SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark On)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
[FEE REQUIRED] FOR THE FISCAL YEAR ENDED
DECEMBER 31, 1993 OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO
FEE REQUIRED] FOR THE TRANSITION PERIOD FROM _____
TO _______

COMMISSION FILE NUMBER 1-3701

THE WASHINGTON WATER POWER COMPANY
(Exact name of Registrant as specified in its charter)

Washington 91-0462470
---------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

1411 East Mission Avenue, Spokane, Washington 99202-2600
---------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code:509-489-0500

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

Name of Each Exchange
Title of Class on Which Registered
-------------- -------------------

Common Stock, no par value, together with New York Stock Exchange
Preferred Share Purchase Rights appurtenant thereto Pacific Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

Title of Class
Preferred Stock, Cumulative, Without Par Value

Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days:

Yes[X] No[ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of Registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [X]

The aggregate market value of the Registrant's outstanding Common Stock, no par
value (the only class of voting stock), held by non- affiliates is
$906,230,048.88, based on the last reported sale price thereof on the
consolidated tape on February 25, 1994.

At February 25, 1994, 52,918,543 shares of Registrant's Common Stock, no par
value (the only class of common stock), were outstanding.

Documents Incorporated By Reference
-----------------------------------
Part of Form 10-K into Which
Document Document is Incorporated
---------------------------------------- -----------------------------

Proxy Statement to be filed in Part III, Items 10, 11,
connection with the annual meeting 12 and 13
of shareholders to be held May 12, 1994

2
THE WASHINGTON WATER POWER COMPANY

INDEX

Item Page
No. No.
- ---- -----

Acronyms and Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii

Part I

1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Company Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Utility Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Non-Utility Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Electric Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Electric Competition and Business Overview . . . . . . . . . . . . . . . . . . . . . . 2
Electric System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Electric Regulatory Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Electric Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Natural Gas Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Natural Gas Competition and Business Overview . . . . . . . . . . . . . . . . . . . . 6
Natural Gas System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Natural Gas Regulatory Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Natural Gas Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Environmental Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Non-Utility Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Electric Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Natural Gas Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . 11

Part II

5. Market for Registrant's Common Equity and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Significant Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 23
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . *

Part III

10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . 45
11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . 46
13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . 46

Part IV

14. Financial Statements, Financial Statement Schedules, Exhibits and Reports on Form 8-K . . 47
Independent Auditors' Report (Relating to Supplemental Schedules) . . . . . . . . . . . . 48
Supplemental Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Independent Auditors' Consent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

* = not an applicable item in the 1993 calendar year for the Company

3
THE WASHINGTON WATER POWER COMPANY

ACRONYMS AND TERMS

The following acronyms and terms are found in multiple locations within the
document.

Acronym/Term Meaning
- ------------ -------

aMW - Average Megawatt - the measure of energy over time

BPA - Bonneville Power Administration

CPUC - California Public Utilities Commission

DSM - Demand Side Management - the process of helping
customers control how they use energy resources

FERC - Federal Energy Regulatory Commission

IPUC - Idaho Public Utilities Commission

IRP - Integrated Resource Planning

MW, MWH - Megawatt, megawatthour, a million watts or a
thousand kilowatts (KW)

OPUC - Public Utility Commission of Oregon

Pentzer - Pentzer Corporation, a wholly-owned subsidiary
of the Company which is the parent company to the
majority of the Company's diversified nonutility
businesses

Therm - Unit of measurement for natural gas; a therm is equal
to one hundred cubic feet (volume) or 100,000 BTUs
(energy)

Watt - Unit of measurement for electricity; a watt is equal
to the rate of work represented by a current of one
ampere under a pressure of one volt

WIDCo - Washington Irrigation & Development Company, a
wholly-owned non-operating subsidiary of the Company

WPNG - WP Natural Gas, the operating division for the
Company's natural gas business in Oregon and
California (the natural gas distribution assets
purchased from CPN)

WUTC - Washington Utilities and Transportation Commission

WWP - The Washington Water Power Company, the Company; in
the context of the Company's natural gas business,
refers to Washington and Idaho natural gas
distribution assets

iii

4
THE WASHINGTON WATER POWER COMPANY

PART I

ITEM 1. BUSINESS

COMPANY OVERVIEW

Incorporated in 1889 under the laws of the State of Washington, The Washington
Water Power Company (WWP, the Company) is an investor-owned company primarily
engaged as a combination electric and natural gas utility serving a 26,000
square mile area known as the Inland Northwest in eastern Washington and
northern Idaho with a population estimated to be in excess of 750,000. Also,
WP Natural Gas (WPNG), an operating division, provides natural gas service in
northeast and southwest Oregon and the South Lake Tahoe region in California
with a population estimated to be in excess of 450,000. The Company's utility
operations include the generation, purchase, transmission, distribution and
sale of electric energy on both a retail and wholesale basis plus the purchase,
transportation, distribution and sale of natural gas. In addition to its
utility operations, the Company owns Pentzer Corporation, parent company to the
majority of the Company's non-utility businesses. Pentzer's portfolio of
investments includes companies involved in advertising display manufacturing,
electronic technology, energy services, financial services, real estate
development and telecommunications.

At December 31, 1993, the Company employed 1,696 people with 1,438 in its
utility operations and 258 in its majority-owned non-utility operations. The
Company headquarters are in Spokane, Washington, which with a population of
about 480,000 in the Greater Spokane Area, serves as the Inland Northwest's
center for business, transportation, health care, education, communication and
agricultural interests.

For the twelve months ended December 31, 1993 and 1992, respectively, the
Company derived operating revenues and income from operations in the following
proportions:

Operating Revenues Income from Operations
------------------ ----------------------
1993 1992 1993 1992
---- ---- ---- ----

Electric 73% 76% 82% 89%
Natural Gas 21% 18% 13% 8%
Non-Utility 6% 6% 5% 3%

UTILITY OVERVIEW

The Company owns and operates nine hydroelectric projects, a wood-waste fueled
generating station and a natural gas combustion turbine. The Company also
retains a 15% ownership in two coal-fired generating facilities, one in
southwestern Washington and one in southeastern Montana. In addition the
Company is in the process of constructing a natural gas combustion turbine
peaking unit in northern Idaho. Four natural gas pipelines provide the Company
access to both domestic and Canadian natural gas supplies. With this diverse
resource portfolio, the Company remains one of the nation's lowest-cost
producers and sellers of energy services.

At December 31, 1993, electric service was supplied to approximately 267,000
customers in eastern Washington and northern Idaho. The Company's average
hourly load for 1993 was 900 aMW. The Company's annual peak load, including
firm contractual obligations, was 2,126 MW. This peak occurred on January 13,
1993, at which time the maximum capacity available from the Company's
generating facilities, contracts and non-firm purchases was 2,335 MW.

At December 31, 1993, the Company's natural gas operations served approximately
196,000 customers in four states. The Company's natural gas business has more
than doubled since 1990 due primarily to the acquisition of the natural gas
distribution properties of CP National in Oregon and South Lake Tahoe,
California in September, 1991. The peak load in 1993 occurred on February 16,
1993 when 2.7 million therms were required. During that peak 3.5 million
therms were available under firm transportation and storage contracts.

NON-UTILITY OVERVIEW

The Company's principal subsidiary, Pentzer, is the parent company of all the
Company's non-utility subsidiaries except for three non-operating subsidiaries.
Wholly-owned Pentzer is a company with approximately $130 million in total
assets and about $86 million in shareholder equity. Pentzer's business
strategy is to acquire controlling interests in a broad range of middle market
companies, to help these companies grow through internal development and
strategic acquisitions, and to sell the portfolio investments either to the
public or to strategic buyers when it becomes most advantageous in meeting
Pentzer's return on invested capital objectives.

1
5
THE WASHINGTON WATER POWER COMPANY

ELECTRIC SERVICE

ELECTRIC COMPETITION AND BUSINESS OVERVIEW

The electric utility business is undergoing numerous changes and is becoming
increasingly competitive as a result of economic, regulatory, and technological
changes. The Company believes that it is well positioned to meet the
challenges described below due to its low production costs, close proximity to
major transmission lines, experience in the wholesale market and its commitment
to high levels of customer satisfaction, cost reduction and continuous
improvement of work processes.

The Company currently competes for new retail electric customers with various
rural electric cooperatives and public utility districts. Challenges facing
the electric retail business include changing technologies which reduce energy
consumption, self- generation and fuel switching by industrial and other large
retail customers, the potential for retail wheeling (described below) and the
costs of increasingly stringent environmental laws. Cogeneration has had only
a minor impact on the Company to date. See "Purchases, Exchanges and Sales"
for additional detail on cogeneration purchases and sales. In addition, if
electric utility companies are eventually required to provide retail wheeling
service, which is the transmission by an electric utility of electric power
from another supplier to a customer located within such utility's service area,
the Company believes it will be in a position to benefit since it is committed
to remaining one of the country's lowest-cost providers of electric energy.

The Company also competes in the wholesale electric market with other western
utilities, including the BPA. Challenges facing the electric wholesale
business include new entrants in the wholesale market and competition from
lower cost generation being developed by independent power producers.

The National Energy Policy Act (NEPA) enacted in 1992 addresses a wide range of
issues affecting the wholesale electric business. NEPA gives the FERC expanded
authority to order electric utilities (a) to transmit electric power to or for
wholesale purchasers and sellers if the result would not unreasonably impair
the continuing reliability of the affected electric systems and (b) to increase
transmission capacity to provide access for wholesale purchasers and sellers of
electric power at prices that permit the recovery by the utility of all costs
incurred in connection with the transmission services. NEPA also created
Exempt Wholesale Generators (EWG's), a new class of independent power plant
owners who are able to sell generation only at the wholesale level. The
Company believes NEPA provides future transmission, energy production and sales
opportunities to the Company and complements the Company's commitment to the
wholesale electric business.

The Company's wholesale electric business remains an important part of the
Company's overall business. Since 1987 the Company has entered into a number
of long-term firm power sales contracts that have increased its wholesale
electric business and the Company intends to continue active pursuit of
wholesale business opportunities. In 1993, 31% of total KWH sales were to
wholesale customers with 55% of these sales under firm contracts.

ELECTRIC SYSTEM

The Company owns and operates nine hydroelectric projects, a wood-waste fueled
generating station and a natural gas combustion turbine in addition to
retaining a 15% ownership in two coal-fired generating facilities.

Hydroelectric Resources Hydroelectric generation is the Company's lowest cost
source of electricity and the availability of hydroelectric generation has a
significant effect on the Company's total power costs. The Company expects to
meet about 49% of its total system requirements with its own hydroelectric
generation and long-term hydro contracts in normal water years. The
streamflows in the Company's drainage systems were 86%, 64% and 116% of normal
in 1993, 1992 and 1991, respectively. For the years 1993, 1992 and 1991,
respectively, the Company's own hydroelectric generation facilities provided
33%, 28% and 38%, while long-term hydro contracts provided approximately 10%,
12% and 14% of the Company's total system requirements.

Thermal Resources The Company has a 15% interest in two coal-fired facilities
- - the Centralia Power Plant (Centralia) in southwestern Washington and Units 3
and 4 of the Colstrip Generating Project (Colstrip) in southeastern Montana.
In addition, the Company owns a woodwaste-fired facility known as the Kettle
Falls Generating Station (Kettle Falls) in northeastern Washington and a
natural gas-fired combustion turbine (CT) in Spokane. The CT is primarily used
for peaking needs. In a normal water year about 32% of the Company's total
system requirements are met by thermal sources. Company-owned thermal
facilities provided 25%, 31% and 26% of the Company's total electricity
requirements for the years 1993, 1992 and 1991, respectively.

6
THE WASHINGTON WATER POWER COMPANY

Centralia, which is operated by PacifiCorp, is supplied with coal under a fuel
supply agreement in effect through December 31, 2020. In 1993, 1992 and 1991
Centralia provided approximately 46%, 40% and 40%, respectively, of the
Company's thermal generation.

Colstrip is supplied with fuel under coal supply and transportation agreements
in effect through December 2019, from adjacent coal reserves owned and
controlled by Entech, Inc. (Entech). Entech is a wholly-owned subsidiary of
The Montana Power Company, which is also the operator of Colstrip. In 1993,
1992 and 1991 Colstrip provided approximately 43%, 51%, and 51% of the
Company's thermal generation, respectively.

Kettle Falls' primary fuel is waste wood generated as a by-product of forest
product processing facilities such as sawmills within an approximate one
hundred mile radius of the plant. Natural gas may be used as an alternate
fuel. The cost of waste wood fuel is heavily influenced by operations of the
forest products industry as well as transportation costs and, therefore, is
subject to significant price variations. Current fuel supplies are adequate
through the remainder of 1994. A combination of long term contracts already in
place plus spot purchases allow the Company the flexibility to meet all
expected future fuel requirements for the plant. In 1993, 1992 and 1991 Kettle
Falls provided approximately 11%, 9% and 9% of the Company's thermal
generation, respectively.

Purchases, Exchanges and Sales In addition to the Company-owned hydro,
long-term hydro contracts and thermal generating resources discussed above,
total system requirements are met with other long-term purchases and exchanges
of power. Other power purchases and exchanges for the years 1993, 1992 and
1991 provided approximately 32%, 29% and 22%, respectively, of the Company's
total system requirements.

The following table summarizes the Company's major long-term wholesale power
agreements as of December 31, 1993 (1):

Contracts Expiring between: Purchases (MW) Exchanges (MW) Sales (MW)
- --------------------------- -------------- -------------- ----------

1994 and 2003 173 79 150
2004 and 2013 217 150 150
2014 and 2023 30 82 150
--- ---- ---
Total 420 311 450

1993 Revenues (Expenses) ($18 million) ($35 million) $51 million

(1) Available capacity may vary pursuant to the provisions of
the specific contracts. See Notes 11 and 13 to Financial Statements for
additional information

Under PURPA, the Company is required to purchase generation from qualifying
facilities, including small hydro and cogeneration projects, at avoided cost
rates adopted by the WUTC and IPUC. The Company purchased approximately 623
million KWH, or about 6% of the Company's total energy requirements, from these
sources at a cost of approximately $26 million in 1993. The largest such
contract is a ten-year power purchase contract between the Company and
Potlatch, one of the Company's major industrial customers, which became
effective on January 1, 1992. Under the terms of the agreement, the Company
purchases 50-55 aMW of Potlatch's electric generation and makes available
approximately 95 aMW of firm energy for sale. In addition, the Company makes
available 25 aMW of interruptible energy and Potlatch must provide an
equivalent amount of reserve generation capacity in case of interruption.

ELECTRIC REGULATORY ISSUES

The Company, as a public utility, is currently subject to regulation by state
utility commissions with respect to rates, accounting, the issuance of
securities and other matters. The electric retail operations are subject to
the jurisdiction of the WUTC and IPUC. The Company is also subject to the
jurisdiction of the FERC for its accounting procedures and its wholesale
transmission rates.

In each regulatory jurisdiction, the prices the Company may charge for utility
services (other than certain wholesale sales and specially negotiated retail
rates for industrial or large commercial customers) are determined on a "cost
of service" basis and are designed to provide, after recovery of allowable
operating expenses, an opportunity to earn a reasonable return on "rate base"
or assets employed in the business. "Rate base" is generally determined by
reference to the original cost (net of accumulated depreciation) of utility
plant in service, subject to various adjustments for deferred taxes and other
items. Over time, rate base is increased by additions to utility plant in
service and reduced by depreciation and retirements of utility plant from
service.

The Company is a licensee under the Federal Power Act and its licensed projects
are subject to the provisions of Part I of that Act. See "Properties -
Electric Properties" for additional information. These provisions include
payment for headwater

7
THE WASHINGTON WATER POWER COMPANY

benefits, condemnation of licensed projects upon payment of just compensation
and take-over of such projects after the expiration of the license upon payment
of the lesser of "net investment" or "fair value" of the project, in either
case plus severance damages.

General Rate Cases

The Company does not currently plan to file for any general electric rate
increases in 1994. The following table summarizes information for the
Company's most recent general electric rate cases:

Approved Effective Change
-------------------------- ---------------------------
Jurisdiction Effective Date ROE Amount (1) %
------------ -------------- ---- ---------- ---
(000's)

WUTC 3-87 12.90% $15,527 8.90%
IPUC (2) 9-86 12.90 3,680 4.30

(1) Anticipated annual revenue effect.
(2) Through June 30, 1994, the IPUC has approved a power cost adjustment
(PCA) mechanism

Integrated Resource Planning (IRP) IRP is a process required by both the WUTC
and IPUC and represents the Company's responsibility to meet customer demand
for reliable energy services at the lowest total cost to both the Company and
its customers. The process entails (1) the forecasting of future energy needs,
(2) the assessment of energy supplies, conservation options, customer costs,
and social and environmental impacts and (3) the development of action plans
which support a least cost resource strategy. The Company's need for future
electric resources to serve retail loads is very minimal. The electric
integrated resource plan accepted by both the IPUC and the WUTC in 1993 showed
that, through the year 1998, the Company's additional electric load
requirements will be met for the most part by a combination of demand side
management, including conversions to natural gas, and the redevelopment of
existing hydro generating plants. The cost of these resources is generally
competitive with the costs of resources being developed by independent power
producers.

Demand Side Management (DSM) Energy efficiency programs, which include
residential space and water heat conversion programs, are material components
of the Company's long-term resource strategy. In 1992 the Company filed a
request with both the WUTC and IPUC for approval of new electric DSM tariffs
which would provide for the implementation of new and revised energy efficiency
programs including the "Energy Exchanger" program, which offers incentives to
the Company's electric space and/or hot water heating customers to convert to
natural gas. In conjunction with the request for tariff approval, DSM
accounting treatment was requested which would allow the Company to defer the
costs in new program investments until the next general rate case. With only
minor modifications, the applications were approved and the effective dates for
implementation were May 1 and July 17, 1992 in Washington and Idaho,
respectively. Reductions in the DSM incentives were approved by both the IPUC
and WUTC in 1993. Justification will be required for continuation of the
programs beyond December 31, 1994. Approximately 18 aMW were saved in 1993
under these programs and over 23 aMW have been saved since the program's
inception.

Power Cost Adjustment (PCA) The Company's PCA surcharge of $2.3 million in
Idaho expired on November 1, 1993. The current balance in the account has not
yet triggered either a surcharge or a refund. In June 1993 the IPUC approved
an extension of the PCA to June 30, 1994. See Note 1 to Financial Statements
for additional details.

8
THE WASHINGTON WATER POWER COMPANY

ELECTRIC OPERATING STATISTICS

Years Ended December 31,
-------------------------------
1993 1992 1991
-------- -------- --------

ENERGY RESOURCES (Millions of KWH):
Hydro generation (from Company facilities) .................... 3,548 2,969 4,297
Thermal generation (from Company facilities) .................. 2,791 3,310 2,941
Purchased power - long-term hydro ............................. 1,117 1,276 1,559
Purchased power - other ...................................... 3,492 2,975 2,531
Power exchanges .............................................. 81 72 (138)
-------- -------- --------
Total power resources ....................................... 11,029 10,602 11,190
Energy losses.................................................. (598) (534) (614)
-------- -------- --------
Total energy resources (net of losses) ...................... 10,431 10,068 10,576
======== ======== ========
ENERGY REQUIREMENTS (Millions of KWH):
Residential ................................................... 3,134 3,024 3,082
Commercial .................................................... 2,373 2,299 2,221
Industrial .................................................... 1,644 1,563 1,148
Public street and highway lighting ............................ 22 20 21
-------- -------- --------
Total retail requirements ................................... 7,173 6,906 6,472
Electric utilities - firm wholesale ........................... 1,798 2,020 2,025
Electric utilities - non-firm wholesale ....................... 1,460 1,142 2,079
-------- -------- --------
Total energy requirements ................................... 10,431 10,068 10,576
======== ======== ========
RESOURCE AVAILABILITY at time of system peak (MW):
Total requirements (winter) (1) ............................... 2,126 2,018 2,042
Total resource availability (winter) .......................... 2,335 2,280 2,222
Total requirements (summer) (2) ............................... 1,682 1,686 1,587
Total resource availability (summer) .......................... 2,206 2,138 2,065

ELECTRIC OPERATING REVENUES (Thousands of Dollars):
Residential ................................................... $153,929 $146,073 $149,165
Commercial .................................................... 126,256 121,277 116,564
Industrial .................................................... 57,133 50,934 39,415
Public street and highway lighting ............................ 3,022 2,891 2,878
-------- -------- --------
Total retail revenue ........................................ 340,340 321,175 308,022
Electric utilities - firm wholesale ........................... 65,420 66,484 58,819
Electric utilities - non-firm wholesale ....................... 43,214 25,307 33,529
-------- -------- --------
Total energy revenues ....................................... 448,974 412,966 400,370
Miscellaneous revenues ........................................ 15,201 11,447 11,401
-------- -------- --------
Total electric revenues ......................................... $464,175 $424,413 $411,771
======== ======== ========
Income from electric operations - After income tax .............. $ 96,680 $101,867 $110,738
======== ======== ========
NUMBER OF ELECTRIC CUSTOMERS (Average for Period):
Residential ................................................... 233,795 227,575 223,364
Commercial .................................................... 28,678 27,781 27,176
Industrial .................................................... 963 974 967
Public street and highway lighting ............................ 308 302 301
-------- -------- --------
Total retail customers ...................................... 263,744 256,632 251,808
Other electric utilities ...................................... 28 26 23
-------- -------- --------
Total electric customers .................................... 263,772 256,658 251,831
======== ======== ========
ELECTRIC RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWH) ................................. 13,406 13,287 13,800
Revenue per KWH (in cents) .................................... 4.91 4.83 4.84
Annual revenue per customer .................................. $658.39 $641.87 $667.81

(1) Includes firm contract obligations of 485 MW, 462 MW and 323 MW and 120 MW,
63 MW and 247 MW of non-firm sales in 1993, 1992 and 1991, respectively.

(2) Includes firm contract obligations of 610 MW, 468 MW and 474 MW in 1993,
1992 and 1991, respectively; 1991 results do not include 150 MW for non-firm
sales. There were no non-firm sales in 1993 or 1992 during the summer
system peak period.

9
THE WASHINGTON WATER POWER COMPANY

NATURAL GAS SERVICE

NATURAL GAS COMPETITION AND BUSINESS OVERVIEW

Natural gas is priced competitively compared to other alternative fuel sources
for both residential and commercial customers. The Company provides programs
that encourage electric customers to convert to natural gas. Significant
growth has occurred in the Company's natural gas business in recent years due
to these conversions. The Company also makes sales or provides transportation
service directly to large natural gas customers.

