<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, 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 July 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 12
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders 33
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,
__________________ ________________
1999 1998 1999 1998
____ ____ ____ ____
<S> <C> <C> <C> <C>
REVENUES $ 943.7 $1,202.2 $1,903.5 $2,462.4
_______ _______ _______ _______
EXPENSES
Purchased power 299.3 535.2 568.0 1,051.7
Other operations and maintenance 274.4 248.6 534.2 521.3
Depreciation and amortization 115.8 115.4 229.0 230.6
Administrative and general 57.9 83.3 122.2 158.2
Taxes, other than income taxes 24.8 25.4 51.1 53.0
Special charges - - - 113.1
_______ _______ _______ _______
TOTAL 772.2 1,007.9 1,504.5 2,127.9
_______ _______ _______ _______
INCOME FROM OPERATIONS 171.5 194.3 399.0 334.5
_______ _______ _______ _______
INTEREST EXPENSE AND OTHER
Interest expense 86.9 94.0 174.9 188.3
Interest capitalized (7.8) (3.7) (11.2) (7.0)
TEG transaction costs - (13.0) - 73.3
Other (income)/expense - net 2.5 (0.2) (3.8) (7.2)
_______ _______ _______ _______
TOTAL 81.6 77.1 159.9 247.4
_______ _______ _______ _______
Income from continuing operations
before income taxes 89.9 117.2 239.1 87.1
Income tax expense 34.9 38.3 92.8 22.8
_______ _______ _______ _______
Income from continuing operations 55.0 78.9 146.3 64.3
Discontinued Operations (less applicable
income tax expense/(benefit): 1999/$0.7;
1998/$(23.5) and $(23.2) 1.1 (38.1) 1.1 (38.6)
_______ _______ _______ _______
NET INCOME 56.1 40.8 147.4 25.7
RETAINED EARNINGS BEGINNING OF PERIOD 738.8 1,006.6 732.0 1,106.3
Cash dividends declared
Preferred stock (4.2) (4.3) (8.4) (8.6)
Common stock per share of $0.27 (80.3) (80.3) (160.6) (160.6)
_______ _______ _______ _______
RETAINED EARNINGS END OF PERIOD $ 710.4 $ 962.8 $ 710.4 $ 962.8
======= ======= ======= =======
EARNINGS ON COMMON STOCK $ 51.3 $ 36.0 $ 137.8 $ 16.1
Average number of common shares
outstanding - Basic (Thousands) 297,331 297,259 297,333 297,160
Dilutive (Thousands) 297,331 297,259 297,333 297,212
EARNINGS (LOSS) PER COMMON SHARE -
Basic and dilutive
Continuing operations $ 0.17 $ 0.25 $ 0.46 $ 0.18
Discontinued operations - (0.13) - (0.13)
_______ _______ _______ _______
TOTAL $ 0.17 $ 0.12 $ 0.46 $ 0.05
======= ======= ======= =======
<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,
_____________________
1999 1998
____ ____
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 147.4 $ 25.7
Adjustments to reconcile net income to
net cash provided by operating activities
(Income)/loss from discontinued operations (1.1) 38.6
Depreciation and amortization 233.3 234.6
Deferred income taxes and investment tax
credits - net 29.7 (44.1)
Special charges - 113.1
(Gain)/loss on sale of assets (9.0) 4.0
TEG transaction costs - 61.0
Utah rate order (37.0) -
Other (8.4) 27.4
Accounts receivable and prepayments 203.3 65.0
Materials, supplies and fuel stock (20.3) (0.7)
Accounts payable and accrued liabilities (138.6) (165.7)
________ ______
Net cash provided by continuing operations 399.3 358.9
Net cash provided by (used in) discontinued
operations 6.1 (324.2)
________ ______
NET CASH PROVIDED BY OPERATING ACTIVITIES 405.4 34.7
________ ______
CASH FLOWS FROM INVESTING ACTIVITIES
Construction (276.2) (299.3)
Investments in and advances to
affiliated companies - net (0.6) (19.7)
Operating companies and assets acquired (0.5) (13.2)
Proceeds from asset sales 167.3 3.4
Proceeds from sales of finance assets, real
estate investments and principal payments 60.4 315.2
Other (20.5) (18.3)
________ ______
NET CASH USED IN INVESTING ACTIVITIES (70.1) (31.9)
________ ______
CASH FLOWS FROM FINANCING ACTIVITIES
