<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 March 31, 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 April 30, 1999, there were 297,331,433 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 11
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 (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 5) - -
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 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.
2. SCOTTISHPOWER MERGER
In December 1998, the Company announced a proposed merger with
ScottishPower 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 merger is subject to approval by the shareholders of both companies
and federal and state regulators.
<PAGE>7
Both companies received clearance from the Securities and Exchange
Commission to commence the mailing of proxy voting materials to shareholders
on May 6, 1999. ScottishPower has scheduled its shareholder vote for June 15,
1999, while the Company's shareholders will vote on June 17, 1999.
The proposed merger has already received clearance under the Hart-Scott-
Rodino Antitrust Improvements Act and from U.K. and Australian regulatory
authorities. Proceedings are currently underway before state regulators in the
Company's western U.S. service territory, where the staff of the Oregon PUC
recently recommended that the merger not be approved. Both companies expect
completion of the regulatory approval process to occur later this year.
3. 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. Final
determination of the net income impact of this sale is pending completion of
a working capital audit.
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
____
(Dollars in Millions)
<S> <C>
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:
<PAGE>8
<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.
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 ordered PacifiCorp
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.
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. The Company issued requests for
proposals to interested parties on July 20, 1998. 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. The price is
subject to adjustments for changes in assets and liabilities assumed by the
buyer. A definitive agreement is expected to be signed after Nor-Cal completes
due diligence. The sale will require approval by the California Public
<PAGE>9
Utilities Commission.
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
high-quality service. If approved by the OPUC, the change will take effect
July 1, 1999. This would result in a price increase of approximately 1.3%, or
$9 million annually, in Oregon.
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.
The credit was created by Congress 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, PacifiCorp
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.
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 affect on the Company's
consolidated financial statements.
<PAGE>10
6. 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>
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:
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>11
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
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
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>12
Domestic electric operations earnings contribution was $75 million, or $0.25
per share, in the first quarter of 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 1998 reduced 1999 first quarter earnings
$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 quarter, consistent with
the Company's recent actions to reduce these costs.
The first quarter 1999 earnings contribution 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 in the quarter 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>13
RESULTS OF OPERATIONS
Domestic Electric Operations
____________________________
Comparison of the three-month periods ended March 31, 1999 and 1998
___________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
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>14
averaged $20 per MWh in the quarter, a 3% increase over the prior year. The
higher prices for these sales added $7 million to revenues in the quarter.
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 4 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 1998 quarter.
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 quarter 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 $3 million to purchased power costs.
<PAGE>15
<TABLE>
<CAPTION>
Short-Term Firm and Spot Market Sales and Purchases
___________________________________________________
1999 1998
____ ____
<S> <C> <C>
Total sales volume (thousands of MWh) 5,719 18,900
Average sales price ($/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 first
quarter of 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 and January 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>16
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
____ ____ ___________ __________ __________
(Dollars in Millions)
<S> <C> <C> <C> <C> <C>
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 in the first quarter of 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 the first quarter of 1999.
The following discussion excludes the effects of the lower currency exchange
rate in 1999.
Revenues
<PAGE>17
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 who 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 in the first quarter of 1999 compared to $19 per MWh in
the first quarter of 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.
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>18
Other Operations
________________
Comparison of the three-month periods ended March 31, 1999 and 1998
___________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
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 quarter 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 quarter 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 and $660 million paid in
January 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 its investment in Synfuels, a company involved in the production
of coal byproducts.
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>19
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 the first three months of 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 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 $117 million in 1999 compared with $138 million
in 1998. Investments in and advances to affiliated companies-net is down $21
million because the first quarter of 1998 reflects PFS's investment in
Synfuels.
On May 10, 1999, the utility partners who own the 1,340 MW coal-fired
Centralia Power Plant and adjacent coal mine announced their intention to sell
to TransAlta for $554 million. This sale is still subject to regulatory
approval and is expected to close near the end of 1999. The Company operates
the plant and owns a 47.5% share. The Company owns and operates the adjacent
Centralia coal mine. 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 March 31, 1999, PacifiCorp had approximately $196 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 March 31, 1999, the consolidated subsidiaries
had access to $826 million of short-term funds through committed bank
revolving credit agreements. Subsidiaries had $432 million outstanding under
bank revolving credit facilities. At March 31, 1999, the Company and its
subsidiaries had $548 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.
