<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 June 30, 1998
_____________
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.)
700 N.E. Multnomah
Suite 1600
Portland, Oregon 97232-4116
(Address of principal executive offices) (Zip code)
503-813-7200
(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 July 31, 1998, there were 297,268,561 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 1. Legal Proceedings 33
Item 4. Submission of Matters to a Vote of Security Holders 33
Item 5. Other Information 34
Item 6. Exhibits and Reports on Form 8-K 34
Signature 35
</TABLE>
<PAGE>2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
<TABLE>
PACIFICORP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Millions of Dollars, except per share amounts)
(Unaudited)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
__________________ _________________
1998 1997 1998 1997
______ ______ ______ ______
<S> <C> <C> <C> <C>
REVENUES $1,923.4 $1,219.5 $3,999.1 $2,261.3
_______ _______ _______ _______
EXPENSES
Operations and maintenance 1,560.0 776.0 3,159.6 1,350.7
Depreciation and amortization 117.0 114.7 233.7 224.0
Administrative and general 88.2 81.1 167.4 150.1
Taxes, other than income taxes 25.5 26.4 53.1 53.8
Special charges - - 113.1 -
_______ _______ _______ _______
TOTAL 1,790.7 998.2 3,726.9 1,778.6
_______ _______ _______ _______
INCOME FROM OPERATIONS 132.7 221.3 272.2 482.7
_______ _______ _______ _______
INTEREST EXPENSE AND OTHER
Interest expense 94.0 112.7 188.3 218.7
Interest capitalized (3.7) (3.4) (7.0) (6.2)
Other (income)/expense - net (13.2) (4.3) 65.5 (4.9)
_______ _______ _______ _______
TOTAL 77.1 105.0 246.8 207.6
_______ _______ _______ _______
Income from continuing operations
before income taxes 55.6 116.3 25.4 275.1
Income tax expense/(benefit) 14.8 40.6 (0.3) 96.7
_______ _______ _______ _______
Income from continuing operations 40.8 75.7 25.7 178.4
Discontinued Operations (less applicable
income tax expense: 1997/$12.3
and $25.2 - 19.1 - 37.4
_______ _______ _______ _______
NET INCOME 40.8 94.8 25.7 215.8
RETAINED EARNINGS BEGINNING OF PERIOD 1,006.6 818.4 1,106.3 782.8
Cash dividends declared
Preferred stock (4.3) (5.5) (8.6) (11.1)
Common stock per share of $0.27 (80.3) (80.0) (160.6) (159.8)
_______ _______ _______ _______
RETAINED EARNINGS END OF PERIOD $ 962.8 $ 827.7 $ 962.8 $ 827.7
======= ======= ======= =======
EARNINGS ON COMMON STOCK $ 36.0 $ 88.7 $ 16.1 $ 203.6
Average number of common shares
outstanding - Basic (Thousands) 297,259 295,901 297,160 295,648
Dilutive (Thousands) 297,259 295,901 297,212 295,648
EARNINGS PER COMMON SHARE -
Basic and dilutive
Continuing operations $ 0.12 $ 0.24 $ 0.05 $ 0.56
Discontinued operations - 0.06 - 0.13
_______ _______ _______ _______
TOTAL $ 0.12 $ 0.30 $ 0.05 $ 0.69
======= ======= ======= =======
<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>
Six Months Ended
June 30,
______________________
1998 1997
______ ______
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 25.7 $ 215.8
Adjustments to reconcile net income to
net cash provided by operating activities
Income from discontinued operations - (37.4)
Depreciation and amortization 237.6 232.3
Deferred income taxes and investment tax
credits - net (63.0) 21.2
Special charges 113.1 -
Other 91.6 (6.1)
Accounts receivable and prepayments 186.6 (11.3)
Materials, supplies and fuel stock (36.2) (12.5)
Accounts payable and accrued liabilities (215.2) 3.0
______ ______
Net cash provided by continuing operations 340.2 405.0
Net cash used in discontinued operations (304.0) (12.9)
______ ______
NET CASH PROVIDED BY OPERATING ACTIVITIES 36.2 392.1
______ ______
CASH FLOWS FROM INVESTING ACTIVITIES
Construction (276.1) (278.3)
Investments in and advances to
affiliated companies - net (19.7) (32.9)
Operating companies and assets acquired (38.6) (281.5)
Proceeds from sales of finance assets, real
estate investments and principal payments 315.2 30.6
Other (14.8) (25.5)
______ ______
NET CASH USED IN INVESTING ACTIVITIES (34.0) (587.6)
______ ______
CASH FLOWS FROM FINANCING ACTIVITIES
Changes in short-term debt 34.6 (85.1)
Proceeds from long-term debt 728.4 735.2
Proceeds from issuance of common stock 8.5 20.8
Dividends paid (168.5) (170.5)
Repayments of long-term debt (744.8) (245.9)
Redemptions of preferred stock - (3.0)
Other 37.9 (51.1)
______ ______
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (103.9) 200.4
______ ______
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (101.7) 4.9
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 741.3 8.4
______ ______
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 639.6 $ 13.3
====== ======
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for
Interest (net of amount capitalized) $ 225.8 $ 251.0
Income taxes 482.7 96.4
<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>
June 30, December 31,
1998 1997
________ ____________
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 639.6 $ 741.3
Accounts receivable less allowance
for doubtful accounts: 1998/$15.4
and 1997/$18.8 846.2 919.5
Materials, supplies and fuel stock at
average cost 252.2 194.3
Real estate investments held for sale - 272.2
Other 37.4 55.0
________ ________
TOTAL CURRENT ASSETS 1,775.4 2,182.3
PROPERTY, PLANT AND EQUIPMENT
Domestic Electric Operations 12,283.9 12,094.6
Australian Electric Operations 1,094.3 1,161.2
Other Operations 57.6 56.9
Accumulated depreciation and amortization (4,422.9) (4,242.4)
________ ________
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 9,012.9 9,070.3
OTHER ASSETS
Investments in and advances to affiliated
companies 270.4 281.6
Intangible assets - net 496.9 524.9
Regulatory assets - net 854.9 871.1
Finance note receivable 208.3 211.2
Finance and real estate assets - net 378.5 349.8
Deferred charges and other 305.2 389.0
________ ________
TOTAL OTHER ASSETS 2,514.2 2,627.6
________ ________
TOTAL ASSETS $13,302.5 $13,880.2
======== ========
<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>
June 30, December 31,
1998 1997
________ ____________
<S> <C> <C>
CURRENT LIABILITIES
Long-term debt currently maturing $ 313.9 $ 365.5
Notes payable and commercial paper 223.8 189.2
Accounts payable 621.7 630.7
Taxes, interest and dividends payable 315.8 701.2
Customer deposits and other 190.6 218.9
________ ________
TOTAL CURRENT LIABILITIES 1,665.8 2,105.5
DEFERRED CREDITS
Income taxes 1,586.1 1,676.1
Investment tax credits 131.2 135.2
Other 726.3 646.2
________ ________
TOTAL DEFERRED CREDITS 2,443.6 2,457.5
LONG-TERM DEBT 4,437.4 4,414.5
COMMITMENTS AND CONTINGENCIES (See Notes 4 and 5) - -
GUARANTEED PREFERRED BENEFICIAL INTERESTS
IN COMPANY'S JUNIOR SUBORDINATED DEBENTURES 340.4 340.4
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: 1998/297,262,897
and 1997/296,908,110 3,283.1 3,274.2
Retained earnings 962.8 1,106.3
Accumulated other comprehensive loss (72.0) (59.6)
________ ________
TOTAL COMMON EQUITY 4,173.9 4,320.9
________ ________
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $13,302.5 $13,880.2
======== ========
<FN>
See accompanying Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 1998
1. FINANCIAL STATEMENTS
The accompanying unaudited condensed consolidated financial statements as
of June 30, 1998 and December 31, 1997 and for the periods ended June 30, 1998
and 1997, 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
June 30, 1998 and 1997 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 incorporated by
reference in the Company's 1997 Annual Report on Form 10-K.
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;
PacifiCorp Financial Services, Inc. ("PFS"), a financial services business;
PacifiCorp Power Marketing, Inc. ("PPM"), engaged in wholesale electricity
trading in the eastern United States energy markets; and TPC Corporation
("TPC"), a natural gas marketing and storage company, purchased April 15,
1997. Together these businesses are referred to herein as the Companies.
Significant intercompany transactions and balances have been eliminated.
The Company sold its wholly owned telecommunications subsidiary, Pacific
Telecom, Inc. ("PTI"), on December 1, 1997. See Note 3. The Company sold
Pacific Generation Company ("PGC") on November 5, 1997, and the natural gas
gathering and processing assets of TPC on December 1, 1997. During May 1998,
a majority of the real estate assets held by PFS were sold.
Investments in and advances to affiliated companies represent investments
in unconsolidated affiliated companies carried on the equity basis, which
approximates the Company's equity in their underlying net book value.