Challenges facing the Company's natural gas business include the potential for
customers to by-pass the Company and securing competitively priced natural gas
supplies for the future. Since 1988 one of the Company's large industrial
customers has built its own pipeline interconnection. However, this customer
still purchases some natural gas services from the Company. The Company prices
its natural gas services, including transportation contracts, competitively and
has varying degrees of flexibility to price its transportation and delivery
rates by means of special contracts to assist in retaining potential by-pass
customers. The Company has signed long-term transportation contracts with two
of its largest industrial customers which minimizes the chances of these
customers by-passing the Company's system.

Order 636B adopted by FERC in 1992 provides the Company more flexibility in
optimizing its natural gas transportation and supply portfolios. While rate
design changes have increased the costs of firm transportation to low load
factor pipeline customers such as the Company, flexible receipt and delivery
points and capacity releases allow temporarily under-utilized transportation to
be released to others when not needed to serve the Company's customers.

NATURAL GAS SYSTEM

The Company's natural gas operations are operated as separate divisions, with
the WWP service territory including the Washington and Idaho properties and the
WPNG service territory including Oregon and California properties.

Natural Gas Supply The Company has access to four natural gas pipelines,
Northwest Pipeline Company (NWP), Pacific Gas Transmission (PGT), Paiute
Pipeline (Paiute) and Alberta Natural Gas Co. Ltd. (ANG), which provide the
Company access to both domestic and Canadian natural gas supplies. Due to this
resource portfolio, the Company remains one of the nation's lowest-cost local
distribution companies. Both WWP and WPNG contract with (1) NWP for three
types of firm service: transportation, liquefied natural gas storage and
underground storage and (2) PGT and ANG for firm transportation. WPNG also
contracts with Paiute for firm transportation and liquefied natural gas storage
to deliver natural gas to its California customers.

Firm winter natural gas supplies are purchased by the Company through
negotiated agreements having terms ranging between one month and eleven years
with a variety of natural gas suppliers. As a result of FERC Order 636B, WWP
has completed the process of converting its NWP natural gas sales to firm
transportation and assuming its share of NWP's natural gas supply contracts.

In January 1993, the Company contracted with ANG, PGT, NWP and Paiute for
additional transportation capacity to be available by November 1995 for service
in the Oregon and California service territory of WPNG. The Company has also
contracted with PGT and ANG for additional capacity for service beginning in
1995 for its Washington and Idaho properties.

Jackson Prairie Natural Gas Storage Project (Storage Project) The Company
retains a one-third ownership interest in the Storage Project, which is an
underground natural gas storage field located near Chehalis, Washington. Under
FERC's open access policy the role of the Storage Project in providing flexible
natural gas supplies is increasingly important to the Company's natural gas
operations. The Storage Project enables the Company to place natural gas into
storage when prices are low or to meet minimum natural gas purchasing
requirements, as well as to withdraw natural gas from storage when spot prices
are high or as needed to meet high demand periods. The Company has released
some of its Storage Project capacity to two other utilities until 1995 and 1996
with a provision under one of the releases to partially recall the released
capacity if the Company determines additional natural gas is required for its
own system supply.

Natural Gas Transportation Services The Company provides transportation
service to customers who obtain their own natural gas supplies. Transportation
service continued to be a significant component of the Company's total system
deliveries in 1993. The competitive nature of the spot natural gas market
results in savings in the cost of purchased natural gas, which encourages large
customers with fuel-switching capabilities to continue to utilize natural gas
for their energy needs. The total volume transported on behalf of
transportation customers was approximately 197.5 million therms in 1993. This
total volume represented approximately 40% of the Company's total system
deliveries in 1993.

10
THE WASHINGTON WATER POWER COMPANY

NATURAL GAS REGULATORY ISSUES

The Company, as a public utility, is currently subject to regulation by several
state utility commissions with respect to rates, accounting, the issuance of
securities and other matters. The natural gas operations are subject to the
jurisdiction of the WUTC, IPUC, OPUC and CPUC in addition to the FERC with
respect to natural gas rates charged for the release of capacity from the
Storage Project. Refer to Electric Regulatory Issues for additional details
regarding the rate setting process.

General Rate Cases

The Company has no current plans to file for any natural gas general rate cases
in 1994. The following table summarizes information for the Company's most
recent general natural gas rate cases (1):

Approved Effective Change
------------------------ -------------------------
Jurisdiction Effective Date ROE Amount (2) %
------------ -------------- ----- ---------- -----
(000's)

WUTC 8-90 12.90 1,131 2.58
IPUC 10-89 12.75 (579) (3.66)
Reconsideration 2-90 12.75 135 0.86

(1) In addition, the Company from time to time, upon request, receives
regulatory approval from the WUTC, the IPUC, the OPUC and the CPUC to
adjust rates to reflect changes in the cost of purchased natural gas
between general rate cases.
(2) Anticipated annual revenue effect.

In September 1991, the Company commenced operations in both California and
Oregon upon the acquisition of the natural gas properties of CP National. The
conditions of the CPUC order approving the acquisition included an exemption
from filing a general rate case until January 1, 1994 and a rate "freeze" until
January 1, 1995. On October 20, 1993, the CPUC granted a one year extension to
January 1, 1995 before the Company is required to file a general rate case. As
a result, the existing rate "freeze" will continue until at least January 1,
1996. The OPUC also authorized a general rate "freeze" which extends to
December 31, 1995. Purchased natural gas costs will continue to be tracked
through to customers in both jurisdictions during the rate "freeze" period.

Integrated Resource Planning (IRP) In 1993 biannual natural gas IRP reports
were accepted by both the WUTC and OPUC. Refer to Electric Regulatory Issues
for a description of the IRP process.

Demand Side Management (DSM) Included with the WUTC and IPUC electric DSM
applications discussed above under Electric Regulatory Issues, the Company
requested approval of new natural gas tariffs which would provide for the
implementation of new and revised energy efficiency programs for the Company's
residential, commercial and industrial natural gas customers. In conjunction
with the request for tariff approval, the Company requested approval of
associated natural gas DSM accounting treatment. With only minor
modifications, the applications were approved. The effective dates for
implementation were May 1 and July 17, 1992 in Washington and Idaho,
respectively, with revisions made in July 1993 and future justification
required for continuance of programs beyond December 31, 1994.

On December 21, 1993, the OPUC authorized the Company to defer revenue
requirement amounts associated with its WPNG DSM investments, and established
an annual rate adjustment mechanism to reflect the deferred costs on a timely
basis. Under this authorization, each December 1 the Company will file a rate
adjustment to recover DSM program costs and margin losses. This filing will be
concurrent with the Company's annual natural gas tracker filing. The effective
date for both the deferrals and the rate adjustment mechanism was January 1,
1994.

Natural Gas Trackers In the second quarter of 1993, the Company filed special
natural gas trackers with the WUTC, IPUC, OPUC and CPUC due primarily to the
increased costs from the pipelines related to the implementation of FERC Order
636B. The increases range from 3% to 25% but will result in no additional net
income to the Company. The trackers were approved by all four state
commissions.

In a separate proceeding, the annual Oregon natural gas tracker became
effective on December 1, 1993. The tracker will increase overall revenue by
about $3.1 million or 8.74% in Oregon but will result in no additional net
income to the Company as it is only a passthrough of changes in the cost of
purchased natural gas and amortization rates pursuant to the Company's natural
gas tracker. The filing also included the acquisition of additional capacity
over the PGT system.

THE WASHINGTON WATER POWER COMPANY

NATURAL GAS OPERATING STATISTICS

Years Ended December 31,
------------------------------
1993 1992 1991(1)
-------- -------- -------

SOURCES OF SUPPLY (Thousands of Therms):
Purchases ..................................................... 300,572 232,726 210,220
Storage - injections .......................................... (26,398) (5,478) (15,633)
Storage - withdrawals ......................................... 20,153 17,229 6,038
Natural gas for transportation ................................ 197,499 181,145 143,222
Distribution system gains (losses)............................. 7,416 (2,663) 984
-------- -------- --------
Total supply ............................................... 499,242 422,959 344,831
======== ======== ========
THERMS DELIVERED (Thousands of Therms):
Residential ................................................... 151,261 117,660 91,786
Commercial .................................................... 114,793 95,624 79,745
Industrial - firm ............................................. 19,035 15,822 13,750
Industrial - interruptible .................................... 15,747 12,350 15,582
-------- -------- --------
Total retail sales .......................................... 300,836 241,456 200,863
Transportation ................................................ 197,499 181,145 143,222
Company use ................................................... 907 358 746
-------- -------- --------
Total therms - sales and transportation ..................... 499,242 422,959 344,831
======== ======== ========
NET SYSTEM MAXIMUM CAPABILITY (Thousands of Therms):
Net system maximum demand (winter) ............................ 2,651 2,277 1,983
Net system maximum firm contractual capacity
(winter) .................................................... 3,523 3,786 2,803

NATURAL GAS OPERATING REVENUES (Thousands of Dollars):
Residential ................................................... $ 68,137 $ 48,395 $ 34,147
Commercial .................................................... 43,542 31,984 23,996
Industrial - firm ............................................. 6,089 4,506 3,477
Industrial - interruptible .................................... 4,784 3,204 3,047
-------- -------- --------
Total retail revenues ....................................... 122,552 88,089 64,667
Transportation ................................................ 10,923 8,663 5,274
Miscellaneous revenues ........................................ 4,072 3,818 3,363
-------- -------- --------
Total natural gas revenues .................................. $137,547 $100,570 $ 73,304
======== ======== ========
Income from natural gas operations -
After income tax ............................................ $ 15,576 $ 9,068 $ 10,265
======== ======== ========
NUMBER OF NATURAL GAS CUSTOMERS (Average for Period):
Residential ................................................... 162,400 148,242 137,726
Commercial .................................................... 22,526 21,816 21,169
Industrial - firm ............................................. 268 266 267
Industrial - interruptible .................................... 39 29 29
-------- -------- --------
Total retail customers ...................................... 185,233 170,353 159,191
Transportation ................................................ 56 60 58
-------- -------- --------
Total natural gas customers ................................. 185,289 170,413 159,249
======== ======== ========
NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
WWP
Annual use per customer (therms) ............................ 1,025 864 934
Revenue per therm (in cents) ................................ 41.55 37.05 35.08
Annual revenue per customer ................................ $425.82 $319.99 $327.57
WPNG
Annual use per customer (therms) ............................ 775 679 250
Revenue per therm (in cents) ................................ 52.78 49.64 49.58
Annual revenue per customer ................................ $409.11 $337.06 $123.79

HEATING DEGREE DAYS:
Spokane, WA
Actual ...................................................... 7,224 6,134 6,639
30 year average ............................................. 6,882 6,882 6,882
% of average ................................................ 105.0 89.1 96.5
Medford, OR
Actual ...................................................... 4,396 3,653 1,607
30 year average ............................................. 4,798 4,798 1,823
% of average ................................................ 91.6 76.1 88.2

(1) Includes WPNG results from September 30 to December 31 except where
otherwise noted; includes a three-month average of WPNG customers and a
twelve-month average of WWP customers.

12
THE WASHINGTON WATER POWER COMPANY

ENVIRONMENTAL MATTERS

The Company is subject to environmental regulation by federal, state and local
authorities. The generation, transmission, distribution, service and storage
facilities in which the Company has an ownership interest have been designed to
comply with all environmental laws presently applicable.

The Company was named a potentially responsible party under the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980 ("CERCLA" or
"Superfund") at the Coal Creek site in Chehalis, Washington. The estimated
cost of clean-up is $12,000,000, which is being shared by over 90 utilities.
The Company is responsible for approximately $800,000 of this cost, the
majority of which was spent in 1993.

In 1993 the EPA referred a matter to the U.S. Justice Department requesting the
Company and other potentially responsible parties to enter into negotiations
for the recovery of costs incurred by EPA and for initiation of action in
connection with the clean-up at the Spokane Junk Yard Site located in Spokane,
Washington. If an action is commenced, the claim is expected to be for $2.4
million in site stabilization costs plus additional costs including attorneys'
fees and site rehabilitation costs. The Company has no records showing that
any Company equipment was ever deposited at the Spokane Junk Yard Site or that
PCB contaminated equipment was delivered to any company which disposed of
materials at the site. Therefore, the Company has disclaimed any liability
with respect to the Spokane Junk Yard Site. If an action is commenced, the
Company will vigorously defend against such claim.

Refer to both Note 11 to Financial Statements: Commitments and Contingencies
and Significant Trends in Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations for additional information.

NON-UTILITY BUSINESS

As of December 31, 1993, the Company had an investment of approximately $93
million in non-utility operations, of which about $86 million was invested in
Pentzer. The remainder was invested in three non-operating subsidiaries, the
largest of which is WIDCo, which maintains a small investment portfolio.
Substantially all of the non-utility operations are controlled by Pentzer, a
wholly owned subsidiary of the Company.

As of December 31, 1993, Pentzer had approximately $130 million in total
assets, or about 7% of the Company's consolidated assets. Pentzer's portfolio
of investments includes companies involved in advertising display
manufacturing, electronic technology, energy services, financial services, real
estate development and telecommunications.

Pentzer's current investment profile focuses on manufacturers and distributors
of industrial and consumer products as well as service businesses. The Company
seeks businesses with above average records of earnings growth in industries
that are not cyclical or dependent upon high levels of research and
development. Emphasis is placed on leading companies with strong market
franchises, dominant or proprietary product lines or other significant
competitive advantages. Pentzer is particularly interested in companies
serving niche markets. Total investment in any one company is generally
limited to $15 million, and control of the acquired company's board of
directors is generally required.

Pentzer's business strategy is to acquire controlling interests in a broad
range of middle market companies, to help these companies grow through internal
development and strategic acquisitions, and to sell the portfolio investments
either to the public or to strategic buyers when it becomes most advantageous
in meeting Pentzer's return on invested capital objectives. Pentzer's goal is
to produce financial returns for the Company's shareholders that, over the long
term, should be higher than that of the utility operations. From time to time,
a significant portion of Pentzer's earnings contributions may be the result of
transactional gains. Accordingly, although the income stream is expected to be
positive, it may be uneven from year to year.

13
THE WASHINGTON WATER POWER COMPANY

ITEM 2. PROPERTIES

ELECTRIC PROPERTIES

The Company's electric properties, located in the States of Washington, Idaho
and Montana, include the following:

Generating Plant

Nameplate Present Year of
No. of Rating Capability FERC License
Units (MW)(1) (MW)(2) Expiration
------ -------- -------- ------------

Hydro Generating Stations (River)
Washington:
Long Lake (Spokane) 4 70.0 72.8 2007
Little Falls (Spokane) 4 32.0 36.0 N/A
Nine Mile (Spokane) 4 12.4 9.0(3) 2007
Upper Falls (Spokane) 1 10.0 10.2 2007
Monroe Street (Spokane) 1 14.8 10.0(4) 2007
Meyers Falls (Colville) 2 1.2 1.3 2023
Idaho:
Cabinet Gorge (Clark Fork) 4 212.5 172.5(5) 2001
Post Falls (Spokane) 6 14.8 18.0 2007
Montana:
Noxon Rapids (Clark Fork) 5 466.2 554.0 2005
------- -------
Total Hydro 833.9 883.8

Thermal Generating Stations
Washington:
Centralia (6) 2 199.5 197.0
Kettle Falls 1 50.7 46.5
Northeast Combustion Turbine (7) 2 61.2 68.0
Montana:
Colstrip (Units 3 and 4) (6) 2 233.4 216.0
------- -------
Total Thermal 544.8 527.5

Total Generation 1,378.7 1,411.3
======= =======

N/A Not applicable.
(1) Nameplate Rating, also referred to as "installed capacity", is the
manufacturer's assigned rating under specified conditions.
(2) Capability is the maximum generation of the plant without exceeding
approved limits of temperature, stress and environmental conditions.
(3) Due to the redevelopment project which was started during 1993, the actual
plant capability at year end declined from 18 MW; upon completion of this
project in mid-1994, the plant capability is expected to rise to 29 MW.
(4) Reduced from 13 MW due to possible penstock enlargement; if completed, the
plant capability is expected to return to 13 MW.
(5) Due to the upgrade project started during 1993 on unit no. 1, the actual
plant capability at year end declined from 230 MW; upon completion of this
project in mid-1994, the plant capability is expected to rise to 240 MW.
(6) Jointly-owned. Data above refers to Company's respective 15% interests.
(7) Used primarily for peaking needs.

Distribution and Transmission Plant

The Company operates approximately 11,250 miles of distribution lines in its
electric system. The Company's transmission system consists of approximately
550 miles of 230 KV line and 1,500 miles of 115 KV line. The Company also owns
a 10% interest in 495 miles of a 500 KV line from Colstrip, Montana and a 15%
interest in 3 miles of a 500 KV line from Centralia, Washington to the nearest
BPA interconnections.

The 230 KV lines are used primarily to transmit power from the Company's Noxon
Rapids and Cabinet Gorge hydro generating stations to major load centers in the
Company's service area. The 230 KV lines also transmit to points of
interconnection with adjoining electric transmission systems for bulk power
transfers. These lines interconnect with BPA

14
THE WASHINGTON WATER POWER COMPANY

at five locations and at one location each with PacifiCorp, Montana Power and
Idaho Power Company. The BPA interconnections serve as points of delivery for
power from the Colstrip and Centralia generating stations as well as for the
interchange of power with the Southwest. The interconnection with PacifiCorp
is the point of delivery for power purchased by the Company from Mid-Columbia
projects' hydro generating stations.

The 115 KV lines provide for transmission of energy as well as providing for
the integration of the Spokane River hydro and Kettle Falls wood-waste
generating stations with service area load centers. These lines interconnect
with BPA at nine locations, Grant County PUD at three locations, Seattle City
Light and Tacoma City Light at two locations and one each with Chelan County
PUD, PacifiCorp, and Montana Power.

Electric Projects Under Construction

Rathdrum Combustion Turbine On October 5, 1993, the IPUC issued an order
approving the combustion turbine project consisting of two 88 MW units.
Construction has begun on the project, which is designed to meet the Company's
peaking needs for both its retail and wholesale obligations. The air quality
permit that has been issued, which allows for the operation of the project as
scheduled, has been challenged and is currently under administrative review.
Natural gas will be used as both the primary and back-up fuel. The Company has
obtained separate construction and long-term lease financing for this project.
The project is currently expected to be completed by early 1995 at an expected
cost of $66 million, of which $29 million had been spent as of December 31,
1993.

Company Hydro The Company continues to study its hydroelectric facilities on
both the Spokane and Clark Fork Rivers to identify additional economic
hydroelectric generating potential. Turbine efficiency improvements are
underway at the Nine Mile project that would increase generating capacity by 12
MW to a total of 29 MW by mid-1994 at an expected cost of $20 million. Similar
improvements are underway at the Cabinet Gorge powerhouse that would increase
capacity by approximately 10 MW to a total of 240 MW at an expected cost of $12
million; it is expected back on-line by the end of the first quarter 1994.
Feasibility studies for upgrading the Company's other hydroelectric facilities
are continuing.

Proposed Acquisition

On February 15, 1994, the Company announced it had reached agreement to acquire
the northern Idaho electric properties of Pacific Power and Light Company, an
operating division of PacifiCorp. The cash purchase price will be $26 million,
subject to closing adjustments, and includes a premium above the book value of
the net assets acquired. Pacific Power's northern Idaho electric system
currently serves approximately 9,300 residential, commercial and industrial
customers. The purchase is subject to regulatory approval by the IPUC and the
FERC. Closing of the transaction is expected to occur during the summer of
1994. See Note 14 to Financial Statements for additional information related
to this acquisition.

NATURAL GAS PROPERTIES

The WWP and WPNG service territories' natural gas properties have natural gas
distribution mains of approximately 2,912 miles and 1,410 miles, respectively.

The Company, NWP and Washington Natural Gas Company each own a one-third
undivided interest in the Storage Project. The Storage Project has a total
peak day deliverability of 4.6 million therms, with a total working natural gas
inventory of 155.2 million therms.

ITEM 3. LEGAL PROCEEDINGS

Refer to Note 11 to Financial Statements: Commitments and Contingencies.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable.

15
THE WASHINGTON WATER POWER COMPANY

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Outstanding shares of Common Stock are listed on the New York and Pacific Stock
Exchanges. As of February 25, 1994, there were approximately 36,000 registered
shareholders of the Company's no par value Common Stock.

It is the intention of the Board of Directors to continue to pay dividends
quarterly on the Common Stock, but the amount of such dividends is dependent on
future earnings, the financial position of the Company and other factors.

For further information, see Notes 8 and 15 to Financial Statements.

16
THE WASHINGTON WATER POWER COMPANY

ITEM 6. SELECTED FINANCIAL DATA

On November 9, 1993, the Company distributed, to shareholders of record on
October 25, 1993, shares of its common stock, without par value, under a
two-for-one stock split effected in the form of a 100% stock dividend. All
references to number of shares and per share information have been adjusted to
reflect the common stock split on a retroactive basis.

In 1992, Pentzer's common stock ownership in ITRON was reduced from
approximately 60% to approximately 40% as a result of the issuance of common
stock by ITRON in an acquisition. Accordingly, beginning in 1992, Pentzer's
share of ITRON's earnings is accounted for by the equity method and is included
in Other Income-Net and its investment in ITRON is reflected on the balance
sheet under Other Property and Investments. ITRON's initial public offering in
November 1993 and Pentzer's sale of a portion of its ITRON stock resulted in a
reduction in Pentzer's ownership interest in ITRON to approximately 25%.

The Company purchased natural gas distribution properties in Oregon and
California from CP National Corporation on September 30, 1991. The 1991
financial information reflects three months of operations of these properties.

On July 31, 1990, WIDCo sold its 50% interest in its coal mining properties.
The consolidated financial statements, notes and selected financial data have
been reclassified to reflect the continuing operations of the Company. The
revenues, expenses, assets and liabilities of the discontinued operations have
been reclassified from those categories and netted into single line items in
the income statements and balance sheets.