Changes in short-term debt (219.9) 34.6
Proceeds from long-term debt 874.3 728.4
Proceeds from issuance of common stock - 8.5
Dividends paid (168.6) (168.5)
Repayments of long-term debt (1,163.4) (744.7)
Other 2.0 37.8
________ ______
NET CASH USED IN FINANCING ACTIVITIES (675.6) (103.9)
________ ______
DECREASE IN CASH AND CASH EQUIVALENTS (340.3) (101.1)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 583.1 740.8
________ ______
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 242.8 $ 639.7
======== ======
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for
Interest (net of amount capitalized) $ 210.4 $ 225.8
Income taxes 27.2 482.7
<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,
1999 1998
________ ___________
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 242.8 $ 583.1
Accounts receivable less allowance
for doubtful accounts: 1999/$17.5
and 1998/$18.0 524.3 703.2
Materials, supplies and fuel stock at
average cost 196.8 175.8
Net assets of discontinued operations
and assets held for sale - 192.4
Other 89.9 87.9
________ ________
TOTAL CURRENT ASSETS 1,053.8 1,742.4
PROPERTY, PLANT AND EQUIPMENT
Domestic Electric Operations 12,640.2 12,460.0
Australian Electric Operations 1,256.3 1,140.4
Other Operations 21.3 22.2
Accumulated depreciation and amortization (4,754.4) (4,553.2)
________ ________
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 9,163.4 9,069.4
OTHER ASSETS
Investments in and advances to affiliated
companies 117.4 114.9
Intangible assets - net 385.3 369.4
Regulatory assets - net 760.0 795.5
Finance note receivable 201.7 204.9
Finance assets - net 298.5 313.7
Deferred charges and other 396.4 378.3
________ ________
TOTAL OTHER ASSETS 2,159.3 2,176.7
________ ________
TOTAL ASSETS $12,376.5 $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>
June 30, December 31,
1999 1998
________ ____________
<S> <C> <C>
CURRENT LIABILITIES
Long-term debt currently maturing $ 192.1 $ 299.5
Notes payable and commercial paper 40.7 260.6
Accounts payable 369.1 566.2
Taxes, interest and dividends payable 288.7 282.7
Customer deposits and other 124.1 168.0
________ ________
TOTAL CURRENT LIABILITIES 1,014.7 1,577.0
DEFERRED CREDITS
Income taxes 1,619.5 1,542.6
Investment tax credits 121.3 125.3
Other 616.5 646.1
________ ________
TOTAL DEFERRED CREDITS 2,357.3 2,314.0
LONG-TERM DEBT 4,466.1 4,559.3
COMMITMENTS AND CONTINGENCIES (See Note 5) - -
GUARANTEED PREFERRED BENEFICIAL INTERESTS
IN COMPANY'S JUNIOR SUBORDINATED DEBENTURES 340.7 340.5
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 3,284.7 3,285.0
Retained earnings 710.4 732.0
Accumulated other comprehensive loss (38.8) (60.7)
________ ________
TOTAL COMMON EQUITY 3,956.3 3,956.3
________ ________
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $12,376.5 $12,988.5
======== ========
<FN>
See accompanying Notes to Condensed Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 1999
1. FINANCIAL STATEMENTS
The accompanying unaudited condensed consolidated financial statements
as of June 30, 1999 and December 31, 1998 and for the periods ended June 30,
1999 and 1998, in the opinion of management, include all adjustments,
constituting only normal recording of accruals, necessary for a fair
presentation of financial position, results of operations and cash flows for
such periods. A significant part of the business of PacifiCorp (the "Company")
is of a seasonal nature; therefore, results of operations for the periods
ended June 30, 1999 and 1998 are not necessarily indicative of the results for
a full year. These condensed consolidated financial statements should be read
in conjunction with the financial statements and related notes in the
Company's 1998 Annual Report on Form 10-K/A Amendment No. 1.