Certain amounts have been reclassified to conform with the 1998 method of
presentation. These reclassifications had no effect on previously reported
consolidated net income.
2. BID FOR THE ENERGY GROUP
During 1997 and 1998, the Company sought to acquire The Energy Group PLC
("TEG"), a diversified international energy group with operations in the
United Kingdom, the United States and Australia. The Company made three
tender offers for TEG. The last offer was valued at $11.1 billion, including
the assumption
<PAGE>7
of $4.1 billion of TEG's debt. In March 1998, Texas Utilities Company made a
tender offer at a higher price. On April 30, 1998, the Company announced that
it would not increase its revised offer for TEG on the basis that a price in
excess of 820 pence per share would not have provided acceptable financial
returns for PacifiCorp shareholders.
The Company recorded an $86 million pretax charge to first quarter 1998
earnings, included in "Other (income)/expense-net," for bank commitment and
facility fees, legal expenses and other related costs incurred since the
Company's original bid for TEG in June of 1997. These costs had been deferred
pending the outcome of the transaction.
Additionally, in connection with the attempt to acquire TEG, a subsidiary
of the Company purchased approximately 46 million shares of TEG at a price of
820 pence per share, or $625 million. The Company recorded a gain on the TEG
shares of $10 million when they were sold on June 2, 1998. In addition, the
Company incurred a pretax loss of $3 million in April 1998 in connection with
closing its foreign currency option contract associated with the bid for TEG.
3. DISCONTINUED OPERATIONS
On December 1, 1997, Holdings completed the sale of PTI for $1.5 billion
in cash plus the assumption of PTI's debt of $713 million. A portion of the
proceeds from the sale of PTI were used to repay short-term debt of Holdings.
The remaining proceeds were invested in short-term money market instruments
and Holdings temporarily advanced excess funds to Domestic Electric Operations
for retirement of short-term debt.
Summarized operating results for PTI were as follows:
<TABLE>
<CAPTION>
Three-Month Six-Month
Period Ended Period Ended
June 30, June 30,
____________ ____________
1997 1997
______ ______
(Dollars in Millions)
<S> <C> <C>
Revenues $134.2 $262.2
_____ _____
Income before income taxes $ 31.4 $ 62.6
Income taxes 12.3 25.2
_____ _____
Net income $ 19.1 $ 37.4
===== =====
</TABLE>
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
<PAGE>8
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.
During 1997, the Utah Public Service Commission (the "PSC") held hearings
on the proper method to be used in allocating costs among the Company's seven
jurisdictions that resulted in an order issued on April 16, 1998. Under the
order, differences in allocations associated with the merger of Pacific Power
and Utah Power will be eliminated over five years on a straight-line basis.
The phase-out of the differences is to be completed by January 1, 2001 and
could reduce Utah prices by approximately $50 million to $60 million per year
once fully implemented. The order itself will not decrease revenues, but is
being included in a general rate case for the overall determination of revenue
requirement by the PSC and will be combined with other cost increases and
decreases to determine the overall impact to customer rates.
In the pending rate case filed on June 1, 1998, the Utah Division of
Public Utilities (the "DPU") proposed adjustments that could result in a $57
million annualized reduction in customer prices. This includes approximately
$21 million of the allocation phase-in. The Committee of Consumer Services
proposed adjustments in the rate case that could reduce customer prices
annually by $79 million, including $21 million relating to the allocation
phase-in. The Company requested no change in customer prices and proposed a
new authorized rate of return on equity of 11.25%. Any required adjustment to
customer prices could be retroactive to February 1997, the date a petition was
filed by the DPU with the PSC requesting a general rate case. If the PSC
approved the DPU proposal in December 1998 and ordered the adjustment to be
retroactive to February 1997, the Company would have collected approximately
$109 million of revenues subject to refund. An adjustment to 1998 earnings of
approximately $68 million would be required when the order was issued and the
amount was determinable. The rate case is expected to be heard by the PSC in
October 1998, with a final order expected by year end. The Company has
announced it will not appeal the Utah allocation order.
On July 9, 1998, the Company announced its intent to seek buyers for its
California and Montana electric distribution assets. This action was in
response to the continued decline in earnings on the assets and changes in the
legislative and regulatory environments, including fixing prices, in these
states where the Company has few distribution properties. The Company issued
requests for proposals to interested parties on July 20, 1998.
In December 1997, the California Public Utilities Commission issued an
order with respect to the Company's filing concerning transition to direct
access requirements enacted in that state. The order mandated a 10% rate
reduction effective January 1, 1998, which would result in a $3.5 million
annual reduction in revenues. The Company has requested a rehearing of this
issue. A referendum slated for the November ballot may require all investor
owned utilities to provide an additional 10% reduction for customers.
An interim order was issued on July 1 by the Montana Public Service
Commission addressing issues necessary to allow larger customers direct access
to other suppliers. Hearings on the remaining issues were originally
scheduled
<PAGE>9
to begin August 25 but have been indefinitely postponed because of the
Company's intent to offer its Montana service territory for sale.
The Oregon Public Utility Commission and the Company have agreed to an
Alternate Form of Regulation ("AFOR") for the Company's Oregon distribution
business. The AFOR allows for index-related price increases in 1998, 1999 and
2000, with an annual cap of 2% of distribution revenues in any one year and an
overall cap of 5% over the three-year period. The estimated revenue increase
in 1998 is approximately $6.9 million. The AFOR also includes incentives to
invest in renewable resources and penalties for failure to maintain the
service quality levels.
The Company continues to evaluate the impact of all changes in regulation
and legislation in the context of its regulatory strategy. Changes in
regulatory environment may significantly affect the Company's future financial
condition, results of operations and cash flows.
5. CONTINGENT LIABILITIES
The Company and its subsidiaries are parties to various legal claims,
actions and complaints, certain of which involve material amounts. Although
the Company is unable to predict with certainty whether or not it will
ultimately be successful in these legal proceedings or, if not, what the
impact might be, management currently believes that disposition of these
matters will not have a materially adverse effect on the Company's
consolidated financial statements.
6. COMPREHENSIVE INCOME
Effective January 1, 1998, the Company adopted SFAS No. 130, "Reporting
Comprehensive Income." This statement requires items previously reported as a
component of common equity be more prominently reported in a separate
financial statement as a component of comprehensive income.
The components of comprehensive income are as follows:
<TABLE>
<CAPTION>
Three-Month Six-Month
Periods Ended Periods Ended
June 30, June 30,
_________________ ________________
1998 1997 1998 1997
______ ______ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Net income $ 40.8 $ 94.8 $ 25.7 $215.8
Other comprehensive income
Foreign currency translation
adjustment, net of taxes:
1998/$(20.9) and $(11.8),
1997/$(16.6) and $(18.7) (32.5) (25.9) (19.5) (29.2)
Unrealized gain on available-
for-sale securities, net of
taxes: 1998/$4.3 7.1 - 7.1 -
Reclassification adjustments for
gains included in net income,
net of taxes: 1998/$4.6 (7.2) - - -
_____ _____ _____ _____
Total comprehensive income $ 8.2 $ 68.9 $ 13.3 $186.6
===== ===== ===== =====
</TABLE>
<PAGE>10
7. NEW ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board (the "FASB")
issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information." SFAS No. 131 requires that companies disclose segment data
based on how management makes decisions about allocating resources to segments
and measuring performance. This standard is effective for fiscal years
beginning after December 15, 1997. Adoption of this standard may result in
additional financial disclosure but will not have an effect on the Company's
financial position or results of operations.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
About Pensions and Other Postretirement Benefits." This statement, which is
effective for fiscal years beginning after December 15, 1997, revises
employers' disclosures about pension and other postretirement benefit plans.
Adoption of this standard will not change the measurement of the liability nor
recognition of expense of these plans.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement, which is effective for
fiscal years beginning after June 15, 1999, requires an entity to recognize
all derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. Adoption of this
standard will have an effect on the Company's financial position and results
of operations. The magnitude of the effect will be determined by the hedges
and derivatives that the Company has in place at the adoption of the standard.
The effects in future periods will be dependent upon the derivatives and
hedges in place at the end of each period.
<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 1997 Annual Report on Form 10-K. Such forward-looking statements
should be considered in light of those factors.
Comparison of the three-month periods ended June 30, 1998 and 1997
__________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss) on
common stock (1)
Domestic Electric Operations $ 52.9 $ 62.2 $ (9.3) (15)
Australian Electric Operations 6.6 8.1 (1.5) (19)
Unregulated Energy Trading (38.1) (1.9) (36.2) *
Other Operations 14.6 1.2 13.4 *
_____ _____ ______
Continuing Operations 36.0 69.6 (33.6) (48)
Discontinued Operations (2) - 19.1 (19.1) (100)
_____ _____ ______
Total $ 36.0 $ 88.7 $ (52.7) (59)
===== ===== ======
Earnings per common share - Basic
and dilutive
Continuing Operations $ 0.12 $ 0.24 $ (0.12) (50)
Discontinued Operations (2) - 0.06 (0.06) (100)
_____ _____ ______
Total $ 0.12 $ 0.30 $ (0.18) (60)
===== ===== ======
<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) amounts
are net of preferred dividend requirements and minority interest.