(Thousands of Dollars except Per Share Data and Ratios)

Years Ended December 31
---------------------------------------------------------------------
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------

Operating Revenues:
Utility . . . . . . . . . . . . $ 601,722 $ 524,983 $ 485,075 $ 470,655 $ 470,585
Non-Utility . . . . . . . . . . 38,877 32,775 81,732 83,786 58,216
---------- ---------- ---------- ---------- ----------
Total . . . . . . . . . . . . . 640,599 557,758 566,807 554,441 528,801
AFUDC/AFUCE . . . . . . . . . . 4,964 3,751 1,999 645 646
Accelerated ADITC . . . . . . . - - - - 9,300
Net Income:
Utility . . . . . . . . . . . . 69,510 63,975 69,211 71,463 61,471
Non-Utility . . . . . . . . . . 13,266 8,292 1,420 684 4,936
Discontinued Operations . . . . - 2,403 1,553 15,457 5,664
---------- ---------- ---------- ---------- ----------
Total . . . . . . . . . . . . . 82,776 74,670 72,184 87,604 72,071
Preferred Stock Dividend
Requirements . . . . . . . . . 8,335 6,817 9,292 8,419 11,750
Income Available for Common Stock 74,441 67,853 62,892 79,185 60,321
Average Common Shares
Outstanding (000s) . . . . . . 51,616 49,550 46,916 45,723 44,647
Earnings per Share:
Utility . . . . . . . . . . . 1.19 1.15 1.28 1.38 1.11
Non-Utility . . . . . . . . . .25 .17 .03 .01 .11
Discontinued operations . . . - .05 .03 .34 .13
---------- ---------- ---------- ---------- ----------
Total . . . . . . . . . . . . 1.44 1.37 1.34 1.73 1.35
Dividends Paid per Common Share.. 1.24 1.24 1.24 1.24 1.24
Total Assets at Year-End:
Utility . . . . . . . . . . . 1,701,652 1,424,812 1,394,800 1,275,122 1,251,882
Non-Utility . . . . . . . . . . 136,186 109,203 126,713 130,889 123,188
---------- ---------- ---------- ---------- ----------
Total . . . . . . . . . . . . 1,837,838 1,534,015 1,521,513 1,406,011 1,375,070
Long-term Debt at Year-End. . . . 647,229 596,897 633,434 561,197 561,265
Preferred Stock Subject to
Mandatory Redemption at
Year-End . . . . . . . . . . . 85,000 85,000 50,000 50,000 70,000
Ratio of Earnings to Fixed Charges 3.45 3.08 2.96 2.79 2.71
Ratio of Earnings to Fixed Charges
and Preferred Dividend
Requirements . . . . . . . . . . 2.77 2.57 2.35 2.31 2.08

17
THE WASHINGTON WATER POWER COMPANY

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The Company is primarily engaged as a utility in the generation, purchase,
transmission, distribution and sale of electric energy and the purchase,
transportation, distribution and sale of natural gas. Natural gas operations
are affected to a significant degree by weather conditions and customer growth.
The Company's electric operations are highly dependent upon hydroelectric
generation for its power supply. As a result, the electric operations of the
Company are significantly affected by weather and streamflow conditions and, to
a lesser degree, by customer growth. Revenues from the sale of surplus energy
to other utilities and the cost of power purchases vary from year to year
depending on streamflow conditions and the wholesale power market. The
wholesale power market in the Northwest region is affected by several factors,
including the availability of water for hydroelectric generation, the
availability of base load plants in the region and the demand for power from
the Southwest region. Usage by retail customers varies from year to year
primarily as a result of weather conditions, the economy in the Company's
service area, customer growth and conservation.

The Company will continue to emphasize the efficient use of energy by its
customers, increase efforts to grow its customer base, especially natural gas,
and continue to manage its operating costs, increase revenues and improve
margins. The Company will also pursue resource opportunities through demand
side management, system upgrades, purchases and other options that will result
in obtaining electric power and natural gas supplies at the lowest possible
cost.

The Company purchased natural gas distribution properties in Oregon and
California from CP National Corporation on September 30, 1991. The 1991
financial statements reflect three months of operations of these properties.
See Note 14 to Financial Statements for further information.

RESULTS OF OPERATIONS

OVERALL OPERATIONS

Overall earnings per share for 1993 were $1.44, compared to $1.37 in 1992 and
$1.34 in 1991. The 1993 results include transactional gains totaling $12.8
million recorded by Pentzer Corporation (Pentzer) as a result of the sale of
several investments in its portfolio and the sale of stock in the initial
public offering by ITRON, Inc. (ITRON) in November 1993. The 1992 results
include an after-tax gain of $4.4 million, or $0.09 per share, due to the
issuance of common stock by ITRON in an acquisition and a transactional gain of
$1.2 million due to the sale of Pentzer's interest in a company involved in
power plant maintenance. Discontinued coal mining operations contributed $2.4
million to net income, or $0.05 per share, in 1992 and $1.6 million, or $0.03
per share, in 1991.

Earnings per share from continuing operations were $1.44 for 1993, $1.32 for
1992 and $1.31 for 1991. Utility income available for common stock increased
$4.0 million, or 7.0%, in 1993 after decreasing $2.8 million, or 4.6%, in 1992.
Utility income available for common stock contributed $1.19 to earnings per
share in 1993, compared to $1.15 in 1992 and $1.28 in 1991. Non-utility income
available for common stock from continuing operations increased $5.0 million in
1993 and $6.9 million in 1992 and contributed $0.25 to earnings per share in
1993, compared to $0.17 in 1992 and $0.03 in 1991.

Slightly colder-than-normal weather during 1993 impacted both electric and
natural gas operations as compared to 1992. Income from electric operations
decreased $1.8 million in 1993, as compared to 1992, primarily as a result of
increases in purchased power costs due to thermal plant outages, a large sale
of wholesale energy and lower hydroelectric generation due to below normal
streamflows, and increases in other operating and maintenance expenses. Income
from natural gas operations increased $9.3 million in 1993 over 1992 due
primarily to increased customer usage from the colder weather and customer
growth. Warmer-than-normal weather throughout most of 1992 significantly
impacted both electric and natural gas operations during the year. Increased
purchased power and fuel costs, due to low hydroelectric generation and reduced
streamflows, combined with decreased customer usage, were responsible for a
decrease of $10.2 million in 1992 income from electric operations as compared
to 1991. Income from natural gas operations decreased $2.3 million in 1992, as
compared to 1991, due primarily to reduced revenues as a result of the
warmer-than-normal temperatures.

18
THE WASHINGTON WATER POWER COMPANY

Electric revenues and expenses were both impacted by a ten-year power purchase
contract, effective January 1992, with Potlatch Corporation (Potlatch), one of
the Company's major industrial customers. Under terms of the agreement, the
Company purchases 50-55 average MW of Potlatch's electric generation and makes
available up to approximately 95 average MW of firm energy for sale. In
addition, the Company makes available 25 average MW of interruptible energy and
Potlatch must provide an equivalent amount of reserve generation capacity in
case of interruption. The increased KWH sales to Potlatch result in increased
industrial revenues to the Company, while the purchase of Potlatch's generating
output increases purchased power expense.

Non-recurring adjustments were made in 1991 to establish reserves for potential
write-offs related to the recovery of costs associated with the Creston
Project, a proposed 2,000 MW coal-fired generating station located near
Creston, Washington, and related transmission. The reserves were calculated
assuming regulators would allow the Company to recover its investment, but
would not allow the Company to earn a return on the investment during a
recovery period. Through December 31, 1993, the Company had invested $11.0
million in the Creston Project. These adjustments decreased Other Income net
of taxes in 1991 by $3.2 million. A non-recurring adjustment was also made
during 1991 to adjust previous accruals of deferred federal income tax related
to electric operations. This adjustment decreased income taxes by $4.0 million
in 1991.

Interest expense decreased $3.4 million in 1993 and $1.0 million in 1992. From
1991 through 1993, $69 million of long-term debt matured and $344 million of
higher-cost debt was redeemed and refinanced at lower interest rates.

Preferred stock dividend requirements increased $1.5 million, or 22.3%, in 1993
due to the issuance of preferred stock in late 1992. Preferred stock dividend
requirements decreased $2.5 million, or 26.6%, in 1992. The redemption of
preferred stock in early 1992, combined with an issuance later in the year at a
lower dividend rate and lower rates on variable rate preferred stock were the
primary reasons for the 1992 decrease.

UTILITY OPERATIONS

Electric Operating Income Summary

1993 vs 1992 1992 vs 1991
Electric Operations --------------- ---------------
(dollars in thousands) 1993 Incr(Decr) % 1992 Incr(Decr) % 1991
---------------------- -------- ---------- --- -------- ---------- --- --------

Operating Revenues $464,175 $39,762 9 $424,413 $12,642 3 $411,771

Operating Expenses:
Purchased Power 118,809 27,100 30 91,709 22,263 32 69,446
Fuel for generation 34,233 (2,863) (8) 37,096 5,297 17 31,799
Other Operating & Maintenance 68,567 10,709 19 57,858 (7,884) (12) 65,742
Administrative & General 29,225 1,170 4 28,055 1,854 7 26,201
Depreciation & Amortization 46,324 4,856 12 41,468 905 2 40,563
Taxes Other than Income 35,021 587 2 34,434 366 1 34,068
-------- ------- --------- -------- ---------
Total Operating Expenses 332,179 41,559 14 290,620 22,801 9 267,819
-------- ------- --------- -------- ---------
Income from Operations 131,996 (1,797) (1) 133,793 (10,159) (7) 143,952
Electric Operations Income Taxes 35,316 3,390 11 31,926 (1,288) (4) 33,214
-------- ------- --------- -------- ---------
Net Operating Income (1) $ 96,680 $(5,187) (5) $101,867 $(8,871) (8) $110,738
======== ======= ======== ======= ========

(1) Does not include interest expense or other income.

Electric revenues increased in all classes for 1993, as compared to 1992, as a
result of customer growth, increased wholesale sales and a slight increase in
customer usage due to colder than normal weather. As the Company's Demand Side
Management programs grow, the electric load is becoming less weather-sensitive
as a result of the shifting of a greater portion of the heat load to natural
gas. Residential and commercial revenues increased by $12.8 million, primarily
as a result of a 3% growth in customers in 1993. Industrial sales during 1993
increased by $6.2 million, or 12%, primarily due to increased KWH sales under
the Potlatch agreement discussed earlier. Wholesale revenues increased by
$16.8 million, or 18%, due primarily to a large sale of wholesale energy over a
six-week period in the first quarter of 1993.

19
THE WASHINGTON WATER POWER COMPANY

Electric revenues increased by 3% in 1992, compared to 1991, due to a
combination of increased industrial sales and customer growth, which offset the
decrease in residential usage due to warm weather. The Company's electric
customer base grew by 2% in 1992, in both the residential and commercial
sectors, which helped to reduce the weather-related impact on revenues.
Industrial sales increased by $11.5 million, or 29%, primarily due to increased
KWH sales under the Potlatch agreement discussed earlier. Commercial sales
increased $4.7 million, or 4%, in 1992, as compared to 1991, due to customer
growth. Residential revenues decreased by $3.1 million, despite a 2% increase
in customers, due to warm weather throughout most of 1992. Wholesale KWH sales
were down 23% in 1992, reflecting low streamflow conditions during the year.
However, increased prices in the secondary market resulted in decreased
wholesale revenues of only $0.6 million, or 1%, in 1992 from 1991.

Electric Revenues, KWH Sales, and Customers by Service Class

1993 vs 1992 1992 vs 1991
(Revenues in thousands, --------------- ---------------
KWH sales in millions) 1993 Incr(Decr) % 1992 Incr(Decr) % 1991
----------------------- -------- ---------- --- -------- --------- --- --------

Electric Revenues:
Residential $153,929 $7,856 5 $146,073 $(3,092) (2) $149,165
Commercial 126,256 4,979 4 121,277 4,713 4 116,564
Industrial 57,133 6,199 12 50,934 11,519 29 39,415
Other Utilities 108,634 16,843 18 91,791 (557) (1) 92,348

Electric KWH Sales:
Residential 3,134 110 4 3,024 (58) (2) 3,082
Commercial 2,373 74 3 2,299 78 4 2,221
Industrial 1,644 81 5 1,563 415 36 1,148
Other Utilities 3,258 96 3 3,162 (942) (23) 4,104

Electric Customers (average):
Residential 233,795 6,220 3 227,575 4,211 2 223,364
Commercial 28,678 897 3 27,781 605 2 27,176
Industrial 963 (11) (1) 974 7 1 967
Other Utilities 28 2 8 26 3 13 23

Below-normal streamflow conditions and thermal plant outages significantly
affected 1993 electric operating results. Hydroelectric generation was 11%
below normal, caused by streamflows which were 86% of normal. Purchased power
increased by $27.1 million, or 30%, in 1993 primarily due to reduced
hydroelectric generation early in the year, a large sale of wholesale energy in
the first quarter and to replace lost thermal generation due to plant outages.
In October 1989, the Idaho Public Utilities Commission (IPUC) approved the
Company's filing for a Power Cost Adjustment (PCA) designed to allow the
Company to change rates to recover or rebate a portion of the difference
between actual and allowed net power supply costs. Net PCA adjustments
accounted for $4.6 million of the increase in other operating and maintenance
expenses from 1992. Higher levels of purchased power resulted in higher
transmission costs which also contributed to the increase in other operating
and maintenance expenses in 1993 over 1992. Shutdowns at thermal generation
plants and improved streamflows in the latter part of 1993 were the primary
reasons for the $2.9 million decrease in fuel costs, and repairs at the plants
resulted in an increase of nearly $2.0 million in other operating and
maintenance expenses.

Warmer-than-normal weather and below-normal streamflow conditions significantly
affected 1992 electric operating results. Hydroelectric generation was 22%
below normal, caused by streamflows which were 64% of normal in 1992. In 1991,
streamflows were 116% of normal. Fuel costs and purchased power costs in 1992
were a combined $27.6 million, or 27%, over levels incurred during 1991, due to
low hydroelectric generation and the Potlatch agreement previously discussed.
Transmission and distribution costs, which decreased $2.2 million and $1.5
million, respectively, contributed to the $7.9 million, or 12%, decrease in
other operating and maintenance expenses. Transmission expenses decreased in
1992 over 1991 due to decreased wholesale KWH sales. Distribution expense was
lower in 1992, compared to 1991, due to mild weather and fewer storm-related
damages. Net PCA adjustments, resulting from low hydroelectric conditions and
prices of secondary energy, accounted for $3.3 million of the decrease in other
operating and maintenance expenses from 1991.

20
THE WASHINGTON WATER POWER COMPANY

NATURAL GAS OPERATIONS

Natural Gas Operating Income Summary

1993 vs 1992 1992 vs 1991
Natural Gas Operations --------------- ----------------
(dollars in thousands) 1993 Incr(Decr) % 1992 Incr(Decr) % 1991
----------------------- -------- --------- --- -------- ---------- --- -------

Operating Revenues $137,547 $36,977 37 $100,570 $27,266 37 $73,304

Operating Expenses:
Natural Gas Purchased 71,867 23,652 49 48,215 17,400 56 30,815
Other Operating & Maintenance 14,286 594 4 13,692 5,089 59 8,603
Administrative & General 13,220 657 5 12,563 2,544 25 10,019
Depreciation & Amortization 9,149 698 8 8,451 3,130 59 5,321
Taxes Other than Income 7,913 2,090 36 5,823 1,401 32 4,422
-------- ------- ------- ------- -------
Total Operating Expenses 116,435 27,691 31 88,744 29,564 50 59,180
-------- ------- ------- ------- -------
Income from Operations 21,112 9,286 79 11,826 (2,298) (16) 14,124
Natural Gas Oper. Income Taxes 5,536 2,778 101 2,758 (1,101) (29) 3,859
-------- ------- ------- ------- --------
Net Operating Income (1) $15,576 $6,508 72 $9,068 $(1,197) (12) $10,265
======== ======= ======= ======== ========

(1) Does not include interest expense or other income.

On September 30, 1991, the Company purchased the Oregon and South Lake Tahoe,
California, natural gas distribution assets of CP National Corporation. The
Company's natural gas operations are operated as separate divisions, with the
WWP service territory including the Washington and Idaho properties and the WP
Natural Gas (WPNG) service territory including the Oregon and California
properties. As of December 31, 1993, there were approximately 73,300 WPNG
natural gas customers and 122,500 WWP natural gas customers.

The Company's natural gas business experienced weather-related impacts on
operating results in both 1993 and 1992. In 1993, weather in the Washington
and Idaho service territory was 5% colder than normal, compared to 11% warmer
than normal in 1992. The Oregon service territory experienced temperatures
only 8% warmer than normal in 1993, compared to 24% warmer in 1992.
Substantial customer growth of 9% in 1993, along with colder weather,
contributed to increased revenues. The 7% growth in customers in 1992 helped
offset the impact of the weather.

Total natural gas operating revenues increased $37.0 million, or 37%, in 1993.
WPNG revenues accounted for an increase of $10.1 million, while WWP revenues
increased $26.9 million. Total therm sales increased by 18% in 1993 due to
customer growth in all service classes except transportation and higher
customer usage due to colder weather in 1993 as compared to 1992.
Approximately 40% of the customer growth in the WWP service area during 1993
was the result of the Company's emphasis on conversion from electric space and
water heating to natural gas through Demand Side Management programs.

Total natural gas revenues increased in all customer classes in 1992 from 1991
due to the WPNG acquisition. WPNG revenues accounted for an increase of $24.5
million in overall natural gas operating revenues, as compared to 1991. In
1992, natural gas revenues from WWP residential and commercial customers rose
by $2.0 million and $0.5 million, respectively, due to growth in the number of
customers, as usage per customer decreased as a result of warm temperatures.

21
THE WASHINGTON WATER POWER COMPANY

Natural Gas Revenues, Therm Sales, and Customers by Service Class

1993 vs 1992 1992 vs 1991
(Revenues in thousands, --------------- ---------------
therm sales in millions) 1993 Incr(Decr) % 1992 Incr(Decr) % 1991
------------------------ -------- ---------- --- --------- ---------- --- --------

Natural Gas Revenues:
Residential $ 68,137 $19,742 41 $ 48,395 $14,248 42 $ 34,147
Commercial 43,542 11,558 36 31,984 7,988 33 23,996
Industrial--firm 6,089 1,583 35 4,506 1,029 30 3,477
Industrial--interruptible 4,784 1,580 49 3,204 157 5 3,047
Transportation 10,923 2,260 26 8,663 3,389 64 5,274

Natural Gas Therm Sales:
Residential 151,261 33,601 29 117,660 25,874 28 91,786
Commercial 114,793 19,169 20 95,624 15,879 20 79,745
Industrial--firm 19,035 3,213 20 15,822 2,072 15 13,750
Industrial--interruptible 15,747 3,397 28 12,350 (3,232) (21) 15,582
Transportation 197,499 16,354 9 181,145 37,923 26 143,222

Natural Gas Customers (average):
Residential 162,400 14,158 10 148,242 10,516 8 137,726
Commercial 22,526 710 3 21,816 647 3 21,169
Industrial--firm 268 2 1 266 (1) - 267
Industrial--interruptible 39 10 34 29 0 - 29
Transportation 56 (4) (7) 60 2 3 58

Natural gas purchased expense increased $23.7 million, or 49%, in 1993 as
compared to 1992, primarily as a result of an increase in therm sales of 76.3
million, or 18%, across all customer classes due to customer growth and colder
weather. Taxes other than income and income taxes also increased substantially
in 1993 due to increased revenues and income.

Natural gas purchased expense and other operating and maintenance expenses
increased $17.4 million and $5.1 million, respectively, in 1992 from 1991. All
other expenses also increased substantially over 1991, primarily as a result of
the operation of the WPNG properties, combined with the Company's continued
emphasis on conversions from electric energy to natural gas.

NON-UTILITY OPERATIONS

Non-Utility Operations Summary

1993 vs 1992 1992 vs 1991
Non-Utility Operations -------------- ---------------
(dollars in thousands) 1993 Incr(Decr) % 1992 Incr(Decr) % 1991
----------------------- ------- --------- -- ------- ---------- --- -------

Operating revenues $38,877 $6,102 19 $32,775 $(48,957) (60) $81,732
Operating expenses 31,135 3,366 12 27,769 (52,862) (66) 80,631
------- ------ ------- -------- -------
Operating income 7,742 2,736 55 5,006 3,905 - 1,101
Other income - net 9,435 1,345 17 8,090 6,820 - 1,270
------- ------ ------- -------- -------
Income before income taxes 17,177 4,081 31 13,096 10,725 - 2,371
Income tax provision 3,911 (893) (19) 4,804 3,853 - 951
------- ------ ------- -------- -------
Net income $13,266 $4,974 60 $8,292 $ 6,872 - $ 1,420
======= ====== ======= ======== =======

Non-utility operations include the results of Pentzer and three non-operating
subsidiary companies. Pentzer's business strategy is to acquire controlling
interests in a broad range of middle-market companies, to help these companies
grow through internal development and strategic acquisitions, and to sell the
portfolio investments to the public or to strategic buyers when it becomes most
advantageous in meeting Pentzer's return on invested capital objectives.
Pentzer's goal is to produce financial returns for the Company's shareholders
that, over the long term, should be higher than that of the utility operations.
From time to time, a significant portion of Pentzer's earnings contributions
may be the result of transactional gains. Accordingly, although the income
stream is expected to be positive, it may be uneven from year to year.

22
THE WASHINGTON WATER POWER COMPANY

For the year ended December 31, 1993, Pentzer had consolidated earnings of
$19.7 million before provision for possible losses. At the end of the year,
Pentzer established a $7.0 million provision for possible write-off of a
portion of its investment portfolio. The provision was recorded based on the
determination that future cashflows may be lower than expected, impairing the
value of certain investments. After deducting this provision, Pentzer reported
consolidated earnings of $12.7 million, which represents a 50% increase over
Pentzer's 1992 earnings of $8.5 million. Pentzer's return on invested capital
increased from 12% in 1992 to 17% in 1993 due, in part, to transactional gains.

Pentzer earnings for 1993 were significantly impacted by transactional gains of
$7.1 million as a result of the sale of companies involved in
telecommunications, technology and energy and by a transactional gain of $5.7
million resulting from the successful completion by ITRON, a company in which
Pentzer is the largest shareholder, of an initial public offering which also
resulted in the sale of a portion of the ITRON shares owned by Pentzer. This
transaction reduced Pentzer's investment in ITRON from approximately 40% to
approximately 25%. Included in other income, total 1993 transactional gains of
$12.8 million compares with transactional gains of $5.6 million in 1992.

In addition to the transactional gains from ITRON in 1993, Pentzer also
recorded a $3.0 million increase in net income as a result of improved earnings
at ITRON.

Pentzer's earnings increase from 1991 to 1992 was primarily attributable to the
1992 transactional gains of $5.6 million relating to ITRON's issuance of common
stock in an acquisition and the sale of Pentzer's interest in a company
involved in power plant maintenance. This issuance of common stock reduced
Pentzer's ownership from approximately 60% to approximately 40%. Accordingly,
Pentzer's investment in ITRON after 1991 is accounted for by the equity method.
The 1991 results presented include ITRON on a fully consolidated basis. The
decrease in revenues and expenses from 1991 to 1992 was primarily due to the
change to the equity method of accounting for ITRON.