The condensed consolidated financial statements of the Company include
the integrated domestic electric utility operations of Pacific Power and Utah
Power and its wholly owned and majority owned subsidiaries. Major
subsidiaries, all of which are wholly owned, are: PacifiCorp Group Holdings
Company ("Holdings"), which holds directly or through its wholly owned
subsidiary, PacifiCorp International Group Holdings Company, all of the
Company's nonintegrated electric utility investments, including Powercor
Australia Limited ("Powercor"), an Australian electricity distributor, and
PacifiCorp Financial Services, Inc. ("PFS"), a financial services business.
Together these businesses are referred to herein as the Companies. Significant
intercompany transactions and balances have been eliminated.
During October 1998, the Company decided to exit its energy trading
business, which consisted of TPC Corporation ("TPC") and PacifiCorp Power
Marketing, Inc. ("PPM"). On April 1, 1999, the Company sold TPC. See Note 3.
During May 1998, the Company sold a majority of the real estate assets held by
PFS. The Company has also decided to exit the majority of its other energy
development businesses and has recorded them at estimated net realizable value
less selling costs.
Investments in and advances to affiliated companies represent
investments in unconsolidated affiliated companies carried on the equity
basis, which approximates the Company's equity in their underlying net book
value.
Certain amounts have been reclassified to conform with the 1999 method
of presentation. These reclassifications had no effect on previously reported
consolidated net income.
2. SCOTTISHPOWER MERGER
In December 1998, the Company announced a proposed merger 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 proposed merger was approved by the shareholders of both companies
in June 1999.
The merger is subject to federal and state regulatory review. Both
companies have applications pending for approval with state regulatory bodies
in Utah, Oregon, Wyoming, Idaho and Washington. Staff members in all the
<PAGE>7
states have recommended approval of the merger, subject to certain conditions.
Hearings are expected to be completed in all states by the end of August.
The proposed merger has received clearance from the U.S. Federal Energy
Regulatory Commission, under the Hart-Scott-Rodino Antitrust Improvements Act
and from U.K., Australian and California regulatory authorities. 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 TPC for sale and ceasing the operations of PPM, which conducted
electricity trading in the eastern United States. PPM's activities in the
eastern United States have been discontinued and all forward electricity
trading has been closed and is going through settlement. On April 1, 1999,
Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. This activity
resulted in an after-tax gain of $1 million in the second quarter of 1999.
The net assets, operating results and cash flows of the energy trading
segment have been classified as discontinued operations for all periods
presented in the consolidated financial statements and notes.
Summarized operating results were as follows:
<TABLE>
<CAPTION>
Three-Month Six-Month
Period Ended Period Ended
June 30, June 30,
______________ ______________
1999 1998 1999 1998
____ ____ ____ ____
(Dollars in Millions)
<S> <C> <C> <C> <C>
Revenues $ - $721.0 $ - $1,537.0
=== ===== === =======
Loss from discontinued
operations (less applicable
income tax benefit of $23.5
and $23.2) $ - $(38.1) $ - $ (38.6)
Gain on disposal (less applicable
income tax of $0.7) 1.1 - 1.1 -
___ _____ ___ _______
Net income/(loss) $1.1 $(38.1) $1.1 $ (38.6)
=== ===== === =======
</TABLE>
As mentioned previously, net assets of the discontinued operations were
sold April 1, 1999. Net assets of the discontinued operations and assets held
for sale as of December 31, 1998 consisted of the following:
<TABLE>
<CAPTION>
December 31,
1998
_____________
(Dollars in Millions)
<S> <C>
Current assets $148.5
Noncurrent assets 152.7
Current liabilities (96.0)
Long-term debt (1.3)
Noncurrent liabilities (28.9)
Assets held for sale 17.4
_____
Net Assets of Discontinued Operations
and Assets Held for Sale $192.4
=====
</TABLE>
<PAGE>8
Holdings had $13 million and $34 million as of June 30, 1999 and
December 31, 1998, respectively, of liabilities in "Customer deposits and
other" relating to the sale or exit of the discontinued operations.