(2) Represents the discontinued operations of PTI.
</FN>
</TABLE>
The Company recorded earnings on common stock of $36 million, or $0.12 per
share, in the second quarter of 1998 compared to $89 million, or $0.30 per
share, in 1997. Second quarter 1997 results included earnings of $19 million,
or $0.06 per share, from the Company's telecommunications operations that were
sold in December of 1997. Second quarter 1998 results included after-tax
charges of $20 million, or $0.07 per share, for reserves for probable credit
losses and $6 million, or $0.02 per share, for known and probable future
trading losses.
<PAGE>12
Domestic Electric Operations earnings contribution was $53 million, or $0.18
per share, as compared to $62 million, or $0.21 per share, in the second
quarter of 1997. Income from operations declined $16 million, or 9%, to
$168 million. Lower wholesale margins in the West, less favorable
hydroelectric conditions, higher depreciation and costs related to Year 2000
issues and implementation of a new SAP software operating environment
contributed to the decrease in operating income.
The Company's Australian Electric Operations contributed earnings of
$7 million, or $0.02 per share, in the second quarter of 1998, compared to
$8 million, or $0.03 per share in 1997. Earnings in the quarter were reduced
by $1 million as the result of unfavorable fluctuations in the currency
exchange rate. Excluding the impact of currency exchange rate fluctuations,
the Company's Australian Electric Operations earnings remained flat when
compared to the second quarter in 1997.
The unregulated energy trading segment reported losses of $38 million in the
quarter as compared to a $2 million loss in the second quarter of 1997.
Second quarter 1998 results included after-tax charges of $20 million, or
$0.07 per share, for reserves for probable credit losses and $6 million, or
$0.02 per share, for known and probable future trading losses. These losses
were a result of extreme price volatility in power markets in the eastern U.S.
during the quarter.
Other operations reported earnings of $15 million in the quarter compared to
earnings of $1 million in 1997. This increase was primarily due to an after-
tax gain of $10 million recorded on the sale of The Energy Group PLC ("TEG")
shares acquired in March 1998.
Comparison of the six-month periods ended June 30, 1998 and 1997
________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss) on
common stock
Domestic Electric Operations $ 58.5 $136.8 $ (78.3) (57)
Australian Electric Operations 20.7 29.1 (8.4) (29)
Unregulated Energy Trading (38.6) (2.9) (35.7) *
Other Operations (24.5) 3.2 (27.7) *
_____ _____ ______
Continuing Operations 16.1 166.2 (150.1) (90)
Discontinued Operations - 37.4 (37.4) (100)
_____ _____ ______
Total $ 16.1 $203.6 $(187.5) (92)
===== ===== ======
Earnings per common share - Basic
and dilutive
Continuing Operations $ 0.05 $ 0.56 $ (0.51) (91)
Discontinued Operations - 0.13 (0.13) (100)
_____ _____ ______
Total $ 0.05 $ 0.69 $ (0.64) (93)
===== ===== ======
<FN>
*Not a meaningful number.
</FN>
</TABLE>
<PAGE>13
The Company recorded earnings on common stock of $16 million, or $0.05 per
share, in 1998 compared to $204 million, or $0.69 per share, in 1997. The
1998 results included an after-tax charge of $70 million, or $0.24 per share,
associated with the Company's work force reduction in the United States, an
after-tax charge of $54 million, or $0.18 per share, associated with the
Company's terminated bid for TEG, after-tax charges of $6 million, or $0.02
per share, for known and probable future trading losses and $20 million, or
$0.07 per share, for reserves for probable credit losses. The 1997 results
included earnings of $37 million, or $0.13 per share, from the Company's
telecommunications operations that were sold in December of 1997.
Domestic Electric Operations earnings contribution was $59 million, or $0.20
per share, in 1998. Excluding the $70 million charge relating to the work
force reduction, the earnings contribution would have been $129 million as
compared to $136 million in 1997. Lower wholesale margins in the West, less
favorable hydroelectric conditions, higher depreciation and costs related to
Year 2000 issues and implementation of a new SAP software operating
environment contributed to the decrease in operating income.
The Company's Australian Electric Operations contributed earnings of $21
million, or $0.07 per share, in 1998, compared to $29 million, or $0.10 per
share, in 1997. Earnings were reduced by $4 million as the result of
unfavorable fluctuations in the currency exchange rate. Earnings in 1997 were
benefited by adjustments totaling $7 million associated with the renegotiation
of certain Tariff H industrial customers contracts while 1998 was only
benefited $3 million for similar contracts.
The unregulated energy trading segment reported losses of $39 million as
compared to a $3 million loss in 1997. The 1998 results included after-tax
charges of $20 million, or $0.07 per share, for reserves for probable credit
losses and $6 million, or $0.02 per share, for known and probable future
trading losses. These losses were a result of extreme price volatility in
power markets in the eastern U.S. during the second quarter.
Other operations reported a loss of $25 million compared to earnings of
$3 million in 1997. This decrease was primarily due to an after-tax charge of
$54 million for costs associated with the Company's terminated bid for TEG,
partially offset by an after-tax gain of $10 million recorded in June 1998 on
the sale of TEG shares acquired in March 1998.
<PAGE>14
RESULTS OF OPERATIONS
Domestic Electric Operations
____________________________
Comparison of the three-month periods ended June 30, 1998 and 1997
__________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Revenues
Residential $ 174.7 $ 171.4 $ 3.3 2
Commercial 160.4 156.0 4.4 3
Industrial 176.0 180.9 (4.9) (3)
Other 7.7 8.2 (0.5) (6)
_______ _______ _______
Retail sales 518.8 516.5 2.3 -
Wholesale sales and
market trading 495.7 254.4 241.3 95
Other 17.1 20.5 (3.4) (17)
_______ _______ _______
Total 1,031.6 791.4 240.2 30
Operating expenses 863.6 607.5 256.1 42
_______ _______ _______
Income from operations 168.0 183.9 (15.9) (9)
Interest expense 81.8 80.1 1.7 2
Minority interest and other (4.2) (5.8) 1.6 28
Income taxes 32.7 41.3 (8.6) 21
_______ _______ _______
Net income 57.7 68.3 (10.6) (16)
Preferred dividend requirement 4.8 6.1 (1.3) (21)
_______ _______ _______
Earnings contribution $ 52.9 $ 62.2 $ (9.3) (15)
======= ======= =======
Energy sales (millions of kWh)
Residential 2,705 2,635 70 3
Commercial 2,924 2,838 86 3
Industrial 5,086 5,155 (69) (1)
Other 160 193 (33) (17)
______ ______ ______
Retail sales 10,875 10,821 54 -
Wholesale sales and
market trading 22,349 11,862 10,487 88
______ ______ ______
Total 33,224 22,683 10,541 46
====== ====== ======
Residential average usage (kWh) 2,185 2,182 3 -
Total customers (end of period) 1,451,503 1,418,578 32,925 2
</TABLE>
Revenues
Domestic Electric Operations revenues increased $240 million, or 30%. This
increase was primarily attributable to a $241 million increase in wholesale
revenues.
Wholesale volumes continued to expand with the active markets. The $241
million increase in revenues was driven by energy volumes that nearly doubled
in 1998 to a total of 22.3 million mWh. Higher short-term and spot market
wholesale energy volumes increased revenues by $212 million. Related energy
prices averaged $19 per mWh in the quarter, a 27% increase over the prior
year. The higher prices for these sales added $29 million to revenues in the
quarter.
<PAGE>15
Residential revenues and energy volumes were up $3 million and 3%,
respectively. Growth in the average number of residential customers of 3%
added $4 million to revenues. This increase was partially offset by volume
decreases due to decreased customer usage, which lowered revenues by
$1 million.
Commercial revenues were up $4 million, or 3%. Energy sales volumes increased
3% over the prior year. Growth in the average number of customers of 2% added
$4 million to revenues.
Industrial revenues decreased $5 million, or 3%. Mild weather and planting
conditions reduced irrigation revenues by $5 million.
The Company's general rate case in Utah is expected to be heard in October
1998. Parties in the case have proposed adjustments that would result in
significant reductions in prices and could require a material reduction to
1998 earnings for revenues collected subject to refund. Regulatory changes
have also occurred in other states in which the Company operates. See Note 4
to the Condensed Consolidated Financial Statements for additional information
concerning pending regulatory proceedings and developments.
The Company continues to evaluate the accounting impact of all changes in
regulation in the context of its regulatory strategy. Changes in regulatory
structure may significantly affect the Company's future financial condition
and results of operations.