23
THE WASHINGTON WATER POWER COMPANY

LIQUIDITY AND CAPITAL RESOURCES

UTILITY

Capital expenditures, excluding Allowance for Funds Used During Construction
(AFUDC) and Allowance for Funds Used to Conserve Energy (AFUCE, a carrying
charge similar to AFUDC for conservation-related capital expenditures), were
$378 million for the 1991-1993 period. In addition, $69 million of long-term
debt matured and $344 million of higher-cost debt and preferred stock was
redeemed and refinanced at lower cost during the 1991-1993 period.

Capital expenditures are funded with internally-generated cash and external
financing. The level of cash generated internally and the amount that is
available for capital expenditures fluctuates from year to year.

During 1993, $274 million of long-term debt, with an average interest rate of
8.67% and 13.6 years remaining to maturity, was redeemed or matured and $250
million of long-term debt was issued at an average interest rate of 6.59% and
with 16.1 years remaining to maturity. In January 1994, authorization was
received for $250 million of Secured Medium Term Notes, Series B, which brings
the total authorized but unissued Secured Medium Term Notes to $275
million as of February 28, 1994.

Capital expenditures are financed on an interim basis with short-term debt.
The Company has $160 million in committed lines of credit, a portion of which
backs up a $50 million commercial paper facility. In addition, the Company may
borrow up to $60 million through other borrowing arrangements with banks. As
of December 31, 1993, $20 million in commercial paper was outstanding, $4
million was outstanding under the committed lines of credit and $44 million was
outstanding under other short-term borrowing arrangements.

The Company's total common equity increased by $47 million to $634 million at
the end of 1993. The 1993 increase was primarily due to the issuance of
approximately 1,900,000 shares of common stock through the Periodic Offering
Program, the Dividend Reinvestment Plan and the Investment and Employee Stock
Ownership Plan for proceeds of $36 million. The utility capital structure at
December 31, 1993, was 49% debt, 10% preferred stock and 41% common equity as
compared to 48% debt, 11% preferred stock and 41% common equity at year-end
1992.

The Company is restricted under various agreements as to the additional
securities it can issue. Under the most restrictive test of the Company's
Mortgage, an additional $431 million of First Mortgage Bonds could be issued as
of December 31, 1993. As of December 31, 1993, under its Restated Articles of
Incorporation, approximately $670 million of additional preferred stock could
be issued at an assumed dividend rate of 7.00%.

During the 1994-1996 period, capital expenditures are expected to be $334
million, and $90 million will be required for long-term debt maturities and
preferred stock sinking fund requirements. During this three-year period, the
Company expects that internally- generated funds will provide approximately 50%
of the funds for its capital expenditures. External financing will be required
to fund maturing long-term debt, preferred stock sinking fund requirements and
the remaining portion of capital expenditures.

See Notes 4 through 8 to Financial Statements, inclusive, for additional
details related to financing activities.

NON-UTILITY

Capital expenditures for the non-utility operations were $15 million for the
1991-1993 period. These capital expenditure requirements were financed
primarily with internally-generated funds. In addition, $2 million of debt
either matured or was redeemed during that same period. The non-utility
operations have $26 million in borrowing arrangements ($20 million outstanding
as of December 31, 1993) to fund capital expenditures and other corporate
requirements on an interim basis. At December 31, 1993, the non-utility
operations had $32 million in cash and marketable securities.

The 1994-1996 non-utility capital expenditures are expected to be $8 million,
and $1 million in debt maturities will also occur. During the next three
years, internally-generated cash and other debt obligations are expected to
provide the majority of the funds for the non-utility capital expenditure
requirements.

24
THE WASHINGTON WATER POWER COMPANY

TOTAL COMPANY CASH REQUIREMENTS
(Millions of Dollars)

Actual Projected (1)
------------------------ -----------------------------
1991 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ----

Capital Expenditures:(2)
Utility:
Hydro production $ 16 $ 10 $ 18 $ 16 $ 16 $ 10
DSM(3) 2 12 29 24 15 13
All other 127(4) 76 88 82 73 85
---- ---- ---- ---- ---- ----
Total Utility 145 98 135 122 104 108
Non-Utility 9 3 3 4 2 2
---- ---- ---- ---- ---- ----
Total Company $154 $101 $138 $126 $106 $110

Debt and Preferred Stock
Maturities, Redemptions &
Sinking Fund Requirements: $9 $130 $274 $0 $45 $45

(1) Excludes $66 million for the combustion turbine project under construction
in Rathdrum, Idaho; the Company has obtained separate construction and
long-term lease financing for this project. Also excludes $26 million for
the proposed acquisition of the northern Idaho electric properties of
Pacific Power and Light, an operating division of PacifiCorp; see Note 14
to Financial Statements for additional information related to this
proposed acquisition.
(2) Excludes AFUDC and AFUCE.
(3) Demand Side Management programs.
(4) Includes $68 million for the acquisition of the CP National Corporation's
natural gas distribution properties in Oregon and California.

SIGNIFICANT TRENDS

Competition

The electric and natural gas utility businesses are undergoing numerous changes
and are becoming increasingly competitive as a result of economic, regulatory
and technological changes. The Company believes that it is well positioned to
meet future challenges due to its low production costs, close proximity to
major transmission lines and natural gas pipelines, experience in the wholesale
electric market and its commitment to high levels of customer satisfaction,
cost reduction and continuous improvement of work processes.

The Company currently competes for new retail electric customers with various
rural electric cooperatives and public utility districts. Challenges facing
the electric retail business include changing technologies which reduce energy
consumption, self-generation and fuel switching by industrial and other large
retail customers, the potential for retail wheeling and the costs of
increasingly stringent environmental laws. In addition, if electric utility
companies are eventually required to provide retail wheeling service, which is
the transmission by an electric utility of electric power from another supplier
to a customer located within such utility's service area, the Company believes
it will be in a position to benefit since it is committed to remaining one of
the country's lowest-cost providers of electric energy.

The Company also competes in the wholesale electric market with other Western
utilities, including the Bonneville Power Administration. Challenges facing
the electric wholesale business include new entrants in the wholesale market
and competition from lower cost generation being developed by independent power
producers.

The National Energy Policy Act (NEPA) enacted in 1992 addresses a wide range of
issues affecting the wholesale electric business. The Company believes NEPA
provides future transmission, energy production and sales opportunities to the
Company and complements the Company's commitment to the wholesale electric
business.

Natural gas is priced competitively compared to other alternative fuel sources
for both residential and commercial customers. Challenges facing the Company's
natural gas business include the potential for customers to by-pass the Company
and securing competitively priced natural gas supplies for the future. Since
1988 one of the Company's large industrial customers has built its own pipeline
interconnection. However, this customer still purchases some

25
THE WASHINGTON WATER POWER COMPANY

natural gas services from the Company. The Company prices its natural gas
services, including transportation contracts, competitively and has varying
degrees of flexibility to price its transportation and delivery rates by means
of special contracts to assist in retaining potential by-pass customers. The
Company has signed long-term transportation contracts with two of its largest
industrial customers which minimizes the risks of these customers by-passing
the Company's system.

Least cost planning for both the electric and natural gas businesses has been
integrated so that the Company's customers are provided the most efficient and
cost-effective products possible for all their energy requirements. The
Company's need for future electric resources to serve retail loads is very
minimal. The electric integrated resource plan accepted by both the IPUC and
the Washington Utility and Transportation Commission (WUTC) in 1993 showed
that, through the year 1998, the Company's additional electric load
requirements will be met for the most part by a combination of demand side
management, including conversions to natural gas, and the redevelopment of
existing hydro generating plants. The cost of these resources is generally
less than costs of resources being developed by independent power producers and
other exempt wholesale generators. The Company's natural gas integrated
resource plan was accepted by both the WUTC and Public Utility Commission of
Oregon (OPUC) in 1993 and insures adequate supplies of natural gas are
available at the least possible cost. The switching of electric heating
customers to natural gas requires increased efforts on the Company's part in
negotiating and securing competitively-priced natural gas supplies for the
future.

Economic and Load Growth

The Company expects economic growth to continue in its eastern Washington and
northern Idaho service area, although at a slower pace than seen in the past
couple of years. The Company, along with others in the service area, continues
its efforts to expand existing businesses and attract new businesses to the
Inland Northwest. In the past, agriculture, mining and lumber have been the
primary industries. However, health care, electronic and other manufacturing,
tourism and the service sectors have become increasingly important industries
that operate in the Company's service area. In addition, the Company also
expects economic growth to continue in its Oregon and California service areas.

The Company anticipates electric retail load growth to average approximately
0.4% annually for the next five years. Although the number of electric
customers is expected to increase, the average annual usage by residential
customers is expected to continue to decline on a weather-adjusted basis due to
newer technologies, construction and appliance efficiency standards and
continued conversions to natural gas where available. The Company anticipates
natural gas load growth, including transportation volumes, in its Washington
and Idaho service area to average approximately 2.7% annually for the next five
years. The Oregon and South Lake Tahoe, California service area is anticipated
to realize 2.6% growth annually during that same period.

Environmental Matters

The Company continues to assess both the potential and actual impact of the
1990 Clean Air Act Amendments (CAAA) on its thermal generating plants. The
Centralia Power Plant (Centralia), which is operated by PacifiCorp, is
classified as a "Phase II" coal-fired plant under the CAAA and as such, will be
required to reduce sulfur dioxide (SO2) emissions by approximately 40% by the
year 2000. Several methods to meet CAAA compliance by reducing SO2 are being
evaluated and a plan is expected to be completed by early 1995. The
alternatives most likely to be used in meeting the compliance standards will be
some combination of lower sulfur coal, SO2 reduction through clean coal
technology and SO2 allowances either purchased or pooled, if available, among
the Centralia owners. The Colstrip Generating Project (Colstrip), which is
also a "Phase II" coal-fired plant operated by Montana Power, is not expected
to be required to implement any additional SO2 mitigation in the foreseeable
future in order to continue operations. Reduction in nitrogen oxides (NOX)
will be required at both Centralia and Colstrip prior to the year 2000. The
anticipated costs for NOX compliance will have a minor economic impact on the
Company.

26
THE WASHINGTON WATER POWER COMPANY

Since December 1991, a number of species of fish, including the Snake River
sockeye salmon and chinook salmon, the Kootenai River white sturgeon and the
bull trout have either been added to the endangered species list under the
Federal Endangered Species Act (ESA), listed as "threatened" under the ESA or
been petitioned for listing under the ESA. Thus far, measures which have been
adopted and implemented to save both the Snake River sockeye and chinook salmon
have not directly impacted generation levels at any of the Company's
hydroelectric dams. The Company does, however, purchase power from four
projects on the Columbia River that are being directly impacted by this
operation. The reduction in generation is relatively small resulting in
minimal economic impact on the Company. Future actions to save the Snake River
salmon, Kootenai River white sturgeon and bull trout could further impact the
Company's hydroelectric resources. However, it is unknown at this time what
impact, if any, will occur from the processes discussed above on the Company's
operations.

See Note 11 to Financial Statements for discussion of additional environmental
matters.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Independent Auditor's Report and Financial Statements begin on page 24.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

Not applicable.

INDEPENDENT AUDITORS' REPORT

The Washington Water Power Company
Spokane, Washington

We have audited the accompanying consolidated balance sheets and statements of
capitalization of The Washington Water Power Company and subsidiaries as of
December 31, 1993 and 1992, and the related consolidated statements of income
and retained earnings, cash flows, and the schedules of information by business
segments for each of the three years in the period ended December 31, 1993.
These financial statements and schedules are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedules based on our audits.

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 and
schedules are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements and schedules. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement and schedule presentation. We
believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements and schedules present
fairly, in all material respects, the financial position of the Company and its
subsidiaries at December 31, 1993 and 1992, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1993, in conformity with generally accepted accounting principles. In
addition, the schedules referred to above present fairly in all material
respects, the segment information of the Company and its subsidiaries in
accordance with generally accepted accounting principles.

As discussed in Notes 2 and 3 to the financial statements, the Company changed
its methods of accounting for other post-employment benefits and income taxes
effective January 1, 1993, to conform with Statements of Financial Accounting
Standards No. 106 and 109.

Deloitte & Touche

Seattle, Washington
January 28, 1994 (February 15, 1994 as to Note 14)

CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
The Washington Water Power Company
For the Years Ended December 31
Thousands of Dollars

1993 1992 1991
-------- -------- --------

OPERATING REVENUES................................ $640,599 $557,758 $566,807
-------- -------- --------
OPERATING EXPENSES:
Operations and maintenance....................... 322,117 262,031 269,808
Administrative and general....................... 55,083 50,016 46,055
Depreciation and amortization.................... 58,354 53,422 52,003
Taxes other than income taxes.................... 44,195 41,664 39,764
-------- -------- --------
Total operating expenses........................ 479,749 407,133 407,630
-------- -------- --------

INCOME FROM OPERATIONS............................ 160,850 150,625 159,177
-------- -------- --------

INTEREST EXPENSE AND (OTHER INCOME):
Interest expense................................. 50,133 53,541 54,552
Interest capitalized and AFUCE (Note 1).......... (3,027) (2,359) (863)
Net gain on sale of subsidiary stock (Note 14)... (9,915) (6,685) -
Other (income) deductions-net (Note 1)........... (1,620) (7,469) (3,229)
-------- -------- --------
Total interest expense and other income-net..... 35,571 37,028 50,460
-------- -------- --------

INCOME BEFORE INCOME TAXES........................ 125,279 113,597 108,717

INCOME TAXES (Notes 1 & 9)........................ 42,503 41,330 38,086
-------- -------- --------

INCOME FROM CONTINUING OPERATIONS................. 82,776 72,267 70,631

Discontinued coal mining operations-net of
income taxes (Note 10).......................... -- 2,403 1,553
-------- -------- --------

NET INCOME........................................ 82,776 74,670 72,184

DEDUCT-Preferred stock dividend requirements...... 8,335 6,817 9,292
-------- -------- --------

INCOME AVAILABLE FOR COMMON STOCK................. $ 74,441 $ 67,853 $ 62,892
======== ======== ========

Average common shares outstanding (thousands)..... 51,616 49,550 46,916

EARNINGS PER SHARE OF COMMON STOCK:
From continuing operations (after preferred
dividends....................................... $1.44 $1.32 $1.31
From discontinued coal mining operations
(Note 10)....................................... -- 0.05 0.03
-------- -------- --------
EARNINGS PER SHARE OF COMMON STOCK................ $1.44 $1.37 $1.34
======== ======== ========

Dividends paid per common share................... $1.24 $1.24 $1.24

RETAINED EARNINGS, JANUARY 1...................... $101,644 $95,047 $89,731

NET INCOME........................................ 82,776 74,670 72,184
DIVIDENDS DECLARED:
Preferred stock (Note 7)......................... (8,219) (6,968) (9,113)
Common stock..................................... (64,209) (61,525) (58,176)
ESOP dividend tax savings......................... 432 420 421
-------- -------- --------
RETAINED EARNINGS, DECEMBER 31.................... $112,424 $101,644 $95,047
======== ======== ========

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS
The Washington Water Power Company
At December 31
Thousands of Dollars

1993 1992
---------- ----------

ASSETS:
UTILITY PLANT-Original Cost (Note 4):
Electric-net.................................................... $1,439,737 $1,365,527
Natural Gas..................................................... 283,232 255,974
---------- ----------
Utility plant.................................................. 1,722,969 1,621,501
Less accumulated depreciation and amortization:
Electric...................................................... 382,508 352,612
Natural Gas................................................... 86,470 77,736
---------- ----------
Net utility plant.......................................... 1,253,991 1,191,153
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in Exchange Power-net................................ 94,383 99,633
Other-net....................................................... 79,376 76,273
---------- ----------
Total other property and investments........................... 173,759 175,906
---------- ----------
CURRENT ASSETS:
Cash and temporary cash investments ............................ 33,718 34,500
Accounts and notes receivable-net (Note 6)...................... 63,649 40,555
Materials and supplies (average cost)........................... 10,997 9,596
Fuel stock (average cost)....................................... 4,201 4,933
Natural gas stored.............................................. 4,350 2,546
Prepayments and other........................................... 5,832 7,054
---------- ----------
Total current assets........................................... 122,747 99,184
---------- ----------
DEFERRED CHARGES:
Investment in terminated nuclear project-net.................... 4,829 7,477
Regulatory assets for deferred income tax (Note 3).............. 177,786 -
Conservation programs........................................... 47,612 19,342
Other-net (Note 1).............................................. 57,114 40,953
---------- ----------
Total deferred charges......................................... 287,341 67,772
---------- ----------
TOTAL......................................................... $1,837,838 $1,534,015
========== ==========
CAPITALIZATION AND LIABILITIES:
CAPITALIZATION (See Consolidated Statements of Capitalization)... $1,416,608 $1,318,932
---------- ----------
CURRENT LIABILITIES:
Accounts payable................................................ 33,840 27,514
Taxes accrued (Note 9).......................................... 19,959 18,151
Interest accrued................................................ 10,046 12,819
Other........................................................... 51,163 40,992
---------- ----------
Total current liabilities...................................... 115,008 99,476
---------- ----------
DEFERRED CREDITS:
Investment tax credits (Note 1)................................. 2,456 2,554
Deferred income taxes (Note 3).................................. 288,905 96,031
Other (Note 1).................................................. 13,838 15,898
---------- ----------
Total deferred credits......................................... 305,199 114,483
---------- ----------
MINORITY INTEREST (Note 14)...................................... 1,023 1,124
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 11 and 14)

TOTAL......................................................... $1,837,838 $1,534,015
========== ==========

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF CAPITALIZATION
The Washington Water Power Company
At December 31
Thousands of Dollars

1993 1992
---------- ----------

COMMON EQUITY:
Common stock, no par value; 100,000,000 shares authorized:
shares outstanding: 1993-52,757,545; 1992-50,888,130 (Note 8).. $ 544,609 $ 508,202
Note receivable from employee stock ownership plan (Note 8)..... (12,756) (13,188)
Capital stock expense and other paid in capital................. (9,898) (9,623)
Retained Earnings............................................... 112,424 101,644
---------- ----------
Total common equity............................................ 634,379 587,035
---------- ----------

PREFERRED STOCK-CUMULATIVE: (Note 7)
10,000,000 shares authorized:
Not subject to mandatory redemption:
Flexible Auction Series J; 500 shares outstanding ($100,000
stated value)................................................. 50,000 50,000
---------- ----------
Total not subject to mandatory redemption..................... 50,000 50,000
---------- ----------

Subject to mandatory redemption:
$8.625 Series I; 500,000 shares outstanding ($100 stated value) 50,000 50,000
$6.95 Series K; 350,000 shares outstanding ($100 stated value). 35,000 35,000
---------- ----------
Total subject to mandatory redemption......................... 85,000 85,000
---------- ----------

LONG-TERM DEBT: (Note 4)
First Mortgage Bonds:
4 5/8% due September 1, 1994................................... - 30,000
4 5/8% due March 1, 1995....................................... 10,000 10,000
6% due August 1, 1996.......................................... - 20,000
7 7/8% due May 1, 2003......................................... - 20,000
7 1/8% due December 1, 2013.................................... 66,700 66,700
7 2/5% due December 1, 2016.................................... 17,000 17,000
9 1/4% due December 1, 2016.................................... - 80,000
10 3/8% due January 1, 2018.................................... - 50,000
Secured Medium-Term Notes Series A
4.72% to 7.54% due 1996 through 2023.......................... 225,000 -
---------- ----------
Total first mortgage bonds.................................... 318,700 293,700
---------- ----------

Pollution Control Bonds:
6% Series due 2023............................................. 4,100 -
10% Series due 2014............................................ - 4,100

Unsecured Medium-Term Notes:
Series A - 7.94% to 9.58% due 1995 through 2007................ 100,000 170,000
Series B - 5.50% to 8.55% due 1995 through 2023................ 150,000 125,000
---------- ----------
Total unsecured medium-term notes............................. 250,000 295,000
---------- ----------

Notes payable (due within one year) and commercial paper to be
refinanced (Note 5)............................................ 68,001 4,000
Other (Note 4).................................................. 6,428 97
---------- ----------
Total long-term debt........................................... 647,229 596,897
---------- ----------

TOTAL CAPITALIZATION............................................. $1,416,608 $1,318,932
========== ==========

The Accompanying Notes are an Integral Part of These Statements.

31
CONSOLIDATED STATEMENTS OF CASH FLOWS
Increase (Decrease) in Cash and Cash Equivalents
The Washington Water Power Company
For the Years Ended December 31
Thousands of Dollars

1993 1992 1991
--------- --------- ---------

OPERATING ACTIVITIES:
Income from continuing operations................ $ 82,776 $ 72,267 $ 70,631
NON-CASH REVENUES AND EXPENSES INCLUDED
IN INCOME FROM CONTINUING OPERATIONS:
Depreciation and amortization................... 66,593 59,802 57,773
Investment tax credit adjustments-net (Note 1).. (98) (703) (1,459)
Provision for deferred income taxes............. 7,060 17,182 6,233
Allowance for equity funds used during
construction................................... (1,666) (1,392) (1,136)
Power and natural gas cost deferrals (Note 1)... (7,624) (11,523) (10,172)
Deferred revenues and other-net................. (1,271) (734) (5,670)
(Increase) decrease in working capital components:
Receivables and prepaid expense-net............ 1,116 126 7,956
Materials & supplies, fuel stock and natural
gas stored.................................... (2,001) 1,047 (2,649)
Payables and other accrued liabilities......... (1,846) (3,575) 10,431
Other-net...................................... 8,767 2,998 (3,828)
Write-down of property and investments.......... - - 5,596
--------- --------- ---------
Net cash flows from continuing operations......... 151,806 135,495 133,706
Net cash flows from discontinued operations
(Note 10)....................................... - 2,403 1,553
--------- --------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES......... 151,806 137,898 135,259
--------- --------- ---------
INVESTING ACTIVITIES:
Construction expenditures (excluding AFUDC-equity
funds).......................................... (111,118) (90,344) (82,982)
Other capital requirements....................... (30,216) (11,640) (5,170)
(Increase) decrease in other noncurrent balance
sheet items-net................................. (4,693) 3,316 (5,039)
Assets acquired and investments in subsidiaries
(Note 14)........................................ 2,725 (17,438) (67,894)
--------- --------- ---------
NET CASH USED IN INVESTING ACTIVITIES............. (143,302) (116,106) (161,085)
--------- --------- ---------
FINANCING ACTIVITIES:
Increase (decrease) in commercial paper, notes
payable and bank borrowings-net................. 64,001 (42,000) 46,000
Sale of unsecured medium-term notes.............. 25,000 113,000 37,000
Redemption and maturity of unsecured medium-term
notes........................................... (70,000) (30,000) -
Sale of secured medium-term notes (a series of
first mortgage bonds)........................... 225,000 - -
Redemption of mortgage bonds..................... (200,000) (75,000) -
Sale of pollution control bonds.................. 4,100 - -
Redemption of pollution control bonds............ (4,100) - -
Issuance of preferred stock...................... - 35,000 -
Redemption of preferred stock.................... - (25,000) -
Redemption premiums.............................. (9,595) (2,956) -
Sale of common stock - net of ESOP note
receivable (Note 8)............................ 25,899 39,233 14,636
Miscellaneous-net................................ (7,817) 12,254 (5,622)
--------- --------- ---------
NET FINANCING ACTIVITIES BEFORE CASH DIVIDENDS.... 52,488 24,531 92,014
Less cash dividends paid........................ (61,773) (57,229) (58,679)
--------- --------- ---------
NET CASH USED IN FINANCING ACTIVITIES............. (9,285) (32,698) 33,335
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH & EQUIVALENTS..... (781) (10,906) 7,509
CASH & EQUIVALENTS AT BEGINNING OF PERIOD......... 34,500 45,406 37,897
--------- --------- ---------
CASH & EQUIVALENTS AT END OF PERIOD............... $ 33,719 $ 34,500 $ 45,406
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period:
Interest........................................ $ 47,854 $ 48,516 $ 51,863
Income Taxes.................................... $ 35,649 $ 28,317 $ 29,053
Noncash financing and investing activities....... $ 13,327 $ 12,865 $ 9,831

The Accompanying Notes are an Integral Part of These Statements.

SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS
The Washington Water Power Company
For the Years Ended December 31
Thousands of Dollars

1993 1992 1991
-------- -------- --------

OPERATING REVENUES:
Electric......................................... $ 464,175 $ 424,413 $ 411,771
Natural Gas (Note 14)............................ 137,547 100,570 73,304
Non-utility (Note 14)............................ 38,877 32,775 81,732
---------- ---------- ----------
Total operating revenues........................ $ 640,599 $ 557,758 $ 566,807
========== ========== ==========
OPERATIONS AND MAINTENANCE EXPENSES:
Electric:
Power purchased................................. $ 118,809 $ 91,709 $ 69,446
Fuel for generation............................. 34,233 37,096 31,799
Other electric.................................. 68,567 57,858 65,742
Natural Gas: (Note 14)
Natural gas purchased for resale................ 71,867 48,215 30,815
Other natural gas............................... 14,286 13,692 8,603
Non-utility (Note 14)............................ 14,355 13,461 63,403
---------- ---------- ----------
Total operations and maintenance expenses....... $ 322,117 $ 262,031 $ 269,808
========== ========== ==========

ADMINISTRATIVE AND GENERAL EXPENSES:
Electric......................................... $ 29,225 $ 28,055 $ 26,201
Natural Gas (Note 14)............................ 13,220 12,563 10,019
Non-utility (Note 14)............................ 12,638 9,398 9,835
---------- ---------- ----------
Total administrative and general expenses....... $ 55,083 $ 50,016 $ 46,055
========== ========== ==========

DEPRECIATION AND AMORTIZATION EXPENSES:
Electric......................................... $ 46,324 $ 41,468 $ 40,563
Natural Gas (Note 14)............................ 9,149 8,451 5,321
Non-utility (Note 14)............................ 2,881 3,503 6,119
---------- ---------- ----------
Total depreciation and amortization expenses.... $ 58,354 $ 53,422 $ 52,003
========== ========== ==========
INCOME FROM OPERATIONS:
Electric......................................... $ 131,996 $ 133,793 $ 143,952
Natural Gas (Note 14)............................ 21,112 11,826 14,124
Non-utility (Note 14)............................ 7,742 5,006 1,101
---------- ---------- ----------
Total income from operations.................... $ 160,850 $ 150,625 $ 159,177
========== ========== ==========
INCOME AVAILABLE FOR COMMON STOCK:
Utility operations............................... $ 61,175 $ 57,158 $ 59,919
Non-utility operations (Note 14)................. 13,266 8,292 1,420
Discontinued coal mining operations (Note 10).... - 2,403 1,553
---------- ---------- ----------
Total income available for common stock ........ $ 74,441 $ 67,853 $ 62,892
========== ========== ==========
ASSETS:
Electric......................................... $1,395,740 $1,177,103 $1,144,619
Natural Gas (Note 14)............................ 224,213 181,402 165,027
Other utility assets............................. 81,699 66,307 85,154
Non-utility assets (Note 14)..................... 136,186 109,203 126,713
---------- ---------- ----------
Total assets.................................... $1,837,838 $1,534,015 $1,521,513
========== ========== ==========
CAPITAL EXPENDITURES (excluding AFUDC/AFUCE):
Electric......................................... $ 104,078 $ 68,393 $ 62,662
Natural Gas (Note 14)............................ 30,774 29,314 14,920
WPNG assets acquired (Note 14)................... - - 67,894
Non-utility...................................... 3,452 3,642 9,206
---------- ---------- ----------
Total capital expenditures...................... $ 138,304 $ 101,349 $ 154,682
========== ========== ==========

The Accompanying Notes are an Integral Part of These Statements.

33
THE WASHINGTON WATER POWER COMPANY

NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SYSTEM OF ACCOUNTS
The accounting records of The Washington Water Power Company (Company) utility
operations are maintained in accordance with the uniform system of accounts
prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by
the appropriate state regulatory commissions.

BASIS OF REPORTING
The accompanying financial statements include the Company's proportionate share
of utility plant and related operations resulting from its interests in jointly
owned plants (See Note 12).

The financial statements are presented on a consolidated basis and, as such,
include the assets, liabilities, revenues and expenses of the Company and its
wholly owned subsidiaries, Pentzer Corporation (Pentzer), Washington Irrigation
and Development Company (WIDCo), The Limestone Company and WP Finance Company.
All material intercompany transactions that are not allowed recovery under
regulation have been eliminated in the consolidation. On July 31, 1990, WIDCo
sold its 50% interest in the Centralia coal mining properties for $40.8
million. As discussed in Note 14, operating results for ITRON are no longer
consolidated and are accounted for on the equity method.

The financial activity of each of the Company's segments is reported in the
"Schedule of Information by Business Segments." Such information is an
integral part of these financial statements.

UTILITY PLANT
The cost of additions to utility plant, including internally developed
information systems, an allowance for funds used during construction and
replacements of units of property and betterments, is capitalized. Maintenance
and repairs of property and replacements determined to be less than units of
property are charged to operating expenses. Costs of depreciable units of
property retired plus costs of removal less salvage are charged to accumulated
depreciation.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Allowance for Funds Used During Construction (AFUDC) represents the cost of
both the debt (Interest Capitalized) and equity funds used to finance utility
plant additions during the construction period. In accordance with the uniform
system of accounts prescribed by regulatory authorities, AFUDC is capitalized
as a part of the cost of utility plant and is credited currently as a noncash
item to Other Income and Interest Capitalized (see Other Income below). The
Company generally is permitted, under established regulatory rate practices, to
recover the capitalized AFUDC and a fair return thereon through its inclusion
in rate base and the provision for depreciation after the related utility plant
has been placed in service. Cash inflow related to AFUDC does not occur until
the related utility plant is placed in service.

The effective AFUDC rate was 10.67% in 1993, 1992 and 1991. The Company's
AFUDC rates do not exceed the maximum allowable rates as determined in
accordance with the requirements of regulatory authorities.

ALLOWANCE FOR FUNDS USED TO CONSERVE ENERGY
The Allowance for Funds Used to Conserve Energy (AFUCE) rate recovers carrying
costs associated with Demand Side Management (DSM) program expenditures until
such investment is included in rate base. AFUCE is capitalized as a part of
the cost of the DSM investment and is credited currently as a noncash item to
Other Income and Interest Capitalized. The AFUCE rate in effect is the last
authorized, or otherwise stipulated, rate of return from the Company's
proceeding for natural gas or electric operations. The rate for Washington is
adjusted for the tax effect of interest. Cash inflow related to AFUCE does not
occur until the related DSM investment is placed in service.

DEPRECIATION
For utility operations, depreciation provisions are computed by a method of
depreciation accounting utilizing unit rates for hydroelectric plants and
composite rates for other properties. Such rates are designed to provide for
retirements of properties at the expiration of their service lives. The rates
for hydroelectric plants include annuity and interest components, in which the
interest component is 6%. For utility operations, the ratio of depreciation
provisions to average depreciable property was 2.68% in 1993, 2.37% in 1992
and 2.44% in 1991.

34
THE WASHINGTON WATER POWER COMPANY

AMORTIZATION
Deferred charges include regulatory assets which are amortized primarily over
periods allowed by regulators. Also included in Deferred Charges, Other are
debt issuance and redemption costs which are amortized over the terms of the
respective debt issues.

POWER AND NATURAL GAS COST ADJUSTMENT PROVISIONS
In 1989, the Idaho Public Utilities Commission (IPUC) approved the Company's
filing for a power cost adjustment mechanism (PCA). The PCA is designed to
allow the Company to change electric rates to recover or rebate a portion of
the difference between actual and allowed net power supply costs. In 1993 and
1991, the Company deferred $4.6 million and $1.8 million, respectively, of net
power supply cost savings, which resulted in like increases in electric
operating expenses. In 1992, the Company deferred $3.3 million of net power
supply costs, which resulted in like decreases in electric operating expenses.
Rate changes are triggered when the deferred balance reaches $2.2 million. A
rate increase was implemented in November 1992 to pass through accumulated
costs. A rate reduction was implemented in May 1991 to pass through
accumulated cost savings. As of December 31, 1993, $0.6 million of costs not
yet subject to a rate increase had accumulated in the PCA deferral account.
The PCA is currently scheduled to end on June 30, 1994.

Under established regulatory practices, the Company is also allowed to adjust
its natural gas rates from time to time to reflect increases or decreases in
the cost of natural gas purchased. Differences between actual natural gas
costs and the natural gas costs allowed in rates are deferred and charged or
credited to expense when regulators approve inclusion of the cost changes in
rates.

OPERATING REVENUES
The Company accrues estimated unbilled revenues for services provided through
month-end.

INCOME TAXES
Provisions for income taxes are based generally on income and expense as
reported for financial statement purposes adjusted principally for the excess
of tax depreciation over book depreciation.

Beginning with 1981 property additions, deferred income taxes are provided for
the tax effect of Accelerated Cost Recovery System (ACRS) depreciation over
straight-line depreciation. Investment tax credits (ITC) are amortized over
the period established by regulators.

The Company and its eligible subsidiaries file consolidated federal income tax
returns. Subsidiaries are charged or credited with the tax effects of their
operations on a stand alone basis. The Company's federal income tax returns
have been examined with all issues resolved, and all payments made, through the
1990 return.

EARNINGS PER COMMON SHARE
Earnings per common share have been computed based on the weighted average
number of common shares outstanding during the period. On November 9, 1993,
the Company distributed, to shareholders of record on October 25, 1993, shares
of its common stock, without par value, under a two-for-one stock split
effected in the form of a 100% stock dividend. All references to number of
shares and per share information have been adjusted to reflect the common stock
split on a retroactive basis.

CASH
For the purposes of the Consolidated Statements of Cash Flows, the Company
considers all temporary investments with an initial maturity of three months or
less to be cash equivalents.

35
THE WASHINGTON WATER POWER COMPANY

OTHER INCOME--NET
Other income-net is composed of the following items:

YEARS ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
------- ------- -------
(Thousands of Dollars)

Interest income................................... $ 4,058 $ 5,566 $ 7,708
Gain (loss) on property dispositions.............. (1,370) 2,405 913
Minority interest................................. (1,273) 36 734
AFUDC (equity).................................... 1,666 1,392 1,136
Creston and related transmission write-off........ - - (4,773)
Miscellaneous..................................... (1,461) (1,930) (2,489)
------- ------- -------
Total $ 1,620 $ 7,469 $ 3,229
======= ======= =======

Non-recurring adjustments were made in 1991 to establish reserves for a
potential write-off related to the recovery of costs associated with the
Creston Project and related transmission. The reserves were calculated
assuming regulators would not allow the Company to earn a return during a
recovery period. These adjustments decreased other income by $4.8 million
before income taxes and decreased income net of taxes by $3.2 million. The
Company's costs of $10,990,000 less a reserve for a potential write-off of
$3,967,000 related to this project as of December 31, 1993, are included in
Other Deferred Charges on the Balance Sheet.

NEW ACCOUNTING STANDARDS

FAS No. 112, entitled "Employers' Accounting for Postemployment Benefits," was
issued by the Financial Accounting Standards Board in November 1992 and is
effective for fiscal years beginning after December 15, 1993. This Statement
requires the accrual of the expected cost of providing benefits to former or
inactive employees after employment but before retirement. It has been
determined that the liabilities related to the Company's Long-Term Disability
and Workers' Compensation programs are affected by this Statement. The Company
does not expect FAS No. 112 to have a material effect on the Company's
financial position or results of operations.

NOTE 2. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS

Effective January 1, 1993, the Company adopted FAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." FAS No. 106
requires the Company to accrue the estimated cost of postretirement benefit
payments during the years the employee provides services. The Company
previously expensed the cost of these benefits, which are principally health
care, as claims were incurred. FAS No. 106 allows recognition of the
unrecognized transition obligation in the year of adoption or the amortization
of such obligation over a period of up to twenty years. The Company has
elected to amortize this obligation of approximately $39,600,000 over a period
of twenty years. Income from continuing operations during 1993 was not changed
by the implementation of this Statement.

The Company has received accounting orders from the Washington Utilities and
Transportation Commission (WUTC) and the IPUC allowing the current deferral of
expense accruals under this Statement as a regulatory asset for future
recovery. At such time that rate recovery is requested and allowed, cumulative
deferrals will be amortized over the remainder of the twenty-year amortization
period. The Company expects to be able to recover the amortized amounts.
Therefore, the Company's cash flows are not affected by implementation of this
Statement.

The Company provides certain health care and life insurance benefits for
substantially all of its retired employees. In 1993, 1992 and 1991, the
Company recognized $1,250,000, $1,290,000 and $1,233,000, respectively, as an
expense for postretirement health care and life insurance benefits. The
following table sets forth the health care plan's funded status at December 31,
1993.

36
THE WASHINGTON WATER POWER COMPANY

Accumulated postretirement benefit obligation:

Retirees 509
Fully eligible plan participants 1,341
Other active plan participants 111
------
Total participants 1,961

Fair value of plan assets $ 636,000
Accumulated postretirement benefit obligations
in excess of plan assets $38,964,000
Unrecognized transition obligation $38,413,000
Accrued postretirement benefit cost, deferred $ 3,981,000

Net postretirement benefit cost for 1993 consisted of the following components:

Service cost - benefits earned during the period $ 776,000
Return on the plan assets (if any) -
Interest cost on accumulated
postretirement benefit obligation $2,018,000
Amortization of transition obligation $1,187,000

The currently assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation is 12.0% for 1993, decreasing
linearly each successive year until it reaches 6.0% in 1997. A
one-percentage-point increase in the assumed health care cost trend rate for
each year would increase the accumulated postretirement benefit obligation as
of December 31, 1993 and net postretirement health care cost by approximately
$3,079,000. The assumed discount rate used in determining the accumulated
postretirement benefit obligation was 7.5%.

The Company has a pension plan covering substantially all of its regular
full-time employees. Some of the Company's subsidiaries also participate in
this plan. Individual benefits under this plan are based upon years of service
and the employee's average compensation as specified in the Plan. The
Company's funding policy is to contribute annually an amount equal to the net
periodic pension cost, provided that such contributions are not less than the
minimum amounts required to be funded under the Employee Retirement Income
Security Act, nor more than the maximum amounts which are currently deductible
for tax purposes. Pension fund assets are invested primarily in marketable
debt and equity securities.

Net pension credit for 1993, 1992 and 1991 is summarized as follows:

1993 1992 1991
-------- -------- --------
(Thousands of Dollars)

Service cost-benefits earned during the period . . . . . . . . . . . . $ 3,150 $ 2,846 $ 2,614
Interest cost on projected benefit obligation . . . . . . . . . . . . . 7,771 7,390 7,064
Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . (15,108) (12,257) (21,933)

Net amortization and deferral . . . . . . . . . . . . . . . . . . . . . 3,717 886 12,586
-------- -------- --------
Net periodic pension cost (income) . . . . . . . . . . . . . . . . (470) (1,135) 331
Less amounts charged (credited) to construction and other accounts . . - (24) 115
Less regulatory adjustments to operating expenses (1) . . . . . . . . . - - 321
-------- -------- --------
Net pension cost credited to operating expenses . . . . . . . . . . $ (470) $ (1,111) $ (105)
======= ======= ========

(1) The Company has received accounting orders from regulatory authorities
requiring the Company to defer the difference between pension cost as
determined under FAS 87 and that determined for ratemaking purposes.

37
THE WASHINGTON WATER POWER COMPANY

The funded status of the Plan and the pension liability at December 31, 1993,
1992 and 1991, are as follows:

1993 1992 1991
--------- --------- ---------
(Thousands of dollars)

Actuarial present value of benefit obligations:
Accumulated benefit obligations (including vested benefits of
$(84,531,000), $(76,226,000) and $(71,133,000), respectively) . . $ (85,368) $ (76,853) $ (71,646)
========= ========= =========
Projected benefit obligation for service rendered to date . . . . $(104,025) $ (95,446) $ (89,780)
Plan assets at fair value . . . . . . . . . . . . . . . . . . . . 126,879 118,883 116,594
--------- --------- ---------
Plan assets in excess of projected benefit obligation . . . . . . 22,854 23,437 26,814
Unrecognized net gain from returns different than assumed . . . . (21,503) (19,733) (22,698)
Prior service cost not yet recognized in pension cost . . . . . . 7,983 8,568 8,107
Unrecognized net asset at year-end (being amortized over
11 to 19 years) . . . . . . . . . . . . . . . . . . . . . . . (12,445) (13,531) (14,617)
Regulatory deferrals . . . . . . . . . . . . . . . . . . . . . . . (3,256) (1,381) (131)
--------- --------- ---------
Pension liability . . . . . . . . . . . . . . . . . . . . . . . . $ (6,367) $ (2,640) $ (2,525)
========= ========= =========

Assumptions used in calculations were:
Discount rate at year-end . . . . . . . . . . . . . . . . . . . . 7.5% 8.5% 8.5%
Rate of increase in future compensation level . . . . . . . . . . 4.0% 5.0% 5.0%
Expected long-term rate of return on assets . . . . . . . . . . . 9.0% 9.0% 9.0%

NOTE 3. ACCOUNTING FOR INCOME TAXES

The Company adopted Statement of Financial Accounting Standards (FAS) No. 109,
"Accounting for Income Taxes," effective January 1, 1993, which supersedes
Accounting Principles Board Opinion 11 previously adopted by the Company. FAS
No. 109 establishes revised financial accounting and reporting standards for
the effects of income taxes.

As of January 1, 1993, the Company accrued net regulatory assets of
$171,365,000 related to the probable recovery of FAS No. 109 deferred tax
liabilities from customers through future rates. In the third quarter, the
balance was adjusted to account for the 35% federal income tax rate, which
brought the accrued net regulatory assets balance to $182,196,000. As such,
the Company's adoption of FAS No. 109 has no effect on income for 1993. The
regulatory assets and deferred tax liabilities are being amortized over the
estimated remaining life of the associated assets.

Deferred income taxes reflect the net tax effects of (a) temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes, and (b) tax credit
carryforwards. The tax effects of significant items comprising the Company's
net deferred tax liability as of January 1, 1993, restated to reflect the 35%
federal income tax rate, are as follows:

Deferred tax liabilities:
Differences between book and tax basis of property $105,677,000
Regulatory assets for FAS 109 184,087,000
Regulatory asset for Skagit 2,000,000
Other 14,990,000
------------
Total deferred tax liabilities $306,754,000
------------

Deferred tax assets:
Reserves not currently deductible $ 17,591,000
Gain on sale of office building 1,755,000
Regulatory liability for FAS 109 1,891,000
Other 6,575,000
------------
Total deferred tax assets $ 27,812,000
------------

Net deferred tax liability $278,942,000
============

38
THE WASHINGTON WATER POWER COMPANY

The provision for income tax expense for 1993 was $42,503,000, of which
$35,443,000 and $7,060,000 is current and deferred tax expense, respectively.
The provision for income tax expense for 1992 was $41,330,000, of which
$24,148,000 and $17,182,000 was current and deferred tax expense, respectively.
The provision for income tax expense for 1991 was $38,086,000, of which
$31,853,000 and $6,233,000 was current and deferred tax expense, respectively.
The current and deferred effective tax rates are approximately the same during
all periods.

NOTE 4. LONG-TERM DEBT

The annual sinking fund requirements and maturities for the next five years for
First Mortgage Bonds and Medium-Term Notes outstanding at December 31, 1993 are
as follows:

YEAR ENDED SINKING FUND
DECEMBER 31 MATURITIES REQUIREMENTS TOTAL
----------- ---------- ------------ -----
(Thousands of Dollars)

1994 .............. $ - $3,187 $ 3,187
1995 .............. 45,000 3,087 48,087
1996 .............. 35,000 2,887 37,887
1997 .............. 20,000 2,887 22,887
1998 .............. 10,000 2,887 12,887

The sinking fund requirements may be met by certification of property additions
at the rate of 167% of requirements. All of the utility plant is subject to
the lien of the Mortgage and Deed of Trust securing outstanding First Mortgage
Bonds.

In 1993, 1992 and 1991, $25,000,000, $113,000,000 and $37,000,000,
respectively, of unsecured Medium-Term Notes, Series A and B (Notes) were
issued. At December 31, 1993, the Company had outstanding $250,000,000 of the
Notes with maturities between 1 and 29 years and with interest rates varying
between 5.50% and 9.58%.

As of December 31, 1993, the Company had authorization to issue up to
$25,000,000 of the $250,000,000 originally authorized in aggregate principal
amount of new First Mortgage Bonds issued in the form of Secured Medium-Term
Notes, Series A (Secured MTNs). The Secured MTNs may be issued from time to
time and may vary in term from 9 months to 30 years. At December 31, 1993, the
Company had outstanding $225,000,000 of the Secured MTNs with maturities
between 2 and 30 years and with interest rates varying between 4.72% and 7.54%.
In January 1994, authorization was received for an additional $250,000,000 of
Secured Medium-Term Notes, Series B, which may vary in term from 9 months to 40
years.

At December 31, 1993, the Company had $68,000,749 outstanding under borrowing
arrangements which will be refinanced in 1994. See Note 5 for details of
credit agreements.

