<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-QT
/ / QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
OR
/X/ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from January 1, 1999 to March 31, 1999
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 November 29, 1999, there were 297,324,604 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 12
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K 25
Signature 26
</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
March 31,
____________________
1999 1998
____ ____
<S> <C> <C>
REVENUES $ 959.8 $1,260.2
_______ _______
EXPENSES
Purchased power 268.7 516.5
Other operations and maintenance 259.8 272.7
Administrative and general 64.3 74.9
Depreciation and amortization 113.2 115.2
Taxes, other than income taxes 26.3 27.6
Special charges - 113.1
_______ _______
TOTAL 732.3 1,120.0
_______ _______
INCOME FROM OPERATIONS 227.5 140.2
_______ _______
INTEREST EXPENSE AND OTHER
Interest expense 88.0 94.3
Interest capitalized (3.4) (3.3)
TEG costs - 86.3
Other income - net (6.3) (7.0)
_______ _______
TOTAL 78.3 170.3
_______ _______
Income (loss) from continuing operations
before income taxes 149.2 (30.1)
Income tax expense/(benefit) 57.9 (15.5)
_______ _______
Income (loss) from continuing operations 91.3 (14.6)
Discontinued Operations (less applicable
income tax expense: 1998/$0.3 - (0.5)
_______ _______
NET INCOME (LOSS) 91.3 (15.1)
RETAINED EARNINGS BEGINNING OF PERIOD 732.0 1,106.3
Cash dividends declared
Preferred stock (4.2) (4.3)
Common stock per share of $0.27 (80.3) (80.3)
_______ _______
RETAINED EARNINGS END OF PERIOD $ 738.8 $1,006.6
======= =======
EARNINGS (LOSS) ON COMMON STOCK $ 86.5 $ (19.9)
Average number of common shares
outstanding - Basic and dilutive (Thousands) 297,334 297,059
EARNINGS (LOSS) PER COMMON SHARE - Basic and dilutive
Continuing operations $ 0.29 $ (0.07)
Discontinued operations - -
_______ ________
TOTAL $ 0.29 $ (0.07)
======= ========
<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>
Three Months Ended
March 31,
____________________
1999 1998
____ ____
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 91.3 $ (15.1)
Adjustments to reconcile net income
(loss) to net cash provided by (used
in) operating activities
Loss on discontinued operations - 0.5
Depreciation and amortization 115.1 118.6
Deferred income taxes and investment tax
credits - net 27.5 (40.6)
Special charges - 113.1
Gain on sale of assets (8.6) (3.6)
Other (10.2) 27.6
Accounts receivable and prepayments 169.9 37.7
Materials, supplies and fuel stock (4.3) (2.3)
Accounts payable and accrued liabilities (107.0) (19.9)
______ ______
Net cash provided by continuing operations 273.7 216.0
Net cash provided by (used in) discontinued
operations 26.1 (295.6)
______ ______
NET CASH PROVIDED BY (USED IN) OPERATING
ACTIVITIES 299.8 (79.6)
______ ______
CASH FLOWS FROM INVESTING ACTIVITIES
Construction (116.4) (110.5)
Investments in and advances to
affiliated companies - net (0.5) (21.0)
Assets and operating companies acquired (0.2) (6.9)
Proceeds from asset sales 14.2 -
Proceeds from sales of finance assets
and principal payments 36.2 46.2
Investment in shares of The Energy Group PLC - (625.5)
Other 10.9 6.2
______ ______
NET CASH USED IN INVESTING ACTIVITIES (55.8) (711.5)
______ ______
CASH FLOWS FROM FINANCING ACTIVITIES
Changes in short-term debt (180.4) 108.7
Proceeds from long-term debt 400.8 417.5
Proceeds from issuance of common stock - 7.9
Dividends paid (84.5) (84.1)
Repayments of long-term debt (548.5) (369.2)
Other 1.7 20.0
______ ______
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES (410.9) 100.8
______ ______
DECREASE IN CASH AND CASH EQUIVALENTS (166.9) (690.3)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 583.1 740.8
______ ______
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 416.2 $ 50.5
====== ======
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for
Interest (net of amount capitalized) $ 116.3 $ 135.7
Income taxes (refunds)/paid (2.4) 367.3
<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>
March 31, December 31,
1999 1998
_________ _____________
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 416.2 $ 583.1
Accounts receivable less allowance
for doubtful accounts: 1999/$17.9
and 1998/$18.0 522.6 703.2
Materials, supplies and fuel stock at