Operating Expenses
Total operating expenses increased $256 million, or 42%. This increase was
primarily attributable to increased purchased power expense to serve the
expanding wholesale market.
Purchased power expense increased $251 million, to $467 million. The higher
expense was primarily due to a 10.6 million mWh increase in short term firm
and spot market energy purchases, more than double the amount of purchases in
the same period of 1997, which increased purchased power expense $226 million.
Short-term firm and spot market purchase prices averaged $19 per mWh in the
quarter versus $13 per mWh in 1997, a 43% increase. The increase in purchase
prices added $22 million to costs. Higher volumes and lower prices relating
to long-term firm purchased power contracts added $2 million to purchased
power costs.
Fuel expense was up $1 million, or 1%, to $99 million. Thermal generation
increased 3% to 11.1 million mWh, resulting in a decrease of 1% in the average
cost per mWh to $8.91. Hydroelectric generation decreased 10% compared to the
second quarter of last year due to less favorable water conditions.
Net power costs in the quarter were $6.56 per mWh, compared to $5.54 per mWh
in the second quarter of 1997, an 18% increase, or $11 million, in operating
costs. Net power cost represents the net cost to serve the Company's domestic
retail customers on a mWh basis. This is measured by the sum of fuel,
purchased power and wheeling expense, less wholesale power and wheeling
revenues. The increase in net power cost was attributable to increased
thermal generation and decreased gross margin on wholesale sales. Thermal
generation increased as a result of the reduced availability of hydroelectric
generation and low cost purchased power.
<PAGE>16
Gross margin on wholesale sales decreased as existing long term wholesale
contracts were replaced with new long term contracts at lower prices.
Other operations and maintenance expense decreased $12 million, or 9%, to
$115 million. Pension expense decreased $5 million due to amortization cost
decreases relating to deferred regulatory pension assets that were written off
in December 1997 and the implementation of the early retirement plan initiated
in the first quarter of 1998. Steam plant maintenance expense decreased $3
million due to overhaul timing differences. Distribution plant maintenance
expense decreased $2 million due to recognition of storm damage expense in
1997.
Depreciation and amortization expense increased $8 million, or 8%, to
$99 million. Higher depreciation rates that were implemented in the fourth
quarter of 1997 added $4 million to expense and increased plant in service
added $4 million.
Administrative and general expenses increased $9 million, or 11%, to $85
million. This increase included $4 million of expenses relating to Year 2000
issues, $2 million related to the Company's new SAP software operating
environment and $2 million of employee related costs.
Other Income and Expense
Interest expense increased $2 million as a result of higher debt balances.
Income tax expense decreased $8 million due to the decline in pretax income.
<PAGE>17
Comparison of the six-month periods ended June 30, 1998 and 1997
________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Revenues
Residential $ 406.5 $ 404.5 $ 2.0 -
Commercial 321.8 306.2 15.6 5
Industrial 338.7 335.9 2.8 1
Other 15.3 16.0 (0.7) (4)
_______ _______ _______
Retail sales 1,082.3 1,062.6 19.7 2
Wholesale sales and
market trading 994.8 484.1 510.7 105
Other 31.5 37.9 (6.4) (17)
_______ _______ _______
Total 2,108.6 1,584.6 524.0 33
Operating expenses 1,844.8 1,204.0 640.8 53
_______ _______ _______
Income from operations 263.8 380.6 (116.8) (31)
Interest expense 161.8 154.2 7.6 5
Minority interest and other (6.9) (13.1) 6.2 47
Income taxes 40.8 90.5 (49.7) (55)
_______ _______ _______
Net income 68.1 149.0 (80.9) (54)
Preferred dividend requirement 9.6 12.2 (2.6) (21)
_______ _______ _______
Earnings contribution $ 58.5 $ 136.8 $ (78.3) (57)
======= ======= =======
Energy sales (millions of kWh)
Residential 6,456 6,462 (6) -
Commercial 5,916 5,622 294 5
Industrial 9,977 9,900 77 1
Other 319 362 (43) (12)
______ ______ ______
Retail sales 22,668 22,346 322 1
Wholesale sales and
market trading 44,792 22,102 22,690 103
______ ______ ______
Total 67,460 44,448 23,012 52
====== ====== ======
Residential average usage (kWh) 5,225 5,366 (141) (3)
Total customers (end of period) 1,451,503 1,418,578 32,925 2
</TABLE>
Revenues
Total Domestic Electric Operations revenues increased $524 million, or 33%.
This increase was primarily attributable to a $511 million increase in
wholesale revenues.
Wholesale volumes continued to expand with the active markets. The $511
million increase in revenues was driven by energy volumes that more than
doubled in 1998 to a total of 44.8 million mWh. Higher short-term and spot
market wholesale energy volumes increased revenues by $451 million. Related
energy prices averaged $20 per mWh, a 26% increase over the prior year. The
higher prices for these sales added $50 million to revenues. Higher long-term
prices partially offset by lower long-term volumes added $10 million to
revenues.
Residential revenues were up $2 million. Growth in the average number of
residential customers of 3% added $10 million to revenues. This increase was
<PAGE>18
partially offset by volume decreases due to decreased customer usage, which
lowered revenues by $7 million, and price decreases which lowered revenues by
$1 million.
Commercial revenues were up $16 million, or 5%. Energy sales volumes
increased 5% over the prior year. Growth in the average number of customers
of 2% added $8 million to revenues and increased customer usage added
$8 million to revenues.
Industrial revenues increased $3 million, or 1%. A 1% increase in energy
sales increased revenues $4 million. Mild weather and planting conditions
reduced irrigation revenues by $5 million. Revenues in 1997 were reduced by
billing adjustments of $3 million for certain industrial customers.
Operating Expenses
Total operating expenses increased $641 million, or 53%. This increase was
primarily attributable to increased purchased power expense to serve the
expanding wholesale market and the $113 million pretax cost for the work force
reduction.
Purchased power expense increased $505 million, to $926 million. The higher
expense was primarily due to a 21.2 million mWh increase in short term firm
and spot market energy purchases, more than double the amount of purchases in
the same period of 1997, which increased purchased power expense $459 million.
Short-term firm and spot market purchase prices averaged $19 per mWh in 1998
versus $14 per mWh in 1997, a 41% increase. The increase in purchase prices
added $35 million to costs. Higher volumes and prices relating to long-term
firm purchased power contracts added $9 million to purchased power costs.
Fuel expense was up $7 million, or 3%, to $221 million. Thermal generation
increased 8% to 24.4 million mWh, resulting in a decrease of 4% in the
average cost per mWh to $9.05. Hydroelectric generation decreased 8% due to
less favorable water conditions.
Net power costs were $6.84 per mWh, compared to $6.80 per mWh in 1997, a 1%
increase, or $3 million, in operating costs. Net power cost represents the
net cost to serve the Company's domestic retail customers on a mWh basis.
This is measured by the sum of fuel, purchased power and wheeling expense,
less wholesale power and wheeling revenues. Thermal generation increased as a
result of the reduced availability of hydroelectric generation and low cost
purchased power. Gross margin on wholesale sales decreased as existing long-
term wholesale contracts were replaced with new long-term contracts at lower
prices.
Other operations and maintenance expense decreased $15 million, or 6%, to
$225 million. Pension expense decreased $10 million due to amortization cost
decreases relating to deferred regulatory pension assets that were written off
in December 1997 and the implementation of the early retirement plan initiated
in the first quarter of 1998. Steam plant maintenance expense decreased
$4 million due to overhaul timing differences. Distribution plant maintenance
expense decreased $2 million due to recognition of storm damage expense in
1997.
Depreciation and amortization expense increased $17 million, or 9%, to
$197 million. Higher depreciation rates that were implemented in the fourth
<PAGE>19
quarter of 1997 added $9 million to expense and increased plant in service
added $8 million.
Administrative and general expenses increased $14 million, or 9%, to
$163 million. This increase includes $4 million of expenses relating to Year
2000 issues, $2 million related to the Company's new SAP software operating
environment and $8 million of employee related costs.
Other Income and Expense
Interest expense increased $8 million to $162 million as a result of higher
debt balances. Income tax expense decreased $50 million due to the decline in
pretax income.
