<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
__________________
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 1-5152
______
PACIFICORP
(Exact name of registrant as specified in its charter)
STATE OF OREGON 93-0246090
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
825 N.E. Multnomah
Suite 2000
Portland, Oregon 97232
(Address of principal executive offices) (Zip code)
503-813-5000
(Registrant's telephone number)
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 twelve 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 at least the past 90 days.
YES X NO
_____ _____
At October 22, 1999, there were 297,390,167 shares of registrant's common
stock outstanding.
<PAGE>1
PACIFICORP
<TABLE>
<CAPTION>
Page No.
________
<S> <C>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Statements of Income
and Retained Earnings 2
Condensed Consolidated Statements of Cash Flows 3
Condensed Consolidated Balance Sheets 4
Notes to Condensed Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
PART II. OTHER INFORMATION
Item 5. Other Information 34
Item 6. Exhibits and Reports on Form 8-K 34
Signature 35
</TABLE>
<PAGE>2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
<TABLE>
PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Millions of Dollars, except per share amounts)
(Unaudited)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
__________________ _________________
1999 1998 1999 1998
____ ____ ____ ____
<S> <C> <C> <C> <C>
REVENUES $1,032.2 $1,918.2 $2,935.7 $4,380.6
_______ _______ _______ _______
EXPENSES
Purchased power 353.5 1,237.6 921.5 2,289.3
Other operations and maintenance 274.8 274.7 809.0 796.0
Depreciation and amortization 112.1 110.2 341.1 340.8
Administrative and general 74.1 81.6 196.3 239.8
Taxes, other than income taxes 25.1 23.7 76.2 76.7
Special charges - - - 113.1
_______ _______ _______ _______
TOTAL 839.6 1,727.8 2,344.1 3,855.7
_______ _______ _______ _______
INCOME FROM OPERATIONS 192.6 190.4 591.6 524.9
_______ _______ _______ _______
INTEREST EXPENSE AND OTHER
Interest expense 85.6 92.5 260.5 280.8
Interest capitalized (3.3) (4.4) (14.5) (11.4)
TEG transaction costs - (0.3) - 73.0
Write down of investments in
energy development companies - 52.0 - 52.0
Other income - net (10.0) (3.5) (13.8) (10.7)
_______ _______ _______ _______
TOTAL 72.3 136.3 232.2 383.7
_______ _______ _______ _______
Income from continuing operations
before income taxes 120.3 54.1 359.4 141.2
Income tax expense 42.1 19.5 134.9 42.3
_______ _______ _______ _______
Income from continuing operations 78.2 34.6 224.5 98.9
Discontinued Operations (less applicable
income tax expense/(benefit): 1999/$-
and $0.7; 1998/$(23.5) and $(23.2) - (122.2) 1.1 (160.8)
_______ _______ _______ _______
NET INCOME (LOSS) 78.2 (87.6) 225.6 (61.9)
RETAINED EARNINGS BEGINNING OF PERIOD 710.4 962.8 732.0 1,106.3
Cash dividends declared
Preferred stock (4.3) (4.2) (12.8) (12.8)
Common stock per share of $0.27 (80.3) (80.1) (240.8) (240.7)
_______ _______ _______ _______
RETAINED EARNINGS END OF PERIOD $ 704.0 $ 790.9 $ 704.0 $ 790.9
======= ======= ======= =======
EARNINGS (LOSS) ON COMMON STOCK $ 73.4 $ (92.4) $ 211.2 $ (76.3)
Average number of common shares
outstanding - Basic (Thousands) 297,356 297,272 297,340 297,197
Dilutive (Thousands) 297,468 297,322 297,365 297,224
EARNINGS (LOSS) PER COMMON SHARE -
Basic and dilutive
Continuing operations $ 0.25 $ 0.10 $ 0.71 $ 0.28
Discontinued operations - (0.41) - (0.54)
_______ _______ _______ _______
TOTAL $ 0.25 $ (0.31) $ 0.71 $ (0.26)
======= ======= ======= =======
<FN>
See accompanying Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>3
<TABLE>
PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
<CAPTION>
Nine Months Ended
September 30,
_____________________
1999 1998
____ ____
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 225.6 $ (61.9)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
(Income)/loss from discontinued operations (1.1) 160.8
Write down of investments in
energy development companies - 52.0
Depreciation and amortization 347.0 347.4
Deferred income taxes and investment tax
credits - net 40.8 (61.0)
Interest capitalized on equity funds (7.5) -
Special charges - 113.1
(Gain)/loss on sale of assets (11.4) 4.0
TEG transaction costs - 61.0
Utah rate order (36.9) -
Other (38.1) 17.3
Accounts receivable and prepayments 94.5 (296.4)
Materials, supplies and fuel stock (5.9) (5.6)
Accounts payable and accrued liabilities 78.7 327.9
________ ________
Net cash provided by continuing operations 685.7 658.6
Net cash provided by (used in) discontinued
operations 18.9 (390.2)
________ ________
NET CASH PROVIDED BY OPERATING ACTIVITIES 704.6 268.4
________ ________
CASH FLOWS FROM INVESTING ACTIVITIES
Construction (416.3) (456.7)
Investments in and advances to
affiliated companies - net (1.5) (25.1)
Operating companies and assets acquired (0.7) (13.5)
Proceeds from asset sales 169.9 5.4
Proceeds from sales of finance assets, real
estate investments and principal payments 69.1 316.8
Other (0.9) (1.1)
________ ________
NET CASH USED IN INVESTING ACTIVITIES (180.4) (174.2)
________ ________
CASH FLOWS FROM FINANCING ACTIVITIES
Changes in short-term debt (226.5) 144.4
Proceeds from long-term debt 1,348.8 1,066.2
Proceeds from issuance of common stock 0.9 8.9
Dividends paid (253.4) (259.6)
Repayments of long-term debt (1,704.9) (1,155.0)
Other 2.4 39.4
________ ________
NET CASH USED IN FINANCING ACTIVITIES (832.7) (155.7)
________ ________
DECREASE IN CASH AND CASH EQUIVALENTS (308.5) (61.5)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 583.1 740.8
________ ________
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 274.6 $ 679.3
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for
Interest (net of amount capitalized) $ 321.1 $ 330.9
Income taxes (received)/paid (21.6) 485.0
<FN>
See accompanying Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>4
<TABLE>
PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(Unaudited)
ASSETS
<CAPTION>
September 30, December 31,
1999 1998
_____________ ____________
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 274.6 $ 583.1
Accounts receivable less allowance
for doubtful accounts: 1999/$19.5
and 1998/$18.0 585.1 703.2
Materials, supplies and fuel stock at
average cost 182.3 175.8
Net assets of discontinued operations
and assets held for sale - 192.4
Other 82.8 87.9
________ ________
TOTAL CURRENT ASSETS 1,124.8 1,742.4
PROPERTY, PLANT AND EQUIPMENT
Domestic Electric Operations 12,747.6 12,460.0
Australian Electric Operations 1,263.3 1,140.4
Other Operations 21.7 22.2
Accumulated depreciation and amortization (4,849.0) (4,553.2)
________ ________
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 9,183.6 9,069.4
OTHER ASSETS
Investments in and advances to affiliated
companies 115.1 114.9
Intangible assets - net 380.3 369.4
Regulatory assets - net 743.9 795.5
Finance note receivable 199.4 204.9
Finance assets - net 299.6 313.7
Deferred charges and other 381.6 378.3
________ ________
TOTAL OTHER ASSETS 2,119.9 2,176.7
________ ________
TOTAL ASSETS $12,428.3 $12,988.5
======== ========
<FN>
See accompanying Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>5
<TABLE>
PACIFICORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
<CAPTION>
September 30, December 31,
1999 1998
____________ ____________
<S> <C> <C>
CURRENT LIABILITIES
Long-term debt currently maturing $ 179.4 $ 299.5
Notes payable and commercial paper 34.1 260.6
Accounts payable 449.5 566.2
Taxes, interest and dividends payable 386.9 282.7
Customer deposits and other 139.1 168.0
________ ________
TOTAL CURRENT LIABILITIES 1,189.0 1,577.0
DEFERRED CREDITS
Income taxes 1,585.9 1,542.6
Investment tax credits 119.3 125.3
Other 592.5 646.1
________ ________
TOTAL DEFERRED CREDITS 2,297.7 2,314.0
LONG-TERM DEBT 4,410.0 4,559.3
COMMITMENTS AND CONTINGENCIES (See Note 5) - -
GUARANTEED PREFERRED BENEFICIAL INTERESTS
IN COMPANY'S JUNIOR SUBORDINATED DEBENTURES 340.8 340.5
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION 175.0 175.0
PREFERRED STOCK 66.4 66.4
COMMON EQUITY
Common shareholders' capital
shares authorized 750,000,000;
shares outstanding: 1999/297,392,933
and 1998/297,343,422 3,285.9 3,285.0
Retained earnings 704.0 732.0
Accumulated other comprehensive loss (40.5) (60.7)
________ ________
TOTAL COMMON EQUITY 3,949.4 3,956.3
________ ________
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $12,428.3 $12,988.5
======== ========
<FN>
See accompanying Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
September 30, 1999
1. FINANCIAL STATEMENTS
The accompanying unaudited condensed consolidated financial statements
as of September 30, 1999 and December 31, 1998 and for the periods ended
September 30, 1999 and 1998, in the opinion of management, include all
adjustments, constituting only normal recording of accruals, necessary for a
fair presentation of financial position, results of operations and cash flows
for such periods. A significant part of the business of PacifiCorp (the
"Company") is of a seasonal nature; therefore, results of operations for the
periods ended September 30, 1999 and 1998 are not necessarily indicative of
the results for a full year. These condensed consolidated financial statements
should be read in conjunction with the financial statements and related notes
in the Company's 1998 Annual Report on Form 10-K/A Amendment No. 1.
