amounts realized as of
December 31 is presented below (dollars in thousands):

<TABLE>
<CAPTION>
1995 1994
<S> <C> <C>
Accumulated present value of benefit obligations:
Retiree benefit obligation . . . . . . . . . . . . $(67,488) $(55,233)
Active employees fully eligible for benefits . . . (5,904) (6,127)
Other active employees . . . . . . . . . . . . . . (33,949) (26,939)
-------- -------
Accumulated benefit obligation . . . . . . . . . . (107,341) (88,299)
Plan assets at fair value. . . . . . . . . . . . . 26,916 18,200
-------- -------
Accumulated benefit obligation greater than
plan assets . . . . . . . . . . . . . . . . . . . (80,425) (70,099)
Unrecognized net gain. . . . . . . . . . . . . . . (13,880) (25,894)
Unrecognized transition obligation . . . . . . . . 89,952 95,993
-------- -------
Postretirement benefit liability recognized in the
Consolidated Balance Sheets. . . . . . . . . . . $ (4,353) $ -
-------- -------
-------- -------

Assumptions used were:
Discount rate . . . . . . . . . . . . . . . . . 7.0% 8.5%
Expected long-term rate of return on assets
(after taxes):
Midwest Resources union plan . . . . . . . . . . 9.0% 9.0%
Midwest Resources salaried plan. . . . . . . . . 4.6% 4.6%
Iowa-Illinois plans. . . . . . . . . . . . . . . 3.0% 3.0%

</TABLE>

For purposes of calculating the postretirement benefit obligation, it is
assumed that health care costs for covered individuals prior to age 65 will
increase by 11% in 1996, and that the rate of increase thereafter will decline
by 1% annually to an ultimate rate of 5% by the year 2002. For covered
individuals age 65 and older, it is assumed that health care costs will increase
by 9% in 1996, and that the rate of increase thereafter will decline by 1%
annually to an ultimate rate of 5% by the year 2000.

-28-
<PAGE>

If the assumed health care trend rates used to measure the expected cost of
benefits covered by the plans were increased by 1%, the total service and
interest cost would increase by $0.9 million and the accumulated postretirement
benefit obligation would increase by $7.6 million.

The Company sponsors defined contribution pension plans (401(k) plans)
covering substantially all employees. The Company's contributions to the plans,
which are based on the participants level of contribution and cannot exceed four
percent of the participants salaries or wages, were $3.7 million, $3.6 million
and $3.6 million for 1995, 1994 and 1993, respectively.

(7) SHORT-TERM BORROWING:

Interim financing of working capital needs and the construction program may
be obtained from the sale of commercial paper or short-term borrowing from
banks. Information regarding short-term debt follows (dollars in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Balance at year-end . . . . . . . . . . . $184,800 $124,500 $173,035
Weighted average interest rate
on year-end balance. . . . . . . . . . . . 5.7% 6.1% 3.4%
Average daily amount outstanding
during the year. . . . . . . . . . . . . . $114,036 $105,728 $117,445
Weighted average interest rate
on average daily amount
outstanding during the year. . . . . . . . 6.0% 4.4% 3.3%
</TABLE>

At December 31, 1995, the Company had bank lines of credit of $250
million to provide short-term financing for its utility operations. As of
December 31, 1995, the Company has regulatory authority to borrow up to $400
million of short-term debt for its utility operations. In January 1996, the
Company entered into a $250 million revolving credit facility agreement to
replace the lines of credit. The Company's commercial paper borrowings are
currently supported by the revolving credit facility.

(8) RATE MATTERS:

The table below shows the Company's recent material general rate activities
(dollars in thousands):

<TABLE>
<S> <C> <C>
Filing entity. . . . . . . . . . . . . . Midwest Midwest
State of filing. . . . . . . . . . . . . Iowa Iowa
Service . . . . . . . . . . . . . . . . Gas Electric
Interim revenue increase:
Amount . . . . . . . . . . . . . . . $ 8,200 $15,600
Percent. . . . . . . . . . . . . . . 3.2% 2.7%
Date collection began. . . . . . . . October 18, 1994 January 1, 1995
Final revenue increase:
Amount . . . . . . . . . . . . . . . $10,600 $20,300
Percent. . . . . . . . . . . . . . . 4.1% 3.4%
Date collection began. . . . . . . . August 1, 1995 August 11, 1995
</TABLE>

-29-
<PAGE>

The table below summarizes the results of the Company's recent
material energy efficiency cost recovery filing activities (dollars in
thousands):

<TABLE>

<S> <C> <C> <C>
Filing entity . . . . . . . . . . Midwest Midwest Iowa-Illinois
State of filing. . . . . . . . . . Iowa Iowa Iowa
Final revenue increase granted*. . $19,700 $18,700 $18,600
Deferred charges to be amortized*. $14,100 $13,400 $13,800
Date collection began. . . . . . . October 12, 1994 January 21, 1995 August 3, 1995

</TABLE>

* Recovery and amortization over a four-year period

(9) DISCONTINUED OPERATIONS:

The Company reflected as discontinued operations at September 30,
1994, all activities of a subsidiary that constructed generating facilities and
a subsidiary that constructed electric distribution and transmission systems.
Essentially all of the assets of these subsidiaries have been sold.

Midwest Capital, under the terms of certain sale agreements, has
indemnified the purchasers of the construction subsidiaries for specified
losses or claims relating to construction projects which occurred prior to
the date of their sale. In addition, Midwest Capital has guaranteed
performance on a joint venture turnkey engineering, procurement and
construction contract for a cogeneration project. The Company has provided a
support agreement to Midwest Capital related to this project. In October
1995, the project received preliminary acceptance from the owner. Management
believes that the likelihood of a material adverse impact to the Company
under any indemnity provision of the sale agreements or construction
contracts or material cash payments by the Company under the support
agreements is remote.