<PAGE>20
Australian Electric Operations
______________________________
Comparison of the three-month periods ended June 30, 1998 and 1997
__________________________________________________________________
<TABLE>
<CAPTION>
Change Due Change % Change
to Currency Due to Due to
1998 1997 Translation Operations Operations
____ ____ ___________ __________ __________
(Dollars in Millions)
<S> <C> <C> <C> <C> <C>
Powercor Earnings Contribution
Revenues
Powercor area $112.3 $137.8 $(25.1) $ (0.4) -
Outside Powercor area
Victoria 20.0 26.3 (4.5) (1.8) (7)
New South Wales 16.9 7.9 (3.7) 12.7 *
_____ _____ _____ _____
149.2 172.0 (33.3) 10.5 6
Other 7.9 6.1 (1.8) 3.6 59
_____ _____ _____ _____
Total 157.1 178.1 (35.1) 14.1 8
Operating expenses 127.6 150.8 (28.6) 5.4 4
_____ _____ _____ _____
Income from operations 29.5 27.3 (6.5) 8.7 32
Interest expense 14.4 16.2 (3.3) 1.5 9
Equity in (income)/losses
of Hazelwood 1.2 (0.5) (0.3) 2.0 *
Other (income)/expense 3.4 (0.4) (0.8) 4.6 *
Income taxes 3.9 3.9 (0.8) 0.8 20
_____ _____ _____ _____
Earnings contribution $ 6.6 $ 8.1 $ (1.3) $ (0.2) 2
===== ===== ===== =====
Powercor energy sales (millions of kWh)
Powercor area 1,867 1,809 58 3
Outside Powercor area
Victoria 590 541 49 9
New South Wales 508 257 251 98
_____ _____ _____
Total 2,965 2,607 358 14
===== ===== =====
</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 second quarter of 1998 as compared to 0.77 in 1997, an 18%
decrease. The effect of this change in exchange rates lowered revenues by $35
million and costs by $34 million in the second quarter of 1998.
The following discussion does not include the effects of the lower currency
exchange rates in 1998.
Revenue
Australia's revenues increased $14 million, or 8%. The increase was partially
attributable to increased energy sales volumes of 358 million kWh, or 14%,
which added $20 million to revenues. Declining prices reduced revenues by
$9 million.
Energy volumes sold to contestable customers outside Powercor's franchise area
were up 300 million kWh and added $13 million to revenues due to customer
gains
<PAGE>21
in New South Wales and $2 million due to customer gains in Victoria. Lower
prices for these sales reduced revenues by $4 million in 1998. Inside
Powercor's franchise area, revenues remained flat as a revenue increase of
$5 million due to increased volumes of 58 million kWh was offset by $6 million
in lower revenues due to price decreases.
Other revenues increased $4 million largely due to $3 million associated with
Tariff H contracts.
Operating Expenses
Purchased power expense decreased $2 million, or 3%, to $68 million. Lower
average prices reduced power costs by $14 million. Prices for purchased power
averaged $25 per mWh in the second quarter of 1998 compared to $29 per mWh in
the second quarter of 1997 due to competition. The decrease was offset in
part by a 13% increase in purchased power volumes that added $12 million to
costs.
Other operating expenses increased $8 million, or 17%, to $45 million.
Increased sales by Powercor to contestable customers outside the Powercor
service area resulted in higher network fees of $11 million. This increase
was offset in part by higher network revenues of $2 million from customers
inside Powercor's franchise area serviced by other energy suppliers.
Other Income and Expense
Other expense increased $5 million primarily due to a reserve relating to a
product recall. Powercor is in the process of negotiating recovery from the
manufacturer.
Equity losses in Hazelwood increased $2 million over the second quarter in
1997 primarily due to a planned outage and increased maintenance costs for one
of the power station units during April and May of 1998.
<PAGE>22
Comparison of the six-month periods ended June 30, 1998 and 1997
________________________________________________________________
<TABLE>
<CAPTION>
Change Due Change % Change
to Currency Due to Due to
1998 1997 Translation Operations Operations
____ ____ ___________ __________ __________
(Dollars in Millions)
<S> <C> <C> <C> <C> <C>
Powercor Earnings Contribution
Revenues
Powercor area $228.8 $278.7 $(45.0) $ (4.9) (2)
Outside Powercor area
Victoria 40.9 49.3 (8.1) (0.3) (1)
New South Wales 37.1 9.7 (7.2) 34.6 *
_____ _____ _____ _____
306.8 337.7 (60.3) 29.4 9
Other 12.8 23.8 (2.6) (8.4) (35)
_____ _____ _____ _____
Total 319.6 361.5 (62.9) 21.0 6
Operating expenses 249.3 279.3 (48.9) 18.9 7
_____ _____ _____ _____
Income from operations 70.3 82.2 (14.0) 2.1 3
Interest expense 30.2 34.5 (6.0) 1.7 5
Equity in losses of Hazelwood 4.2 2.5 (0.9) 2.6 104
Other (income)/expense 3.0 (0.4) (0.6) 4.0 *
Income taxes 12.2 16.5 (2.3) (2.0) (12)
_____ _____ _____ _____
Earnings contribution $ 20.7 $ 29.1 $ (4.2) $ (4.2) (14)
===== ===== ===== =====
Powercor energy sales (millions of kWh)
Powercor area 3,664 3,670 (6) -
Outside Powercor area
Victoria 1,190 1,041 149 14
New South Wales 1,083 316 767 *
_____ _____ _____
Total 5,937 5,027 910 18
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Currency Exchange Rates
The currency exchange rate for converting Australian dollars to U.S. dollars
was 0.65 in 1998 as compared to 0.77 in 1997, a 16% decrease. The effect of
this change in exchange rates lowered revenues by $63 million and costs by
$59 million.
The following discussion does not include the effects of the lower currency
exchange rate in 1998.
Revenue
Australia's revenues increased $21 million, or 6%. The increase was
attributable to increased energy sales volumes of 910 million kWh, or 18%,
which added $42 million to revenues. Declining prices reduced revenues by
$13 million.
Energy volumes sold to contestable customers outside Powercor's franchise area
were up 916 million kWh and added $35 million to revenues due to customer
gains in New South Wales and $7 million due to customer gains in Victoria.
Lower prices for these sales reduced revenues by $7 million in 1998. Inside
Powercor's
<PAGE>23
franchise area, revenues decreased $5 million primarily due to a $6 million
decrease in prices.
Other revenues decreased $8 million as a result of $5 million in revenues
associated with Tariff H contract renegotiations in 1998, offset by
$14 million of Tariff H contract renegotiations in 1997.
Operating Expenses
Purchased power expense decreased $4 million, or 2%, to $126 million. Lower
average prices reduced power costs by $31 million. Prices for purchased power
averaged $23 per mWh compared to $28 per mWh in 1997 due to competition. The
decrease was offset in part by an 18% increase in purchased power volumes that
added $27 million to costs.
Other operating expenses increased $23 million, or 25%, to $108 million.
Increased sales to contestable customers outside the Powercor service area
resulted in higher network fees of $27 million. This increase was offset in
part by higher network revenues of $5 million from customers inside Powercor's
franchise area serviced by other energy suppliers.
Other Income and Expense
Other expense increased $4 million primarily due to a reserve relating to a
product recall. Powercor is in the process of negotiating recovery from the
manufacturer.
Equity losses in Hazelwood increased $3 million over 1997 primarily due to a
planned outage and increased maintenance costs for one of the power station
units during April and May of 1998.
Income taxes decreased $2 million primarily due to a decrease in taxable
income.
<PAGE>24
Unregulated Energy Trading
__________________________
Comparison of the three-month periods ended June 30, 1998 and 1997
__________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
<S> <C> <C> <C> <C>
Revenues
Natural gas $255.5 $152.3 $103.2 68
Electricity 465.6 69.2 396.4 *
_____ _____ _____
Total 721.1 221.5 499.6 *
_____ _____ _____
Cost of sales
Natural gas 259.1 145.4 113.7 78
Purchased electric power 517.1 68.9 448.2 *
_____ _____ _____
Total 776.2 214.3 561.9 *
Gross margin (loss) (55.1) 7.2 (62.3) *
Depreciation and amortization 1.5 3.9 (2.4) (62)
Administrative and other 5.0 5.1 (0.1) (2)
_____ _____ _____
Loss from operations
Natural gas (8.4) (0.1) (8.3) *
Electricity (53.2) (1.7) (51.5) *
_____ _____ _____
Total (61.6) (1.8) (59.8) *
_____ _____ _____
Interest expense 0.6 1.7 (1.1) (65)
Other income (0.6) (0.9) 0.3 33
Income tax benefit (23.5) (0.7) (22.8) *
_____ _____ _____
Net loss
Natural gas (5.7) (0.9) (4.8) *
Electricity (32.4) (1.0) (31.4) *
_____ _____ _____
Total $(38.1) $ (1.9) (36.2) *
===== ===== =====
Energy sales
Natural gas (MMcf) 104,000 66,000 38,000 58
Electricity (millions of kWh) 20,830 3,168 17,662 *
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Electricity trading generated revenues of $466 million, but reported a gross
margin loss of $51 million and a net loss for the quarter of $32 million.
During the quarter a credit reserve of $32 million pretax was recorded as a
result of a default by a supplier of power on a commitment to deliver power
and an additional $10 million pretax charge was recorded for known and
probable future trading losses. Gross margin losses on electricity trading
transactions amounted to $9 million.