The condensed consolidated financial statements of the Company include
the integrated domestic electric utility operations of Pacific Power and Utah
Power and its wholly owned and majority owned subsidiaries. Major
subsidiaries, all of which are wholly owned, are: PacifiCorp Group Holdings
Company ("Holdings"), which holds directly or through its wholly owned
subsidiary, PacifiCorp International Group Holdings Company, all of the
Company's nonintegrated electric utility investments, including Powercor
Australia Limited ("Powercor"), an Australian electricity distributor, and
PacifiCorp Financial Services, Inc. ("PFS"), a financial services business.
Together these businesses are referred to herein as the Companies. Significant
intercompany transactions and balances have been eliminated.
During October 1998, the Company decided to exit its energy trading
business, which consisted of TPC Corporation ("TPC") and PacifiCorp Power
Marketing, Inc. ("PPM"). On April 1, 1999, the Company sold TPC. See Note 3.
During May 1998, the Company sold a majority of the real estate assets held by
PFS. The Company has also decided to exit the majority of its other energy
development businesses and has recorded them at estimated net realizable value
less selling costs.
Investments in and advances to affiliated companies represent
investments in unconsolidated affiliated companies carried on the equity
basis, which approximates the Company's equity in their underlying net book
value.
Certain amounts have been reclassified to conform with the 1999 method
of presentation. These reclassifications had no effect on previously reported
consolidated net income.
2. SCOTTISHPOWER MERGER
In December 1998, the Company announced a proposed merger ("the merger")
with Scottish Power PLC ("ScottishPower"). Under the terms of the agreement,
each share of the Company's stock will be converted tax-free into a right to
receive 0.58 American Depositary Shares (each ADS represents four ordinary
shares) or 2.32 ordinary shares of ScottishPower.
The proposed merger was approved by the shareholders of both companies
in June 1999.
The merger is subject to federal and state regulatory review. The
proposed merger has received clearance from state regulators in Oregon,
Wyoming, Washington and California, the U.S. Federal Energy Regulatory
<PAGE>7
Commission ("FERC"), the Federal Communications Commission, the Nuclear
Regulatory Commission, under the Hart-Scott-Rodino Antitrust Improvements Act
and from U.K. and Australian regulatory authorities. The companies are
awaiting an approval order from Wyoming. Both companies have applications
pending for approval in Utah and Idaho, where staff members have recommended
approval, subject to certain conditions. Both companies expect completion of
the regulatory approval process to occur before year end. Costs associated
with the merger were $4 million for the third quarter 1999 and $12 million for
the year-to-date September 1999.
3. DISCONTINUED OPERATIONS
In October 1998, the Company decided to exit its energy trading business
by offering TPC for sale and ceasing the operations of PPM, which conducted
electricity trading in the eastern United States. PPM's activities in the
eastern United States have been discontinued and all forward electricity
trading has been closed and is going through settlement. On April 1, 1999,
Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. This activity
resulted in an after-tax gain of $1 million in the second quarter of 1999.
The net assets, operating results and cash flows of the energy trading
segment have been classified as discontinued operations for all periods
presented in the consolidated financial statements and notes.
Summarized operating results were as follows:
<TABLE>
<CAPTION>
Three-Month Nine-Month
Period Ended Period Ended
September 30, September 30,
_____________ ______________
1999 1998 1999 1998
____ ____ ____ ____
<S> <C> <C> <C> <C>
(Dollars in Millions)
Revenues $ - $1,424.0 $ - $2,961.0
=== ======= === =======
Loss from discontinued
operations (less applicable
income tax benefit of $1.1
and $24.3) $ - $ (3.1) $ - $ (41.7)
Loss on disposal, including
provision of $20.0 for
operating losses during
phase-out period (less
applicable income tax
benefit $59.1) - (119.1) - (119.1)
Gain on disposal (less applicable
income tax of $0.7) - - 1.1 -
___ ________ ___ _______
Net income/(loss) $ - $ (122.2) $1.1 $ (160.8)
=== ======== === =======
</TABLE>
<PAGE>8
As mentioned previously, net assets of the discontinued operations were
sold April 1, 1999. Net assets of the discontinued operations and assets held
for sale as of December 31, 1998 consisted of the following:
<TABLE>
<CAPTION>
December 31,
1998
____________
(Dollars in Millions)
<S> <C>
Current assets $148.5
Noncurrent assets 152.7
Current liabilities (96.0)
Long-term debt (1.3)
Noncurrent liabilities (28.9)
Assets held for sale 17.4
_____
Net Assets of Discontinued Operations
and Assets Held for Sale $192.4
=====
</TABLE>
Holdings had $21 million and $34 million as of September 30, 1999 and
December 31, 1998, respectively, of liabilities in "Customer deposits and
other" relating to the sale or exit of the discontinued operations.
4. ACCOUNTING FOR THE EFFECTS OF REGULATION
Domestic Electric Operations prepares its financial statements in
accordance with Statement of Financial Accounting Standards ("SFAS") 71,
"Accounting for the Effects of Certain Types of Regulations." Under this
statement, the Company may defer certain costs as regulatory assets and
certain obligations as regulatory liabilities. Regulatory assets and
liabilities represent probable future revenues that will be recovered from, or
refunded to, customers through the ratemaking process.
The Emerging Issues Task Force of the Financial Accounting Standards
Board (the "EITF") concluded in 1997 that SFAS 71 should be discontinued when
detailed legislation or regulatory orders regarding competition are issued.
Additionally, the EITF concluded that regulatory assets and liabilities
applicable to businesses being deregulated should be written off unless their
recovery is provided for through future regulated cash flows. Recoverability
of regulatory assets is assessed at each reporting period.
On March 4, 1999, the Utah Public Service Commission (the "UPSC")
ordered the Company to reduce customer prices by 12%, or $85 million annually
effective March 1, 1999, and to make a one-time refund of $40 million to
customers. Approximately $38 million of the refund relating to 1997 and 1998
was recorded in December 1998. The remaining $2 million was recorded in the
first quarter of 1999. The ordered rate reduction is the culmination of a
general rate case in Utah that began in 1997. The Company has decided not to
appeal the ordered rate reduction to the Utah Supreme Court.
On September 20, 1999, the Company filed for a rate increase before the
UPSC. The Company is asking for an increase of $67 million, or 9.9%, based on
a test year ending December 31, 1998. The Company's effective date for this
tariff increase is expected to be in May 2000.
The Utah Division of Public Utilities and the Utah Committee of Consumer
Services have recommended approval of the merger, subject to certain
conditions agreed to by the Company. These conditions include a merger credit
for retail tariff customers of $12 million per year for four years beginning
in 2000. The credit can be wholly or partially eliminated in years three and
four to the extent that merger savings are reflected in prices.
In 1998, the Company announced its intent to sell its California
electric distribution assets. This action was in response to the continued
<PAGE>9
decline in earnings on the assets and the changes in the legislative and
regulatory environments in California. On April 9, 1999, the Company announced
it had entered into a letter of intent with Nor-Cal Electric Authority for the
sale of the assets to Nor-Cal for $178 million. A definitive agreement was
signed on July 15, 1999. On August 16, 1999, the Company filed an application
with the California Public Utility Commission (the "CPUC") for approval of the
sale and expects to file an application for approval with FERC by the middle
of November. The sale is expected to close early next year.
On April 30, 1999, the Company filed for changes in the prices it
charges Oregon customers. The filing was required as part of a 1998 Oregon
Public Utility Commission (the "OPUC") order which uses set formulas to
moderate the impact of cost fluctuations on customer prices, while assuring
high-quality service. The filing also contained a request to increase the
revenues collected under its system benefits charge. The changes were approved
by the OPUC in June 1999, and became effective July 1, 1999. This will result
in a price increase of approximately 1.3%, or $9 million annually, in Oregon.
On November 5, 1999, the Company filed for a rate increase before the
OPUC. This rate increase contains two phases. In the first phase, the Company
is asking for an increase of $61.8 million, or 8.5%. The Company's effective
date for this phase of the tariff increase is expected to be in the fall of
2000. In the second phase, the Company is asking for an increase of up to
$26.4 million, or 3.4%, to be effective at the end of the term of the current
Alternative Form of Regulation on July 1, 2001.
During 1999, legislation was enacted in Oregon that requires competition
for industrial and large commercial customers of both the Company and Portland
General Electric by October 1, 2001. Residential customers will receive a
portfolio of commodity service options. The law exempts publicly-owned
utilities and Idaho Power's Oregon service territory. The law defers to the
OPUC decisions on a variety of important issues, including the method for
valuation of stranded costs/benefits, consumer protections, marketer
certification, environmental issues, and competitive services. The legislation
also calls for the functional separation of certain assets and the
establishment of a code-of-conduct for electric companies and their affiliates
to protect consumers against anti-competitive practices. The legislation also
directs the investor-owned utilities to collect a 3% public benefit tax from
regulated customers. The Company will be participating in the OPUC proceedings
over the next two years that establish the rules and procedures that will
implement the new law. The Company will continue to evaluate the finance and
accounting impacts, including the continued propriety of applying SFAS 71, as
the OPUC proceedings progress. The impacts, if any, are uncertain.
On October 6, 1999, the OPUC issued an order approving the merger. As
part of this approval, the Company has agreed to implement a merger credit to
Oregon customers of $12 million per year for three years beginning in 2001 and
$15 million in 2004. In years three and four, $9 million and $12 million,
respectively, of the credit can be partially or wholly eliminated to the
extent that merger savings are reflected in prices.