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 has been implemented. The main areas of risk
are in: power supply (generating plant and system controls); information
<PAGE>20
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 is to have successfully identified, corrected and tested
its existing critical systems by July 1, 1999. The Company requires that all
new hardware or software acquired by the Company be vendor certified Year 2000
ready before it is installed.
On March 5, 1999, PacifiCorp announced that its domestic electric
operations were advancing the control system clocks and operating all thermal
generating units in the Year 2000 mode from now until the end of the first
quarter of the year 2000. The same procedure is taking place in the Company's
transmission and distribution systems and is one of the final steps to having
all critical systems ready for the Year 2000 by July 1, 1999.
A summary of the Company's progress to date in areas affected by Year
2000 issues is set forth in the following table:
<TABLE>
<CAPTION>
Remediation
Inventory Assessment and Testing
_________ __________ ___________
(% Completed)
<S> <C> <C> <C>
Electric Systems 100 100 76
Computer Systems
Central Applications
To Correct 100 100 100
Central Applications
To Replace 100 100 75
Desktop 100 100 45
</TABLE>
The Company's ability to maintain normal operations into the year 2000
will also be affected by Year 2000 readiness of third parties from whom the
Company purchases products and services or with whom the Company exchanges
information. As of January 25, 1999, the Company believes it had identified
100% of its critical third-party supplier relationships and requested that
these parties report their Year 2000 readiness. At March 31, 1999, the
critical third parties reported they would be Year 2000 ready on or before the
dates in the table below:
<TABLE>
<CAPTION>
Readiness Target Dates Percent of all Critical Third
(on or before) Parties Ready
<S> <C>
12/31/1998 14%
03/31/1999 19
06/30/1999 76
09/30/1999 91
12/31/1999 96
(no Readiness Target Date reported) 4
</TABLE>
The Company is in contact with these third parties and their Year 2000
readiness information is updated as required.
The Company is also in the process of identifying third parties that are
"super critical." An elevated Year 2000 readiness assessment, which includes a
<PAGE>21
site visit, will be performed for each of them. To date, two super critical
vendors have been identified. One vendor supplies chemical reagents used in
air emission control equipment at some generating plants. One week's supply
can be maintained. The plants would be able to generate power, but after a
week may not be able to meet air quality regulations. This vendor has advised
the Company that it will be Year 2000 ready by September 30, 1999. An on-site
assessment has been performed. The Company recently identified the second
critical vendor, which provides services to the Company. A review of this
vendor's Year 2000 project is scheduled for May 1999.
The Company has no single retail customer that accounts for more than
1.7% of its retail utility revenues and the 20 largest retail customers
account 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 drill on April 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 up to 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.
<PAGE>22
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. An emergency backup plan is being developed for deployment
by the third quarter of 1999 to enable third party off-site processing of
payments. 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 uses two systems to
maintain shareholder records, transfer stock, issue 1099 dividend statements
and process dividend payments. One system is certified ready now, and the
other is expected to be Year 2000 ready by June 30, 1999.
The Company has incurred $15.4 million in costs relating to the Year
2000 project through March 31, 1999. The majority of these costs have been
incurred to repair software problems. The total cost of the Year 2000 project
is estimated at $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
<PAGE>23
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 March 31, 1999 and
December 31, 1998 and for the three-month periods ended March 31, 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>24
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 March 31, 1999, and the related condensed
consolidated statements of income and retained earnings and cash flows for the
three-month periods ended March 31, 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,
consolidated changes in common shareholders' equity, and consolidated 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
May 10, 1999
<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.
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 of
awareness of incorporation by reference.
Exhibit 27: Financial Data Schedule for the quarter ended
March 31, 1999 (filed electronically only).
(b) Reports on Form 8-K.
On Form 8-K, dated May 9, 1999, under "Item 5. Other Events," the
Company filed a news release reporting financial results for the
three months ended March 31, 1999.
<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 May 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 of awareness of incorporation by reference.
Exhibit 27: Financial Data Schedule for the quarter
ended March 31, 1999 (filed electronically only).