average cost 180.4 175.8
Net assets of discontinued operations
and assets held for sale 192.4 192.4
Other 69.2 87.9
________ ________
TOTAL CURRENT ASSETS 1,380.8 1,742.4
PROPERTY, PLANT AND EQUIPMENT
Domestic Electric Operations 12,527.6 12,460.0
Australian Electric Operations 1,180.3 1,140.4
Other Operations 20.5 22.2
Accumulated depreciation and amortization (4,641.3) (4,553.2)
________ ________
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 9,087.1 9,069.4
OTHER ASSETS
Investments in and advances to affiliated
companies 114.3 114.9
Intangible assets - net 373.7 369.4
Regulatory assets - net 780.7 795.5
Finance note receivable 203.1 204.9
Finance assets - net 309.1 313.7
Deferred charges and other 393.4 378.3
________ ________
TOTAL OTHER ASSETS 2,174.3 2,176.7
________ ________
TOTAL ASSETS $12,642.2 $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>
March 31, December 31,
1999 1998
_________ ____________
<S> <C> <C>
CURRENT LIABILITIES
Long-term debt currently maturing $ 236.1 $ 299.5
Notes payable and commercial paper 80.3 260.6
Accounts payable 410.0 566.2
Taxes, interest and dividends payable 343.4 282.7
Customer deposits and other 163.1 168.0
________ ________
TOTAL CURRENT LIABILITIES 1,232.9 1,577.0
DEFERRED CREDITS
Income taxes 1,565.3 1,542.6
Investment tax credits 123.3 125.3
Other 651.3 646.1
________ ________
TOTAL DEFERRED CREDITS 2,339.9 2,314.0
LONG-TERM DEBT 4,519.0 4,559.3
COMMITMENTS AND CONTINGENCIES (See Note 6) - -
GUARANTEED PREFERRED BENEFICIAL INTERESTS
IN COMPANY'S JUNIOR SUBORDINATED DEBENTURES 340.6 340.5
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: 1999/297,331,433
and 1998/297,343,422 3,284.3 3,285.0
Retained earnings 738.8 732.0
Accumulated other comprehensive income (54.7) (60.7)
________ ________
TOTAL COMMON EQUITY 3,968.4 3,956.3
________ ________
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $12,642.2 $12,988.5
======== ========
<FN>
See accompanying Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
March 31, 1999
1. FINANCIAL STATEMENTS
The accompanying unaudited condensed consolidated financial statements
as of March 31, 1999 and December 31, 1998 and for the periods ended March 31,
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 March 31, 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 ("PPM"). See Note 4. 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.
2. CHANGE IN FISCAL YEAR
Effective November 30, 1999, the Company changed its fiscal year end
from December 31 to March 31, which is the fiscal year end for Scottish Power
PLC ("ScottishPower"). See Note 3. A three-month transition period from
January 1, 1999 through March 31, 1999 is covered by this report.
3. SCOTTISHPOWER MERGER
On November 29, 1999, the Company and ScottishPower completed their
proposed merger under which the Company became an indirect subsidiary of
<PAGE>7
ScottishPower. The Company will continue to operate under its current name,
and its headquarters will remain in Portland, Oregon.
Each share of the Company's stock was 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. Cash will be paid in lieu of
fractional shares.
4. DISCONTINUED OPERATIONS
In October 1998, the Company decided to exit its energy trading business
by offering for sale TPC, 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 June 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
Period Ended
March 31,
_____________
1998
____
<S> <C>
(Dollars in Millions)
Revenues $816.0
=====
Net loss from discontinued operations (less
applicable income tax expense of $0.4) $ (0.5)
=====
</TABLE>
Net assets of the discontinued operations of the energy trading segment
and assets held for sale consisted of the following:
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
________ ____________
<S> <C> <C>
(Dollars in Millions)
Current assets $107.1 $148.5
Noncurrent assets 176.7 152.7
Current liabilities (78.6) (96.0)
Long-term debt (1.3) (1.3)
Noncurrent liabilities (28.9) (28.9)
Assets held for sale 17.4 17.4
_____ _____
Net Assets of Discontinued Operations
and Assets Held for Sale $192.4 $192.4
===== =====
</TABLE>
Holdings had $45 million and $34 million as of March 31, 1999 and
December 31, 1998, respectively, of liabilities in "Customer deposits and
other" relating to the sale of the discontinued operations.