On April 30, 1999, the Company filed documents with the Idaho Public
Utilities Commission (the "IPUC") to implement the next step in the gradual
retirement of a federal energy credit. The proposed reduction in the credit
would increase electric prices for Utah Power residential and irrigation
customers in southeastern Idaho. The filing, once approved by the IPUC, would
reduce the credits from the federal Bonneville Power Administration (the
"BPA") and increase residential prices 3.35%, or $1 million, and irrigation
prices 4%, or $1 million. These price increases are not expected to have a
material impact on earnings.
Congress created the federal credit in 1980 to share the benefits of
<PAGE>10
federally owned hydroelectric plants with customers of investor-owned
utilities in the Columbia River drainage area. When Congress recommended in
1995 that the current exchange method be phased out by June 2001, the Company
worked out a settlement with BPA in 1997 to implement the order of Congress.
Without the settlement, prices would have increased more than 30% in two
years. The settlement provided credits of $48 million over five years for the
Company's customers, $6 million more than without the settlement. The
additional money is being used to lessen the impact of price increases as the
BPA exchange credit is phased out.
Staff members of the IPUC have recommended approval of the merger,
subject to certain conditions. In Idaho, the Company has offered a $1.6
million per year merger credit to retail tariff customers for four years
beginning on January 1, 2000. The credit could be wholly or partially
eliminated in years three and four to the extent that merger savings are
reflected in prices.
On July 26, 1999, the Company filed for a rate increase before the
Wyoming Public Service Commission (the "WPSC"). The Company is asking for an
increase of $12 million, or 4.9%, based on a test year ending December 31,
1998. The effective date for this tariff increase is expected to be in the
spring of 2000.
On October 5, 1999, the WPSC announced it has decided to approve the
merger, subject to the preparation and issuance of a final order. The
companies have agreed to make a filing guaranteeing a minimum of $4 million
per year in cost savings that will be reflected in future rate cases.
On October 14, 1999, the Washington Utilities and Transportation
Commission (the "WUTC") approved the merger. Washington retail customers will
receive a merger credit of $3 million per year for four years beginning in
2001. The credit can be wholly or partially eliminated in all years to the
extent that merger savings are reflected in prices.
On August 6, 1999, the Company filed applications with the OPUC, the
WUTC, the UPSC, the WPSC and the IPUC seeking orders approving the sale of the
Company's interests in the Centralia plant and mine. A similar application was
filed with the CPUC on August 27, 1999. The Company's applications also seek
Commission orders adopting the Company's proposed treatment of the gain from
the sale.
5. CONTINGENT LIABILITIES
The Company and its subsidiaries are parties to various legal claims,
actions and complaints, certain of which involve material amounts. Although
the Company is unable to predict with certainty whether or not it will
ultimately be successful in these legal proceedings or, if not, what the
impact might be, management currently believes that disposition of these
matters will not have a materially adverse effect on the Company's
consolidated financial statements.
<PAGE>11
6. COMPREHENSIVE INCOME
The components of comprehensive income are as follows:
<TABLE>
<CAPTION>
Three-Month Nine-Month
Periods Ended Periods Ended
September 30, September 30,
_____________ ______________
1999 1998 1999 1998
____ ____ ____ ____
<S> <C> <C> <C> <C>
(Dollars in Millions)
Net income $ 78.2 $(87.6) $225.6 $(61.9)
Other comprehensive income
Foreign currency translation
adjustment, net of taxes:
1999/$(0.9) and $13.2,
1998/$0.7 and $(11.1) (1.5) 1.1 20.5 (18.4)
Unrealized gain on available-
for-sale securities, net of
taxes: 1999/($0.1) and $(0.2),
1998/$4.3 (0.2) - (0.3) 7.1
_____ _____ _____ _____
Total comprehensive income $ 76.5 $(86.5) $245.8 $(73.2)
===== ===== ===== =====
</TABLE>
<PAGE>12
7. SEGMENT INFORMATION
Selected information regarding the Company's operating segments,
Domestic Electric Operations, Australian Electric Operations and Other
Operations, are as follows:
<TABLE>
<CAPTION>
Domestic Australian Other
Total Electric Electric Discontinued Operations &
Millions of dollars Company Operations Operations Operations Eliminations
___________________ _______ __________ __________ __________ ____________
<S> <C> <C> <C> <C> <C>
For the three months ended:
September 30, 1999
Net sales and revenues
(all external) $1,032.2 $ 856.9 $158.8 $ - $ 16.5
Income from continuing
operations 78.2 62.4 5.2 - 10.6
September 30, 1998
Net sales and revenues
(all external) $1,918.2 $1,758.9 $149.5 $ - $ 9.8
Income (loss) from
continuing operations 34.6 54.7 6.5 - (26.6)
Loss from discontinued
operations (122.2) - - (122.2) -
For the nine months ended:
September 30, 1999
Net sales and revenues
(all external) $2,935.7 $2,436.4 $466.2 $ - $ 33.1
Income from continuing
operations 224.5 185.2 24.7 - 14.6
Income from discontinued
operations 1.1 - - 1.1 -
September 30, 1998
Net sales and revenues
(all external) $4,380.6 $3,867.5 $469.1 $ - $ 44.0
Income (loss) from
continuing operations 98.9 122.8 27.2 - (51.1)
Loss from discontinued
operations (160.8) - - (160.8) -
</TABLE>
<PAGE>13
Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SUMMARY RESULTS OF OPERATIONS
This report includes forward-looking statements that involve a number of risks
and uncertainties that may influence the financial performance and earnings of
the Company and its subsidiaries, including the factors identified in the
Company's 1998 Annual Report on Form 10-K/A Amendment No. 1. Such forward-
looking statements should be considered in light of those factors.
Comparison of the three-month periods ended September 30, 1999 and 1998
_______________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss) on
common stock (1)
Domestic Electric Operations $ 57.6 $ 49.9 $ 7.7 15
Australian Electric Operations 5.2 6.5 (1.3) (20)
Other Operations 10.6 (26.6) 37.2 140
_____ ______ _____
Continuing Operations 73.4 29.8 43.6 146
Discontinued Operations (2) - (122.2) 122.2 100
_____ ______ _____
Total $ 73.4 $ (92.4) $165.8 *
===== ====== =====
Earnings (loss) per common share -
Basic and dilutive
Continuing Operations $ 0.25 $ 0.10 $ 0.15 150
Discontinued Operations (2) - (0.41) 0.41 100
_____ ______ _____
Total $ 0.25 $ (0.31) $ 0.56 *
===== ====== =====
<FN>
(1) Earnings contribution (loss) on common stock by segment: (a) does not
reflect elimination for interest on intercompany borrowing arrangements;
(b) includes income taxes on a separate company basis, with any benefit
or detriment of consolidation reflected in Other Operations; (c) is net
of preferred dividend requirements and minority interest.
(2) Represents the discontinued operations of TPC and PPM.
</FN>
</TABLE>
The Company recorded earnings on common stock of $73 million, or $0.25 per
share, in the third quarter of 1999 compared to a loss of $92 million, or
$0.31 per share, in 1998. Third quarter 1998 results included losses of $122
million, or $0.41 per share, from the Company's energy trading activities,
which the Company decided to discontinue in October 1998 and a $32 million, or
$0.11 per share, loss relating to the decision to shut down or sell its other
energy development businesses. Third quarter 1999 results included $4 million,
or $0.01 per share, for ScottishPower merger costs.
Domestic electric operations earnings contribution was $58 million, or $0.19
per share, as compared to $50 million, or $0.17 per share, in the third
quarter of 1998. Third quarter 1999 reflected $4 million, or $0.01 per share,
of ScottishPower merger costs and a $15 million, or $0.05 per share, decline
relating to the Utah rate order received in March 1999. These decreases were
partially offset by decreased interest expense of $10 million, or $0.03 per
share, due to funds received by domestic electric operations as intercompany
dividends from Holdings of $500 million and $660 million in October 1998 and
January 1999, respectively.
<PAGE>14
The Company's Australian electric operations contributed earnings of $5
million, or $0.02 per share, in the third quarter of 1999, compared to $7
million, or $0.02 per share, in 1998. This reduction was primarily
attributable to increased purchase power expense.
Other operations reported earnings of $11 million, or $0.04 per share, in the
quarter compared to losses of $27 million, or $0.09 per share, in 1998. This
increase was primarily due a $32 million, or $0.11 per share, loss in 1998
relating to the decision to shut down or sell its other energy development
businesses.
Comparison of the nine-month periods ended September 30, 1999 and 1998
______________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss) on
common stock
Domestic Electric Operations $170.8 $ 108.4 $ 62.4 58
Australian Electric Operations 24.7 27.2 (2.5) (9)
Other Operations 14.6 (51.1) 65.7 129
_____ ______ _____
Continuing Operations 210.1 84.5 125.6 149
Discontinued Operations 1.1 (160.8) 161.9 101
_____ ______ _____
Total $211.2 $ (76.3) $287.5 *
===== ====== =====
Earnings (loss) per common share -
Basic and dilutive
Continuing Operations $ 0.71 $ 0.28 $ 0.43 *
Discontinued Operations - (0.54) 0.54 100
_____ ______ _____
Total $ 0.71 $ (0.26) $ 0.97 *
===== ====== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
The Company recorded earnings on common stock of $211 million, or $0.71 per
share, in 1999 compared to losses of $76 million, or $0.26 per share, in 1998.
The 1998 results included an after-tax charge of $70 million, or $0.24 per
share, associated with the Company's work force reduction in the United
States, an after-tax charge of $54 million, or $0.18 per share, associated
with the Company's terminated bid for The Energy Group PLC ("TEG"), a $10
million, or $0.03 per share, gain relating to the sale of TEG shares and a $2
million, or $0.01 per share, loss relating to closing foreign currency options
in April 1998 associated with the terminated bid for TEG. In addition, 1998
included losses of $161 million from the Company's energy trading activities,
which the Company decided to discontinue in October 1998, and a $32 million,
or $0.11 per share, loss relating to the decision to shut down or sell its
other energy development businesses.