Net assets of the construction subsidiaries are separately presented
on the Consolidated Balance Sheets as Investment in Discontinued Operations.
Proceeds received from the disposition of the construction investments through
December 31, 1995, were $4.1 million. Revenues from discontinued activities,
as well as the results of operations and the estimated income (loss) on the
disposal of discontinued operations for the years ended December 31 are as
follows (in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Operating Revenues . . . . . . . . . $ 7,334 $ 69,958 $ 94,350
-------- -------- ---------
-------- -------- ---------
Income (loss) from discontinued
operations before
income taxes . . . . . . . . $ 880 $ (2,788) $ (7,033)
Income tax benefit (expense) . . . . (463) 908 3,179
-------- -------- ---------
Total. . . . . . . . . . . . $ (417) $ (1,880) $ (3,854)
-------- -------- ---------
-------- -------- ---------

Loss on disposal before
income taxes . . . . . . . . $ - $(11,576) $ -
Income tax benefit . . . . . . . . . - 7,811 -
-------- ------- ---------
Total. . . . . . . . . . . . $ - $ (3,765) $ -
-------- -------- ---------
-------- -------- ---------
</TABLE>
-30-

<PAGE>

(10) CONCENTRATION OF CREDIT RISK:

The Company's electric utility operations serve 549,000 customers in
Iowa, 83,000 customers in western Illinois and 3,000 customers in southeastern
South Dakota. The Company's gas utility operations serve 471,000 customers in
Iowa, 65,000 customers in western Illinois, 60,000 customers in southeastern
South Dakota and 4,000 customers in northeastern Nebraska. The largest
communities served by the Company are the Iowa and Illinois Quad-Cities; Des
Moines, Sioux City, Cedar Rapids, Waterloo, Iowa City and Council Bluffs, Iowa;
and Sioux Falls, South Dakota. The Company's utility operations grant unsecured
credit to customers, substantially all of whom are local businesses and
residents. As of December 31, 1995, billed receivables from the Company's
utility customers totalled $126 million.

The Company has investments in preferred stocks of companies in the
utility industry. As of December 31, 1995, the total cost of these investments
was $163 million.

InterCoast has entered into leveraged lease agreements with companies
in the airline industry. As of December 31, 1995, the receivables under these
agreements totalled $38 million.

(11) PREFERRED SHARES:

On December 15, 1994, the Company redeemed all of its outstanding
$4.36 Series, $4.22 Series and $7.50 Series preferred shares. The redemption
was made at a premium, which resulted in a charge to net income on common shares
of $312,000.

The $5.25 Series Preferred Shares, which are not redeemable prior to
November 1, 1998 for any purpose, are subject to mandatory redemption on
November 1, 2003 at $100 per share. The $7.80 Series Preferred Shares, which
are not redeemable prior to May 1, 1996 for any purpose, have sinking fund
requirements under which 66,600 shares will be redeemed at $100 per share each
May 1, beginning in 2001 through May 1, 2006.

The total outstanding cumulative preferred stock that is not subject
to mandatory redemption requirements may be redeemed at the option of the
Company at prices which, in the aggregate, total $95.1 million. The aggregate
total the holders of all preferred stock outstanding at December 31, 1995, are
entitled to upon involuntary bankruptcy is $141.8 million plus accrued
dividends. Annual dividend requirements for preferred stock outstanding at
December 31, 1995, total $9.1 million.

-31-
<PAGE>

(12) SEGMENT INFORMATION:

Information related to segments of the Company's business is as
follows for the years ended December 31 (in thousands):

1995 1994 1993
<S> <C> <C> <C>
UTILITY
Electric-
Operating revenues . . . . . . . . . . $ 1,094,647 $1,021,660 $1,002,970
Cost of fuel, energy and capacity. . . 230,261 213,987 217,385
Depreciation and amortization expense. 136,324 132,886 129,814
Other operating expenses . . . . . . . 459,344 438,811 424,589
----------- --------- ---------
Operating income . . . . . . . . . . . $ 268,718 $ 235,976 $ 231,182
----------- --------- ---------
----------- --------- ---------

Gas-
Operating revenues . . . . . . . . . $ 459,588 $ 492,015 $ 538,989
Cost of gas sold . . . . . . . . . . . 279,025 326,782 366,049
Depreciation and amortization expense. 22,626 21,343 21,008
Other operating expenses . . . . . . . 122,017 111,644 110,970
----------- --------- ---------
Operating income . . . . . . . . . . . $ 35,920 $ 32,246 $ 40,962
----------- --------- ---------
----------- --------- ---------
Operating income . . . . . . . . . . . . $ 304,638 $ 268,222 $ 272,144
Other income (expense) . . . . . . . . . (4,074) (3,712) 21,185
Interest charges . . . . . . . . . . . . 83,977 76,606 83,524
----------- --------- ---------
Income from continuing operations
before income taxes . . . . . . . . . . 216,587 187,904 209,805
Income taxes . . . . . . . . . . . . . . 84,098 66,759 75,917
----------- --------- ---------
Income from continuing operations. . . . $ 132,489 $ 121,145 $ 133,888
----------- --------- ---------
----------- --------- ---------

Capital Expenditures-
Electric . . . . . . . . . . . . . . . $ 133,490 $ 164,870 $ 178,903
Gas. . . . . . . . . . . . . . . . . . 57,281 46,799 36,178

NONREGULATED
Revenues . . . . . . . . . . . . . . . . $ 169,409 $ 177,235 $ 140,976
Cost of sales. . . . . . . . . . . . . . 128,685 130,621 96,656
Depreciation, depletion
and amortization . . . . . . . . . . . 26,573 24,884 18,771
Other operating expenses . . . . . . . . 17,657 16,346 16,797
----------- --------- ---------
Operating income (loss). . . . . . . . . (3,506) 5,384 8,752
Other income . . . . . . . . . . . . . . 15,734 37,084 30,978
Interest charges . . . . . . . . . . . . 30,425 31,638 30,421
Income (loss) from continuing operations
before income taxes. . . . . . . . . . (18,197) 10,830 9,309
Income taxes . . . . . . . . . . . . . . (16,114) (4,410) (4,508)
----------- --------- ---------
Income (loss) from continuing
operations . . . . . . . . . . . . . . $ (2,083) $ 15,240 $ 13,817
----------- --------- ---------
----------- --------- ---------