Included in other long-term debt are the following items related to
non-utility operations:

OUTSTANDING AT DECEMBER 31
--------------------------
1993 1992
------ ------
(Thousands of Dollars)

Industrial revenue bonds, variable rate payable through 2003 $ 500 $ 550
Notes payable - variable rate payable through 1998 . . . . 6,635 -
Capital lease obligations . . . . . . . . . . . . . . . . 22 -
------ -----
Total non-utility . . . . . . . . . . . . . . . . . 7,157 550
Less: current portion . . . . . . . . . . . . . . . . . 57 50
------ -----
Net non-utility long-term debt . . . . . . . . . . . $7,100 $ 500
====== =====

In accordance with FAS No. 107 "Disclosures About Fair Value of Financial
Instruments," the fair value of the Company's long-term debt at December 31,
1993 and 1992 is estimated to be $690.0 million, or 107% of the carrying value,
and $612.1 million, or 103% of the carrying value, respectively. These
estimates are based on available market information and appropriate valuation
methodologies.

39
THE WASHINGTON WATER POWER COMPANY

NOTE 5. BANK BORROWINGS AND COMMERCIAL PAPER

At December 31, 1993, the Company maintained total lines of credit with various
banks under two separate credit agreements amounting to $160,000,000. The
Company has a revolving line of credit expiring December 9, 1995, which
provides a total credit commitment of $70,000,000. The second revolving credit
agreement is composed of two tranches totaling $90,000,000. The one-year
tranche is renewable each year through 1995 and provides for up to $50,000,000
of notes to be outstanding at any one time. The three-year tranche expires
September 30, 1995, and provides for up to $40,000,000 of notes to be
outstanding at any one time. The Company pays commitment fees of up to 1/5%
per annum on the average daily unused portion of each credit agreement.

In addition, under various agreements with banks, the Company can have up to
$60,000,000 in loans outstanding at any one time, with the loans available at
the banks' discretion. These arrangements provide, if funds are made
available, for fixed-term loans for up to 180 days at a fixed rate of interest.

Balances and interest rates of bank borrowings under these arrangements were as
follows:

YEARS ENDED DECEMBER 31,
--------------------------------------
1993 1992 1991
------- ------- -------
(Dollars in thousands)

BALANCE OUTSTANDING AT END OF PERIOD:
Fixed-term loans............................ $44,001 $ 4,000 $13,000
Commercial paper............................ 20,000 - 3,000
Revolving credit agreement.................. 4,000 - 30,000

MAXIMUM BALANCE DURING PERIOD:
Fixed-term loans............................ $69,000 $26,000 $20,000
Commercial paper............................ 20,000 24,000 20,805
Revolving credit agreement.................. 28,000 30,000 34,000

AVERAGE DAILY BALANCE DURING PERIOD:
Fixed-term loans............................ $24,499 $ 9,989 $ 3,797
Commercial paper............................ 7,791 7,351 4,131
Revolving credit agreement.................. 5,030 7,212 4,250

AVERAGE ANNUAL INTEREST RATE DURING PERIOD:
Fixed-term loans............................ 3.38% 4.26% 5.48%
Commercial paper............................ 3.46 4.18 5.51
Revolving credit agreement.................. 3.49 4.19 5.43

AVERAGE ANNUAL INTEREST RATE AT END OF PERIOD:
Fixed-term loans............................ 3.55% 4.43% 5.34%
Commercial paper............................ 3.58 - 5.55
Revolving credit agreement.................. 3.65 - 5.28

Non-utility operations have $26 million of credit arrangements available. At
December 31, 1993, 1992 and 1991, $19.7 million, $7.8 million and $9.3 million,
respectively, were outstanding.

NOTE 6. ACCOUNTS RECEIVABLE SALE

The Company has entered into an agreement whereby it can sell, on a revolving
basis, up to $40,000,000 of interests in certain accounts receivable, both
billed and unbilled. The Company is obligated to pay fees which approximate
the purchaser's cost of issuing commercial paper equal in value to the
interests in receivables sold. The amount of such fees is included in
operating expenses. At both December 31, 1993 and 1992, $40,000,000 in
receivables had been sold pursuant to the agreement.

40
THE WASHINGTON WATER POWER COMPANY

NOTE 7. PREFERRED STOCK

CUMULATIVE PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION:
The dividend rate on Flexible Auction Preferred Stock, Series J is reset every
49 days based on an auction. During 1993, the dividend rate varied from 3.00%
to 3.27% and at December 31, 1993, was 3.14%. Series J is subject to
redemption at the Company's option at a redemption price of 100% per share plus
accrued dividends.

CUMULATIVE PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION:

Redemption requirements:

$8.625, Series I - On June 15, 1996, 1997, 1998, 1999 and 2000, the
Company must redeem 100,000 shares at $100 per share plus accumulated
dividends. The Company may, at its option, redeem up to 100,000 shares in
addition to the required redemption on any redemption date.

$6.95, Series K - On September 15, 2002, 2003, 2004, 2005 and 2006, the
Company must redeem 17,500 shares at $100 per share plus accumulated
dividends through a mandatory sinking fund. Remaining shares must be
redeemed on September 15, 2007. The Company has the right to redeem an
additional 17,500 shares on each September 15 redemption date.

There are $30 million in mandatory redemption requirements during the 1994-1998
period.

In accordance with FAS No. 107 "Disclosures About Fair Value of Financial
Instruments," the fair value of the Company's preferred stock at December 31,
1993 and 1992 is estimated to be $93.8 million, or 110% of the carrying value,
and $89.4 million, or 105% of the carrying value, respectively. These
estimates are based on available market information and appropriate valuation
methodologies.

NOTE 8. COMMON STOCK

In April 1990, the Company sold 1,000,000 shares of its common stock to the
Trustee of the Investment and Employee Stock Ownership Plan for Employees of
the Company (Plan) for the benefit of the participants and beneficiaries of the
Plan. In payment for the shares of Common Stock, the Trustee issued a
promissory note payable to the Company in the amount of $14,125,000. Dividends
paid on the stock held by the Trustee, plus Company contributions to the Plan,
if any, are used by the Trustee to make interest and principal payments on the
promissory note. The balance of the promissory note receivable from the
Trustee ($12,755,500 at December 31, 1993) is reflected as a reduction to
common equity. The shares of Common Stock are allocated to the accounts of
participants in the Plan as the note is repaid. During 1993, the cost recorded
for the Plan was $2,216,000. This included the cost for an additional 165,335
shares which were issued for ongoing employee and Company contributions to the
Plan. Interest on the note payable, cash and stock contributions to the Plan
and dividends on the shares held by the Trustee were $1,238,000, $1,776,000 and
$1,231,000, respectively.

In February 1990, the Company adopted a shareholder rights plan pursuant to
which holders of Common Stock outstanding on March 2, 1990, or issued
thereafter, have been granted one preferred share purchase right ("Right") on
each outstanding share of Common Stock. Each Right, initially evidenced by and
traded with the shares of Common Stock, entitles the registered holder to
purchase one one-hundredth of a share of Preferred Stock of the Company,
without par value, at an exercise price of $40, subject to certain adjustments,
regulatory approval and other specified conditions. The Rights will be
exercisable only if a person or group acquires 10% or more of the Common Stock
or announces a tender offer, the consummation of which would result in the
beneficial ownership by a person or group of 10% or more of the Common Stock.
The Rights may be redeemed, at a redemption price of $0.01 per Right, by the
Board of Directors of the Company at any time until any person or group has
acquired 10% or more of the Common Stock. The Rights will expire on February
16, 2000.

41
THE WASHINGTON WATER POWER COMPANY

In November 1991, the Company received authorization to issue from time to time
1,500,000 shares of Common Stock under a Periodic Offering Program (POP).
During 1992, the remaining 1,107,600 shares of the first POP were issued under
this program for net proceeds of $18.0 million. In the second half of 1992,
the Company received authorization to issue a second 1,500,000 shares of common
stock under the POP. Through December 31, 1993, 927,600 shares of the second
POP were issued for net proceeds of $17.3 million.

The Company has a Dividend Reinvestment and Stock Purchase Plan under which the
Company's stockholders may automatically reinvest their dividends and make
optional cash payments for the purchase of the Company's Common Stock.

Sales of Common Stock for 1993, 1992 and 1991, are summarized below (dollar
amounts in thousands):

1993 1992 1991
--------------------- --------------------- --------------------
Shares Amount Shares Amount Shares Amount
------ ------ ------ ------ ------ ------

Balance at January 1.............. 50,888,130 $508,202 47,901,602 $458,371 46,423,826 $434,936
---------- -------- ---------- -------- ---------- --------
Employee Investment Plan (401-K) 165,335 3,216 186,724 3,147 150,460 2,317
Dividend Reinvestment Plan...... 1,127,680 21,779 1,341,004 22,721 934,916 14,551
Periodic Offering............... 576,400 11,412 1,458,800 23,963 392,400 6,567
---------- -------- ---------- -------- ---------- --------
Total Issues.................... 1,869,415 36,407 2,986,528 49,831 1,477,776 23,435
---------- -------- ---------- -------- ---------- --------
Balance at December 31............ 52,757,545 $544,609 50,888,130 $508,202 47,901,602 $458,371
========== ======== ========== ======== ========== ========

42
THE WASHINGTON WATER POWER COMPANY

NOTE 9. FEDERAL INCOME TAXES

A reconciliation of federal income taxes derived from statutory tax rates
applied to income from continuing operations for accounting purposes and such
taxes charged to expense for the consolidated Company is as follows:

FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------
1993 1992 1991
------ ------- --------
(Thousands of Dollars)

Computed federal income taxes at statutory rate ....... $43,363 $38,296 $36,005
Increase (decrease) in tax resulting from:
Accelerated tax depreciation ....................... (2,229) 1,784 1,852
Prior year audit adjustment ........................ (278) (4,505) -
Deferred federal income tax adjustment ............. - - (4,000)
Weatherization disallowance ........................ 384 809 927
Investment tax credits ............................. (98) (702) (1,459)
Equity earnings in affiliates ...................... (560) 509 -
Other timing differences ........................... 1,676 2,770 2,553
------- ------- -------
Total federal income tax expense* .................... 42,258 38,961 35,878
Add: State income tax expense ..................... 245 2,369 2,208
------- ------- -------
Federal and state income taxes ........................ $42,503 $41,330 $38,086
======= ======= =======

*Federal Income Tax Expense:
Utility ........................................... $36,385 $34,372 $34,992
Non-utility ....................................... 5,873 4,589 886
------- ------- --------
Total Federal Income Tax Expense ...................... $42,258 $38,961 $35,878
======= ======= =======

INCOME TAX EXPENSE CONSISTS OF THE FOLLOWING:
Federal taxes currently provided ...................... $34,749 $25,708 $30,385
Prior period adjustment ............................... (278) (4,505) -
Deferred income taxes:
Depreciation differences ........................... 4,953 10,576 8,156
Loss on reacquired debt ............................ 2,032 668 (447)
Sale and leaseback of office building .............. 496 113 113
Disallowance of weatherization deduction ........... 384 809 927
Amortization of Investment in Exchange Power ....... (1,516) 516 527
Deferred federal income tax adjustment ............. - - (4,000)
Creston and related transmission reserve ........... 36 2,832 (1,623)
Investment tax credits-net ......................... (98) (702) (1,459)
Other .............................................. 1,500 2,946 3,299
------- ------- -------
Total federal income tax expense ...................... 42,258 38,961 35,878
State income tax expense ........................... 245 2,369 2,208
------- ------- -------
Federal and state income taxes ........................ $42,503 $41,330 $38,086
======= ======= =======
Federal statutory rate 35% 34% 34%

NOTE 10. DISCONTINUED COAL MINING OPERATIONS

Washington Irrigation & Development Company (WIDCo) owned an undivided one-half
interest in coal mining properties near Centralia, Washington, which it
operated and which supplied coal to the Centralia Steam Electric Generating
Plant owned 15% by the Company. On July 31, 1990, WIDCo sold its 50% interest
in the Centralia coal mining properties for $40.8 million. A tax adjustment of
$1.6 million related to the sale was recorded in 1991. Net income of $2.4
million in 1992 resulted from accounting adjustments and a refund of federal
income taxes for years prior to the sale. The consolidated financial
statements have been reclassified to reflect the continuing operations of the
Company. The revenues, expenses, assets and liabilities of the discontinued
operations have been reclassified from those categories and netted into single
line items for discontinued operations in the Balance Sheets and Income
Statements.

43
THE WASHINGTON WATER POWER COMPANY

NOTE 11. COMMITMENTS AND CONTINGENCIES

SUPPLY SYSTEM PROJECT 3

In 1985, the Company and the Bonneville Power Administration (BPA) reached a
settlement surrounding litigation related to the suspension of construction of
Washington Public Power Supply System (Supply System) Project 3. Project 3 is
a partially constructed 1,240 MW nuclear generating plant in which the Company
has a 5% interest. Under the settlement agreement, the Company receives power
deliveries from BPA from 1987 to 2017 in proportion to the Company's investment
in Project 3.

The settlement with BPA and other parties does not affect the Company's
obligations under the Ownership Agreement among the owners of Project 3. In
connection with its 1993 rate proceedings, BPA has proposed termination of
Project 1 and 3. Termination of Project 3 will require proposal of a
termination budget and approval by BPA and the Project 3 Owners under the
Ownership Agreement. The Company would be reimbursed for the cost of
termination under the settlement with BPA.

The only material claim against the Company arising out of the Company's
involvement in Project 3, which is still pending in the United States District
Court for the Western District of Washington (District Court), is the claim of
Chemical Bank, as bond fund trustee for Supply System Projects 4 and 5, against
all owners of Projects 1, 2 and 3 for unjust enrichment in the allocation of
certain costs of common services and facilities among the Supply System's five
nuclear projects. Projects 4 and 5 were being constructed adjacent to Projects
1 and 3, respectively, under a plan to share certain costs. Chemical Bank is
seeking a reallocation of $495 million in costs (plus interest since
commencement of construction in 1976) originally allocated to Projects 4 and 5.

On October 7, 1992, the District Court issued an order ruling in favor of the
defendants, including the Company, that the "proportional" allocation
methodology actually employed by the Supply System was permitted by the
Projects 4 and 5 bond resolution. This ruling does not resolve all cost
reallocation claims pending in the District Court, including whether the Supply
System correctly followed its methodology. Chemical Bank has indicated its
intent to assert claims for cost reallocations based upon other theories which
have not been litigated. The case is now in the discovery phase on those
claims, as settlement talks were not successful.

The Company cannot predict whether Chemical Bank will ultimately be successful
in its claim for reallocation of any of the costs of Supply System projects,
nor can the Company predict any amounts which might be reallocated to Project 3
or to the Company due to its 5% ownership interest therein. The Company also
has claims pending against the Supply System and Chemical Bank with respect to
a subordinated loan made by the Company to Projects 4 and 5 in 1981, in the
amount of approximately $11 million including interest. The District Court has
deferred ruling on the Company's motion to set-off the amount due on the loan,
including interest, against any recovery by Chemical Bank on its cost
reallocation claims. The Company intends to continue to defend this suit
vigorously. Since the discovery is not yet complete, the Company is unable to
assess the likelihood of an adverse outcome in this litigation, or estimate an
amount or range of potential loss in the event of an adverse outcome.

NEZ PERCE TRIBE

On December 6, 1991, the Nez Perce Tribe filed an action against the Company in
U. S. District Court for the District of Idaho alleging, among other things,
that two dams formerly operated by the Company, the Lewiston Dam on the
Clearwater River and the Grangeville Dam on the South Fork of the Clearwater
River, provided inadequate passage to migrating anadromous fish in violation of
rights under treaties between the Tribe and the United States made in 1855 and
1863. The Lewiston and Grangeville Dams, which had been owned and operated by
other utilities under hydroelectric licenses from the Federal Power Commission
(the "FPC", predecessor of the FERC) prior to acquisition by the Company, were
acquired by the Company in 1937 with the approval of the FPC, but were
dismantled and removed in 1973 and 1963, respectively. The Tribe initially
indicated through expert opinion disclosures that they were seeking actual and
punitive damages of $208 million. However, supplemental disclosures reflect
allegations of actual loss under different assumptions of between $425 million
and $650 million. Discovery in this case has been stayed pending a decision by
the Court on a case involving some similar issues between Idaho Power Company
and the Nez Perce Tribe. The case is not yet set for trial. The Company
intends to vigorously defend against the Tribe's claims. Since the discovery
is not yet complete, the Company is unable to assess the likelihood of an
adverse outcome in this litigation, or estimate an amount or range of potential
loss in the event of an adverse outcome.

44
THE WASHINGTON WATER POWER COMPANY

LITTLE FALLS PROJECT

Pending before the U. S. District Court in the Eastern District of Washington
is the case of Spokane Tribe of Indians v. WWP. This matter involves a claim
of the Spokane Tribe of Indians for damages arising out of the Company's Little
Falls Hydroelectric Development that was constructed on the Spokane River
pursuant to a 1905 Act of Congress. The Tribe is claiming the Company's dam
interfered with Indian fishing rights. The Tribe is also seeking a declaratory
judgment and quiet title to part of the property comprising the Little Falls
Hydroelectric Development. Discovery conducted by the Company revealed that
the Tribe may seek damages in the range of $100 million to $1.4 billion, to
compensate them for the alleged loss of fishing rights, alleged lost
opportunity to develop the properties, and alleged damage to the Tribe's
cultural heritage. The trial of these matters is currently scheduled for April
1994 in the United States District Court for the Eastern District of
Washington, in Spokane, Washington. On the merits, the Company claims that it
has all of the right, title and interest necessary for the construction,
operation and maintenance of the Little Falls Development, which rights, title
and interest were duly acquired from the United States pursuant to a 1905 Act
of Congress. The Company intends to vigorously defend against the Tribe's
claims. The Company is unable to assess the likelihood of an adverse outcome
in this litigation, or estimate an amount or range of potential loss in the
event of an adverse outcome.

STEAM HEAT PLANT

The Company recently completed an updated investigation of an oil spill that
occurred several years ago in downtown Spokane at the site of the Company's
steam heat plant. The Company purchased the plant in 1916 and operated it as a
non-regulated plant until it was deactivated in 1986 in a business decision
unrelated to the leak. After the Bunker C fuel oil spill, initial studies
suggested that the oil was being adequately contained by both geological
features and man-made structures. The Washington State Department of Ecology
(DOE) concurred with these findings. However, more recent tests confirm that
the oil has migrated beyond the steam plant property. On December 6, 1993, the
Company asked the DOE to approve a voluntary proposal to begin extracting the
underground oil. The extraction process is intended to remove quantities of
the oil and relieve any pressure on the deposit which might cause it to move.
In December 1993, the Company established a reserve of $2.0 million, which is
the current best estimate of mitigation costs.

FIRESTORM

On October 16, 1991, gale-force winds struck a five-county area in eastern
Washington and a seven-county area in northern Idaho. These winds were
responsible for causing 92 separate wildland fires, resulting in two deaths and
the loss of 114 homes and other structures, some of which were located in the
Company's service territory. On October 13, 1993, three separate class action
lawsuits were filed by private individuals in the Superior Court of Spokane
County in connection with fires occurring in the Midway, Nine Mile and
Chattaroy regions of eastern Washington. Service of these suits, together with
a fourth suit, occurred on January 7, 1994. Complainants allege various
theories of tortious conduct, including negligence, creation of a public
nuisance, strict liability and trespass. The lawsuits seek recovery for
property damage, emotional and mental distress, lost income and punitive
damages, but do not specify the amount of damages being sought. The Superior
Court has yet to certify these lawsuits as class actions. The Company intends
to vigorously defend against all such pending claims. Since the discovery is
not yet complete, the Company is unable to assess the likelihood of an adverse
outcome in this litigation, or estimate an amount or range of potential loss in
the event of an adverse outcome.

OTHER CONTINGENCIES

The Company has long-term contracts related to the purchase of fuel for thermal
generation, natural gas and hydroelectric power. Terms of the natural gas
purchase contracts range from one month to five years and the majority provide
for minimum purchases at the then effective market rate. The Company also has
various agreements for the purchase, sale or exchange of power with other
utilities, cogenerators, small power producers and government agencies. For
information relating to certain long-term purchased power contracts, see Note
13.

45
THE WASHINGTON WATER POWER COMPANY

NOTE 12. JOINTLY-OWNED ELECTRIC FACILITIES

The Company is involved in several jointly owned generating plants. Financing
for the Company's ownership in the projects is provided by the Company. The
Company's share of related operating and maintenance expenses for plants in
service is included in corresponding accounts in the Consolidated Statements of
Income. The following table indicates the Company's percentage ownership and
the extent of the Company's investment in such plants at December 31, 1993:

COMPANY'S CURRENT SHARE OF
-------------------------------------------------------------------
KW of Construction
Installed Fuel Ownership Plant in Accumulated Net Plant Work in
Project Capacity Source (%) Service Depreciation In Service Progress
- ------- --------- ------ ---------- -------- ------------ ---------- ------------
(Thousands of Dollars)

In service:
Centralia ......... 1,313,000 Coal 15% $ 54,424 $29,285 $ 25,139 $ 273
Colstrip 3 & 4 .... 1,400,000 Coal 15 263,882 72,184 191,698 -

NOTE 13. LONG-TERM PURCHASED POWER CONTRACTS WITH REQUIRED MINIMUM PAYMENTS

Under fixed contracts with Public Utility Districts, the Company has agreed to
purchase portions of the output of certain generating facilities. Although the
Company has no investment in such facilities, these contracts provide that the
Company pay certain minimum amounts (which are based at least in part on the
debt service requirements of the supplier) whether or not the facility is
operating. The cost of power obtained under the contracts, including payments
made when a facility is not operating, is included in operations and
maintenance expense in the Consolidated Statements of Income. Information as
of December 31, 1993, pertaining to these contracts is summarized in the
following table:

COMPANY'S CURRENT SHARE OF
---------------------------------------------------------------
Contract
Debt Revenue Expira-
Kilowatt Annual Service Bonds tion
Output Capability Costs(2) Costs(3) Outstanding Date
------ ---------- -------- -------- ----------- --------

PUBLIC UTILITY DISTRICT (Thousands of Dollars)
(PUD) CONTRACTS:
Chelan County PUD:
Lake Chelan Project ........ 100.0% (1) 58,000 $ 2,685 $ 311 $ 3,710 1995
Rocky Reach Project ........ 2.9 37,000 1,016 584 5,503 2011
Grant County PUD:
Priest Rapids Project ...... 6.1 55,000 1,658 1,119 8,616 2005
Wanapum Project ............ 8.2 75,000 2,392 1,724 15,530 2009
Douglas County PUD:
Wells Project .............. 3.9 30,000 970 595 7,797 2018
-------- ------- ------- --------
Totals ............. 255,000 $ 8,721 $ 4,333 $ 41,156
======== ======= ======= ========

(1) The Company purchases 100% of the Lake Chelan Project output and sells back
to the PUD about 40% of the output to supply local service area
requirements.
(2) The annual costs will change in proportion to the percentage of output
allocated to the Company in a particular year. Amounts represent the
operating costs for the year 1993.
(3) Included in annual costs.