Domestic electric operations earnings contribution was $171 million, or $0.57
per share, in 1999 compared to $108 million, or $0.37 per share, in 1998.
Excluding the $70 million charge relating to the work force reduction, the
earnings contribution in 1998 would have been $178 million. The Utah rate
order received in March 1999 reduced earnings $35 million, or $0.12 per share,
and ScottishPower merger costs reduced earnings $12 million, or $0.04 per
share. These decreases were partially offset by decreased interest expense and
increased interest income from the intercompany dividends domestic electric
operations received from Holdings.
<PAGE>15
The Company's Australian electric operations contributed earnings of $25
million, or $0.09 per share, in 1999, compared to $27 million, or $0.09 per
share, in 1998. Earnings in 1998 were benefited by adjustments totaling $4
million associated with the renegotiations of certain Tariff H industrial
customers contracts.
Other operations reported earnings of $15 million, or $0.05 per share, in 1999
compared to a loss of $51 million, or $0.18 per share, in 1998. This increase
was primarily due to an after-tax charge of $54 million for costs associated
with the Company's terminated bid for TEG and a $32 million loss relating to
the decision to shut down or sell its other energy development businesses,
partially offset by an after-tax gain of $10 million on the sale of TEG
shares. In addition, interest income decreased $28 million, or $0.09 per
share, as the result of cash dividends paid by Holdings to domestic electric
operations.
<PAGE>16
RESULTS OF OPERATIONS
Domestic Electric Operations
____________________________
Comparison of the three-month periods ended September 30, 1999 and 1998
_______________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Revenues
Residential $ 182.9 $ 191.8 $ (8.9) (5)
Commercial 172.9 173.6 (0.7) -
Industrial 196.5 203.5 (7.0) (3)
Other 8.1 8.4 (0.3) (4)
_______ _______ _______
Retail sales 560.4 577.3 (16.9) (3)
Wholesale sales and
market trading 275.5 1,164.0 (888.5) (76)
Other 21.0 17.6 3.4 19
_______ _______ _______
Total 856.9 1,758.9 (902.0) (51)
Operating expenses 688.1 1,587.4 (899.3) (57)
_______ _______ _______
Income from operations 168.8 171.5 (2.7) (2)
Interest expense 66.8 82.9 (16.1) (19)
Minority interest and other (3.3) 0.4 (3.7) *
Income taxes 42.9 33.5 9.4 28
_______ _______ _______
Net income 62.4 54.7 7.7 14
Preferred dividend requirement 4.8 4.8 - -
_______ _______ _______
Earnings contribution $ 57.6 $ 49.9 $ 7.7 15
======= ======= =======
Energy sales (millions of kWh)
Residential 2,942 2,929 13 -
Commercial 3,361 3,250 111 3
Industrial 5,536 5,831 (295) (5)
Other 184 181 3 2
______ ______ _______
Retail sales 12,023 12,191 (168) (1)
Wholesale sales and
market trading 8,359 34,227 (25,868) (76)
______ ______ _______
Total 20,382 46,418 (26,036) (56)
====== ====== =======
Residential average usage (kWh) 2,371 2,356 15 1
Total customers (end of period) 1,453,714 1,459,029 (5,315) -
</TABLE>
Revenues
Total domestic electric operations revenues decreased $902 million, or 51%,
from the third quarter of 1998. This decrease was primarily attributable to a
$889 million decrease in wholesale revenues. The sale of the Company's Montana
service area in November 1998 decreased revenues $9 million, while the Utah
rate order reduced revenues by $25 million.
Residential revenues were down $9 million, or 5%. Excluding the impact of the
Montana sale, residential revenues were down $7 million. Energy volumes were
up 3% primarily due to customer growth of 2% that added $4 million to
revenues. Price increases in Oregon added $2 million to revenues. The Utah
rate order reduced residential revenues by $11 million.
Commercial revenues were down $1 million. Excluding the impact of the Montana
sale, commercial revenues were up $3 million, energy volumes were up 6% and
customer growth was 2%. Increased commercial customers added $5 million to
revenues. Volume increases added $4 million to revenues and price increases
<PAGE>17
added $3 million to revenues. The Utah rate order reduced commercial revenues
by $9 million.
Industrial revenues decreased $7 million, or 3%. Excluding the impact of the
Montana sale, industrial revenues were down $4 million. Energy volumes and
average customers were down 3%. The Company has participated in open access
pilot programs in Oregon that reduced revenues $4 million. Under these
programs, customers were allowed to choose service by another utility, with no
franchise rights to that customer, for a specific time period. These are not
ongoing programs and industrial revenues gained or lost under these programs
are not expected to continue beyond 1999. Price increases in Oregon and
Wyoming added $4 million to industrial revenues. Increased irrigation usage
added $1 million to industrial revenues. The Utah rate order reduced
industrial revenues by $5 million.
Wholesale sales decreased $889 million. The decrease in revenues was driven by
a 76% decline in energy volumes. Lower short-term and spot market wholesale
energy volumes decreased revenues by $806 million. Related energy prices
averaged $32 per MWh in the quarter, a 6% decrease over the prior year. The
lower prices for these sales reduced revenues $66 million in the quarter. This
decline in energy volumes is consistent with the Company's decision to scale
back short-term wholesale sales. A decrease in long-term firm contracts
reduced revenues $16 million.
See Note 4 regarding regulation of domestic electric operations' utility
properties.
Operating Expenses
Total operating expenses decreased $899 million, or 57%, in the quarter. This
decrease was primarily attributable to decreased purchased power expense due
to the decline in wholesale sales.
Purchased power expense decreased $899 million. The lower expense was
primarily due to a 26.8 million MWh decrease in short-term firm and spot
market energy purchases, which decreased purchased power expense $947 million.
Short-term firm and spot market purchase prices averaged $36 per MWh in the
quarter versus $34 per MWh in 1998, a 6% increase. The increase in purchase
prices increased costs $45 million.
<TABLE>
<CAPTION>
Short-Term and Spot Market Sales and Purchases*
_______________________________________________
1999 1998
____ ____
<S> <C> <C>
Total sales volume (thousands of MWh) 4,957 30,512
Average sales price ($/MWh) $ 31.57 $ 33.71
_______ _______
Revenues ($, millions) $ 156 $ 1,029
Total purchase volume (thousands of MWh) 4,601 31,410
Average purchase price ($/MWh) $ 36.22 $ 33.99
_______ _______
Expenses ($, millions) $ 167 $ 1,068
_______ _______
Net ($, millions) $ (11) $ (39)
======= =======
<FN>
*This table does not represent the gross margin of the short-term trading
business, but rather is an aggregate of the short-term business undertaken
to balance the complete energy obligations of the Company.
</FN>
</TABLE>
Fuel expense was down $9 million, or 7%, in 1999. Thermal generation was up 2%
to 13.8 million MWh. The average cost per MWh decreased to $9.09 from $9.93 in
the prior year due to lower average fuel costs and a shift in the mix of
generation from higher cost plants in 1998 to lower cost plants in 1999. The
<PAGE>18
shift in generation mix resulted from unscheduled plant outages of low cost
facilities in 1998.
Other operations and maintenance expense increased $9 million, or 9%. Employee
related costs increased $3 million, customer service costs increased $3
million and increased tree trimming expense added $2 million.
Administrative and general expenses decreased $2 million, or 2%, to $77
million due to billing adjustments.
Depreciation and amortization expense increased $2 million, or 2%, due to
increased plant in service.
Other Income and Expense
Domestic electric operations interest expense was $67 million, a decrease of
$16 million from 1998, as a result of lower debt balances. The lower debt
balances were due to dividends received from Holdings in October 1998 and
January 1999 that were used to pay down intercompany debt owed to Holdings and
some external debt. Other income and expense was up $5 million primarily due
to increased timber sales and decreased new product expenses partially offset
by $4 million in ScottishPower merger costs.
The United States Environmental Protection Agency (the "EPA") has recently
commenced enforcement action against the owners of certain coal-fired
generating plants in the eastern and midwestern United States. The EPA is
alleging that the plant owners have failed to obtain the necessary permits
under the Clean Air Act in connection with certain alleged modifications at
the plants and that the owners have failed to install additional pollution
control equipment as required. If the EPA prevails in its position, the
companies named in the action will be required to make significant capital
expenditures to install pollution control equipment. The Company does not have
an ownership interest in any of the plants involved in this matter, and the
Company is not a party to this action. Nevertheless, the Company has become
aware that the EPA is engaged in fact-finding with respect to coal-fired
generating plants throughout the country. The Company is unable to predict the
outcome of the EPA's fact-finding effort.
<PAGE>19
Comparison of the nine-month periods ended September 30, 1999 and 1998
______________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Revenues
Residential $ 587.5 $ 598.3 $ (10.8) (2)
Commercial 491.3 495.4 (4.1) (1)
Industrial 517.0 542.2 (25.2) (5)
Other 23.0 23.7 (0.7) (3)
_______ _______ ________
Retail sales 1,618.8 1,659.6 (40.8) (2)
Wholesale sales and
market trading 759.5 2,158.8 (1,399.3) (65)
Other 58.1 49.1 9.0 18
_______ _______ ________
Total 2,436.4 3,867.5 (1,431.1) (37)
Operating expenses 1,930.5 3,432.2 (1,501.7) (44)
_______ _______ ________
Income from operations 505.9 435.3 70.6 16
Interest expense 202.5 244.7 (42.2) (17)
Minority interest and other (8.5) (6.5) (2.0) (30)
Income taxes 126.7 74.3 52.4 71
_______ _______ ________
Net income 185.2 122.8 62.4 51
Preferred dividend requirement 14.4 14.4 - -
_______ _______ ________
Earnings contribution $ 170.8 $ 108.4 $ 62.4 58
======= ======= ========
Energy sales (millions of kWh)
Residential 9,504 9,385 119 1
Commercial 9,382 9,166 216 2
Industrial 15,218 15,808 (590) (4)
Other 498 500 (2) -
______ _______ _______
Retail sales 34,602 34,859 (257) (1)
Wholesale sales and
market trading 27,204 79,019 (51,815) (66)
______ _______ _______
Total 61,806 113,878 (52,072) (46)
====== ======= =======
Residential average usage (kWh) 7,650 7,579 71 1
Total customers (end of
period) 1,453,714 1,459,029 (5,315) -
</TABLE>
Revenues
Total domestic electric operations revenues decreased $1,431 million, or 37%,
from 1998. This decrease was primarily attributable to a $1,399 million
decrease in wholesale revenues. The sale of the Company's Montana service area
in November 1998 decreased revenues $30 million, while the Utah rate order
reduced revenues by $57 million.