The Company's natural gas storage, marketing and trading business, acquired in
April 1997, recorded net losses of $6 million for the quarter compared to a
net loss of $1 million in the second quarter of 1997. Natural gas trading
revenues increased $103 million to $255 million and gross margin decreased
$11 million to a negative $4 million. The gross margin decreased $6 million
as a result of the
<PAGE>25
sale of the Company's gas gathering and processing assets in December 1997.
The remaining decrease in gross margin is due to unfavorable price variances
of $4 million.
<PAGE>26
Comparison of the six-month periods ended June 30, 1998 and 1997
________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
<S> <C> <C> <C> <C>
Revenues
Natural gas $ 573.6 $152.3 $ 421.3 *
Electricity 963.1 108.1 855.0 *
_______ _____ _______
Total 1,536.7 260.4 1,276.3 *
_______ _____ _______
Cost of sales
Natural gas 574.3 145.4 428.9 *
Purchased electric power 1,012.3 106.8 905.5 *
_______ _____ _______
Total 1,586.6 252.2 1,334.4 *
Gross margin (loss) (49.9) 8.2 (58.1) *
Depreciation and amortization 3.0 3.9 (0.9) (23)
Administrative and other 9.4 7.6 1.8 24
_______ _____ _______
Loss from operations
Natural gas (9.3) (0.1) (9.2) *
Electricity (53.0) (3.2) (49.8) *
_______ _____ _______
Total (62.3) (3.3) (59.0) *
_______ _____ _______
Interest expense 0.9 1.8 (0.9) (50)
Other income (1.4) (0.9) (0.5) (56)
Income tax benefit (23.2) (1.3) (21.9) *
_______ _____ _______
Net loss
Natural gas (6.3) (0.9) (5.4) *
Electricity (32.3) (2.0) (30.3) *
_______ _____ _______
Total $ (38.6) $ (2.9) (35.7) *
======= ===== =======
Energy sales
Natural gas (MMcf) 238,000 66,000 172,000 *
Electricity (millions of kWh) 40,716 4,629 36,087 *
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Electricity trading generated revenues of $963 million, but reported a gross
margin loss of $49 million and a net loss of $32 million. A credit reserve of
$32 million pretax was recorded as a result of a default by a supplier of
power on a commitment to deliver power and an additional $10 million pretax
charge was recorded for known and probable future trading losses. Gross
margin losses on electricity trading transactions completed in the first six
months of 1998 amounted to $7 million.
The Company's natural gas storage, marketing and trading business, acquired in
April 1997, recorded net losses of $6 million compared to a net loss of
$1 million in 1997. Natural gas trading revenues increased $421 million to
$574 million and gross margin decreased $8 million to a negative $1 million.
The gross margin decreased $6 million as a result of the sale of the Company's
gas gathering and processing assets in December 1997. The remaining decrease
in gross margin is due to unfavorable price variances of $4 million.
<PAGE>27
Other Operations
________________
Comparison of the three-month periods ended June 30, 1998 and 1997
__________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss)
PFS $ 0.9 $ 4.4 $ (3.5) (80)
PGC - 2.6 (2.6) (100)
Holdings and other 13.7 (5.8) 19.5 *
_____ ____ _____
Total $ 14.6 $ 1.2 $ 13.4 *
===== ==== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Other operations reported earnings of $15 million in the quarter compared to
earnings of $1 million in the same period a year ago. On March 2, 1998, a
subsidiary of Holdings purchased approximately 46 million shares of TEG at a
price of 820 pence per share, or $625 million, utilizing a portion of the cash
proceeds from asset sales. On June 2, 1998, the subsidiary sold the shares
and recorded an after-tax gain of $10 million.
Results from other operations were benefited by a $9 million after-tax
increase in interest income and reduced interest expense as the result of cash
received from asset sales in 1997.
Other unregulated energy development activities incurred $7 million of after
tax losses, or $0.02 per share, compared to a loss of $1 million in the second
quarter of 1997.
<PAGE>28
Comparison of the six-month periods ended June 30, 1998 and 1997
________________________________________________________________
<TABLE>
<CAPTION>
%
1998 1997 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss)
PFS $ 7.5 $ 9.5 $ (2.0) (21)
PGC - 4.0 (4.0) (100)
Holdings and other (32.0) (10.3) (21.7) *
_____ _____ _____
Total $(24.5) $ 3.2 $(27.7) *
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Other operations reported a loss of $25 million compared to earnings of
$3 million in the same period a year ago. The loss was primarily the result
of an $86 million pretax charge for costs associated with the Company's
terminated bid for TEG. These costs, dating back to June of 1997, had been
deferred pending the outcome of the proposed transaction.
On March 2, 1998, a subsidiary of Holdings purchased approximately 46 million
TEG shares at a price of 820 pence per share, or $625 million, utilizing a
portion of the cash proceeds from asset sales. On June 2, 1998, the
subsidiary sold the shares and recorded an after-tax gain of $10 million.
Results from other operations were benefited by a $23 million after-tax
increase in interest income and reduced interest expense as the result of cash
received from asset sales in 1997. The after-tax cash proceeds from these
sales totaled approximately $1.5 billion.
During May 1998, PFS received approximately $80 million in cash proceeds for
the sale of a majority of its real estate assets.
Other unregulated energy development activities incurred $12 million of after-
tax losses, or $0.04 per share, compared to a loss of $2 million, or $0.01 per
share, in 1997.
<PAGE>29
FINANCIAL CONDITION -
For the six months ended June 30, 1998:
OPERATING ACTIVITIES
Net cash flows provided by continuing operations were $340 million during
the period compared to $405 million in the first six months of 1997. The
$65 million decrease in operating cash flows was primarily attributable to
income tax payments of $65 million relating to gains on sales of subsidiaries
in the fourth quarter of 1997 and expenditures relating to the terminated bid
for TEG.
Net cash used in discontinued operations represents payment of income
taxes associated with a $671 million pretax gain recorded in December 1997 on
the sale of PTI.
INVESTING ACTIVITIES
Capital spending totaled $334 million in 1998 compared with $593 million
in 1997. Expenditures relating to operating companies acquired decreased to
$38 million in 1998 from $282 million in 1997 primarily because the 1997
period included the purchase of TPC in April.
Disposition of Assets
Management of the eight investor and publicly-owned utility partners who
own the 1,340 megawatt coal-fired Centralia Power Project in Washington have
agreed to hire an investment advisor to pursue the possible sale of the plant
and the adjacent Centralia Mine. The sale of the plant is being considered by
the owners, in part, because of emerging deregulation and competition in the
electricity industry. The Company operates the plant and owns a 47.5 percent
share. The Company owns and operates the adjacent Centralia Mine.
On July 9, 1998, the Company announced its intent to seek buyers for its
California and Montana electric distribution assets. This action was in
response to the continued decline in earnings on the assets and changes in the
legislative and regulatory environments, including fixing prices, in these
states where the Company has few distribution properties. The Company issued
requests for proposals to interested parties on July 20, 1998.
Bid for The Energy Group
During 1997 and 1998, the Company sought to acquire TEG, a diversified
international energy group with operations in the United Kingdom, the United
States and Australia. The Company made three tender offers for TEG. The last
offer was valued at $11.1 billion, including the assumption of $4.1 billion of
TEG's debt. In February 1998, Texas Utilities Company also made a tender
offer at a higher price. On April 30, 1998, the Company announced that it
would not increase its revised offer for TEG on the basis that a price in
excess of 820 pence per share would not have provided acceptable financial
returns for PacifiCorp shareholders.
The Company recorded an $86 million pretax charge to first quarter 1998
earnings for bank commitment and facility fees, legal expenses and other
related
<PAGE>30
costs incurred since the Company's original bid for TEG in June of 1997.
These costs had been deferred pending the outcome of the transaction.
Additionally, in connection with its attempt to acquire TEG, a subsidiary
of the Company purchased approximately 46 million shares of TEG at a price of
820 pence per share, or $625 million. On June 2, 1998, the subsidiary sold
the shares and recorded an after-tax gain of $10 million.
The Company incurred a pretax loss of $3 million in April 1998 in
connection with closing its foreign currency option contract associated with
the bid for TEG.
CAPITALIZATION
At June 30, 1998, the Company had approximately $327 million of
commercial paper and uncommitted bank borrowings outstanding at a weighted
average rate of 5.8%. These borrowings are supported by $700 million of
revolving credit agreements. At June 30, 1998, the consolidated subsidiaries
had access to $823 million of short-term funds through committed bank
revolving credit agreements. Subsidiaries had $431 million outstanding under
bank revolving credit facilities. At June 30, 1998, the Companies had
$550 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.
In January 1998, Australian Electric Operations issued $400 million of
6.15% Notes due 2008. At the same time, in order to mitigate foreign currency
exchange risk, Australian Electric Operations entered into a series of
currency exchange agreements in the same amount and for the same duration as
the underlying United States denominated notes. The proceeds of the Notes
were used to repay Australian bank bill borrowings.