<PAGE>8
5. 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
three months ended March 31, 1999. The ordered rate reduction is the
culmination of a general rate case in Utah that began in 1997.
On September 20, 1999, the Company filed for a rate increase before the
UPSC. The Company is asking for an annual increase of $67 million, or 9.9%,
based on a test year ended December 31, 1998. The Company's effective date for
this tariff increase is expected to be in May 2000.
On November 24, 1999, the UPSC approved the merger. As part of the
approval, the Company offered 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
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. On November 15, 1999, the Company filed an application for approval with
the Federal Energy Regulatory Commission ("FERC"). The sale is expected to
close early in 2000.
On April 30, 1999, the Company filed for changes in the prices it
charges Oregon customers. The filing is 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
<PAGE>9
high-quality service. The filing also contained a request to increase the
revenues collected under its system benefits charge. These changes were
approved by the OPUC in June 1999, and became effective July 1, 1999. This
resulted 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 annual 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 annual
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 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
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.
<PAGE>10
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.
On November 15, 1999, the IPUC approved the merger. In Idaho, the
Company 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
annual increase of $12 million, or 4.9%, based on a test year ended 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 and issued a final written order on November 22, 1999. The companies
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.
6. 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
7. COMPREHENSIVE INCOME
The components of comprehensive income are as follows:
<TABLE>
<CAPTION>
Millions of dollars/For three months ended March 31 1999 1998
________________________________________________________________________
<S> <C> <C>
Net income (loss) $ 91.3 $(15.1)
Other comprehensive income
Foreign currency translation adjustment, net
of taxes 1999/$3.9 and 1998/$9.1 6.1 13.0
Unrealized gain on available-for-sale
securities, net of taxes: 1999/$- (0.1) -
Unrealized gain on shares of The Energy
Group PLC, net of taxes of $4.6 - 7.2
_____ _____
Total comprehensive income $ 97.3 $ 5.1
===== =====
</TABLE>
8. 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:
March 31, 1999
Net sales and revenues
(all external) $ 959.8 $ 807.2 $147.0 $ - $ 5.6
Income from continuing
operations 91.3 80.2 10.4 - 0.7
March 31, 1998
Net sales and revenues
(all external) $1,260.2 $1,077.0 $162.5 $ - $20.7
Income (loss) from
continuing operations (14.6) 10.4 14.1 - (39.1)
Loss from discontinued
operations (0.5) - - (0.5) -
</TABLE>
<PAGE>12
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 March 31, 1999 and 1998
___________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
<S> <C> <C> <C> <C>
(Dollars in Millions)
Earnings contribution (loss) on
common stock (1)
Domestic Electric Operations $ 75.4 $ 5.6 $ 69.8 *
Australian Electric Operations 10.4 14.1 (3.7) (26)
Other Operations 0.7 (39.1) 39.8 102
_____ _____ _____
Continuing Operations 86.5 (19.4) 105.9 *
Discontinued Operations (2) - (0.5) 0.5 100
_____ _____ _____
Total $ 86.5 $(19.9) $106.4 *
===== ===== =====
Earnings (loss) per common
share - Basic and dilutive
Continuing Operations $ 0.29 $ (0.7) $ 0.36 *
Discontinued Operations (2) - - - -
_____ _____ _____
Total $ 0.29 $ (0.7) $ 0.36 *
===== ===== =====
<FN>
*Not a meaningful number.
(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 $87 million, or $0.29 per
share, compared to a loss of $20 million, or $0.07 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 and 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").
<PAGE>13
Domestic electric operations earnings contribution was $75 million, or $0.25
per share, in the three months ended March 31, 1999 compared to $6 million, or
$0.02 per share, in 1998. Excluding the $70 million charge relating to the
work force reduction, the earnings contribution in 1998 would have been
$76 million, or $0.26 per share.