</TABLE>
<PAGE>
<TABLE>
EXHIBIT (12)(a)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO FIXED CHARGES
<CAPTION>
Three Months
Ended
1994 1995 1996 1997 1998 March 31, 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 $ 88.0
Estimated interest portion of
rentals charged to expense........ 5.6 4.5 4.1 6.6 5.7 2.2
Preferred dividends of
wholly owned subsidiary........... - - 15.3 32.9 42.9 11.7
----------------------------------------------------------------
Total fixed charges............. $ 307.6 $ 340.9 $ 434.4 $ 477.6 $ 420.3 $101.9
================================================================
Earnings, as defined:*
Income from continuing operations... $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7 $149.2
Add (deduct):
Provision for income taxes........ 209.0 192.1 236.5 111.8 59.1 57.9
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 3.7
Fixed charges as above............ 307.6 340.9 434.4 477.6 420.3 101.9
----------------------------------------------------------------
Total earnings.................. $ 900.7 $ 921.8 $1,084.8 $ 813.0 $ 658.7 $312.7
================================================================
Ratio of Earnings to Fixed Charges.... 2.9x 2.7x 2.5x 1.7x 1.6x 3.1x
================================================================
<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>
Three Months
Ended
1994 1995 1996 1997 1998 March 31, 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 $ 88.0
Estimated interest portion of
rentals charged to expense........ 5.6 4.5 4.1 6.6 5.7 2.2
Preferred dividends of
wholly owned subsidiary........... - - 15.3 32.9 42.9 11.7
----------------------------------------------------------------
Total fixed charges............. $ 307.6 $ 340.9 $ 434.4 $ 477.6 $ 420.3 $101.9
Preferred Stock Dividends,
as defined:*...................... 60.8 57.2 46.2 33.8 29.5 7.8
----------------------------------------------------------------
Total fixed charges and
preferred dividends........... $ 368.4 $ 398.1 $ 480.6 $ 511.4 $ 449.8 $109.7
================================================================
Earnings, as defined:*
Income from continuing operations... $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7 $149.2
Add (deduct):
Provision for income taxes........ 209.0 192.1 236.5 111.8 59.1 57.9
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 3.7
Fixed charges as above............ 307.6 340.9 434.4 477.6 420.3 101.9
----------------------------------------------------------------
Total earnings.................. $ 900.7 $ 921.8 $1,084.8 $ 813.0 $ 658.7 $312.7
================================================================
Ratio of Earnings to Combined Fixed
Charges and Preferred Stock
Dividends........................... 2.4x 2.3x 2.3x 1.6x 1.5x 2.9x
================================================================
<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
May 10, 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
March 31, 1999 and 1998, as indicated in our report dated May 10, 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 March 31, 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>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S
FORM 10-Q DATED MARCH 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000075594
<NAME> PACIFICORP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7901100
<OTHER-PROPERTY-AND-INVEST> 1674000
<TOTAL-CURRENT-ASSETS> 1380800<F1>
<TOTAL-DEFERRED-CHARGES> 393400
<OTHER-ASSETS> 1292900
<TOTAL-ASSETS> 12642200
<COMMON> 3229600
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 738800
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3968400
175000
66400
<LONG-TERM-DEBT-NET> 4491800
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 80300
<LONG-TERM-DEBT-CURRENT-PORT> 236000
0
<CAPITAL-LEASE-OBLIGATIONS> 27200
<LEASES-CURRENT> 100
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3597000
<TOT-CAPITALIZATION-AND-LIAB> 12642200
<GROSS-OPERATING-REVENUE> 959800
<INCOME-TAX-EXPENSE> 57900
<OTHER-OPERATING-EXPENSES> 732300
<TOTAL-OPERATING-EXPENSES> 790200
<OPERATING-INCOME-LOSS> 169600
<OTHER-INCOME-NET> 9700
<INCOME-BEFORE-INTEREST-EXPEN> 179300
<TOTAL-INTEREST-EXPENSE> 88000
<NET-INCOME> 91300
4800
<EARNINGS-AVAILABLE-FOR-COMM> 86500
<COMMON-STOCK-DIVIDENDS> 80300
<TOTAL-INTEREST-ON-BONDS> 220400
<CASH-FLOW-OPERATIONS> 299800
<EPS-PRIMARY> 0.29
<EPS-DILUTED> 0.29
<FN>
<F1>CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED
OPERATIONS OF $175,000.
</FN>
</TABLE>