Residential revenues were down $11 million. Excluding the impact of the
Montana sale, residential revenues were up $1 million. Energy volumes were up
4% and customer growth was 3%. Growth in the average number of residential
customers added $12 million to revenues. Volume increases, primarily due to
weather, added $9 million to revenues and price increases in Oregon added $4
million to revenues. The Utah rate order reduced residential revenues by $24
million.
Commercial revenues were down $4 million, or 1%. Excluding the impact of the
Montana sale, commercial revenues were up $6 million. Energy volumes were up
5% and customer growth was 3%. Increased commercial customers added $14
million to revenues. Volume increases added $8 million to revenues and price
increases in Oregon added $6 million to revenues. The Utah rate order reduced
commercial revenues by $22 million.
<PAGE>20
Industrial revenues decreased $25 million, or 5%. Excluding the impact of the
Montana sale, industrial revenues were down $17 million. Energy volumes were
down 2% and average customers declined 4%. Decreased energy volumes due to the
cyclical nature of industrial customer usage drove a $12 million decrease in
revenues. The Company has participated in open access pilot programs in Oregon
that reduced revenues $8 million. Increased irrigation usage added $4 million
to industrial revenues. The Utah rate order reduced industrial revenues by $11
million.
Wholesale sales decreased $1,399 million, or 65%. The decrease in revenues was
driven by a 66% decline in energy volumes. Lower short-term and spot market
wholesale energy volumes decreased revenues by $1,344 million. Related energy
prices averaged $24 per MWh in 1999, an 8% decrease over the prior year. The
lower prices for these sales reduced revenues $36 million compared to the
prior year. This decline in energy volumes is consistent with the Company's
decision to scale back short-term wholesale sales. Decreased long-term
contract volumes and prices reduced revenues $19 million.
Other revenue increased $9 million, or 18%, primarily due to increased
wheeling revenue.
See Note 4 regarding regulation of domestic electric operations' utility
properties.
Operating Expenses
Total operating expenses decreased $1,502 million, or 44%. This decrease was
primarily attributable to decreased purchased power expense due to the decline
in wholesale sales and the $113 million pretax special charge in 1998 for the
workforce reduction.
Purchased power expense was $712 million, a decrease of $1,389 million. The
lower expense was due to a 53.1 million MWh decrease in short-term firm and
spot market energy purchases.
<TABLE>
<CAPTION>
Short-Term and Spot Market Sales and Purchases*
_______________________________________________
1999 1998
____ ____
<S> <C> <C>
Total sales volume (thousands of MWh) 16,641 68,690
Average sales price ($/MWh) $ 23.70 $ 25.83
_______ _______
Revenues ($, millions) $ 394 $ 1,774
Total purchase volume (thousands of MWh) 15,874 68,966
Average purchase price ($/MWh) $ 24.56 $ 25.85
_______ _______
Expenses ($, millions) $ 390 $ 1,783
_______ _______
Net ($, millions) $ 4 $ (9)
======= =======
<FN>
*This table does not represent the gross margin of the short-term trading
business, but rather is an aggregate of the short-term business undertaken
to balance the complete energy obligations of the Company.
</FN>
</TABLE>
Fuel expense was down $7 million, or 2%, to $349 million in 1999. Thermal
generation remained flat at 38.0 million MWh. The average cost per MWh
decreased to $9.17 from $9.37 in the prior year due to lower average fuel
costs and a shift in the mix of generation from higher cost plants to lower
cost plants. Hydroelectric generation increased 12% compared to 1998 due to
favorable water conditions.
Other operations and maintenance and administrative and general expenses was
$575 million, an increase of $4 million. Implementation of the Company's new
<PAGE>21
SAP software operating environment in 1999 resulted in changes in
classification of costs between operations and maintenance and administrative
and general expenses.
Other operations and maintenance expense increased $36 million, or 11%, to
$365 million. Increased tree trimming added $6 million to expenses, increased
materials and contracts primarily relating to overhaul costs added $5 million
and increased labor added $3 million. Employee related costs increased $3
million and customer service costs increased $6 million. In addition,
operations and maintenance was up $15 million due to costs reclassified from
administrative and general upon conversion to SAP in January 1999.
Administrative and general expenses decreased $32 million, or 13%, to $209
million. This decrease was primarily due to a reduction in labor and employee
related costs of $16 million and a reduction in Year 2000 costs of $2 million.
Billing adjustments decreased costs $3 million and property insurance
decreased $4 million. In addition, administrative and general expense was down
$15 million due to costs reclassified to operations and maintenance expense
upon conversion to SAP in January 1999. These decreases were partially offset
by an $11 million increase in costs relating to the ongoing implementation of
the Company's new SAP software operating environment.
Depreciation and amortization expense increased $4 million, or 1%, to $295
million due to $12 million of costs attributable to increased plant in
service, partially offset by an $8 million reduction from lower rates.
Other Income and Expense
Domestic electric operations interest expense was down $42 million as a result
of lower debt balances. The lower debt balances were due to the dividends
received from Holdings that were used to pay down intercompany debt owed to
Holdings and some external debt. Other expense was up $1 million primarily due
to $12 million in ScottishPower merger costs and an $11 million decrease in
emission allowance sales. These increases were partially offset by increased
interest income of $7 million as a result of the dividends received from
Holdings, some of which was invested in interest bearing investments. In
addition, timber sales were up and new product expenses were down. Income tax
expense was $127 million, an increase of $52 million primarily due to the
increase in pretax income.
<PAGE>22
Australian Electric Operations
______________________________
Comparison of the three-month periods ended September 30, 1999 and 1998
_______________________________________________________________________
<TABLE>
<CAPTION>
Change Due Change % Change
to Currency Due to Due to
1999 1998 Translation Operations Operations
____ ____ ___________ __________ __________
(Dollars in Millions)
<S> <C> <C> <C> <C> <C>
Powercor Earnings Contribution
Revenues
Powercor area $115.2 $108.3 $ 9.3 $ (2.4) (2)
Outside Powercor area
Victoria 19.0 19.3 1.6 (1.9) (10)
New South Wales 18.7 15.8 1.5 1.4 9
Queensland 0.6 - - 0.6 *
Australian Capital
Territory 0.4 0.3 - 0.1 33
_____ _____ _____ _____
153.9 143.7 12.4 (2.2) (2)
Other 4.9 5.8 0.7 (1.6) (28)
_____ _____ _____ _____
Total 158.8 149.5 13.1 (3.8) (3)
Operating expenses 136.4 126.0 10.7 (0.3) -
_____ _____ _____ _____
Income from operations 22.4 23.5 2.4 (3.5) (15)
Interest expense 14.5 13.6 1.2 (0.3) (2)
Equity in (income)/losses
of Hazelwood (2.1) (0.3) 0.1 (1.9) *
Other (income)/expense 0.3 - - 0.3 *
Income taxes 4.5 3.7 0.5 0.3 8
_____ _____ _____ _____
Earnings contribution $ 5.2 $ 6.5 $ 0.6 $ (1.9) (29)
===== ===== ===== =====
Powercor energy sales (millions of kWh)
Powercor area 1,801 1,885 (84) (4)
Outside Powercor area
Victoria 566 596 (30) (5)
New South Wales 562 560 2 -
Queensland 13 - 13 *
Australian Capital Territory 7 6 1 16
_____ _____ _____
Total 2,949 3,047 (98) (3)
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Currency Exchange Rates
The currency exchange rate for converting Australian dollars to U.S. dollars
was 0.65 in the third quarter of 1999 as compared to 0.60 in 1998, an 8%
increase. The effect of this change in exchange rates increased both revenues
and costs by $13 million in the third quarter of 1999.
The following discussion excludes the effects of the higher currency exchange
rates in 1999.
Revenue
Australia's revenues decreased $4 million, or 3%. This decrease was driven by
a decline in energy volumes sold of 98 million kWh, or 3%, resulting in a $5
million decline in revenues. Volumes were down primarily due to the loss of a
few large contestable industrial customers inside Powercor's franchise area.
This decrease was partially offset by increased prices that added $2 million
to revenues.
<PAGE>23
Operating Expenses
Purchased power expense increased $9 million, or 14%. Higher average prices
increased power costs by $11 million. Prices for purchased power averaged $24
per MWh in the third quarter of 1999 compared to $21 per MWh in the third
quarter of 1998. This price increase was partially the result of a contract
dispute between Powercor and one of its power suppliers in Australia. The
power supplier did not meet its contractual obligation to deliver power to
Powercor at the agreed upon rate which forced Powercor to purchase power on
the open market at a higher rate than last year.
Year to date, the contract dispute with the power supplier has resulted in $15
million of higher purchased power costs and $3 million in legal fees. Powercor
has brought suit to enforce the contract and recover its damages. The ultimate
financial outcome of the litigation cannot be determined at this time. Any
favorable result is expected to have a positive impact on earnings as all
costs incurred for replacement power and legal fees have been expensed as
incurred.