The Utah rate order received in March 1999 reduced earnings for the three
months ended March 31, 1999 by $6 million, or $0.02 per share. This decrease
was offset by lower interest expense and increased interest income totaling
$11 million, or $0.04 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. Non-fuel operations
and maintenance and administrative and general costs declined 2% in the three
months ended March 31, 1999, consistent with the Company's recent actions to
reduce these costs.
The earnings contribution for the three months ended March 31, 1999 from the
Company's Australian electric operations totaled $10 million, or $0.04 per
share, compared to $14 million, or $0.05 per share, in 1998. The decreased
earnings contribution from Australian operations was primarily attributable to
an increase in purchased power expense.
Other operations reported income of $1 million for the three months ended
March 31, 1999 compared to losses of $39 million in the same period a year
ago. The increase in earnings was primarily due the $54 million after-tax
charge for costs associated with the Company's terminated bid for TEG in 1998.
This increase was partially offset by decreased earnings from PFS and
Holdings.
<PAGE>14
RESULTS OF OPERATIONS
Domestic Electric Operations
____________________________
Comparison of the three-month periods ended March 31, 1999 and 1998
___________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
<S> <C> <C> <C> <C>
(Dollars in Millions)
Revenues
Residential $ 231.2 $ 231.8 $ (0.6) -
Commercial 159.0 161.4 (2.4) (1)
Industrial 151.8 162.7 (10.9) (7)
Other 7.2 7.6 (0.4) (5)
_______ _______ _______
Retail sales 549.2 563.5 (14.3) (3)
Wholesale sales 240.0 499.1 (259.1) (52)
Other 18.0 14.4 3.6 25
_______ _______ _______
Total 807.2 1,077.0 (269.8) (25)
Operating expenses 611.6 981.2 (369.6) (38)
_______ _______ _______
Income from operations 195.6 95.8 99.8 104
Interest expense 67.6 80.0 (12.4) (16)
Minority interest and other (6.0) (2.7) 3.3 122
Income taxes 53.8 8.1 45.7 *
_______ _______ _______
Net income 80.2 10.4 69.8 *
Preferred dividend requirement 4.8 4.8 - -
_______ _______ _______
Earnings contribution $ 75.4 $ 5.6 $ 69.8 *
======= ======= =======
Energy sales (millions of kWh)
Residential 3,773 3,751 22 1
Commercial 2,993 2,992 1 -
Industrial 4,628 4,891 (263) (5)
Other 153 159 (6) (4)
______ ______ _______
Retail sales 11,547 11,793 (246) (2)
Wholesale sales 9,636 22,443 (12,807) (57)
______ ______ _______
Total 21,183 34,236 (13,053) (38)
====== ====== =======
Residential average usage (kWh) 3,064 3,042 22 1
Total customers (end of period) 1,442,195 1,445,900 (3,705) -
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Revenues
Domestic electric operations revenues decreased $270 million, or 25%. This
decrease was primarily attributable to a $259 million decrease in wholesale
revenues. The sale of the Company's Montana service area in November 1998
decreased revenues by $12 million and the Utah rate order reduced revenues by
$10 million.
Wholesale sales decreased $259 million. The decrease in revenues was driven by
a 57% decline in energy volumes. Lower short-term and spot market wholesale
energy volumes decreased revenues by $264 million. Related energy prices
<PAGE>15
averaged $20 per MWh in the three months ended March 31, 1999, a 3% increase
over the prior year. The higher prices for these sales added $7 million to
revenues in the three months ended March 31, 1999. This decline in energy
volumes is consistent with the Company's decision to scale back short-term
wholesale sales.
Residential revenues were down $1 million. Excluding the impact of the sale of
Montana, residential revenues were up $5 million, energy volumes were up 4%
and customer growth was 2%. Growth in the average number of residential
customers added $5 million to revenues. Volume increases primarily due to
colder weather added $3 million to revenues. The Utah rate order reduced
residential revenues by $4 million.
Commercial revenues were down $2 million, or 1%. Excluding the impact of the
sale of Montana, commercial revenues were up $1 million. Increased commercial
customers added $5 million to revenues. The Utah rate order reduced commercial
revenues by $4 million.
Industrial revenues decreased $11 million, or 7%. Excluding the impact of the
sale of Montana, industrial revenues were down $8 million, energy volumes were
down 4% and average customers were down 4%. Decreased energy volumes due to
the cyclical nature of industrial customer usage drove a $6 million decrease
in revenues. The Utah rate order reduced industrial revenues by $2 million.