On May 12, 1998, the Company issued $200 million of 6.375% secured
medium-term notes due May 15, 2008 in the form of First Mortgage Bonds.
Proceeds were used to repay short-term debt.
YEAR 2000
The Company is continuing its enterprise-wide program to assess and
mitigate or eliminate the business risk associated with year 2000 issues
within the Company's information technology and communication systems, as well
as similar risks related to transactions with other businesses. The systems
that could be affected by year 2000 issues have been identified and an
implementation plan has been developed. The Company is participating with
industry organizations to identify year 2000 issues and develop solutions that
will allow for uninterrupted production and delivery of power. Revised
estimates of costs for the total project are approximately $30 million. The
Company has incurred $5 million in costs related to the year 2000 project
through June 30, 1998. Risks to the Company associated with year 2000 issues
include power production and delivery interruptions, customer information and
service disruptions, and administrative and accounting systems malfunctions.
The Company is still developing contingency plans for year 2000 issues.
<PAGE>31
______________________________________________________________________________
The condensed consolidated financial statements as of June 30, 1998 and
December 31, 1997 and for the three-and six-month periods ended June 30, 1998
and 1997 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>32
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 June 30, 1998, and the related condensed
consolidated statements of income and retained earnings for the three- and
six-month periods ended June 30, 1998 and cash flows for the six-month periods
ended June 30, 1998 and 1997. 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, 1997, and the related consolidated statements of income and
retained earnings and of cash flows for the year then ended (not presented
herein); and in our report dated February 3, 1998 (March 2, 1998 as to Note
2), 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, 1997 is fairly stated,
in all material respects, in relation to the consolidated balance sheet from
which it has been derived.
DELOITTE & TOUCHE LLP
July 21, 1998
<PAGE>33
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
______ _________________
In Larry and Barbara Rainey, et al. v. PacifiCorp (see "Item 3.
______________________________________________
Legal Proceedings" at page 25 of the Company's Annual Report on Form
10-K for the year ended December 31, 1997), on May 14, 1998, the
Superior Court granted the Company's motion for summary judgment
dismissing all of the plaintiffs' negligent flood control claims,
leaving only plaintiffs' claims based upon a failure to warn theory
of liability.
Item 4. Submission of Matters to a Vote of Security Holders
______ ___________________________________________________
At the Company's annual meeting of shareholders on May 13, 1998, the
shareholders ratified the appointment of Deloitte & Touche LLP to
serve as independent auditors of the Company for the year 1998 and
rejected a shareholder proposal. Votes cast in relation to the
appointment of Deloitte & Touche LLP are summarized as follows:
<TABLE>
<CAPTION>
Against Or Abstentions And
For Withheld Broker Non-votes
___ _________ ________________
<S> <C> <C> <C>
243,266,460 1,325,646 1,516,126
</TABLE>
Votes cast to reject a shareholder proposal are summarized as
follows:
<TABLE>
<CAPTION>
Against Or Abstentions And
For Withheld Broker Non-votes
___ _________ ________________
<S> <C> <C> <C>
3,000 246,076,916 -
</TABLE>
The shareholders also elected four Class II Directors, each for
terms expiring at the Annual Meeting in the year 2001. Votes cast
in relation to these matters are summarized as follows:
<TABLE>
<CAPTION>
Against Or Abstentions And
For Withheld Broker Non-votes
___ _________ ________________
<S> <C> <C> <C>
Class II
Kathryn A. Braun 237,494,898 8,613,333 -
Robert G. Miller 240,117,584 5,990,648 -
Alan K. Simpson 239,612,437 6,495,795 -
Verl R. Topham 239,940,698 6,167,534 -
</TABLE>
The Directors whose terms continued and the years their terms expire
are as follows:
W. Charles Armstrong (Class I, 2000); Frederick W. Buckman (Class
III, 1999); C. Todd Conover (Class I, 2000); Nolan E. Karras (Class
I, 2000); Keith R. McKennon (Class I, 2000); Don M. Wheeler (Class
III, 1999); Nancy Wilgenbusch (Class III, 1999); Peter I. Wold
(Class III, 1999).
<PAGE>34
Item 5. Other Information
______ _________________
As stated in the Company's Proxy Statement for the 1998 Annual
Meeting of Shareholders, shareholders wishing to present proposals
for action at a shareholders' meeting must do so in accordance with
the Company's Bylaws. To be timely, a shareholders' notice must be
in writing, delivered to or mailed and received at the principal
executive offices of the Company not less than 60 days nor more than
90 days prior to the meeting. If the Company holds its 1999 Annual
Meeting on May 19, 1999 in accordance with the Company's Bylaws, to
be timely such shareholders' notice must be delivered to or mailed
and received at the principal executive offices of the Company not
earlier than February 18, 1999 nor later than March 20, 1999.
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 June 30,
1998 (filed electronically only).
(b) Reports on Form 8-K.
On Form 8-K, dated July 1, 1998, under Item 5. "Other Events," the
Company filed news releases reporting the promotion of Richard T.
O'Brien to the position of executive vice president and chief
operating officer and the earnings shortfall expected for the second
quarter of 1998.
On Form 8-K, dated July 31, 1998, under Item 5. "Other Events," the
Company filed a news release discussing the regulatory proceedings
in the state of Utah.
<PAGE>35
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PACIFICORP
Date August 12, 1998 By ROBERT R. DALLEY
___________________________ ___________________________________
Robert R. Dalley
Controller
(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 June 30, 1998 (filed electronically only).
</TABLE>
<PAGE>
<TABLE>
EXHIBIT (12)(a)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO FIXED CHARGES
<CAPTION>
Six Months
______________________________________________ Ended
1993 1994 1995 1996 1997 June 30, 1998
____ ____ ____ ____ ____ _____________
(In Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense..................... $ 333.5 $ 302.0 $ 336.4 $ 415.0 $ 439.8 $188.4
Estimated interest portion of
rentals charged to expense......... 4.8 5.6 4.5 4.1 6.6 4.7
Preferred dividends of
wholly owned subsidiary............ - - - 15.3 33.1 14.1
_______ _______ _______ _______ _______ _____
Total fixed charges.............. $ 338.3 $ 307.6 $ 340.9 $ 434.4 $ 479.5 $207.2
======= ======= ======= ======= ======= =====
Earnings, as defined:*
Income from continuing operations.... $ 371.8 $ 397.5 $ 402.0 $ 430.2 $ 225.4 $ 25.3
Add (deduct):
Provision for income taxes......... 163.6 209.0 191.8 236.5 109.5 (0.3)
Minority interest.................. 2.7 1.3 1.4 1.8 1.9 (0.7)
Undistributed income of less
than 50% owned affiliates........ (16.2) (14.7) (15.0) (18.2) (11.1) 5.4
Fixed charges as above............. 338.3 307.6 340.9 434.4 479.5 207.2
_______ _______ _______ _______ _______ _____
Total earnings................... $ 860.2 $ 900.7 $ 921.1 $1,084.7 $ 805.2 $236.9
======= ======= ======= ======= ======= =====
Ratio of Earnings to Fixed Charges..... 2.5x 2.9x 2.7x 2.5x 1.7x 1.1x
==== ==== ==== ==== ==== ====
<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>
Six Months
______________________________________________ Ended
1993 1994 1995 1996 1997 June 30, 1998
____ ____ ____ ____ ____ _____________
(In Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense..................... $ 333.5 $ 302.0 $ 336.4 $ 415.0 $ 439.8 $188.4
Estimated interest portion of
rentals charged to expense...... 4.8 5.6 4.5 4.1 6.6 4.7
Preferred dividends of
wholly owned subsidiary............ - - - 15.3 33.1 14.1
_______ _______ _______ _______ _______ _____
Total fixed charges.............. $ 338.3 $ 307.6 $ 340.9 $ 434.4 $ 479.5 $207.2
Preferred Stock Dividends,
as defined:*....................... 56.8 60.8 57.0 46.2 33.9 9.5
_______ _______ _______ _______ _______ _____
Total fixed charges and
preferred dividends............ $ 395.1 $ 368.4 $ 397.9 $ 480.6 $ 513.4 $216.7
======= ======= ======= ======= ======= =====
Earnings, as defined:*
Income from continuing operations.... $ 371.8 $ 397.5 $ 402.0 $ 430.2 $ 225.4 $ 25.3
Add (deduct):
Provision for income taxes......... 163.6 209.0 191.8 236.5 109.5 (0.3)
Minority interest.................. 2.7 1.3 1.4 1.8 1.9 (0.7)
Undistributed income of less than
50% owned affiliates............. (16.2) (14.7) (15.0) (18.2) (11.1) 5.4
Fixed charges as above............. 338.3 307.6 340.9 434.4 479.5 207.2
_______ _______ _______ _______ _______ _____
Total earnings................... $ 860.2 $ 900.7 $ 921.1 $1,084.7 $ 805.2 $236.9
======= ======= ======= ======= ======= =====
Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.. 2.2x 2.4x 2.3x 2.3x 1.6x 1.1x
==== ==== ==== ==== ==== ====
<FN>
*"Fixed charges" represent consolidated interest charges, an estimated amount representing the interest
factor in rents and preferred dividend requirements of majority-owned subsidiaries. "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 LLP
___________ _____________________________________________________
Suite 3900 Telephone:(503)222-1341
111 S.W. Fifth Avenue Facsimile:(503)224-2172
Portland, Oregon 97204-3642
EXHIBIT 15
August 7, 1998
PacifiCorp
700 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
June 30, 1998 and 1997, as indicated in our report dated July 21, 1998;
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 June 30, 1998, 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; and Registration Statement Nos. 33-62095
and 333-09115 on Form S-3.