4. ACCOUNTING FOR THE EFFECTS OF REGULATION
Domestic Electric Operations prepares its financial statements in
accordance with Statement of Financial Accounting Standards ("SFAS") 71,
"Accounting for the Effects of Certain Types of Regulations." Under this
statement, the Company may defer certain costs as regulatory assets and
certain obligations as regulatory liabilities. Regulatory assets and
liabilities represent probable future revenues that will be recovered from, or
refunded to, customers through the ratemaking process.
The Emerging Issues Task Force of the Financial Accounting Standards
Board (the "EITF") concluded in 1997 that SFAS 71 should be discontinued when
detailed legislation or regulatory orders regarding competition are issued.
Additionally, the EITF concluded that regulatory assets and liabilities
applicable to businesses being deregulated should be written off unless their
recovery is provided for through future regulated cash flows. Recoverability
of regulatory assets is assessed at each reporting period.
On March 4, 1999, the Utah Public Service Commission (the "UPSC")
ordered the Company to reduce customer prices by 12%, or $85 million annually
effective March 1, 1999, and to make a one-time refund of $40 million to
customers. Approximately $38 million of the refund relating to 1997 and 1998
was recorded in December 1998. The remaining $2 million was recorded in the
first quarter of 1999. The ordered rate reduction is the culmination of a
general rate case in Utah that began in 1997. The Company has decided not to
appeal the ordered rate reduction to the Utah Supreme Court.
In 1998, the Company announced its intent to sell its California
electric distribution assets. This action was in response to the continued
decline in earnings on the assets and the changes in the legislative and
regulatory environments in California. On April 9, 1999, the Company announced
it had entered into a letter of intent with Nor-Cal Electric Authority for the
sale of the assets to Nor-Cal for $178 million. A definitive agreement was
signed on July 15, 1999. The Federal Energy Regulatory Commission and the
California Public Utility Commission must now approve the sale, which is
expected to close early next year.
On April 30, 1999, the Company filed for changes in the prices it
charges Oregon customers. The filing was required as part of a 1998 Oregon
Public Utility Commission (the "OPUC") order which uses set formulas to
moderate the impact of cost fluctuations on customer prices, while assuring
high-quality service. The filing also contained a request to increase the
revenues collected under its system benefits charge. The changes were approved
by the OPUC in June 1999, and became effective July 1, 1999. This will result
in a price increase of approximately 1.3%, or $9 million annually, in Oregon.
On July 23, 1999, the Oregon legislature approved Senate Bill 1149. This
legislation requires competition for industrial and large commercial customers
of both the Company and Portland General Electric by October 1, 2001.
Residential customers will receive a portfolio of commodity service options.
The bill exempts publicly-owned utilities and Idaho Power's Oregon service
territory. The bill defers to the OPUC decisions on a variety of important
issues, including the method for valuation of stranded costs/benefits,
consumer protections, marketer certification, environmental issues, and
competitive services. The legislation also calls for the functional separation
of certain assets and the establishment of a code-of-conduct for electric
companies and their affiliates to protect consumers against anti-competitive
practices. The Company will be participating in the OPUC proceedings over the
next two years
<PAGE>9
that establish the rules and procedures that will implement the bill. The
Company will continue to evaluate the finance and accounting impacts,
including the continued propriety of applying SFAS 71, as the OPUC proceedings
progress. The impacts, if any, are uncertain.
On April 30, 1999, the Company filed documents with the Idaho Public
Utilities Commission (the "IPUC") to implement the next step in the gradual
retirement of a federal energy credit. The proposed reduction in the credit
would increase electric prices for Utah Power residential and irrigation
customers in southeastern Idaho. The filing, once approved by the IPUC, would
reduce the credits from the federal Bonneville Power Administration (the
"BPA") and increase residential prices 3.35%, or $1 million, and irrigation
prices 4%, or $1 million. These price increases are not expected to have a
material impact on earnings.
Congress created the federal credit in 1980 to share the benefits of
federally owned hydroelectric plants with customers of investor-owned
utilities in the Columbia River drainage area. When Congress recommended in
1995 that the current exchange method be phased out by June 2001, the Company
worked out a settlement with BPA in 1997 to implement the order of Congress.
Without the settlement, prices would have increased more than 30% in two
years. The settlement provided credits of $48 million over five years for the
Company's customers, $6 million more than without the settlement. The
additional money is being used to lessen the impact of price increases as the
BPA exchange credit is phased out.