Capital expenditures . . . . . . . . . . $ 56,162 $ 52,609 $ 86,505

-32-

</TABLE>

<PAGE>

1995 1994 1993
<S> <C> <C> <C>
ASSET INFORMATION
Identifiable assets-
Electric (a) . . . . . . . . . . . . . $2,947,832 $2,915,749 $2,891,487
Gas (a). . . . . . . . . . . . . . . . 709,742 693,203 662,634
Used in overall utility
operations . . . . . . . . . . . . . 46,644 71,399 67,622
Nonregulated . . . . . . . . . . . . . . 819,303 735,423 749,518
---------- ---------- ----------
Total assets . . . . . . . . . . . . . . $4,523,521 $4,415,774 $4,371,261
---------- ---------- ----------
---------- ---------- ----------

</TABLE>

(a) Utility plant less accumulated provision for depreciation, accounts
receivable, accrued unbilled revenues, inventories, deferred gas
expense, energy adjustment clause balance, nuclear decommissioning
trust fund and regulatory assets.

(13) FAIR VALUE OF FINANCIAL INSTRUMENTS:

The following methods and assumptions were used to estimate the fair
value of each class of financial instruments Tariffs for the Company's
utility services are established based on historical cost ratemaking.
Therefore, the impact of any realized gains or losses related to financial
instruments applicable to the Company's utility operations is dependent on
the treatment authorized under future ratemaking proceedings.

Cash and cash equivalents - The carrying amount approximates fair value
due to the short maturity of these instruments.

Quad-Cities nuclear decommissioning trust fund - Fair value is based on
quoted market prices of the investments held by the fund.

Marketable securities - Fair value is based on quoted market prices.

Debt securities - Fair value is based on the discounted value of the
future cash flows expected to be received from such investments.

Equity investments carried at cost - Fair value is based on an estimate
of the Company's share of partnership equity, offers from unrelated third
parties or the discounted value of the future cash flows expected to be
received from such investments.

Notes payable - Fair value is estimated to be the carrying amount due
to the short maturity of these issues.

Preferred shares - Fair value of preferred shares with mandatory
redemption provisions is estimated based on the quoted market prices for
similar issues.

-33-

<PAGE>

Long-term debt - Fair value of long-term debt is estimated based on
the quoted market prices for the same or similar issues or on the current rates
offered to the Company for debt of the same remaining maturities. The following
table presents the carrying amount and estimated fair value of certain financial
instruments as of December 31 (in thousands):

1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- --------- --------- --------
<S> <C> <C> <C> <C>
Financial Instruments Owned by the Company:
Equity investments carried at
costs . . . . . . . . . . . . . . . $ 58,972 $ 61,316 $ 22,352 $ 23,930

Financial Instruments Issued by the Company:
Preferred shares; subject to mandatory
redemption . . . . . . . . . . . . $ 50,000 $ 52,800 $ 50,000 $ 50,836
Long-term debt, including current
portion . . . . . . . . . . . . . . $1,468,617 $1,528,504 $1,471,127 $1,391,372

</TABLE>

The amortized cost, gross unrealized gain and losses and estimated fair
value of investments in debt and equity securities at December 31, 1995 and
1994, are summarized as follows (in thousands):

1995
Amortized Unrealized Unrealized Fair
Cost Gains Losses Value
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Available-for-sale:
Equity securities $254,111 $ 7,132 $ (9,278) $251,965
Municipal Bonds 38,098 3,228 (210) 41,116
Cash equivalents 8,092 - - 8,092
Other debt securities 42,734 355 (6,507) 36,582
-------- -------- -------- --------
$343,035 $ 10,715 $(15,995) $337,755
-------- -------- -------- --------
-------- -------- -------- --------

Held-to-maturity:
Equity securities $ 11,389 $ - $ (786) $ 10,603
Debt securities 19,440 31 (921) 18,550
-------- -------- -------- --------
$ 30,829 $ 31 $ (1,707) $ 29,153
-------- -------- -------- --------
-------- -------- -------- --------

</TABLE>

-34-

<PAGE>

<TABLE>
<CAPTION>
1994
Amortized Unrealized Unrealized Fair
Cost Gains Losses Value
--------- -------- --------- ---------

<S> <C> <C> <C> <C>
Available-for-sale:
Equity securities $171,201 $2,388 $(14,703) $158,886
Municipal bonds 43,034 749 (1,773) 42,010
Cash equivalents 5,836 - - 5,836
Other debt securities 4,102 - - 4,102
--------- -------- --------- ---------
$224,173 $3,137 $(16,476) $210,834
--------- -------- --------- ---------
--------- -------- --------- ---------

Held-to-maturity:
Equity securities $ 40,628 $ - $ (1,374) $ 39,254
Debt securities 14,804 39 (1,849) 12,994
--------- -------- --------- ---------
$ 55,432 $ 39 $ (3,223) $ 52,248
--------- -------- --------- ---------
--------- -------- --------- ---------

</TABLE>

At December 31, 1995, the debt securities held by the Company had the
following maturities (in thousands):

<TABLE>
<CAPTION>
Amortized Fair
Cost Value
--------- --------
<S> <C> <C>
Within 1 year $ 2,575 $ 2,454
1 through 5 years 38,345 36,934
5 through 10 years 35,788 32,239
Over 10 years 23,564 24,621

</TABLE>

During 1995, the Company re-evaluated the classification of its
securities classified as held-to-maturity and available-for-sale. As a result,
certain securities, with a total amortized cost of $33.1 million and a market
value of $33.8 million, were transferred from securities classified as held-to-
maturity to available-for-sale securities.