Other revenue increased $4 million due to increased wheeling revenues.
See Note 5 regarding regulation of domestic electric operations' utility
properties.
Operating Expenses
Total operating expenses decreased $370 million, or 38%. 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
work force reduction that occurred in the same period in 1998.
Purchased power expense decreased $249 million, to $210 million. The lower
expense was primarily due to a 12.5 million MWh decrease in short-term firm
and spot market energy purchases which decreased purchased power expense $243
million. Short-term firm and spot market purchase prices averaged $19 per MWh
in the three months ended March 31, 1999 versus $20 per MWh in 1998, a 5%
decrease. The decrease in purchase prices reduced costs $9 million. Higher
volumes relating to long-term firm purchased power contracts added $3 million
to purchased power costs.
<PAGE>16
<TABLE>
<CAPTION>
Short-Term Firm and Spot Market Sales and Purchases
___________________________________________________
1999 1998
____ ____
<S> <C> <C>
Total sales volume (thousands of MWh) 5,719 18,900
Average sales price ($/MWh) $ 20.32 $ 19.77
_______ _______
Revenues (millions) $ 116 $ 374
Total purchase volume (thousands of MWh) 5,111 17,635
Average purchase price ($/MWh) $ 18.61 $ 19.70
_______ _______
Expenses (millions) $ 95 $ 347
_______ _______
Net (millions) $ 21 $ 27
======= =======
</TABLE>
Fuel expense was down $3 million, or 3%, to $120 million in 1999. Thermal
generation was down 4% to 12.8 million MWh. The average cost per MWh increased
to $9.31 from $9.17 in the prior year due to increased generation at plants
with higher fuel costs. The shift in generation resulted from unscheduled
plant outages. Hydroelectric generation increased 13% compared to the three
months ended March 31, 1998 due to favorable water conditions.
Other operations and maintenance expense increased $2 million, or 2%, to $113
million. Increased tree trimming added $3 million to expenses, which was
partially offset by a reduction in labor costs of $1 million.
Administrative and general expenses decreased $5 million, or 7%, to $73
million primarily due to a reduction in labor and employee related costs of
$12 million. This decrease was partially offset by a $6 million increase in
costs relating to the ongoing implementation of the Company's new SAP software
operating environment and increased outside services of $2 million.
Other Income and Expense
Domestic electric operations' interest expense was down $12 million to $68
million 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.
Interest income increased $5 million as a result of the dividends received
from Holdings, some of which was invested in interest bearing instruments.
Income tax expense increased $46 million, to $54 million, due to the increase
in pretax income.
<PAGE>17
Australian Electric Operations
______________________________
Comparison of the three-month periods ended March 31, 1999 and 1998
___________________________________________________________________
<TABLE>
<CAPTION>
Change Due Change % Change
to Currency Due to Due to
1999 1998 Translation Operations Operations
____ ____ ___________ __________ __________
<S> <C> <C> <C> <C> <C>
(Dollars in Millions)
Powercor Earnings Contribution
Revenues
Powercor area $103.2 $116.5 $(5.5) $(7.8) (7)
Outside Powercor area
Victoria 18.1 20.9 (0.9) (1.9) (9)
New South Wales 19.4 20.2 (0.9) 0.1 -
Queensland 0.5 - - 0.5 *
Australian Capital Territory 0.4 - - 0.4 *
_____ _____ ____ ____
141.6 157.6 (7.3) (8.7) (6)
Other 5.4 4.9 (0.3) 0.8 16
_____ _____ ____ ____
Total 147.0 162.5 (7.6) (7.9) (5)
Operating expenses 112.2 121.7 (5.8) (3.7) (3)
_____ _____ ____ ____
Income from operations 34.8 40.8 (1.8) (4.2) (10)
Interest expense 14.4 15.8 (0.7) (0.7) (4)
Equity in losses of Hazelwood 3.7 3.0 (0.2) 0.9 30
Other (income)/expense (0.1) (0.4) - 0.3 (75)
Income taxes 6.4 8.3 (0.3) (1.6) (19)
_____ _____ ____ ____
Earnings contribution $ 10.4 $ 14.1 $(0.6) $(3.1) (22)
===== ===== ==== ====
Powercor energy sales (millions of kWh)
Powercor area 1,666 1,797 (131) (7)
Outside Powercor area
Victoria 586 600 (14) (2)
New South Wales 579 575 4 1
Queensland 13 - 13 *
Australian Capital Territory 8 - 8 *
_____ _____ ____
Total 2,852 2,972 (120) (4)
===== ===== ====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Currency Exchange Rates
The currency exchange rate for converting Australian dollars to U.S. dollars
was 0.63 for the three months ended March 31, 1999 as compared to 0.67 in
1998, a 6% decrease in the quarter. The effect of this change in exchange
rates lowered revenues by $8 million and costs by $7 million in 1999.