On July 26, 1999, the Company filed for a rate increase before the
Wyoming Public Service Commission. The Company is asking for an increase of
$12 million, or 4.9%, based on a test year ending December 31, 1998. The
Company's Wyoming results of operation for the test year reflected
justification for an increase in annual revenues of $48 million, but the
Company is limiting its proposed price increase to $12 million as a result of
a stipulation reached in connection with the pending merger approval
proceeding in that state. The Company's proposed effective date for this
tariff increase is January 1, 2000.
5. CONTINGENT LIABILITIES
The Company and its subsidiaries are parties to various legal claims,
actions and complaints, certain of which involve material amounts. Although
the Company is unable to predict with certainty whether or not it will
ultimately be successful in these legal proceedings or, if not, what the
impact might be, management currently believes that disposition of these
matters will not have a materially adverse effect on the Company's
consolidated financial statements.
<PAGE>10
6. COMPREHENSIVE INCOME
The components of comprehensive income are as follows:
<TABLE>
<CAPTION>
Three-Month Six-Month
Periods Ended Periods Ended
June 30, June 30,
_______________ _______________
1999 1998 1999 1998
____ ____ ____ ____
(Dollars in Millions)
<S> <C> <C> <C> <C>
Net income $ 56.1 $ 40.8 $147.4 $ 25.7
Other comprehensive income
Foreign currency translation
adjustment, net of taxes:
1999/$10.1 and $14.0,
1998/$(20.9) and $(11.8) 15.9 (32.5) 22.0 (19.5)
Unrealized gain on available-
for-sale securities, net of
taxes: 1998/$4.3 - 7.1 (0.1) 7.1
Reclassification adjustments for
gains included in net income,
net of taxes: 1998/$4.6 - (7.2) - -
_____ _____ _____ _____
Total comprehensive income $ 72.0 $ 8.2 $169.3 $ 13.3
===== ===== ===== =====
</TABLE>
7. NEW ACCOUNTING STANDARDS
In June 1999, the Financial Accounting Standards Board issued SFAS 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133 - an amendment of FASB Statement
No. 133." This statement delays the effective date of SFAS 133 for one year,
to fiscal years beginning after June 15, 2000. This statement affects the
Company by allowing the delay of implementation of SFAS 133.
<PAGE>11
8. SEGMENT INFORMATION
Selected information regarding the Company's operating segments,
Domestic Electric Operations, Australian Electric Operations and Other
Operations, are as follows:
<TABLE>
<CAPTION>
Domestic Australian Other
Total Electric Electric Discontinued Operations &
Millions of dollars Company Operations Operations Operations Eliminations
___________________ _______ __________ __________ ___________ ____________
<S> <C> <C> <C> <C> <C>
For the three months ended:
June 30, 1999
Net sales and revenues
(all external) $ 943.7 $ 772.3 $160.4 $ - $ 11.0
Income from continuing
operations 55.0 42.6 9.1 - 3.3
Income from discontinued
operations 1.1 - - 1.1 -
June 30, 1998
Net sales and revenues
(all external) $1,202.2 $1,031.6 $157.1 $ - $ 13.5
Income from continuing
operations 78.9 57.7 6.6 - 14.6
Loss from discontinued
operations (38.1) - - (38.1) -
For the six months ended:
June 30, 1999
Net sales and revenues
(all external) $1,903.5 $1,579.5 $307.4 $ - $ 16.6
Income from continuing
operations 146.3 122.8 19.5 - 4.0
Income from discontinued
operations 1.1 - - 1.1 -
June 30, 1998
Net sales and revenues
(all external) $2,462.4 $2,108.6 $319.6 $ - $ 34.2
Income (loss) from
continuing operations 64.3 68.1 20.7 - (24.5)
Loss from discontinued
operations (38.6) - - (38.6) -
</TABLE>
<PAGE>12
Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SUMMARY RESULTS OF OPERATIONS
This report includes forward-looking statements that involve a number of risks
and uncertainties that may influence the financial performance and earnings of
the Company and its subsidiaries, including the factors identified in the
Company's 1998 Annual Report on Form 10-K/A Amendment No. 1. Such forward-
looking statements should be considered in light of those factors.