Other operating expenses decreased $9 million, or 18%. Decreased network rates
resulted in lower network fees of $4 million and an increase in customers
inside Powercor's franchise area serviced by other energy suppliers resulted
in higher network revenues of $3 million. Grid fees decreased $2 million.
<PAGE>24
Comparison of the nine-month periods ended September 30, 1999 and 1998
______________________________________________________________________
<TABLE>
<CAPTION>
Change Due Change % Change
to Currency Due to Due to
1999 1998 Translation Operations Operations
____ ____ ___________ __________ __________
(Dollars in Millions)
<S> <C> <C> <C> <C> <C>
Powercor Earnings Contribution
Revenues
Powercor area $327.4 $337.1 $ 8.2 $ (17.9) (5)
Outside Powercor area
Victoria 54.9 60.2 1.4 (6.7) (11)
New South Wales 55.7 52.9 1.4 1.4 3
Queensland 1.7 - - 1.7 -
Australian Capital
Territory 1.1 0.3 - 0.8 *
_____ _____ _____ _____
440.8 450.5 11.0 (20.7) (5)
Other 25.4 18.6 0.6 6.2 33
_____ _____ _____ _____
Total 466.2 469.1 11.6 (14.5) (3)
Operating expenses 379.5 375.3 9.6 (5.4) (1)
_____ _____ _____ _____
Income from operations 86.7 93.8 2.0 (9.1) (10)
Interest expense 43.3 43.8 1.1 (1.6) (4)
Equity in losses of Hazelwood 3.5 3.9 0.1 (0.5) (13)
Other (income)/expense (0.1) 3.0 - (3.1) (103)
Income taxes 15.3 15.9 0.4 (1.0) (6)
_____ _____ _____ _____
Earnings contribution $ 24.7 $ 27.2 $ 0.4 $ (2.9) (11)
===== ===== ===== =====
Powercor energy sales (millions of kWh)
Powercor area 5,178 5,549 (371) (7)
Outside Powercor area
Victoria 1,701 1,786 (85) (5)
New South Wales 1,669 1,643 26 2
Queensland 41 - 41 *
Australian Capital Territory 23 6 17 *
_____ _____ _____
Total 8,612 8,984 (372) (4)
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Currency Exchange Rates
The currency exchange rate for converting Australian dollars to U.S. dollars
was 0.65 in 1999 as compared to 0.63 in 1998. The effect of this change in
exchange rates increased both revenues and costs by $12 million.
The following discussion does not include the effects of the lower currency
exchange rate in 1999.
Revenue
Australia's revenues decreased $15 million, or 3%. This decrease was driven by
a decline in energy volumes sold of 372 million kWh, or 4%, resulting in a $22
million decline in revenues.
Energy volumes sold to contestable customers outside Powercor's franchise area
were down 2 million kWh while revenues remained flat. Decreased prices reduced
revenues $3 million compared to 1998. Inside Powercor's franchise area,
revenues decreased $18 million primarily due to a 370 million kWh decrease in
energy sold. Volumes are down due to the loss of a few large contestable
industrial customers.
Other revenues increased $6 million primarily due to the recognition of
<PAGE>25
contract settlement received from the Australian government of $5 million and
$3 million from construction projects for customers who own their own
distribution assets, including other distribution businesses in Australia.
These increases were partially offset by $4 million associated with Tariff H
contracts recognized in 1998.
Operating Expenses
Purchased power expense increased $16 million, or 8%, to $210 million. Higher
average prices increased power costs by $24 million. Prices for purchased
power averaged $24 per MWh in 1999 compared to $21 per MWh in 1998. This price
increase was the result of the contract dispute between Powercor and one of
its power suppliers in Australia. This price increase was partially offset by
decreased purchase volumes that reduced expenses $8 million.
Other operating expenses decreased $24 million, or 29%, to $59 million.
Decreased rates resulted in lower network fees of $7 million and an increase
in the number of customers inside Powercor's franchise area serviced by other
energy suppliers resulted in higher network revenues of $14 million.
Maintenance expense decreased $5 million primarily because 1998 included costs
relating to the replacement of the faulty switches associated with a product
recall.
Administrative and general expense increased $8 million primarily due to
increased redundancy payments and legal fees associated with the disputed
purchase power contracts. Redundancy payments are required by contract when
employees are displaced during a company restructuring. Powercor recently
outsourced various functions that resulted in displaced employees who were
eligible for redundancy payments.
Other Income and Expense
Other expense decreased $3 million primarily due to a reserve recorded in 1998
relating to a product recall. Powercor is in the process of negotiating
recovery from the product's manufacturer.
The Company recorded losses of $4 million in 1999 and 1998 on its equity
investment in the Hazelwood power station.
<PAGE>26
Other Operations
________________
Comparison of the three-month periods ended September 30, 1999 and 1998
_______________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution
PFS $ 2.9 $ (1.0) $ 3.9 *
Holdings and other
Write down of investments in
energy development companies - (32.4) 32.4 100
Other 7.7 6.8 0.9 13
_____ _____ _____
$ 10.6 $(26.6) $ 37.2 140
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Other operations reported earnings of $11 million, or $0.04 per share, in the
quarter compared to losses of $27 million, or $0.09 per share, in the same
period a year ago. Losses relating to the decision to exit its other energy
development businesses totaled $32 million, or $0.11 per share, in 1998.
Results from other operations for the quarter were lower by approximately $10
million, or $0.03 per share, as a result of decreased interest income. Cash
dividends of $500 million in October 1998 and $660 million in January 1999
were paid by Holdings to domestic electric operations. This cash had been
invested by Holdings in interest bearing investments prior to the dividends.
Other energy development businesses incurred losses of $6 million, or $0.02
per share, in the third quarter of 1998. The Company shut down or sold some of
these businesses in 1999.
PacifiCorp Financial Services earnings contribution increased by $4 million,
or $0.01 per share, compared to the third quarter of 1998 due to increased tax
credits received on the sales of synthetic coal fuel.
Earnings at Pacific Klamath Energy, Inc. were up $3 million, or $0.01 per
share, due to the cogeneration project under development in Klamath Falls,
Oregon.
<PAGE>27
Comparison of the nine-month periods ended September 30, 1999 and 1998
______________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss)
PFS $ 5.7 $ 6.5 $ (0.8) (12)
Holdings and other
TEG costs - (45.6) 45.6 100
Write down of investments in
energy development companies - (32.4) 32.4 100
Other 8.9 20.4 (11.5) (56)
_____ _____ _____
$ 14.6 $(51.1) $ 65.7 129
===== ===== =====
</TABLE>
Other operations reported income of $15 million, or $0.05 per share, compared
to a loss of $51 million, or $0.18 per share, in the same period a year ago.
The increase in earnings was primarily due to an $86 million pretax ($54
million after-tax) charge in 1998 for costs associated with the Company's
terminated bid for TEG and a $52 million pretax ($32 million after-tax) loss
relating to the decision to shut down or sell its other energy development
businesses. These increases were partially offset by a $16 million pretax ($10
million after-tax) gain on the sale of TEG shares.
Results from other operations were lower by approximately $28 million, or
$0.09 per share, in decreased interest income as the result of the cash
dividends paid by Holdings to domestic electric operations. This cash had been
invested by Holdings in interest bearing instruments prior to the dividends.
PFS reported income of $6 million in 1999 compared to $7 million in 1998. This
decrease was primarily attributable to the sale of its affordable housing
properties and operating leases that reduced income $5 million. In May 1998,
PFS sold a majority of its investments in affordable housing for $80 million,
which approximated book value. This decrease was partially offset by increased
income of $3 million relating to tax credits received on the sale of synthetic
coal fuel.
Other energy development businesses incurred losses of $19 million, or $0.06
per share, in 1998.
Earnings at Pacific Klamath Energy, Inc. were up $6 million, or $0.02 per
share, due to the cogeneration project under development in Klamath Falls,
Oregon.
<PAGE>28
FINANCIAL CONDITION -
For the nine months ended September 30, 1999:
OPERATING ACTIVITIES
Net cash flows provided by continuing operations were $686 million
during the period compared to $659 million in the first nine months of 1998.
The $27 million increase in operating cash flows was primarily attributable to
decreased working capital requirements.
Net cash used in discontinued operations in 1998 represents payment of
income taxes in the first quarter associated with a $671 million pretax gain
recorded in December 1997 on the sale of PTI. Net cash provided by
discontinued operations in 1999 represents payments received from TPC on its
intercompany note payable to Holdings.
INVESTING ACTIVITIES
Capital spending totaled $419 million in 1999 compared with $495 million
in 1998. Construction expenditures decreased $41 million in 1999 primarily
because the 1998 period included the construction of synthetic coal fuel
plants. Investments in and advances to affiliated companies-net was down $23
million because 1998 included investments in other energy development
companies that the Company decided to exit in October 1998.
On May 10, 1999, the utility partners who own the 1,340 MW coal-fired
Centralia Power Plant announced their intention to sell the plant and the
adjacent coal mine owned by the Company to TransAlta for $554 million. The
sale is subject to regulatory approval and is expected to close during the
first half of 2000. The Company operates the plant and owns a 47.5% share. The
Company expects to realize a gain on the sale, but the amount will not be
determined until the regulatory approval process has been completed.