The following discussion excludes the effects of the lower currency exchange
rate in 1999.
<PAGE>18
Revenues
Australian electric operations' revenues decreased $8 million, or 5%. This
decrease was attributable to a decline in energy volumes sold of 120 million
kWh, or 4%.
Energy volumes sold to contestable customers outside Powercor's franchise area
were up 11 million kWh and added $1 million to revenues due to customer gains
in Queensland and Australian Capital Territory. Inside Powercor's franchise
area, revenues decreased $8 million due to a 131 million kWh decrease in
energy sold. Volumes are down due to the loss of a few large contestable
customers.
Other revenues increased $1 million largely as a result of an increase in
revenue from construction projects for customers who own their own
distribution assets, some of whom are other distribution businesses in
Australia.
Operating Expenses
Purchased power expense increased $4 million, or 7%, to $59 million. Higher
average prices increased power costs by $6 million. Prices for purchased power
averaged $22 per MWh for the three months ended March 31, 1999 compared to $19
per MWh in 1998. This price increase was the result of a contract dispute
Powercor is having with a power supplier 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
rate higher than it paid last year. This increase was offset in part by a 4%
decrease in purchased power volumes that reduced costs $2 million.
As of September 30, 1999, the contract dispute with the power supplier had
resulted in $15 million of higher purchased power costs and $3 million in
legal fees. Powercor brought suit to enforce the contract and recover its
damages. On November 17, 1999, the Supreme Court of Victoria upheld the
validity of these contracts. On December 14, 1999, the Court ordered specific
performance on the remaining contracts and payment for failure to perform in
the past. This order is still subject to appeal.
Other operating expenses decreased $8 million, or 28%, to $19 million.
Decreased rates resulted in lower network fees of $2 million and an increase
in customers inside Powercor's franchise area serviced by other energy
suppliers resulted in higher network revenues of $6 million.
Administrative and general costs decreased $1 million, or 7%, to $12 million
due to the outsourcing of certain functions in the information technology
department.
Other Income and Expense
The Company recorded losses in 1999 of $4 million compared to losses of $3
million in 1998 on its equity investment in the Hazelwood power station.
Income tax expense was down $2 million, or 19%, due to a decrease in taxable
income.
<PAGE>19
Other Operations
Comparison of the three-month periods ended March 31, 1999 and 1998
___________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
<S> <C> <C> <C> <C>
(Dollars in Millions)
Earnings contribution (loss)
PFS $(0.4) $ 6.6 $(7.0) (107)
Holdings and other
TEG costs - (53.5) 53.5 100
Other 1.1 7.8 (6.7) (86)
____ _____ ____
$ 0.7 $(39.1) $39.8 (102)
==== ===== ====
</TABLE>
Other operations reported income of $1 million in the three months ended
March 31, 1999 compared to losses of $39 million 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.
Results from other operations for the three months ended March 31, 1999 were
reduced by approximately $11 million, or $0.04 per share, in decreased
interest income as the result of cash dividends of $500 million paid in
October 1998 and $660 million paid in January 1999 by Holdings to domestic
electric operations. This cash had been invested by Holdings in interest
bearing instruments prior to the dividends.
For 1999, PFS reported break even results, a $7 million decrease from 1998.
This decrease was primarily attributable to the sale of its affordable housing
properties and operating leases that reduced income $6 million. In May 1998,
PFS sold a majority of its investments in affordable housing for $80 million,
which approximated book value. In addition, PFS incurred a $1 million loss
relating to sales of synthetic coal fuel by its subsidiaries.