The proceeds and the gross realized gains and losses on the
disposition of investments held by the Company for the years ended December 31,
are as follows (in thousands):

1995 1994
<S> <C> <C>
Proceeds from sales $107,692 $135,769
Gross realized gains 3,923 10,338
Gross realized losses (3,158) 5,234
</TABLE>

-35-

<PAGE>

(14) INCOME TAX EXPENSE:

Income tax expense from continuing operations includes the following
for the years ended December 31 (in thousands):

1995 1994 1993
<S> <C> <C> <C>
Income taxes
Current
Federal . . . . . . . . . . $45,635 $20,036 $57,179
State . . . . . . . . . . . 12,071 5,387 12,295
-------- -------- --------
57,706 25,423 69,474
Deferred
Federal . . . . . . . . . . 15,905 37,316 7,610
State . . . . . . . . . . . 2,550 6,565 3,996
-------- -------- --------
18,455 43,881 11,606
Investment tax credit, net. . (8,177) (6,955) (9,671)
-------- -------- --------
Total income tax expense. . . $67,984 $62,349 $71,409
-------- -------- --------
-------- -------- --------
</TABLE>

Included in Deferred Income Taxes in the Consolidated Balance Sheets as of
December 31 are deferred tax assets and deferred tax liabilities as follows
(in thousands):

1995 1994
<S> <C> <C>
Deferred tax assets
Related to:
Investment tax credits . . . $ 63,374 $ 67,279
Unrealized losses. . . . . . 7,548 4,008
Pensions . . . . . . . . . . 17,938 16,834
AMT credit carry forward . . 18,738 34,555
Nuclear reserves and
decommissioning . . . . . 8,367 8,340
Other. . . . . . . . . . . . 10,679 14,640
-------- --------
Total. . . . . . . . . . . . $126,644 $145,656
-------- --------
-------- --------

1995 1994
Deferred tax liabilities
Related to:
Depreciable property . . . . $533,750 $563,099
Income taxes recoverable
through future rates. . . 207,631 206,856
Intangible drilling costs. . 38,278 17,062
Energy efficiency. . . . . . 28,616 17,635
Reacquired debt. . . . . . . 17,595 18,575
FERC Order 636 . . . . . . . 16,073 17,939
Other. . . . . . . . . . . . 31,275 30,155
-------- --------
Total. . . . . . . . . . . . $873,218 $871,321
-------- --------
-------- --------

</TABLE>

The following table is a reconciliation between the effective income tax
rate, before preferred stock dividends, indicated by the Consolidated
Statements of Income and the statutory federal income tax rate for the years
ended December 31:

-36-

<PAGE>

1995 1994 1993
<S> <C> <C> <C>
Effective federal and state
income tax rate . . . . . . . . . . . . . . 34% 31% 33%
Amortization of investment tax credit . . . . 4 4 4
Resolution of prior year tax issue. . . . . . - 2 -
State income tax, net of federal income
tax benefit . . . . . . . . . . . . . . . . (5) (4) (5)
Dividends received deduction. . . . . . . . . 2 2 2
Other . . . . . . . . . . . . . . . . . . . . - - 1
---- ---- ----
Statutory federal income tax rate . . . . . . 35% 35% 35%
---- ---- ----
---- ---- ----

</TABLE>

(15) INVENTORIES:

Inventories include the following amounts as of December 31 (in
thousands):

1995 1994
<S> <C> <C>
Materials and supplies, at average cost. . . $ 27,442 $ 31,688
Coal stocks, at average cost . . . . . . . . 32,163 26,878
Fuel oil, at average cost. . . . . . . . . . 1,523 1,907
Gas in storage, at LIFO cost . . . . . . . . 21,883 30,347
Other. . . . . . . . . . . . . . . . . . . . 2,224 1,428
--------- ---------
Total. . . . . . . . . . . . . . . . . . . . $ 85,235 $ 92,248
--------- ---------
--------- ---------

</TABLE>

At December 31, 1995 prices, the current cost of gas in storage was
$31.4 million.

(16) OTHER INFORMATION:

The Company has completed a merger-related restructuring plan during
1995. Other operating expenses in the Consolidated Statements of Income for
1995 includes $33.4 million related to the restructuring plan.

Non-Operating - Other, Net, as shown on the Consolidated Statements of
Income includes the following for the years ended December 31 (in thousands):

1995 1994 1993
<S> <C> <C> <C>
Allowance for equity funds used
during construction . . . . . . . . . . . . . $ 481 $ 452 $ -
Gain on sale of assets, net. . . . . . . . . . 8,570 4,468 20,164
Income (loss) from equity method investments . (312) 2,712 2,073
Energy efficiency carrying charges . . . . . . 3,092 1,681 1,172
Merger costs . . . . . . . . . . . . . . . . . (4,624) (4,510) -
Other-than-temporary declines in value
of investments and other assets . . . . . . . (17,971) (1,791) (2,939)
Other. . . . . . . . . . . . . . . . . . . . . 297 1,304 372
--------- ---------- --------
Total. . . . . . . . . . . . . . . . . . . . . $(10,467) $ 4,316 $ 20,842
--------- ---------- --------
--------- ---------- --------

</TABLE>

-37-

<PAGE>

(17) HOLDING COMPANY PROPOSAL

The Company's Board of Directors has approved the formation of a
holding company for MidAmerican's organizational structure. The holding company
would have two wholly owned subsidiaries consisting of MidAmerican (utility
operations) and InterCoast. Consummation of the holding company structure is
subject to approval by holders of a majority of the outstanding shares of the
Company's common stock. In addition, certain orders must be received from the
ICC, IUB, FERC, and the Nuclear Regulatory Commission. Subject to such
approvals, each share of MidAmerican common stock will be exchanged for one
share of the holding company's stock. It is management's intent, if possible,
to complete the formation of the holding company and share exchange by the end
of 1996.