Actual expenses for payments made under the above contracts for the years 1993,
1992 and 1991, were $8,721,000, $8,433,000 and $7,589,000, respectively. The
estimated aggregate amounts of required minimum payments (the Company's share
of debt service costs) under the above contracts for the next five years are
$4,338,000 in 1994, $4,775,000 in 1995, $3,830,000 in 1996, $4,300,000 in 1997
and $4,684,000 in 1998 (minimum payments thereafter are dependent on then
market conditions). In addition, the Company will be required to pay its
proportionate share of the variable operating expenses of these projects.

46
THE WASHINGTON WATER POWER COMPANY

NOTE 14. ACQUISITIONS AND DISPOSITIONS

During 1993, Pentzer acquired three companies, two involved in financial
services and one in point-of-purchase display manufacturing. Sales of
companies involved in telecommunications, technology and energy services
resulted in transactional gains of $7.1 million. At December 31, 1993, Pentzer
had approximately $130 million in assets compared to $103 million at the end of
1992.

In 1992, Pentzer's common stock ownership in ITRON was reduced from
approximately 60% to approximately 40% as a result of the issuance of common
stock by ITRON in an acquisition. Accordingly, beginning in 1992, Pentzer's
share of ITRON's earnings is accounted for by the equity method and is included
in Other Income-Net and its investment in ITRON is reflected on the balance
sheet under Other Property and Investments. As a result of ITRON's initial
public offering in November 1993 and Pentzer's sale of a portion of its ITRON
stock, Pentzer's ownership interest in ITRON was reduced to approximately 25%.

In December 1992, the Company completed the purchase of the northern Idaho
electric distribution assets of Citizens Utilities. The cash purchase price of
$1.2 million included a premium above the book value of the net assets
acquired. The premium will be amortized over a 19-month period. The purchase
provided approximately 2,100 additional electric customers. The Company
believes that this acquisition will not have a material impact on its revenues
or its operations.

On September 30, 1991, the Company completed the purchase of the Oregon and
South Lake Tahoe, California, natural gas assets of CP National Corporation, a
subsidiary of ALLTEL Corporation, for approximately $67.9 million. The cash
purchase included a premium of approximately $24.9 million above the book value
of the net assets acquired. The premium and other costs associated with
acquiring the properties will be amortized under a straight-line method over 20
years and the amortization may be accelerated depending upon earnings. The
California and Oregon Commissions have agreed to a general rate "freeze" which
extends to January 1, 1996, in California and to December 31, 1995, in Oregon.
Purchased natural gas costs will continue to be tracked through to customers
during the rate "freeze" period.

On February 15, 1994, the Company announced it had reached agreement to acquire
the northern Idaho electric properties of Pacific Power & Light Company, an
operating division of PacifiCorp. The cash purchase price will be $26 million,
subject to adjustments upon closing. The approximate book value of the assets
is $19 million. The purchase agreement is subject to approval by the IPUC and
FERC. It is anticipated the acquisition will be completed mid-year 1994.
Pacific Power's northern Idaho electric system currently serves approximately
9,300 customers. The Company believes this acquisition will not have a
material impact on its revenues or its operations.

47
THE WASHINGTON WATER POWER COMPANY

NOTE 15. SELECTED QUARTERLY INFORMATION (UNAUDITED)

The Company's electric and natural gas operations are significantly affected by
weather conditions. Consequently, there can be large variances in revenues,
expenses and net income between quarters based on seasonal factors such as
temperatures and streamflow conditions.

A summary of quarterly operations (in thousands of dollars except for per share
amounts) for 1993 and 1992 follows. All references to number of shares and per
share information have been adjusted to reflect the common stock split on a
retroactive basis.

THREE MONTHS ENDED
-----------------------------------------------------------
MARCH JUNE SEPTEMBER DECEMBER
31 30 30 31
-------- -------- -------- --------

1993
Operating revenues ..................... $212,978 $126,876 $123,507 $177,238
Operating income ....................... 67,410 30,232 20,403 42,805
Net income ............................. 36,031 15,765 7,394 23,586
Income available for common stock ...... 33,932 13,686 5,312 21,511
Earnings per share:
Continuing utility operations ........ $0.61 $0.19 $0.07 $0.32
Continuing non-utility operations .... $0.05 $0.08 $0.03 $0.09
----- ----- ----- -----
Total ................................ $0.66 $0.27 $0.10 $0.41

Dividends paid per common share ........ $0.31 $0.31 $0.31 $0.31

Trading price range per share:
High ................................. $19 3/8 $19 13/16 $20 3/4 $19 1/8
Low .................................. $18 15/16 $19 1/4 $20 $18 1/8

1992
Operating revenues ..................... $157,146 $118,761 $118,555 $163,135
Operating income ....................... 48,475 32,365 24,591 45,195
Net income from discontinued operations. - 858 1,545 -
Net income ............................. 25,508 16,247 9,901 23,013
Income available for common stock ...... 23,978 14,662 8,337 20,876
Earnings per share:
Continuing utility operations ........ $0.42 $0.23 $0.10 $0.40
Continuing non-utility operations .... $0.08 $0.04 $0.04 $0.01
Discontinued operations............... - $0.02 $0.03 -
----- ----- ----- ------
Total ................................ $0.50 $0.29 $0.17 $0.41

Dividends paid per common share ........ $0.31 $0.31 $0.31 $0.31

Trading price range per share:
High ................................. $17 $17 1/8 $18 3/8 $17 3/4
Low .................................. $15 15/16 $16 1/8 $16 11/16 $17

48
THE WASHINGTON WATER POWER COMPANY

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information regarding the directors of the Registrant has been omitted pursuant
to General Instruction G to Form 10-K. Reference is made to the Registrant's
Proxy Statement to be filed with the Securities and Exchange Commission in
connection with the Registrant's annual meeting of shareholders to be held on
May 12, 1994.

Executive Officers of the Registrant

Name Age Business Experience During Past 5 Years
- ---- --- ---------------------------------------

Paul A. Redmond 57 Chairman of the Board, President and Chief Executive Officer
since February 1994; Chairman of the Board and Chief Executive
Officer May 1988 - February 1994.

James R. Harvey 56 President and Chief Operating Officer from May 1988 until retirement
February 1994.

W. Lester Bryan 53 Senior Vice President - Rates & Resources since May 1992;
Vice President - Power Supply August 1983 - May 1992.

Jon E. Eliassen 46 Vice President - Finance and Chief Financial Officer
since March 1986.

Gary G. Ely 46 Vice President - Natural Gas since February 1991;
Vice President - Marketing & Gas Supply May 1989 -
February 1991; Vice President - Marketing May 1986 - May
1989.

Robert D. Fukai 44 Vice President - Human Resources, Corporate Services &
Marketing since January 1993 Vice President - Corporate
Services & Human Resources October 1992 - December 1992;
Vice President - Operations May 1986 - October 1992.

JoAnn Matthiesen 53 Vice President - Organization Effectiveness, Public Relations &
Assistant to the Chairman since January 1993; Vice President -
Marketing, Public Relations & Assistant to the Chairman February
1991 - January 1993; Manager - Public Relations & Assistant to the
Chairman August 1990 - February 1991; prior to employment with
the Registrant in August 1990: Chief Operating Officer - Dominican
Outreach Services and President - Dominican Outreach Foundation
May 1988 - July 1990.

Nancy J. Racicot 46 Vice President - Operations since October 1992;
Vice President - Corporate Services March 1990 - October 1992;
Manager - Administrative Services April 1988 - March 1990.

Ronald R. Peterson 41 Treasurer since February 1992; Manager - Customer Information
Services March 1991 - February 1992; Supervisor - Corporate
Accounting March 1987 - March 1991.

John W. Buergel 50 Controller since May 1990; Manager - Operations April 1988 - May 1990.

Terry L. Syms 45 Corporate Secretary & Supervisor - Shareholder Services since March 1988.

All of the Company's executive officers, with the exception of Messrs. Harvey,
Bryan, Ely, Fukai and Buergel and Ms. Racicot, were officers or directors of
one or more of the Company's subsidiaries in 1993.

Executive officers are elected annually by the Board of Directors.

49
THE WASHINGTON WATER POWER COMPANY

ITEM 11. EXECUTIVE COMPENSATION

Information regarding executive compensation has been omitted pursuant to
General Instruction G to Form 10-K. Reference is made to the Registrant's
Proxy Statement to be filed with the Securities and Exchange Commission in
connection with the Registrant's annual meeting of shareholders to be held on
May 12, 1994.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

(a) Security ownership of certain beneficial owners (owning 5% or more of
Registrant's voting securities):

None.

(b) Security ownership of management:

Information regarding security ownership of management has been
omitted pursuant to General Instruction G to Form 10-K. Reference is
made to the Registrant's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Registrant's
annual meeting of shareholders to be held on May 12, 1994.

None.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information regarding certain relationships and related transactions has been
omitted pursuant to General Instruction G to Form 10-K. Reference is made to
the Registrant's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Registrant's annual meeting of shareholders
to be held on May 12, 1994.

50
THE WASHINGTON WATER POWER COMPANY

PART IV

ITEM 14. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND
REPORTS ON FORM 8-K

(a) 1. Financial Statements (Included in Part II of this report):

Independent Auditors' Report

Consolidated Statements of Income and Retained Earnings for the
Years Ended December 31, 1993, 1992 and 1991

Consolidated Balance Sheets, December 31, 1993 and 1992

Consolidated Statements of Capitalization, December 31, 1993 and
1992

Consolidated Statements of Cash Flows for the Years Ended December
31, 1993, 1992 and 1991

Schedule of Information by Business Segments for the Years Ended
December 31, 1993, 1992 and 1991

Notes to Financial Statements

(a) 2. Financial Statement Schedules (Included in Part IV of this report):

Independent Auditors' Report (Relating to Supplemental Schedules)

Supplemental Schedules for the Years Ended December 31, 1993, 1992
and 1991:

Schedule V(a), (b), (c) - Property, Plant and Equipment

Schedule VI(a),(b), (c) - Accumulated Depreciation and
Amortization of Property, Plant and Equipment

Schedule X - Supplementary Income Statement Information

Other schedules are omitted because of the absence of conditions
under which they are required or because the required information
is given in the financial statements or notes thereto.

(a) 3. Exhibits:

Reference is made to the Exhibit Index commencing on page 58. The
Exhibits include the management contracts and compensatory plans or
arrangements required to be filed as exhibits to this Form 10-K by
Item 601(10)(iii) of Regulation S-K.

(b) Reports on Form 8-K:

Dated November 9, 1993 regarding the two-for-one stock split in the
form of a 100% stock dividend.

INDEPENDENT AUDITORS' REPORT

The Washington Water Power Company
Spokane, Washington

We have audited the consolidated financial statement of The Washington Water
Power Company and subsidiaries as of December 31, 1993 and 1992, and for each
of the three years in the period ended December 31, 1993, and have issued our
report thereon dated January 28, 1994 (February 15, 1994 as to Note 14); such
financial statement and report are included in Part II of this Annual Report on
Form 10-K. Our audits also comprehended the financial statement schedules of
The Washington Water Power Company, listed in Item 14(a)2. These financial
statement schedules are the responsibility of the Company's management. Our
responsibility is to express an opinion based on our audits. In our opinion,
such financial statement schedules, when considered in relation to the basic
financial statements taken as a whole, present fairly in all material respects,
the information shown therein.

Deloitte & Touche

Seattle, Washington
January 28, 1994 (February 15, 1994 as to Note 14)

SCHEDULE V(a)

THE WASHINGTON WATER POWER COMPANY

Property, Plant and Equipment
For the Year Ended December 31, 1993
(Thousands of Dollars)

Column A Column B Column C Column D Column E Column F
-------------- ----------- ----------- ----------- ------------ -------------
Balance at Additions Other Balance
Beginning at Changes at End of
Classification of Period Cost Retirements Add (Deduct) Period
-------------- ----------- ---------- ----------- ------------ -------------

UTILITY:
Electric
Intangible plant $ 5,284 $ 1,251 $ - $ 125(1) $ 6,660
Production plant 628,529 9,657 683 228(2) 637,731
Transmission plant 218,233 10,290 344 - 228,179
Distribution plant 409,484 26,155 2,631 - 433,008
General plant 75,524 11,561 4,838 - 82,247
General plant 1,177 - - (1,177)(3) 0
---------- --------- --------- --------- ----------
Total electric 1,338,231 58,914 8,496 (824) 1,387,825

Natural Gas
Intangible 28,696 81 - - 28,777
Production 980 - - - 980
Underground
storage plant 14,723 217 - - 14,940
Transmission 2,807 253 - - 3,060
Distribution plant 198,734 28,184 10 - 226,908
General plant 4,591 698 1 - 5,288
---------- --------- --------- --------- ----------
Total natural gas 250,531 29,433 11 - 279,953

CWIP 32,739 22,452(4) - - 55,191
---------- --------- --------- --------- ----------
Total utility 1,621,501 110,799 8,507 (824) 1,722,969

NON-UTILITY: 44,741 4,349 2,003 (3,412) 43,675
---------- --------- --------- --------- ----------

Total $1,666,242 $ 115,148 $ 10,510 $ (4,236) $1,766,644
========== ========= ========= ======== ==========

The cost of additions includes completed projects transferred from CWIP. The
Company's 1993 construction program was financed with internally-generated
funds, bank borrowings and commercial paper, and proceeds from the sales of
preferred and common stock and long-term debt.

(1) Represents balance of Citizen Utility acquisition adjustment.
(2) Amortization of reserve for nonrecovery of a portion of the Kettle Falls
project in accordance with FAS 90.
(3) Represents the redistribution of Citizen Utility Electric Plant to
appropriate category.
(4) Represents $110,796,000 spent on construction less $88,344,000 closed to
plant in service from CWIP.

49
53

SCHEDULE V(b)

THE WASHINGTON WATER POWER COMPANY

Property, Plant and Equipment
For the Year Ended December 31, 1992
(Thousands of Dollars)

Column A Column B Column C Column D Column E Column F
-------- ----------- --------- ----------- ----------- ----------
Balance at Additions Other Balance
Beginning at Changes at End of
Classification of Period Cost Retirements Add (Deduct) Period
- ---------------------- ----------- --------- ----------- ------------ ----------

UTILITY:
Electric
Intangible plant $ 8,440 $ 451 $ 3,607 $ - $ 5,284
Production plant 594,394 34,076 169 228(1) 628,529
Transmission plant 214,516 3,884 167 - 218,233
Distribution plant 385,656 26,180 2,352 - 409,484
General plant 70,600 6,639 1,715 - 75,524
General plant - - - 1,177(2) 1,177
----------- --------- --------- --------- -----------
Total electric 1,273,606 71,230 8,010 1,405 1,338,231

Natural Gas
Intangible 28,158 - 11 549(3) 28,696
Production 980 - - - 980
Underground
storage plant 13,920 805 2 - 14,723
Transmission 2,807 - - - 2,807
Distribution plant 175,844 23,112 222 - 198,734
General plant 4,755 506 670 - 4,591
----------- --------- --------- --------- -----------
Total natural gas 226,464 24,423 905 549 250,531

CWIP 39,820 (7,081)(4) - - 32,739
----------- --------- --------- --------- -----------
Total utility 1,539,890 88,572 8,915 1,954 1,621,501

NON-UTILITY: 59,299 3,642 1,424 (16,776)(5) 44,741
----------- --------- --------- --------- -----------

Total $ 1,599,189 $ 92,214 $ 10,339 $ (14,822) $ 1,666,242
=========== ========= ========= ========= ===========

The cost of additions includes completed projects transferred from CWIP. The
Company's 1992 construction program was financed with internally-generated
funds, bank borrowings and commercial paper, and proceeds from the sales of
preferred and common stock and long-term debt.

(1) Amortization of reserve for nonrecovery of a portion of the Kettle Falls
project in accordance with FAS 90.
(2) Represents the purchase of Citizen Utility Electric Plant.
(3) Acquisition adjustment related to purchase of natural gas assets from CP
National Corporation.
(4) Represents $89,748,000 spent on construction less $96,829,000 closed to
plant in service from CWIP.
(5) Deconsolidation of ITRON, Inc.

SCHEDULE V(c)

THE WASHINGTON WATER POWER COMPANY

Property, Plant and Equipment
For the Year Ended December 31, 1991
(Thousands of Dollars)

Column A Column B Column C Column D Column E Column F
-------- ----------- ---------- ----------- ------------ -----------
Balance at Additions Other Balance
Beginning at Changes at End of
Classification of Period Cost Retirements Add (Deduct) Period
- ---------------------- ----------- ---------- ----------- ------------ -----------

UTILITY:
Electric
Intangible plant $ 8,002 $ 438(5) $ - $ - $ 8,440
Production plant 588,637 6,516 987 228 (1) 594,394
Transmission plant 211,724 3,546 754 - 214,516
Distribution plant 367,608 20,600 2,541 (11)(2) 385,656
General plant 65,159 6,905(5) 1,464 - 70,600
----------- ---------- --------- ---------- -----------
Total electric 1,241,130 38,005 5,746 217 1,273,606

Natural Gas
Intangible - 1,534 - 26,624 (3) 28,158
Production - 980 - - 980
Underground
storage plant 14,474 196 750 - 13,920
Transmission - 2,807 - - 2,807
Distribution plant 99,319 76,499 (26) - 175,844
General plant 962 3,848 55 - 4,755
----------- ---------- --------- ---------- -----------
Total natural gas 114,755 85,864 779 26,624 226,464

CWIP 19,774 20,046(6) - - 39,820
----------- ---------- --------- ---------- -----------
Total utility 1,375,659 143,915 6,525 26,841 1,539,890

NON-UTILITY: 54,019 9,261 1,533 (2,448)(4) 59,299
----------- ---------- --------- ---------- -----------
Total $ 1,429,678 $ 153,176 $ 8,058 $ 24,393 $ 1,599,189
=========== ========== ========= ========== ===========

NOTE: All balances have been restated to exclude the assets of the Company's
discontinued coal mining operations. These properties were sold in 1990. The
amount of WP Natural Gas assets in Column F is $73,828,000.

The cost of additions includes completed projects transferred from CWIP. The
Company's 1991 construction program was financed with internally-generated
funds, bank borrowings and commercial paper, and proceeds from the sales of
preferred and common stock and long-term debt.

(1) Amortization of reserve for non-recovery of a portion of the Kettle Falls
project in accordance with FAS 90.
(2) Amortization of adjustment related to City of Worley acquisition.
(3) Acquisition adjustment related to purchase of natural gas assets from CP
National Corporation.
(4) Reclassification of software development costs.
(5) Includes $234,237 of computer software transferred from general plant to
intangible plant.
(6) Represents $143,915,000 spent on construction less $123,869,000 closed to
plant in service from CWIP.

55
SCHEDULE VI(a)

THE WASHINGTON WATER POWER COMPANY

Accumulated Depreciation and Amortization
of Property, Plant and Equipment
for the Year Ended December 31, 1993
(Thousands of Dollars)

Column A Column B Column C Column D Column E Column F
-------- -------- -------- -------- -------- --------
Additions
Balance at Charged to Other Balance
Beginning Costs and Changes at End of
Classification of Period Expenses Retirements Add (Deduct) Period
-------------- ---------- ---------- ----------- ------------ --------
(1) (2)

UTILITY:

Electric $ 352,612 $ 36,377 $ 7,769 $ 1,288 (3) $ 382,508

Natural Gas 77,736 8,839 105 - 86,470
---------- --------- --------- --------- ----------
Total utility 430,348 45,216 7,874 1,288 468,978

NON-UTILITY: 11,702 1,978 591 (2,060)(4) 11,029
---------- --------- --------- --------- ----------
Total $ 442,050 $ 47,194 $ 8,465 $ (772) $ 480,007
========== ========= ========= ========= ==========

(1) Retirements are reported net of cost of removal and salvage.
(2) Reference is made to Note 1 to Financial Statements for depreciation
method.
(3) Pertains to adjustment resulting from sale of equipment, transfers to
non-utility, acquisition premium for Citizens Utility of ($340,298) and
$838,911 accumulated depreciation acquired at the time of the purchase of
Citizens Utility.
(4) Represents a transfer relating to the accrued liability for Steam Heat
Environmental clean-up.

56
SCHEDULE VI(b)

THE WASHINGTON WATER POWER COMPANY

Accumulated Depreciation and Amortization
of Property, Plant and Equipment
for the Year Ended December 31, 1992
(Thousands of Dollars)

Column A Column B Column C Column D Column E Column F
-------------- ----------- ---------- ----------- ------------ --------
Additions
Balance at Charged to Other Balance
Beginning Costs and Changes at End of
Classification of Period Expenses Retirements Add (Deduct) Period
-------------- ----------- ---------- ----------- ------------ ---------
(1) (2)

UTILITY:

Electric $ 324,862 $ 35,973 $ 8,450 $ 227 (3) $ 352,612

Natural Gas 70,382 8,236 882 - 77,736
---------- --------- --------- --------- ----------
Total utility 395,244 44,209 9,332 227 430,348

NON-UTILITY: 20,731 1,773 948 (9,854)(4) 11,702
---------- --------- --------- --------- ----------
Total $ 415,975 $ 45,982 $ 10,280 $ (9,627) $ 442,050
========== ========= ========= ========= ==========

NOTE: All balances have been restated to exclude the accumulated depreciation
and amortization on the Company's discontinued coal mining operations. These
properties were sold in 1990. The amount in Column F related to WP Natural Gas
is $31,460.

57
SCHEDULE VI(c)

THE WASHINGTON WATER POWER COMPANY

Accumulated Depreciation and Amortization
of Property, Plant and Equipment
for the Year Ended December 31, 1991
(Thousands of Dollars)

UTILITY:

Electric $295,963 $35,342 $6,443 $ - $324,862

Natural Gas 38,276 4,064 315 28,357(3) 70,382
-------- ------- ------ ------- --------
Total utility 334,239 39,406 6,758 28,357 395,244

NON-UTILITY: 20,078 4,016 1,028 (2,335)(4) 20,731
-------- ------- ------ ------- --------
Total $354,317 $43,422 $7,786 $26,022 $415,975
======== ======= ====== ======= ========

- ---------
NOTE: All balances have been restated to exclude the accumulated depreciation
and amortization on the Company's discontinued coal mining operations. These
properties were sold in 1990. The amount in Column F related to WP Natural Gas
is $29,404.