Other energy development businesses recorded no earnings or losses in 1999
compared to a loss of $5 million, or $0.02 per share, in 1998. This reduction
in losses was the result of the decision to exit these development businesses
in October 1998.
<PAGE>20
FINANCIAL CONDITION -
For the three months ended March 31, 1999:
OPERATING ACTIVITIES
Net cash flows provided by continuing operations were $274 million
during the period compared to $216 million in 1998. The $58 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 early 1998 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 $117 million in 1999 compared with $138 million
in 1998. Investments in and advances to affiliated companies-net is down $21
million because the three months ended March 31, 1998 included the
construction of synthetic coal fuel plants by subsidiaries of PFS.
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
<PAGE>21
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.
YEAR 2000
This Year 2000 disclosure reflects the status of the Company's
preparedness through December 31, 1999. This disclosure is consistent with
those given previously by the Company. As of January 13, 2000, the Company has
experienced some minor Year 2000 related problems with its business systems
that were quickly identified and corrected. Due to the nature of Year 2000
problems, it is still too early to determine whether additional problems will
occur. While the Company does not anticipate any major Year 2000 problems to
occur, it is continuing to monitor systems for any latent Year 2000 issues.
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 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 early 2000 with full-time
employees and contractors completing the final wrap-up of the project. The
<PAGE>22
following summarizes the status of the Year 2000 project as of December 1,
1999.
Areas complete (as of December 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
Continued compliance testing
Contingency exercises
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.
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 100%
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.
<PAGE>23
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 required 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 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.
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.
<PAGE>24
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 implemented its Customer Service System in October 1999, and
upgrades to its large customer billing system were installed in November 1999.
The Operations Management System was replaced in November 1999. All of these
systems are Year 2000 ready.
Mining
______
Few Year 2000 impacts have been identified within the mining
subsidiaries. The Year 2000 project completed its activities in October 1999.
The Company has incurred $25.4 million in costs relating to the Year
2000 project through November 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.
______________________________________________________________________________
<PAGE>25
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
______ ________________________________
(a) Exhibits.
Exhibit 12(a): Statements of Computation of Ratio of Earnings to
Fixed Charges. (Incorporated by reference to Exhibit 12(a) to Form
10-Q for the quarter ended March 31, 1999, dated May 12, 1999,
File No. 1-5152.)
Exhibit 12(b): Statements of Computation of Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends.
(Incorporated by reference to Exhibit 12(b) to Form 10-Q for the
quarter ended March 31, 1999, dated May 12, 1999, File No. 1-
5152.)
Exhibit 15: Letter re unaudited interim financial information of
awareness of incorporation by reference. (Incorporated by
reference to Exhibit 15 to Form 10-Q for the quarter ended March
31, 1999, dated May 12, 1999, File No. 1-5152.)
Exhibit 27: Financial Data Schedule for the quarter ended
March 31, 1999 (filed electronically only). (Incorporated by
reference to Exhibit 27 to Form 10-Q for the quarter ended March
31, 1999, dated May 12, 1999, File No. 1-5152.)
(b) Reports on Form 8-K.
On Form 8-K, dated November 29, 1999, the Company reported
"Item 1. Change in Control of Registrant," "Item 4. Changes in
Registrant's Certifying Accountant" and "Item 8. Change in Fiscal
Year."
<PAGE>26
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 January 13, 2000 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. (Incorporated by reference
to Exhibit 12(a) to Form 10-Q for the quarter ended
March 31, 1999, dated May 12, 1999, File No. 1-5152.)
Exhibit 12(b): Statements of Computation of Ratio of
Earnings to Combined Fixed Charges and Preferred Stock
Dividends. (Incorporated by reference to Exhibit 12(b)
to Form 10-Q for the quarter ended March 31, 1999,
dated May 12, 1999, File No. 1-5152.)
Exhibit 15: Letter re unaudited interim financial
information of awareness of incorporation by reference.
(Incorporated by reference to Exhibit 15 to Form 10-Q
for the quarter ended March 31, 1999, dated May 12,
1999, File No. 1-5152.)
Exhibit 27: Financial Data Schedule for the quarter
ended March 31, 1999 (filed electronically only).
(Incorporated by reference to Exhibit 27 to Form 10-Q
for the quarter ended March 31, 1999, dated May 12,
1999, File No. 1-5152.)
</TABLE>