(18) UNAUDITED QUARTERLY OPERATING RESULTS:

1995 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
(In thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating revenues . . . . . . . . . . $461,422 $371,712 $434,623 $455,887
Operating income . . . . . . . . . . . 78,841 56,312 99,887 66,092
Income from continuing operations. . . 37,577 26,674 37,457 28,698
Income (loss) from discontinued
operations . . . . . . . . . . . . . - 516 - (99)
Earnings on common stock . . . . . . . 35,296 24,908 35,780 26,780

Earnings per average common share:
Income from continuing operations. . $ 0.35 $ 0.24 $ 0.36 $ 0.27
Income (loss) from discontinued
operations . . . . . . . . . . . . - 0.01 - -
-------- -------- -------- --------
Earnings per average common share. . . $ 0.35 $ 0.25 $ 0.36 $ 0.27
-------- -------- -------- --------
-------- -------- -------- --------

1994 1st Quarter 2nd Quarter 3rd Quarter* 4th Quarter
----------- ----------- ----------- -----------
(In thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating revenues . . . . . . . . . . $ 529,422 $ 368,126 $ 382,492 $ 410,870
Operating income . . . . . . . . . . . 86,855 55,949 85,570 45,232
Income from continuing operations. . . 47,468 24,748 42,125 22,044
Loss from discontinued operations. . . (759) (603) (4,236) (47)
Earnings on common stock . . . . . . . 44,136 21,571 35,315 19,167

Earnings per average common share:
Income from continuing operations . $ 0.46 $ 0.23 $ 0.40 $ 0.19
Loss from discontinued operations . (0.01) (0.01) (0.04) -
-------- -------- -------- --------

Earnings per average common share. . . $ 0.45 $ 0.22 $ 0.36 $ 0.19
-------- -------- -------- --------
-------- -------- -------- --------

</TABLE>

* Includes the estimated loss on the disposal of the construction
subsidiaries.

The quarterly data reflect seasonal variations common in the utility industry.

-38-

<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of MidAmerican Energy Company and
Subsidiaries:

We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of MidAmerican Energy Company (an Iowa
corporation) and subsidiaries, as of December 31, 1995 and 1994, and the related
consolidated statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We did not audit the 1994 and 1993 financial statements of Iowa-
Illinois Gas and Electric Company, one of the companies merged in 1995 to form
MidAmerican Energy Company in a transaction accounted for as a pooling-of-
interests, as discussed in Note (1)(a). Such statements are included in the
consolidated financial statements of MidAmerican Energy Company and subsidiaries
and reflect total assets constituting 42% in 1994 and total revenues
constituting 36% in 1994 and 1993, of the related consolidated totals. These
statements were audited by other auditors whose report has been furnished to us
and our opinion, insofar as it relates to the amounts included for Iowa-Illinois
Gas and Electric Company, is based solely upon the report of the other auditors.

We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes 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, based on our report and the report of the other
auditors, the financial statements referred to above present fairly, in all
material respects, the financial position of MidAmerican Energy Company and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.

/s/ Arthur Andersen LLP

Chicago, Illinois
January 26, 1996

-39-

<PAGE>

REPORT OF MANAGEMENT

Management is responsible for the preparation of all information contained in
this Annual Report, including the financial statements. The statements and
related financial information have been prepared in conformity with generally
accepted accounting principles. In the opinion of management, the financial
position, results of operation and cash flows of the Company are reflected
fairly in the statements. The statements have been audited by the Company's
independent public accountants, Arthur Andersen LLP.

The Company maintains a system of internal controls which is designed to
provide reasonable assurance, on a cost effective basis, that transactions are
executed in accordance with management's authorization, the financial statements
are reliable and the Company's assets are properly accounted for and
safeguarded. The Company's internal auditors continually evaluate and test the
system of internal controls and actions are taken when opportunities for
improvement are identified. Management believes that the system of internal
controls is effective.

The Audit Committee of the Board of Directors, the members of which are
directors who are not employees of the Company, meets regularly with management,
the internal auditors and Arthur Andersen LLP to discuss accounting, auditing,
internal control and financial reporting matters. The Company's independent
public accountants are appointed annually by the Board of Directors on
recommendation of the Audit Committee. The internal auditors and Arthur
Andersen LLP each have full access to the Audit Committee, without management
representatives present.

/s/ Stanley J. Bright
President,
Office of the Chief Executive Officer

/s/ Lance E. Cooper
Group Vice President
Finance and Accounting

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<PAGE>

FIVE-YEAR FINANCIAL STATISTICS

<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Earnings per average common share --
Continuing operations:
Utility operations $ 1.24 $ 1.12 $ 1.29 $ 0.82 $ 1.33
Nonregulated activities (.02) 0.16 0.14 0.01 (.01)
Discontinued operations - (0.06) (0.04) 0.01 -
------- ------- ------- ------- -------
Earnings per average common share $ 1.22 $ 1.22 $ 1.39 $ 0.84 $ 1.32
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Return on average common equity (%) 10.1 10.1 11.6 7.1 11.2
Cash dividends declared per common share $ 1.18 $ 1.17 $ 1.17 $ 1.28 $ 1.38
Common dividend payout ratio (%) 97 96 84 152 105
Ratio of earnings to fixed charges
Consolidated 2.8 2.8 2.9 1.9 2.5
Utility only 3.4 3.3 3.4 2.3 2.9
Ratio of earnings to fixed charges and
Cooper Nuclear Station debt service
Consolidated 2.7 2.7 2.8 1.9 2.4
Utility only 3.3 3.2 3.3 2.2 2.8
Capitalization ratios % --
Common shareholders' equity 44.3 43.9 44.0 43.8 42.9
Preferred shares, not subject to
mandatory redemption 3.2 3.3 4.1 2.8 2.8
Preferred shares, subject to
mandatory redemption 1.8 1.8 1.9 1.8 3.0
Long-term debt (excluding
current portion) 50.7 51.0 50.0 51.6 51.3
Book value per common share at year-end $ 12.17 $ 12.08 $ 12.07 $ 11.86 $ 12.12
Quarterly earnings per average common
share outstanding --
1st quarter $ 0.35 $ 0.45 $ 0.44 $ 0.28 $ 0.36
2nd quarter 0.25 0.22 0.22 0.13 0.27
3rd quarter 0.36 0.36 0.52 0.26 0.47
4th quarter 0.27 0.19 0.20 0.17 0.22
Number of fulltime employees --
Utility 3,331 4,077 4,196 4,305 4,370
Nonregulated 271 274 347 200 140
Utility construction expenditures $190,771 $211,669 $215,081 $188,344 $177,061
Net cash from utility operations less
dividends as a % of construction 134 121 103 71 100