(1) Retirements are reported net of cost of removal and salvage.
(2) Reference is made to Note 1 to Financial Statements for depreciation
method.
(3) Represents balance of accumulated depreciation & amortization for WP
Natural Gas at time of purchase.
(4) Reclassification related to intangibles and software development costs.

SCHEDULE X

THE WASHINGTON WATER POWER COMPANY

Supplementary Income Statement Information
for the Years Ended December 31, 1993, 1992 and 1991
(Thousands of Dollars)

1993 1992 1991
---- ---- ----

Taxes, other than income taxes, are as follows:
Real and personal property $ 23,061 $ 21,058 $ 20,739
Federal and state social security 5,453 5,477 6,174
State excise 9,940 10,712 10,189
Municipal occupation taxes and license fees 8,991 8,203 7,714
Miscellaneous 2,066 1,809 2,200
--------- --------- ---------
Total $ 49,511 $ 47,259 $ 47,016
========= ========= =========
Charged to:
Operating expenses - taxes other than income $ 44,195 $ 41,664 $ 39,764
Utility plant, clearing and
other sundry accounts 5,316 5,595 7,252
--------- --------- ---------
Total $ 49,511 $ 47,259 $ 47,016
========= ========= =========

Amounts of maintenance and repairs, and depreciation, other than as set out
separately in the Consolidated Statements of Income and Retained Earnings,
are not material.

Amounts of advertising costs are not material.

59
THE WASHINGTON WATER POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

THE WASHINGTON WATER POWER COMPANY

March 4, 1994 By /s/ PAUL A. REDMOND
------------- -----------------------------------------------------------------
Date Paul A. Redmond
Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.

Signature Title Date
--------- ----- ----

Principal Executive
/s/ PAUL A. REDMOND Officer and Director March 4, 1994
-----------------------------------------
Paul A. Redmond (Chairman of the Board,
President and Chief Executive Officer)
Principal Financial
/s/ J. E. ELIASSEN and Accounting Officer March 4, 1994
-----------------------------------------
J. E. Eliassen (Vice President - Finance
and Chief Financial Officer)

/s/ DAVID A. CLACK Director March 4, 1994
-----------------------------------------
David A. Clack

/s/ DUANE B. HAGADONE Director March 4, 1994
-----------------------------------------
Duane B. Hagadone

/s/ ROBERT S. JEPSON, JR. Director March 4, 1994
-----------------------------------------
Robert S. Jepson, Jr.

/s/ EUGENE W. MEYER Director March 4, 1994
-----------------------------------------
Eugene W. Meyer

/s/ H. NORMAN SCHWARZKOPF Director March 4, 1994
-----------------------------------------
General H. Norman Schwarzkopf

/s/ B. JEAN SILVER Director March 4, 1994
-----------------------------------------
B. Jean Silver

/s/ LARRY A. STANLEY Director March 4, 1994
-----------------------------------------
Larry A. Stanley

/s/ R. JOHN TAYLOR Director March 4, 1994
-----------------------------------------
R. John Taylor

/s/ EUGENE THOMPSON Director March 4, 1994
-----------------------------------------
Eugene Thompson

56
60
THE WASHINGTON WATER POWER COMPANY

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration Statement No.
2-81697 on Form S-8, in Registration Statement No. 2-94816 on Form S-8, in
Registration Statement No. 33-10040 on Form S-3, in Registration Statement No.
33-32148 on Form S-8, in Registration Statement No. 33-40333 on Form S-3, in
Registration Statement No. 33-49662 on Form S-3, in Registration Statement No.
33-60136 on Form S-3, and in Registration Statement No. 33-51669 on Form S-3 of
our report dated January 28, 1994 (February 15, 1994 as to Note 14), appearing
in this Annual Report on Form 10-K of The Washington Water Power Company for
the year ended December 31, 1993.

Deloitte & Touche

Seattle, Washington
March 4, 1994

61
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX

Previously Filed*
------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

3(a) 1-3701 (with 1992 3(a) Restated Articles of Incorporation of the Company
Form 10-K) dated as of January 27, 1989 and Amended as of
September 16, 1992.

3(b) ** 3(b) Bylaws of the Company, as amended, February 8, 1994.

4(a)-1 2-4077 B-3 Mortgage and Deed of Trust, dated as of June 1, 1939.

4(a)-2 2-9812 4(c) First Supplemental Indenture, dated as of October 1, 1952.

4(a)-3 2-60728 2(b)-2 Second Supplemental Indenture, dated as of May 1, 1953.

4(a)-4 2-13421 4(b)-3 Third Supplemental Indenture, dated as of December 1, 1955.

4(a)-5 2-13421 4(b)-4 Fourth Supplemental Indenture, dated as of March 15, 1967.

4(a)-6 2-60728 2(b)-5 Fifth Supplemental Indenture, dated as of July 1, 1957.

4(a)-7 2-60728 2(b)-6 Sixth Supplemental Indenture, dated as of January 1, 1958.

4(a)-8 2-60728 2(b)-7 Seventh Supplemental Indenture, dated as of August 1, 1958.

4(a)-9 2-60728 2(b)-8 Eighth Supplemental Indenture, dated as of January 1, 1959.

4(a)-10 2-60728 2(b)-9 Ninth Supplemental Indenture, dated as of January 1, 1960.

4(a)-11 2-60728 2(b)-10 Tenth Supplemental Indenture, dated as of April 1, 1964.

4(a)-12 2-60728 2(b)-11 Eleventh Supplemental Indenture, dated as of March 1, 1965.

4(a)-13 2-60728 2(b)-12 Twelfth Supplemental Indenture, dated as of May 1, 1966.

4(a)-14 2-60728 2(b)-13 Thirteenth Supplemental Indenture, dated as of August 1, 1966.

4(a)-15 2-60728 2(b)-14 Fourteenth Supplemental Indenture, dated as of April 1, 1970.

4(a)-16 2-60728 2(b)-15 Fifteenth Supplemental Indenture, dated as of May 1, 1973.

4(a)-17 2-60728 2(b)-16 Sixteenth Supplemental Indenture, dated as of February 1, 1975.

4(a)-18 2-60728 2(b)-17 Seventeenth Supplemental Indenture,
dated as of November 1, 1976.

4(a)-19 2-69080 2(b)-18 Eighteenth Supplemental Indenture, dated as of June 1, 1980.

4(a)-20 1-3701 (with 4(a)-20 Nineteenth Supplemental Indenture, dated as of January 1, 1981.
1980 Form 10-K)

*Incorporated herein by reference.
**Filed herewith.

62
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX (continued)

Previously Filed*
------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

4(a)-21 2-79571 4(a)-21 Twentieth Supplemental Indenture, dated as of August 1, 1982.

4(a)-22 1-3701 (with 4(a)-22 Twenty-First Supplemental Indenture,
Form 8-K dated dated as of September 1, 1983.
September 20, 1983)

4(a)-23 2-94816 4(a)-23 Twenty-Second Supplemental Indenture,
dated as of March 1, 1984.

4(a)-24 1-3701 (with 4(a)-24 Twenty-Third Supplemental Indenture,
1986 Form 10-K) dated as of December 1, 1986.

4(a)-25 1-3701 (with 4(a)-25 Twenty-Fourth Supplemental Indenture,
1987 Form 10-K) dated as of January 1, 1988.

4(a)-26 1-3701 (with 4(a)-26 Twenty-Fifth Supplemental Indenture,
1989 Form 10-K) dated as of October 1, 1989.

4(a)-27 33-51669 4(a)-27 Twenty-Sixth Supplemental Indenture,
dated as of April 1, 1993.

4(a)-28 ** Twenty-Seventh Supplemental Indenture,
dated as of January 1, 1994.

4(b)-1 1-3701 (with 4(e)-1 Loan Agreement between City of Forsyth, Rosebud County,
1989 Form 10-K) and the Company, dated as of November 1, 1989 (Series
1989 A and 1989 B). Replaces Exhibit 4(c)-1 (agreement between the Company
and City of Forsyth, Rosebud County, Montana, dated as of October 1, 1986)
filed with Form 10-K for 1986 and Exhibit 4(g)-1 (agreement between the
Company and City of Forsyth, Rosebud County, Montana, dated as of April 1,
1987) filed with Form 10-K for 1987.

4(b)-2 1-3701 (with 4(e)-2 Indenture of Trust, Pollution Control Revenue Refunding
1989 Form 10-K) Bonds (Series 1989 A and 1989 B) between City of Forsyth
Rosebud County, Montana and Chemical Bank, dated as of November 1, 1989.
Replaces Exhibit 4(e)-2 (Indenture of Trust between City of Forsyth,
Rosebud County, Montana and Chemical Bank dated as of October 1, 1986)
filed with Form 10-K for 1986 and Exhibit 4(g)-2 (Indenture of Trust
between City of Forsyth, Rosebud County, Montana and Chemical Bank, dated
as of April 1, 1987) filed with Form 10-K for 1987.

4(c)-1 1-3701 (with 4(h)-1 Indenture between the Company and
1988 Form 10-K) Chemical Bank dated as of July 1, 1988
(Series A and B Medium-Term Notes).

*Incorporated herein by reference.
**Filed herewith.

63
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX (continued)

Previously Filed*
--------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

4(d)-1 1-3701 (with 4(j)-1 Credit Agreements between the Company and the Toronto-
1992 Form 10-K) Dominion (Texas), Inc., the Toronto-Dominion Bank
Houston Agency, The Bank of New York, CIBC, Inc. and
and Citicorp USA, Inc. with the Toronto-Dominion
(Texas), Inc. as agent, dated as of October 1, 1992.

4(e)-1 1-3701 (with 4(k)-1 Credit Agreements between the Company and Seattle-First
1992 Form 10-K) National Bank, West One Bank Idaho, N.A., First Interstate
Bank of Washington, N.A., First Security Bank of Idaho, N.A.,
U.S. Bank of Washington, N.A., and Washington Trust Bank with
Seattle-First National Bank as agent, dated as of
December 10, 1992.

10(a) 2-60728 5(b) Power Sales Contract (Lake Chelan Project) with
Public Utility District No. 1 of Chelan County,
Washington, dated as of June 21, 1955.

10(b)-1 2-13788 13(e) Power Sales Contract (Rocky Reach Project) with
Public Utility District No. 1 of Chelan County, Washington,
dated as of November 14, 1957.

10(b)-2 2-60728 10(b)-1 Amendment to Power Sales Contract (Rocky Reach
Project) with Public Utility District No. 1 of Chelan
County, Washington, dated as of June 1, 1968.

10(c)-1 2-13421 13(d) Power Sales Contract (Priest Rapids Project) with Public Utility District
No. 2 of Grant County, Washington, dated as of May 22, 1956.

10(c)-2 2-60728 5(d)-1 Second Amendment to Power Sales Contract (Priest Rapids
Project) with Public Utility District No. 2 of Grant
County, Washington, dated as of December 19, 1977.

10(d)-1 2-60728 5(e) Power Sales Contract (Wanapum Project) with
Public Utility District No. 2 of Grant County,
Washington, dated as of June 22, 1959.

10(d)-2 2-60728 5(e)-1 First Amendment to Power Sales Contract (Wanapum
Project) with Public Utility District No. 2 of Grant
County, Washington, dated as of December 19, 1977.

10(d)-3 2-60728 5(f) Reserved Share Power Sales Contract (Priest Rapids
and Wanapum Projects) with Public Utility District No. 2
of Grant County, Washington, dated as of June 22, 1956.

* Incorporated herein by reference.
** Filed herewith.

64
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX (continued)

Previously Filed*
--------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

10(d)-4 2-60728 5(f)-1 First Amendment to Reserved Share Power Sales Contract
(Priest Rapids and Wanapum Projects) with Public
Utility District No. 2 of
Grant County, Washington, dated as of December 19, 1977.

10(e)-1 2-60728 5(g) Power Sales Contract (Wells Project) with Public Utility District No. 1
of Douglas County, Washington, dated as of September 18, 1963.

10(e)-2 2-60728 5(g)-1 Amendment to Power Sales Contract (Wells Project)
with Public Utility District No. 1 of Douglas County, Washington, dated
as of February 9, 1965.

10(e)-3 2-60728 5(h) Reserved Share Power Sales Contract (Wells Project)
with Public Utility District No. 1 of Douglas County, Washington, dated
as of September 18, 1963.

10(e)-4 2-60728 5(h)-1 Amendment to Reserved Share Power Sales Contract
(Wells Project) with Public Utility District No. 1 of Douglas County,
Washington, dated as of February 9, 1965.

10(f) 2-60728 5(i) Canadian Entitlement Exchange Agreement executed by
Bonneville Power Administration Columbia Storage Power Exchange and the
Company, dated as of August 13, 1964.

10(g) 2-60728 5(j) Pacific Northwest Coordination Agreement,
dated as of September 15, 1964.

10(h)-1 2-60728 5(k) Ownership Agreement between the Company, Pacific Power & Light
Company, Puget Sound Power & Light Company, Portland General Electric
Company, Seattle City Light, Tacoma City Light and Grays Harbor and
Snohomish County Public Utility Districts as owners of the Centralia
Steam Electric Generating Plant, dated as of May 15, 1969.

10(h)-3 1-3701 (with Form 10(h)-3 Centralia Fuel Supply Agreement between
10-K for 1991) PacifiCorp Electric Operations, as the Seller,
and the Company, Puget Sound Power
Power & Light Company, Portland General
Electric Company, Seattle City Light,
Tacoma City Light and Grays Harbor and
Snohomish County Public Utility Districts,
as the Buyers of coal for the Centralia Steam
Electric Generating Plant, dated as of
January 1, 1991.

* Incorporated herein by reference.
** Filed herewith.

65
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX (continued)

Previously Filed*
--------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

10(i)-1 2-47373 13(y) Agreement between the Company, Bonneville Power Administration
and Washington Public Power Supply System for purchase and
exchange of power from the Nuclear Project No. 1 (Hanford), dated
as of January 6, 1973.

10(i)-2 2-60728 5(m)-1 Amendment No. 1 to the Agreement between the Company
between the Company, Bonneville Power Administration and Washington Public
Power Supply System for purchase and exchange of power from the
Nuclear Project No. 1 (Hanford), dated as of May 8, 1974.

10(i)-3 1-3701 (with 10(i)-3 Agreement between BPA, the Montana Power Company,
Form 10-K for PP&L, PGE, PSP&L, the Company and the Supply
1986) 1986) System for relocation costs of Nuclear Project No. 1 (Hanford)
dates as of July 9, 1986.

10(j)-1 2-60728 5(n) Ownership Agreement of Nuclear Project No. 3, sponsored by
Washington Public Power Supply System, dated as of September 17, 1973.

10(j)-2 1-3701 (with 1 Settlement Agreement and Covenant Not to Sue executed
Form 10-Q for by the United States Department of Energy acting
quarter ended by and through the Bonneville Power Administration
September 30, and the Company, dated as of September 17, 1985,
1985) describing the settlement of Project 3 litigation.

10(j)-3 1-3701 (with 2 Agreement to Dismiss Claims and Covenant
Form 10-Q for Not to Sue between the Washington Public
quarter ended Power Supply System and the Company, dated
September 30, as of September 17, 1985, describing the settlement
1985) of Project 3 litigation with the Supply System.

10(j)-4 1-3701 (with 3 Agreement among Puget Sound Power & Light
Form 10-Q for Company, the Company, Portland General Electric
quarter ended Company and PacifiCorp dba Pacific Power & Light
September 30, Company, agreeing to execute contemporaneously
1985) an irrevocable offer, to and for the benefit of the Bonneville
Power Administration, dated as of September 17, 1985.

10(k)-2 2-66184 5(r) Service Agreement (Natural Gas Storage Service), dated as of
August 27, 1979, between the Company and Northwest Pipeline Corporation.

10(k)-3 2-60728 5(s) Service Agreement (Liquefaction-Storage Natural Gas Service),
dated as of December 7, 1977, between the Company and Northwest Pipeline
Corporation.

* Incorporated herein by reference.
** Filed herewith.

66
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX (continued)

Previously Filed*
--------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

10(k)-4 1-3701 (with 10(k)-4 Amendment dated as of January 1, 1990,
1989 Form 10-K) to Firm Transportation Agreement,
dated as of June 25, 1988, between
the Company and Northwest Pipeline Corporation.

10(k)-5 1-3701 (with 10(k)-5 Service Agreement (ODL-1 Firm Service,
1989 Form 10-K) dated as of March 29, 1989, between the
Company and Northwest Pipeline Corporation

10(k)-6 1-3701 (with 10(k)-6 Firm Transportation Service Agreement, dated
1992 Form 10-K) as of April 25, 1991, between the Company
and Pacific Gas Transmission Company.

10(k)-7 1-3701 (with 10(k)-7 Service Agreement Applicable to Firm
1992 Form 10-K) Transportation Service, dated June 12, 1991,
between the Company and Alberta Natural
Gas Company Ltd.

10(k)-8 1-3701 (with 10(k)-8 Natural Gas Sale and Purchase Agreement, dated
1992 Form 10-K) October 31, 1991, between the Company and
AEC Oil and Gas Company.

10(k)-9 1-3701 (with 10(k)-9 Natural Gas Purchase Contract, dated December 11,
1992 Form 10-K) 1991, between the Company and Grand
Valley Gas Company and Amerada Hess
Canada Ltd.

10(k)-10 1-3701 (with 10(k)-10 Natural Gas Purchase Contract, dated December 13,
1992 Form 10-K) 1991, between the Company and Grand
Valley Gas Company and PanCanadian
Petroleum Limited.

10(l)-1 1-3701 (with 13(b) Letter of Intent for the Construction and Ownership
Form 8-K for of Colstrip Units No. 3 and 4, sponsored by The
August 1976) Montana Power Company, dated as of April 16, 1974.

10(l)-2 1-3701 (with 10(s)-7 Ownership and Operation Agreement for Colstrip
1981 Form 10-K) Units No. 3 and 4, sponsored by The Montana
Power Company, dated as of May 6, 1981.

10(l)-3 1-3701 (with 10(s)-2 Coal Supply Agreement for Colstrip
1981 Form 10-K) Units No. 3 and 4 between The Montana
Power Company, Puget Sound Power &
Light Company, Portland General
Electric Company, Pacific Power &
Light Company, Western Energy
Company and the Company, dated
as of July 2, 1980.

* Incorporated herein by reference.
** Filed herewith.

67
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX (continued)

Previously Filed*
--------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

10(l)-4 1-3701 (with 10(s)-3 Amendment No. 1 to Coal Supply
1981 Form 10-K) Agreement for Colstrip Units No. 3 and 4,
dated as of July 10, 1981.

10(l)-5 1-3701 (with 10(l)-5 Amendment No. 4 to Coal Supply
1988 Form 10-K) Agreement for Colstrip Units No. 3 and 4,
dated as of January 1, 1988.

10(m)-1 1-3701 (with 10 Purchase and Sale Agreement between
Form 10-Q for the Company and General Waterworks
quarter ended Corporation, dated as of July 28, 1982,
June 30, 1982) relating to the sale of the Company's
water properties.

10(m)-2 1-3701 (with 10(n)-2 Lease Agreement between the Company and IRE-4
1986 Form 10-K) New York, Inc., dated as of December 15, 1986,
relating to the Company's central operating facility.

10(n) 1-3701 (with 10(v) Supplemental Agreement No. 2, Skagit/Hanford Project,
1983 Form 10-K) dated as of December 27, 1983, relating to the termination
of the Skagit/Hanford Project.

10(o) 1-3701 (with 10(p)-1 Agreement for Purchase and Sale of Firm
1986 Form 10-K) Firm Capacity and Energy between
Puget Sound Power & Light Company
and the Company, dated as of August 1, 1986.

10(p) 1-3701 (with 10(q)-1 Electric Service and Purchase Agreement between
1991 Form 10-K) Potlatch Corporation and the Company, dated
as of January 3, 1991.

10(q) 1-3701 (with 10(r)-1 Power Sale Agreement between the Company
1992 Form 10-K) and the Northern California Power Agency
dated October 11, 1991.

10(r) 1-3701 (with 10(s)-1 Agreements for Purchase and Sale of Firm Capacity
1992 Form 10-K) between the Company and Portland General Electric
Company dated March and June 1992.

10(s)-1 1-3701 (with 10(t)-1 Employment Agreement between the Company
1992 Form 10-K) and Paul A. Redmond. (***)

10(s)-2 1-3701 (with 10(t)-2 Employment Agreement between the Company
1992 Form 10-K) and James R. Harvey, Jr. (***)

* Incorporated herein by reference.
** Filed herewith.
*** Management contracts or compensatory plans filed as exhibits
by reference per Item 601(10)(iii) of Regulation S-K.

68
THE WASHINGTON WATER POWER COMPANY

EXHIBIT INDEX (continued)

Previously Filed*
--------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------

10(s)-3 1-3701 (with 10(t)-3 Employment Agreement between the Company
1992 Form 10-K) and W. Lester Bryan. (***)

10(s)-4 1-3701 (with 10(t)-4 Employment Agreement between the Company
1992 Form 10-K) and Jon E. Eliassen. (***)

10(s)-5 1-3701 (with 10(t)-5 Employment Agreement between the Company
1992 Form 10-K) and Robert D. Fukai. (***)

10(s)-6 1-3701 (with 10(t)-6 Executive Officers' 1993 Incentive Plan. (***)
1992 Form 10-K)

10(s)-7 1-3701 (with 10(t)-7 CEO 1993 Incentive Stock Plan. (***)
1992 Form 10-K)

10(s)-8 1-3701 (with 10(t)-8 Executive Deferral Plan of the Company. (***)
1992 Form 10-K)

10(s)-9 1-3701 (with 10(t)-9 The Company's Unfunded Outside Director
1992 Form 10-K) Retirement Plan. (***)

10(s)-10 1-3701 (with 10(t)-10 The Company's Unfunded Supplemental
1992 Form 10-K) Executive Retirement Plan. (***)

10(s)-11 1-3701 (with 10(t)-11 The Company's Unfunded Supplemental
1992 Form 10-K) Executive Disability Plan. (***)

10(s)-12 1-3701 (with 10(t)-12 Income Continuation Plan of the Company. (***)
1992 Form 10-K)

10(s)-13 1-3701 (with 10(t)-13 Director Compensation Arrangements. (***)
1992 Form 10-K)

12 ** Statement re computation of ratio of earnings to fixed
charges and preferred dividend requirements.

21 ** Subsidiaries of Registrant.

23 ** See page 57 for consent of Deloitte & Touche,
Independent Auditors.

* Incorporated herein by reference.
** Filed herewith.
*** Management contracts or compensatory plans filed as exhibits
by reference per Item 601(10)(iii) of Regulation S-K.