CAPITALIZATION
At September 30, 1999, PacifiCorp had approximately $147 million of
commercial paper and uncommitted bank borrowings outstanding at a weighted
average rate of 6.3%. These borrowings are supported by $700 million of
revolving credit agreements. At September 30, 1999, the consolidated
subsidiaries had access to $722 million of short-term funds through committed
bank revolving credit agreements. Subsidiaries had $415 million outstanding
under bank revolving credit facilities. At September 30, 1999, the Company and
its subsidiaries had $529 million of short-term debt classified as long-term
debt as they have the intent and ability to support short-term borrowings
through the various revolving credit facilities on a long-term basis. The
Company and its subsidiaries have intercompany borrowing arrangements
providing for temporary loans of funds between parties at short-term market
rates.
INTEREST RATE EXPOSURE
The Company's market risk to interest rate change is primarily related to
long-term debt with fixed interest rates. The Company uses interest rate
swaps, forwards, futures and collars to adjust the characteristics of its
liability portfolio. This strategy is consistent with the Company's capital
structure policy that provides guidance on overall debt to equity and variable
rate debt as a percent of capitalization levels for both the consolidated
organization and its principal subsidiaries. Based on the Company's overall
interest rate exposure, the estimated potential one-day loss in fair value as
a result of near-term change in interest rates, within a 95% confidence level
using historical interest rate movements based on the VAR model, was $23
million at September 30, 1999.
<PAGE>29
YEAR 2000
The Company's Year 2000 project has been underway since mid-1996. A
standard methodology of inventory, assessment, remediation and testing of
hardware, software and equipment was implemented. The main areas of risk are
in: power supply (generating plant and system controls); information
technology (computer software and hardware); business disruption; and supply
chain disruption. The first two areas of risk are within the Company's own
business operations. The others are areas of risk the Company might face from
interaction with other companies, such as critical suppliers and customers.
The Company's plan was to successfully identify, correct and test its existing
critical systems by July 1, 1999, and to require all new hardware or software
acquired by the Company to be vendor certified Year 2000 ready before it is
installed.
The Company completed its testing and remediation on all critical
systems and met the July 1, 1999 milestone to be ready for the year 2000.
Following months of successful preparation and testing the Company has
finished advancing the system clocks in all thermal generating units and
substations to dates beyond March 1, 2000. The Company will reset the dates on
equipment during the second quarter of 2000. By operating in the year 2000
now, the Company is demonstrating confidence in its Year 2000 preparation and
plans to conduct business as usual on January 1, 2000. This also reduces any
risks inherent in the end-of-year and leap year date turnovers to producing
and delivering electric power.
The Company's Year 2000 project office continues to coordinate all Year
2000 activities throughout the corporation, as well as with suppliers and
business partners. This work will continue well into the first quarter of
2000 with full-time employees and contractors completing the final wrap-up of
the project. The following summarizes the status of the Year 2000 project as
of November 1, 1999.
Areas complete (as of November 1, 1999)
_______________________________________
Computer Systems - Correct and Test
Computer Systems - Applications to replace
Electric Systems - Inventory
Electric Systems - Assessment
Electric Systems - Correct and Test
Initial Contingency planning
Computer Systems - Desktop
Non-Critical Systems - Enterprise wide
Areas to be completed Target Date for Completion Status
_____________________ __________________________ ______
Continued compliance testing November 30, 1999 On schedule
Contingency exercises November 30, 1999 On going
As the Company finalizes its Year 2000 readiness, the focus will shift
to a management program to maintain its Year 2000-ready status. This strategy
includes Year 2000 testing of all system modifications and qualifying all new
equipment as Year 2000 ready before it is purchased and installed.
<PAGE>30
The Company is actively working with its suppliers of products and
services to determine the extent to which the suppliers' operations, and the
products and services they provide, are Year 2000 ready. The Company believes
it has identified and assessed 100% of its critical third-party suppliers. The
Company's critical third-party vendors reported they would be Year 2000 ready
on or before the dates below:
Readiness Target Dates Percent of all Critical Third
(on or before) Parties Ready
12/31/1998 14%
03/31/1999 18%
06/30/1999 44%
09/30/1999 79%
12/31/1999 99%
(no Readiness Target Date reported) 1%
The Company is in contact with these third parties, and their Year 2000
readiness information is updated as required.
To the extent that these parties are considered mission-critical to the
business and experience Year 2000 problems in their systems, the mission-
critical business functions may be adversely affected. The Company plans to
mitigate this risk by developing and testing contingency plans throughout
1999.
As of December 31, 1998, the Company had no single retail customer that
accounted for more than 1.7% of its retail utility revenues and the 20 largest
retail customers accounted for 13.9% of total retail electric revenues. The
Company has not performed a formal assessment of its customers' Year 2000
readiness.
The Company's mining operations contingency plan calls for increased
stockpiles of fuel to be available to supply the generating plants.
The Company, the North American Electric Reliability Council ("NERC")
and the Western Systems Coordinating Council ("WSCC") are working closely
together to ensure the integrity of the interconnected electrical distribution
and transmission system in the Company's service area and the western United
States. NERC coordinates the efforts of the ten regional electric reliability
councils throughout the United States, while WSCC is focused on reliable
electric service in the western United States. These agencies require Year
2000 readiness for all interconnected electric utilities by July 1, 1999. The
Company has submitted its draft contingency plans to the WSCC as required by
NERC. The Company successfully participated in the NERC sponsored industry
preparedness drills on April 9, 1999 and September 9, 1999.
The Company's worst case planning scenario assumes the following:
1. The public telecommunication system is not available or not
functioning reliably for as long as a week.
2. At midnight on December 31, 1999, there is a near simultaneous
loss of multiple generating units resulting in transmission system
instability and regional black outs. Restoration of service will
start immediately, but some areas may not be fully restored and
stable for twenty-four hours.
3. Temporary loss of automated transmission system monitoring and
control systems. These functions must be performed manually during
restoration.
<PAGE>31
4. Temporary loss of customer billing system. Customers on billing
cycles in the early part of the month may receive an estimated
billing that will be adjusted the following month.
5. Temporary loss of receivables processing system.
6. Temporary loss of automated payroll system. Employees will be
paid, but some automated functions must be performed manually.
7. Temporary loss of automated shareholder services systems.
Information must be available to be accessed manually while
automated systems are being restored.
To address this potential scenario and in cooperation with efforts by
NERC and WSCC, the Company plans to establish a precautionary posture for its
system leading into December 31, 1999. This is similar to the posture taken
when severe winter weather is anticipated in areas of its service territory.
Regional connections would be deliberately disconnected only during, or
immediately following, a system disturbance in order to prevent further
cascading outages and to facilitate restoration. Additional personnel will be
on hand at control centers. Facilities such as power plants and key major
substations will also have additional personnel standing by. Backup systems
will be serviced and tested, as appropriate, prior to the transition period.
Additional generation will be brought on line for the transition period as
needed.
The Company is continuing to expand its extensive microwave network in
1999. Because this system is self-controlled and has been undergoing extensive
analysis for Year 2000 readiness, the Company considers this a reliable
alternative to the public telephone network if needed. Emergency power systems
will be tested and made ready. In addition to the microwave system, the
Company has an extensive radio network. Through integration of the Company's
radio and microwave facilities, Company personnel can effectively "dial-up"
telephones throughout the Company's area. Radio units will be deployed at key
locations during the transition period. The Company is also planning to
station satellite telephones at system dispatching facilities and key power
plants.
The Company's payment processing system has been certified by the vendor
as Year 2000 ready. Check issuance has been outsourced to a vendor who is Year
2000 ready. To the extent possible, accounts payable checks and wire transfers
will be processed early in December. Arrangements are expected to be made with
the Company's banks to cover critical payment obligations for up to seventy-
two hours should wire transfers be disrupted. The Company's systems to
maintain shareholder records, transfer stock, issue 1099 dividend statements
and process dividend payments are certified Year 2000 ready.
Powercor
________
Powercor successfully implemented its Customer Service System in October
1999, while upgrades to its large customer billing system will be installed in
November 1999. The Operations Management System will also be replaced in
November 1999. The latter two systems are on schedule.
Mining
______
Few Year 2000 impacts have been identified within the mining
subsidiaries. The Year 2000 project continues according to schedule. Legacy
business systems are being upgraded or replaced to address Year 2000 issues
and these efforts will be completed in October 1999.
The Company has incurred $21.8 million in costs relating to the Year
2000
<PAGE>32
project through September 30, 1999. The majority of these costs have been
incurred to repair software problems. The total cost of the Year 2000 project
is estimated at $26 to $30 million, which will be principally funded from
operating cash flows. This estimate does not include the cost of system
replacements that will be Year 2000 ready, but are not being installed
primarily to resolve Year 2000 problems. Year 2000 information technology
("IT") remediation costs amount to approximately 5% of IT's budget. The
Company has not delayed any IT projects that are critical to its operations as
a result of Year 2000 remediation work. No independent verification of risk
and cost estimates has been undertaken to date.
The dates on which the Company believes the Year 2000 project will be
completed and the expected costs and other impacts of the Year 2000 issues are
based on management's best estimates, which were derived utilizing numerous
assumptions concerning future events, including the availability of certain
resources, the completion of third-party modification plans and other factors.
There can be no assurance that these estimates will be achieved, or that there
will not be a delay in, or increased costs associated with, the Company's
implementation of its Year 2000 project.
______________________________________________________________________________
The condensed consolidated financial statements as of September 30, 1999
and December 31, 1998 and for the three-and nine-month periods ended
September 30, 1999 and 1998 have been reviewed by Deloitte & Touche LLP,
independent accountants, in accordance with standards established by the
American Institute of Certified Public Accountants. A copy of their report is
included herein.