</TABLE>

COMMON STOCK DIVIDENDS AND PRICES

<TABLE>
<CAPTION>
Price Range
----------------------------------------------------------
Dividends Declared MidAmerican Iowa-Illinois Resources
------------------------- ----------------- ------------------ -----------------
MEC IWG MWR High Low High Low High Low
------- ------- ------- -------- ------- -------- ------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1995
4th Quarter $ 0.30 $ - $ - $17 1/8 $15 $ - $ - $ - $ -
3rd Quarter 0.30 - - 15 5/8 13 5/8 - - - -
2nd Quarter - 0.4325 0.29 - - 22 19 7/8 15 13 5/8
1st Quarter - 0.4325 0.29 - - 22 1/8 19 14 5/8 13 3/8
1994
4th Quarter $ - $0.4325 $0.29 - - $20 5/8 $18 7/8 $14 1/2 $12 7/8
3rd Quarter - 0.4325 0.29 - - 22 1/2 19 1/4 15 3/8 13 1/2
2nd Quarter - 0.4325 0.29 - - 24 1/2 19 7/8 16 3/4 13 7/8
1st Quarter - 0.4325 0.29 - - 24 3/4 22 3/8 18 16

</TABLE>

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<PAGE>

MIDAMERICAN ENERGY COMPANY
FIVE-YEAR CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
------------------------------------------------------
1995 1994 1993 1992 1991
-------- -------- -------- -------- --------
(In thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Electric utility $1,094,647 $1,021,660 $1,002,970 $ 936,027 $ 968,799
Gas utility 459,588 492,015 538,989 484,687 473,251
Nonregulated 169,409 177,235 140,976 70,344 46,513
---------- --------- --------- --------- ---------
1,723,644 1,690,910 1,682,935 1,491,058 1,488,563
---------- --------- --------- --------- ---------

OPERATING EXPENSES
Utility:
Cost of fuel, energy and
Capacity 230,261 213,987 217,385 211,924 212,647
Cost of gas sold 279,025 326,782 366,049 326,097 323,113
Other operating expenses (2) 399,648 354,190 340,720 329,911 306,508
Maintenance 85,363 101,275 101,601 93,769 91,548
Depreciation and amortization 158,950 154,229 150,822 144,646 135,062
Property and other taxes 96,350 94,990 93,238 97,479 94,872
---------- --------- --------- --------- ---------
1,249,597 1,245,453 1,269,815 1,203,826 1,163,750
Nonregulated (2) 172,915 171,851 132,224 69,522 46,692
---------- --------- --------- --------- ---------
1,422,512 1,417,304 1,402,039 1,273,348 1,210,442
---------- --------- --------- --------- ---------

OPERATING INCOME 301,132 273,606 280,896 217,710 278,121
---------- --------- --------- --------- ---------

NON-OPERATING INCOME (3) 11,660 33,372 52,163 15,656 28,023
---------- --------- --------- --------- ---------

INTEREST CHARGES
Interest on long-term debt 110,505 105,753 111,065 114,732 106,538
Other interest expense 9,449 6,446 5,066 5,899 16,380
Allowance for borrowed funds (5,552) (3,955) (2,186) (2,162) (4,347)
---------- --------- --------- --------- ---------
114,402 108,244 113,945 118,469 118,571
---------- --------- --------- --------- ---------

INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME
TAXES 198,390 198,734 219,114 114,897 187,573
INCOME TAXES 67,984 62,349 71,409 26,812 59,604
---------- --------- --------- --------- ---------
INCOME FROM CONTINUING
OPERATIONS 130,406 136,385 147,705 88,085 127,969
INCOME (LOSS) FROM
DISCONTINUED OPERATIONS
(net of income taxes) (4) 417 (5,645) (3,854) 794 203
---------- --------- --------- --------- ---------
NET INCOME 130,823 130,740 143,851 88,879 128,172
PREFERRED DIVIDENDS 8,059 10,551 8,367 8,735 9,708
---------- --------- --------- --------- ---------

EARNINGS ON COMMON STOCK $ 122,764 $ 120,189 $ 135,484 $ 80,144 $ 118,464
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------

AVERAGE COMMON SHARES
OUTSTANDING 100,401 98,531 97,762 95,430 89,844
EARNINGS PER COMMON SHARE $ 1.22 $ 1.22 $ 1.39 $ 0.84 $ 1.32

</TABLE>

(1) The Company was formed on July 1, 1995, through a merger, as discussed
in Note (1)(a) of Notes to Consolidated Financial Statements (Notes).
All data on this statement reflect the pooled amounts of the
predecessor companies. Non-Operating income includes $4.5 million and
$4.6 million of merger-related costs in 1994 and 1995, respectively.
(2) Utility other operating expenses include $31.9 million of costs related
to a restructuring and work force reduction plan implemented and
completed in 1995. In addition, nonregulated other expenses for 1995
includes $1.5 million of related costs.
(3) During 1995, the Company recorded approximately $18 million of expense
for the write-down of certain nonregulated assets. In 1993, the Company
recorded an $18.5 million pre-tax gain on the exchange of natural gas
service territory. The exchange resulted in a decrease of
approximately 33,000 natural gas customers.
(4) In 1994 the Company announced its intent to divest its construction
subsidiaries. Refer to Note (9) of Notes.