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 JUNE 30, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000075594
<NAME> PACIFICORP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> JUN-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7855000
<OTHER-PROPERTY-AND-INVEST> 1925200
<TOTAL-CURRENT-ASSETS> 1733000
<TOTAL-DEFERRED-CHARGES> 305200
<OTHER-ASSETS> 1441700
<TOTAL-ASSETS> 13260100
<COMMON> 3211100
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 962800
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4173900
175000
66400
<LONG-TERM-DEBT-NET> 4414100
<SHORT-TERM-NOTES> 16900
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 206900
<LONG-TERM-DEBT-CURRENT-PORT> 312900
0
<CAPITAL-LEASE-OBLIGATIONS> 23300
<LEASES-CURRENT> 1000
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3869700
<TOT-CAPITALIZATION-AND-LIAB> 13260100
<GROSS-OPERATING-REVENUE> 3999100
<INCOME-TAX-EXPENSE> (300)
<OTHER-OPERATING-EXPENSES> 3726900
<TOTAL-OPERATING-EXPENSES> 3726600
<OPERATING-INCOME-LOSS> 272500
<OTHER-INCOME-NET> (58500)
<INCOME-BEFORE-INTEREST-EXPEN> 214000
<TOTAL-INTEREST-EXPENSE> 188300
<NET-INCOME> 25700
9600
<EARNINGS-AVAILABLE-FOR-COMM> 16100
<COMMON-STOCK-DIVIDENDS> 160200
<TOTAL-INTEREST-ON-BONDS> 222200
<CASH-FLOW-OPERATIONS> 36200
<EPS-PRIMARY> 0.05
<EPS-DILUTED> 0.05
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S
FORM 10-K DATED DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<CIK> 0000075594
<NAME> PACIFICORP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7825500
<OTHER-PROPERTY-AND-INVEST> 2051300
<TOTAL-CURRENT-ASSETS> 2182300
<TOTAL-DEFERRED-CHARGES> 389000
<OTHER-ASSETS> 1432100
<TOTAL-ASSETS> 13880200
<COMMON> 3214600
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1106300
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4320900
175000
66400
<LONG-TERM-DEBT-NET> 4390700
<SHORT-TERM-NOTES> 6300
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 182900
<LONG-TERM-DEBT-CURRENT-PORT> 364600
0
<CAPITAL-LEASE-OBLIGATIONS> 23800
<LEASES-CURRENT> 900
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4348700
<TOT-CAPITALIZATION-AND-LIAB> 13880200
<GROSS-OPERATING-REVENUE> 6275100
<INCOME-TAX-EXPENSE> 109500
<OTHER-OPERATING-EXPENSES> 5475500
<TOTAL-OPERATING-EXPENSES> 5585000
<OPERATING-INCOME-LOSS> 690100
<OTHER-INCOME-NET> (25200)
<INCOME-BEFORE-INTEREST-EXPEN> 664900
<TOTAL-INTEREST-EXPENSE> 439500
<NET-INCOME> 663700<F1>
22800
<EARNINGS-AVAILABLE-FOR-COMM> 640900<F1>
<COMMON-STOCK-DIVIDENDS> 320000
<TOTAL-INTEREST-ON-BONDS> 217500
<CASH-FLOW-OPERATIONS> 834100
<EPS-PRIMARY> 2.16<F1>
<EPS-DILUTED> 2.16<F1>
<FN>
<F1>NET INCOME AND EARNINGS AVAILABLE FOR COMMON
INCLUDE INCOME FROM DISCONTINUED OPERATIONS
OF $89,200, GAIN ON SALE OF DISCONTINUED OPERATIONS
OF $365,100 AND EXTRAORDINARY LOSS FROM REGULATORY
ASSET IMPAIRMENT OF $16,000. EPS INCLUDES EARNINGS
PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF
$0.30, GAIN ON SALE OF DISCONTINUED OPERATIONS OF
$1.23 AND EXTRAORDINARY LOSS FROM REGULATORY ASSET
IMPAIRMENT OF $0.05.
</FN>
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S
FORM 10-Q DATED SEPTEMBER 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<CIK> 0000075594
<NAME> PACIFICORP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7894600
<OTHER-PROPERTY-AND-INVEST> 2487200
<TOTAL-CURRENT-ASSETS> 1974400<F1>
<TOTAL-DEFERRED-CHARGES> 358500
<OTHER-ASSETS> 1881300
<TOTAL-ASSETS> 14596000
<COMMON> 3244200
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 816100
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4060300
175000
66400
<LONG-TERM-DEBT-NET> 4835800
<SHORT-TERM-NOTES> 148300
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 559100
<LONG-TERM-DEBT-CURRENT-PORT> 626900
0
<CAPITAL-LEASE-OBLIGATIONS> 23900
<LEASES-CURRENT> 900
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4099400
<TOT-CAPITALIZATION-AND-LIAB> 14596000
<GROSS-OPERATING-REVENUE> 4271100
<INCOME-TAX-EXPENSE> 112400
<OTHER-OPERATING-EXPENSES> 3508100
<TOTAL-OPERATING-EXPENSES> 3620500
<OPERATING-INCOME-LOSS> 650600
<OTHER-INCOME-NET> (93700)
<INCOME-BEFORE-INTEREST-EXPEN> 556900
<TOTAL-INTEREST-EXPENSE> 331600
<NET-INCOME> 289800<F1>
18000
<EARNINGS-AVAILABLE-FOR-COMM> 271800<F1>
<COMMON-STOCK-DIVIDENDS> 239300
<TOTAL-INTEREST-ON-BONDS> 213800
<CASH-FLOW-OPERATIONS> 609700
<EPS-PRIMARY> .92<F1>
<EPS-DILUTED> .92<F1>
<FN>
<F1>CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED
OPERATIONS OF $803,500. NET INCOME AND EARNINGS AVAILABLE
FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS
OF $64,500. EPS INCLUDES EARNINGS PER COMMON SHARE FROM
DISCONTINUED OPERATIONS OF $0.22.
</FN>
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S
FORM 10-Q DATED JUNE 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<CIK> 0000075594
<NAME> PACIFICORP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7865600
<OTHER-PROPERTY-AND-INVEST> 2533100
<TOTAL-CURRENT-ASSETS> 1767200<F1>
<TOTAL-DEFERRED-CHARGES> 325600
<OTHER-ASSETS> 1888900
<TOTAL-ASSETS> 14380400
<COMMON> 3241200
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 827700
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4068900
175000
135500
<LONG-TERM-DEBT-NET> 5336800
<SHORT-TERM-NOTES> 166900
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 432200
<LONG-TERM-DEBT-CURRENT-PORT> 271800
0
<CAPITAL-LEASE-OBLIGATIONS> 24300
<LEASES-CURRENT> 900
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3768100
<TOT-CAPITALIZATION-AND-LIAB> 14380400
<GROSS-OPERATING-REVENUE> 2261300
<INCOME-TAX-EXPENSE> 96700
<OTHER-OPERATING-EXPENSES> 1778600
<TOTAL-OPERATING-EXPENSES> 1875300
<OPERATING-INCOME-LOSS> 386000
<OTHER-INCOME-NET> 11100
<INCOME-BEFORE-INTEREST-EXPEN> 397100
<TOTAL-INTEREST-EXPENSE> 218700
<NET-INCOME> 215800<F1>
12200
<EARNINGS-AVAILABLE-FOR-COMM> 203600<F1>
<COMMON-STOCK-DIVIDENDS> 159400
<TOTAL-INTEREST-ON-BONDS> 213100
<CASH-FLOW-OPERATIONS> 392100
<EPS-PRIMARY> .69<F1>
<EPS-DILUTED> .69<F1>
<FN>
<F1>CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED
OPERATIONS OF $789,900. NET INCOME AND EARNINGS AVAILABLE
FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS
OF $37,400. EPS INCLUDES EARNINGS PER COMMON SHARE FROM
DISCONTINUED OPERATIONS OF $0.13.
</FN>
</TABLE>