<PAGE>33
Deloitte & Touche LLP
_____________________ ______________________________________________________
Suite 3900 Telephone:(503)222-1341
111 S.W. Fifth Avenue Facsimile:(503)224-2172
Portland, Oregon 97204-3698
INDEPENDENT ACCOUNTANTS' REPORT
PacifiCorp:
We have reviewed the accompanying condensed consolidated balance sheet of
PacifiCorp and subsidiaries as of September 30, 1999, and the related
condensed consolidated statements of income and retained earnings for the
three- and nine-month periods ended September 30, 1999 and 1998 and related
condensed consolidated statements of cash flows for the nine-month periods
ended September 30, 1999 and 1998. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures
to financial data and of making inquiries of persons responsible for financial
and accounting matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing standards, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to such condensed consolidated financial statements for them to
be in conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet of PacifiCorp and subsidiaries as of
December 31, 1998, and the related consolidated statements of income, changes
in common shareholders' equity and cash flows for the year then ended (not
presented herein); and in our report dated March 5, 1999, we expressed an
unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 1998 is fairly stated, in all material
respects, in relation to the consolidated balance sheet from which it has been
derived.
DELOITTE & TOUCHE LLP
November 4, 1999
<PAGE>34
PART II. OTHER INFORMATION
Item 5. Other Information
_______ _________________
In anticipation of and contingent upon completion of the merger,
the Company's Board of Directors declared a stub-period dividend
on November 10, 1999, for shareholders of record as of the close
of business on the business day prior to the date of completion of
the merger. The Board did not declare a regular quarterly dividend
on common shares. The Board typically declares quarterly dividends
at its regularly scheduled meetings in February, May, August and
November. The Company will pay the stub dividend based upon the
daily equivalent of its current $1.08 annual dividend for the days
elapsed from November 15, 1999, the date the last common dividend
was paid, to the merger closing date. The equivalent daily
dividend rate is approximately $0.0029589 per share. The stub-
period dividend will be paid 28 days after the date of completion
of the merger.
Item 6. Exhibits and Reports on Form 8-K
______ ________________________________
(a) Exhibits.
Exhibit 12(a): Statements of Computation of Ratio of Earnings to
Fixed Charges.
Exhibit 12(b): Statements of Computation of Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends.
Exhibit 15: Letter re unaudited interim financial information.
Exhibit 27: Financial Data Schedule for the quarter ended
September 30, 1999 (filed electronically only).
(b) Reports on Form 8-K.
None
<PAGE>35
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
PACIFICORP
Date November 12, 1999 By ROBERT R. DALLEY
____________________________ ____________________________________
Robert R. Dalley
Controller and
Chief Accounting Officer
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION PAGE
_______ ___________ ____
<S> <C> <C>
Exhibit 12(a): Statements of Computation of Ratio of
Earnings to Fixed Charges.
Exhibit 12(b): Statements of Computation of Ratio of
Earnings to Combined Fixed Charges and Preferred Stock
Dividends.
Exhibit 15: Letter re unaudited interim financial
information.
Exhibit 27: Financial Data Schedule for the quarter
ended September 30, 1999 (filed electronically only).
</TABLE>
<PAGE>
<TABLE>
EXHIBIT (12)(a)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO FIXED CHARGES
<CAPTION>
Nine Months
Ended
1994 1995 1996 1997 1998 Sept. 30, 1999
____ ____ ____ ____ ____ ______________
(In Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense.................. $ 302.0 $ 336.4 $ 415.0 $ 438.1 $ 371.7 $260.5
Estimated interest portion of
rentals charged to expense...... 5.6 4.5 4.1 6.6 5.7 6.7
Preferred dividends of
wholly owned subsidiary......... - - 15.3 32.9 42.9 34.0
-----------------------------------------------------------------
Total fixed charges........... $ 307.6 $ 340.9 $ 434.4 $ 477.6 $ 420.3 $301.2
=================================================================
Earnings, as defined:*
Income from continuing
operations...................... $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7 $359.5
Add (deduct):
Provision for income taxes...... 209.0 192.1 236.5 111.8 59.1 134.9
Minority interest............... 1.3 1.4 1.8 1.9 (0.7) -
Undistributed income of less than
50% owned affiliates.......... (14.7) (15.0) (18.2) (11.1) 10.3 3.6
Fixed charges as above.......... 307.6 340.9 434.4 477.6 420.3 301.2
-----------------------------------------------------------------
Total earnings................ $ 900.7 $ 921.8 $1,084.8 $ 813.0 $ 658.7 $799.2
=================================================================
Ratio of Earnings to Fixed Charges.. 2.9x 2.7x 2.5x 1.7x 1.6x 2.7x
=================================================================
<FN>
* "Fixed charges" represent consolidated interest charges, an estimated amount representing the interest
factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Earnings" represent
the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing
operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges,
(d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees.
</FN>
</TABLE>
<PAGE>
<TABLE>
EXHIBIT (12)(b)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
Nine Months
Ended
1994 1995 1996 1997 1998 Sept. 30, 1999
____ ____ ____ ____ ____ ______________
(In Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense................... $ 302.0 $ 336.4 $ 415.0 $ 438.1 $ 371.7 $260.5
Estimated interest portion of
rentals charged to expense..... 5.6 4.5 4.1 6.6 5.7 6.7
Preferred dividends of
wholly owned subsidiary........ - - 15.3 32.9 42.9 34.0
--------------------------------------------------------------
Total fixed charges.......... 307.6 340.9 434.4 477.6 420.3 301.2
Preferred Stock Dividends,
as defined:*................... 60.8 57.2 46.2 33.8 29.5 23.1
--------------------------------------------------------------
Total fixed charges and
preferred dividends........ $ 368.4 $ 398.1 $ 480.6 $ 511.4 $ 449.8 $324.3
==============================================================
Earnings, as defined:*
Income from continuing
operations..................... $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7 $359.5
Add (deduct):
Provision for income taxes..... 209.0 192.1 236.5 111.8 59.1 134.9
Minority interest.............. 1.3 1.4 1.8 1.9 (0.7) -
Undistributed income of less than
50% owned affiliates......... (14.7) (15.0) (18.2) (11.1) 10.3 3.6
Fixed charges as above......... 307.6 340.9 434.4 477.6 420.3 301.2
--------------------------------------------------------------
Total earnings............... $ 900.7 $ 921.8 $1,084.8 $ 813.0 $ 658.7 $799.2
==============================================================
Ratio of Earnings to Combined
Fixed Charges and Preferred
Stock Dividends.................. 2.4x 2.3x 2.3x 1.6x 1.5x 2.5x
===============================================================
<FN>
* "Fixed charges" represent consolidated interest charges, an estimated amount representing the interest
factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Preferred Stock
Dividends" represent preferred dividend requirements multiplied by the ratio which pre-tax income from
continuing operations bears to income from continuing operations. "Earnings" represent the aggregate of
(a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority
interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e)
undistributed income of less than 50% owned affiliates without loan guarantees.
</FN>
</TABLE>
<PAGE>
Deloitte &
Touche
__________ _____________________________________________________
Deloitte & Touche LLP Telephone:(503)222-1341
Suite 3900 Facsimile:(503)224-2172
111 S.W. Fifth Avenue
Portland, Oregon 97204-3642
Exhibit 15
November 4, 1999
PacifiCorp
825 N.E. Multnomah
Portland, Oregon
We have made a review, in accordance with standards established by the
American Institute of Certified Public Accountants, of the unaudited interim
financial information of PacifiCorp and subsidiaries for the periods ended
September 30, 1999 and 1998, as indicated in our report dated November 4,
1999; because we did not perform an audit, we expressed no opinion on that
information.
We are aware that our report referred to above, which is included in your
Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, is
incorporated by reference in Registration Statement Nos. 33-51277, 33-54169,
33-57043, 33-58461, 333-10885, and 333-45851, all on Form S-8; Registration
Statement No. 33-36239 on Form S-4; Registration Statement Nos. 33-62095 and
333-09115 on Form S-3; and Form F-4 No. 333-77877.
We also are aware that the aforementioned report, pursuant to Rule 436(c)
under the Securities Act of 1933, is not considered a part of the Registration
Statement prepared or certified by an accountant or a report prepared or
certified by an accountant within the meaning of Sections 7 and 11 of that
Act.
DELOITTE & TOUCHE LLP
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S
FORM 10-Q DATED SEPTEMBER 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIALS.
</LEGEND>
<CIK> 0000075594
<NAME> PACIFICORP
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7943200
<OTHER-PROPERTY-AND-INVEST> 1735800
<TOTAL-CURRENT-ASSETS> 1124800
<TOTAL-DEFERRED-CHARGES> 381600
<OTHER-ASSETS> 1242900
<TOTAL-ASSETS> 12428300
<COMMON> 3245400
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 704000
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3949400
175000
66400
<LONG-TERM-DEBT-NET> 4382800
<SHORT-TERM-NOTES> 1000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 33100
<LONG-TERM-DEBT-CURRENT-PORT> 179400
0
<CAPITAL-LEASE-OBLIGATIONS> 27200
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3614000
<TOT-CAPITALIZATION-AND-LIAB> 12428300
<GROSS-OPERATING-REVENUE> 2935700
<INCOME-TAX-EXPENSE> 134900
<OTHER-OPERATING-EXPENSES> 2344100
<TOTAL-OPERATING-EXPENSES> 2479000
<OPERATING-INCOME-LOSS> 456700
<OTHER-INCOME-NET> 28300
<INCOME-BEFORE-INTEREST-EXPEN> 485000
<TOTAL-INTEREST-EXPENSE> 260500
<NET-INCOME> 225600<F1>
14400
<EARNINGS-AVAILABLE-FOR-COMM> 211200<F1>
<COMMON-STOCK-DIVIDENDS> 240900
<TOTAL-INTEREST-ON-BONDS> 213000
<CASH-FLOW-OPERATIONS> 704600
<EPS-BASIC> 0.71
<EPS-DILUTED> 0.71
<FN>
<F1>NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDES INCOME FROM
DISCONTINUED OPERATIONS OF $1,100.
</FN>
</TABLE>