-42-
<PAGE>

MIDAMERICAN ENERGY COMPANY
FIVE-YEAR CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31
-----------------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ---------- ---------- -----------
(In thousands)
<S> <C> <C> <C> <C> <C>
ASSETS
UTILITY PLANT
Electric $3,881,699 $3,765,004 $3,642,415 $3,534,703 $3,455,061
Gas 695,741 663,792 639,276 628,856 575,113
---------- ---------- ---------- ---------- ----------
4,577,440 4,428,796 4,281,691 4,163,559 4,030,174
Less accumulated depreciation and amortization 2,027,055 1,885,870 1,801,668 1,680,033 1,572,946
---------- ---------- ---------- ---------- ----------
2,550,385 2,542,926 2,480,023 2,483,526 2,457,228
Construction work in progress 104,164 101,252 111,726 67,664 51,176
---------- ---------- ---------- ---------- ----------
Total 2,654,549 2,644,178 2,591,749 2,551,190 2,508,404
---------- ---------- ---------- ---------- ----------

POWER PURCHASE CONTRACT 212,148 221,998 248,643 243,146 248,949
---------- ---------- ---------- ---------- ----------

INVESTMENT IN DISCONTINUED OPERATIONS - 15,249 22,206 23,686 23,854
---------- ---------- ---------- ---------- ----------

CURRENT ASSETS
Cash and cash equivalents 41,216 33,778 24,289 25,079 30,384
Receivables, less reserves 261,105 212,902 226,054 225,566 205,440
Inventories 85,235 92,248 100,675 98,608 91,753
Other 22,252 19,035 24,911 26,182 20,277
---------- ---------- ---------- ---------- ----------
409,808 357,963 375,929 375,435 347,854
---------- ---------- ---------- ---------- ----------

INVESTMENTS 826,496 752,428 760,308 727,929 673,789
---------- ---------- ---------- ---------- ----------

OTHER ASSETS 420,520 423,958 372,426 192,630 107,819
---------- ---------- ---------- ---------- ----------

TOTAL ASSETS $4,523,521 $4,415,774 $4,371,261 $4,114,016 $3,910,669
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------

CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common shareholders' equity $1,225,715 $1,204,112 $1,180,510 1,159,676 1,128,858
Preferred shares, not subject to mandatory redemption 89,945 89,955 109,871 74,242 74,291
Preferred shares, subject to mandatory redemption 50,000 50,000 50,000 48,625 79,200
Long-term debt 1,403,322 1,398,255 1,341,003 1,368,784 1,351,385
---------- ---------- ---------- ---------- ----------
2,768,982 2,742,322 2,681,384 2,651,327 2,633,734
---------- ---------- ---------- ---------- ----------

CURRENT LIABILITIES
Notes payable 184,800 124,500 173,035 120,244 67,629
Current portion of long-term debt 65,295 72,872 66,371 32,952 10,991
Current portion of power purchase contract 13,029 12,080 10,830 8,065 8,948
Accounts payable 142,759 110,175 129,504 115,763 117,573
Taxes accrued 81,898 91,653 110,923 101,585 101,879
Interest accrued 30,635 30,659 31,021 31,395 31,678
Other 57,000 54,473 52,237 53,563 39,378
---------- ---------- ---------- ---------- ----------
575,416 496,412 573,921 463,567 378,076
---------- ---------- ---------- ---------- ----------

OTHER LIABILITES
Power purchase contract 112,700 125,729 140,655 138,085 141,890
Deferred income taxes 746,574 725,665 670,288 596,144 525,056
Investment tax credit 95,041 100,871 106,729 113,846 119,989
Other 224,808 224,775 198,284 151,047 111,924
---------- ---------- ---------- ---------- ----------
1,179,123 1,177,040 1,115,956 999,122 898,859
---------- ---------- ---------- ---------- ----------
TOTAL CAPITALIZATION
AND LIABILITIES $4,523,521 $4,415,774 $4,371,261 $4,114,016 $3,910,669
---------- ----------- ---------- ---------- ----------
---------- ----------- ---------- ---------- ----------

</TABLE>

-43-
<PAGE>

MIDAMERICAN ENERGY COMPANY
FIVE-YEAR ELECTRIC UTILITY STATISTICS

FOR THE YEAR ENDED DECEMBER 31 1995 1994 1993 1992 1991
---------- ---------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C>
REVENUES (IN THOUSANDS)
Residential $ 434,105 $ 400,346 $ 386,047 $ 343,842 $ 379,240
Small general service 252,427 253,703 242,205 236,292 241,277
Large general service 219,075 204,481 193,616 199,256 197,795
Other sales 60,160 57,731 56,198 30,878 31,354
Sales for resale 105,472 84,260 104,461 106,982 98,748
---------- ---------- ---------- --------- ----------
Total from electric sales 1,071,239 1,000,521 982,527 917,250 948,414
Other electric revenue 23,408 21,139 20,443 18,777 20,385
---------- ---------- ---------- --------- ----------
Total $1,094,647 $1,021,660 $1,002,970 $ 936,027 $ 968,799
---------- ---------- ---------- --------- ----------
---------- ---------- ---------- --------- ----------

KWH SALES (IN THOUSANDS)
Residential 4,767,608 4,500,265 4,475,883 4,098,567 4,540,923
Small general service 3,920,792 4,062,993 3,937,360 3,885,898 3,989,071
Large general service 5,351,933 5,091,685 4,851,493 4,993,213 4,895,098
Other 957,463 938,620 930,117 470,444 479,257
Sales for resale 5,509,161 3,605,092 5,566,208 6,386,957 6,163,480
---------- ---------- ---------- --------- ----------
Total 20,506,957 18,198,655 19,761,061 19,835,079 20,067,829
---------- ---------- ---------- --------- ----------
---------- ---------- ---------- --------- ----------

REVENUES BY CUSTOMER CLASS (% OF TOTAL)
Residential 40.5 40.0 39.3 37.5 40.0
Small general service 23.6 25.4 24.7 25.7 25.4
Large general service 20.5 20.4 19.7 21.7 20.9
Other 5.6 5.8 5.7 3.4 3.3
Sales for resale 9.8 8.4 10.6 11.7 10.4
---------- ---------- ---------- --------- ----------
Total 100.0 100.0 100.0 100.0 100.0
---------- ---------- ---------- --------- ----------
---------- ---------- ---------- --------- ----------