Comparison of the three-month periods ended June 30, 1999 and 1998
__________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ _____ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss) on
common stock (1)
Domestic Electric Operations $ 37.8 $ 52.9 $(15.1) (29)
Australian Electric Operations 9.1 6.6 2.5 38
Other Operations 3.3 14.6 (11.3) (77)
_____ _____ _____
Continuing Operations 50.2 74.1 (23.9) (32)
Discontinued Operations (2) 1.1 (38.1) 39.2 103
_____ _____ _____
Total $ 51.3 $ 36.0 $ 15.3 43
===== ===== =====
Earnings (loss) per common share -
Basic and dilutive
Continuing Operations $ 0.17 $ 0.25 $(0.08) (32)
Discontinued Operations (2) - (0.13) 0.13 100
_____ _____ _____
Total $ 0.17 $ 0.12 $ 0.05 42
===== ===== =====
<FN>
(1) Earnings contribution (loss) on common stock by segment: (a) does not
reflect elimination for interest on intercompany borrowing arrangements;
(b) includes income taxes on a separate company basis, with any benefit
or detriment of consolidation reflected in Other Operations; (c) is net
of preferred dividend requirements and minority interest.
(2) Represents the discontinued operations of TPC and PPM.
</FN>
</TABLE>
The Company recorded earnings on common stock of $51 million, or $0.17 per
share, in the second quarter of 1999 compared to $36 million, or $0.12 per
share, in 1998. Second quarter 1998 results included losses of $38 million, or
$0.13 per share, from the Company's energy trading activities, which the
Company decided to discontinue in October 1998. The second quarter 1998 also
included a $10 million, or $0.03 per share, gain relating to the sale of The
Energy Group PLC ("TEG") shares and a $2 million, or $0.01 per share, loss
relating to closing foreign currency options in April 1998 associated with the
terminated bid for TEG. Second quarter 1999 results included $8 million, or
$0.03 per share, for ScottishPower merger costs.
Domestic electric operations earnings contribution was $38 million, or $0.13
per share, as compared to $53 million, or $0.18 per share, in the second
quarter of 1998. Second quarter 1999 reflected $8 million, or $0.03 per share,
of ScottishPower merger costs and a $14 million, or $0.05 per share, decline
relating to the Utah rate order received in March 1999. These decreases were
partially offset by decreased interest expense and increased interest income
having a total effect of $10 million, or $0.03 per share, due to funds
received by domestic electric operations as intercompany dividends from
Holdings of $500 million and $660 million in October 1998 and January 1999,
respectively.
<PAGE>13
The Company's Australian electric operations contributed earnings of $9
million, or $0.03 per share, in the second quarter of 1999, compared to $7
million, or $0.02 per share, in 1998. Second quarter 1998 earnings were
reduced by $3 million, or $0.01 per share, due to a reserve for a product
recall.
Other operations reported earnings of $3 million, or $0.01 per share, in the
quarter compared to earnings of $15 million, or $0.05 per share, in 1998. This
decrease was primarily due to an after-tax gain of $10 million, or $0.03 per
share, recorded on the sale of the TEG shares acquired in March 1998.
Comparison of the six-month periods ended June 30, 1999 and 1998
________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss) on
common stock
Domestic Electric Operations $113.2 $ 58.5 $ 54.7 94
Australian Electric Operations 19.5 20.7 (1.2) (6)
Other Operations 4.0 (24.5) 28.5 116
_____ _____ _____
Continuing Operations 136.7 54.7 82.0 150
Discontinued Operations 1.1 (38.6) 39.7 103
_____ _____ _____
Total $137.8 $ 16.1 $121.7 *
===== ===== =====
Earnings (loss) per common share -
Basic and dilutive
Continuing Operations $ 0.46 $ 0.18 $ 0.28 *
Discontinued Operations - (0.13) 0.13 100
_____ _____ _____
Total $ 0.46 $ 0.05 $ 0.41 *
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
The Company recorded earnings on common stock of $138 million, or $0.46 per
share, in 1999 compared to $16 million, or $0.05 per share, in 1998. The 1998
results included an after-tax charge of $70 million, or $0.24 per share,
associated with the Company's work force reduction in the United States, an
after-tax charge of $54 million, or $0.18 per share, associated with the
Company's terminated bid for TEG, a $10 million, or $0.03 per share, gain
relating to the sale of the TEG shares, a $2 million, or $0.01 per share, loss
relating to closing foreign currency options in April 1998 associated with the
terminated bid for TEG and a $39 million, or $0.13 per share, loss from the
Company's energy trading activities, which the Company decided to discontinue
in October 1998.