SALES AS A % OF TOTAL
Residential 23.2 24.7 22.7 20.6 22.6
Small general service 19.1 22.3 19.9 19.6 19.9
Large general service 26.1 28.0 24.5 25.2 24.4
Other 4.7 5.2 4.7 2.4 2.4
Sales for resale 26.9 19.8 28.2 32.2 30.7
---------- ---------- ---------- --------- ----------
Total 100.0 100.0 100.0 100.0 100.0
---------- ---------- ---------- --------- ----------
---------- ---------- ---------- --------- ----------

RETAIL ELECTRIC SALES BY JURISDICTION (%)
Iowa 89.5 88.6 88.7 87.8 87.6
Illinois 9.9 10.9 10.9 11.8 12.1
South Dakota 0.6 0.5 0.4 0.4 0.3

CUSTOMERS (END OF YEAR)
Residential 551,384 548,106 541,220 536,767 530,869
Small general service 72,616 69,905 68,829 71,843 71,127
Large general service 945 743 744 833 838
Other 9,744 9,518 9,572 5,156 5,044
Sales for resale 55 59 63 61 61
---------- ---------- ---------- --------- ----------
Total 634,744 628,331 620,428 614,660 607,939
---------- ---------- ---------- --------- ----------
---------- ---------- ---------- --------- ----------

ANNUAL AVERAGE PER RESIDENTIAL CUSTOMER
Revenue per Kwh (cents) 9.11 8.90 8.62 8.39 8.35
KWh sales 8,670 8,265 8,310 7,681 8,598

COOLING DEGREE DAYS
Actual 1,112 912 813 603 1,303
Percent warmer (colder) than normal 14.1 (6.5) (16.4) (38.5) 33.0

ELECTRIC PEAK DEMAND (NET MW) 3,553 3,226 3,284 2,902 3,227

SUMMER NET ACCREDITED CAPABILITY (MW) 4,311 4,145 4,072 4,116 3,996

</TABLE>

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<PAGE>

MIDAMERICAN ENERGY COMPANY
FIVE-YEAR GAS UTILITY STATISTICS

FOR THE YEAR ENDED DECEMBER 31 1995 1994 1993 1992 1991
----------- ---------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C>
REVENUES (IN THOUSANDS)
Residential $ 279,819 $ 287,171 $ 319,359 $ 282,688 $ 271,312
Small general service 128,501 142,894 150,913 133,384 127,600
Large general service 23,280 36,729 37,761 43,919 47,107
Sales for resale and other 5,303 5,514 10,376 2,648 5,340
----------- ---------- ---------- ---------- ---------
Total revenue from gas sales 436,903 472,308 518,409 462,639 451,359
Gas transported 16,677 12,842 13,457 17,473 16,231
Other gas revenues 6,008 6,865 7,123 4,575 5,661
----------- ---------- ---------- ---------- ---------
Total $ 459,588 $ 492,015 $ 538,989 $ 484,687 $ 473,251
----------- ---------- ---------- ---------- ---------
----------- ---------- ---------- ---------- ---------

THROUGHPUT (MMBTU IN THOUSANDS)
Sales
Residential 57,153 54,732 60,612 56,072 57,770
Small general service 32,786 32,677 34,504 31,894 32,464
Large general service 6,222 8,253 9,681 12,357 13,616
Sales for resale and other 3,582 3,231 4,305 837 2,213
----------- ---------- ---------- ---------- ---------
Total sales 99,743 98,893 109,102 101,160 106,063
Gas transported 50,695 43,293 39,570 34,686 30,052
----------- ---------- ---------- ---------- ---------
Total 150,438 142,186 148,672 135,846 136,115
----------- ---------- ---------- ---------- ---------
----------- ---------- ---------- ---------- ---------

REVENUES BY CUSTOMER CLASS (%
OF TOTAL)
Residential 61.7 59.2 60.0 58.9 58.0
Small general service 28.3 29.4 28.4 27.8 27.3
Large general service 5.1 7.6 7.1 9.1 10.1
Sales for resale and other 1.2 1.1 2.0 0.6 1.1
Gas Transported 3.7 2.7 2.5 3.6 3.5
----------- ---------- ---------- --------- ---------
Total 100.0 100.0 100.0 100.0 100.0
----------- ---------- ---------- ---------- ---------
----------- ---------- ---------- ---------- ---------

SALES AS A % OF TOTAL (EXCLUDING
GAS TRANSPORTED)
Residential 57.3 55.3 55.6 55.5 54.5
Small general service 32.9 33.0 31.6 31.5 30.6
Large general service 6.2 8.4 8.9 12.2 12.8
Sales for resale and other 3.6 3.3 3.9 0.8 2.1
----------- ---------- ---------- ---------- ---------
Total 100.0 100.0 100.0 100.0 100.0
----------- ---------- ---------- ---------- ---------
----------- ---------- ---------- ---------- ---------

RETAIL GAS SALES BY JURISDICTION (%)
Iowa 78.0 76.6 74.5 73.4 74.1
Illinois 10.7 11.9 11.4 11.6 11.8
South Dakota 10.6 10.8 5.4 2.2 2.0
Other 0.7 0.7 8.7 12.8 12.1

CUSTOMERS (END OF YEAR)
Residential 541,732 535,301 526,863 552,660 542,084
Small general service 57,207 55,855 54,972 54,918 54,189
Large general service 830 876 868 1,020 1,059
Gas transported and other 1,128 171 128 123 98
----------- ---------- ---------- ---------- ---------
Total 600,897 592,203 582,831 608,721 597,430
----------- ---------- ---------- ---------- ---------
----------- ---------- ---------- ---------- ---------

ANNUAL AVERAGES PER RESIDENTIAL
CUSTOMER
Revenue per MMBtu $ 4.90 $ 5.25 $ 5.27 $ 5.04 $ 4.70
MMBtu sales 106 103 111 103 108

HEATING DEGREE DAYS
Actual 6,841 6,565 7,097 6,302 6,505
Percent colder (warmer) than normal 0.9 (3.5) 3.2 (8.7) (7.3)

COST PER MMBTU $ 2.80 $ 3.30 $ 3.36 $ 3.22 $ 3.05

</TABLE>

-45-