Domestic electric operations earnings contribution was $113 million, or $0.38
per share, in 1999 compared to $59 million, or $0.20 per share, in 1998.
Excluding the $70 million charge relating to the work force reduction, the
earnings contribution in 1998 would have been $129 million. The Utah rate
order received in March 1999 reduced earnings $20 million, or $0.07 per share,
and ScottishPower merger costs reduced earnings $8 million, or $0.03 per
share. These decreases were partially offset by decreased interest expense and
increased interest income from the intercompany dividends domestic electric
operations received from Holdings.
The Company's Australian electric operations contributed earnings of $20
million, or $0.07 per share, in 1999, compared to $21 million, or $0.07 per
share, in 1998. Earnings in 1998 were benefited by adjustments totaling $3
<PAGE>14
million associated with the renegotiation of certain Tariff H industrial
customers contracts.
Other operations reported earnings of $4 million, or $0.01 per share, in 1999
compared to a loss of $25 million, or $0.09 per share, in 1998. This increase
was primarily due to an after-tax charge of $54 million for costs associated
with the Company's terminated bid for TEG and a $2 million, or $0.01 per
share, loss relating to closing foreign currency options in April 1998,
partially offset by an after-tax gain of $10 million on the sale of TEG
shares. In addition, interest income decreased $18 million, or $0.06 per
share, as the result of cash dividends paid by Holdings to domestic electric
operations.
<PAGE>15
RESULTS OF OPERATIONS
Domestic Electric Operations
____________________________
Comparison of the three-month periods ended June 30, 1999 and 1998
__________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Revenues
Residential $ 173.4 $ 174.7 $ (1.3) (1)
Commercial 159.4 160.4 (1.0) (1)
Industrial 168.7 176.0 (7.3) (4)
Other 7.7 7.7 - -
_______ _______ _______
Retail sales 509.2 518.8 (9.6) (2)
Wholesale sales and
market trading 244.0 495.7 (251.7) (51)
Other 19.1 17.1 2.0 12
_______ _______ _______
Total 772.3 1,031.6 (259.3) (25)
Operating expenses 630.8 863.6 (232.8) (27)
_______ _______ _______
Income from operations 141.5 168.0 (26.5) (16)
Interest expense 68.1 81.8 (13.7) (17)
Minority interest and other 0.8 (4.2) 5.0 119
Income taxes 30.0 32.7 (2.7) (8)
_______ _______ _______
Net income 42.6 57.7 (15.1) (26)
Preferred dividend requirement 4.8 4.8 - -
_______ _______ _______
Earnings contribution $ 37.8 $ 52.9 $ (15.1) (29)
======= ======= =======
Energy sales (millions of kWh)
Residential 2,789 2,705 84 3
Commercial 3,028 2,924 104 4
Industrial 5,054 5,086 (32) (1)
Other 161 160 1 1
______ ______ _______
Retail sales 11,032 10,875 157 1
Wholesale sales and
market trading 9,209 22,349 (13,140) (59)
______ ______ _______
Total 20,241 33,224 (12,983) (39)
====== ====== =======
Residential average usage (kWh) 2,257 2,185 72 3
Total customers (end
of period) 1,446,500 1,451,503 (5,003) -
</TABLE>
Revenues
Total domestic electric operations revenues decreased $259 million, or 25%,
from the second quarter of 1998. This decrease was primarily attributable to a
$252 million decrease in wholesale revenues. The sale of the Company's Montana
service area in November 1998 decreased revenues $9 million, while the Utah
rate order reduced revenues by $22 million.
Residential revenues were down $1 million, or 1%. Excluding the impact of the
Montana sale, residential revenues were up $3 million, energy volumes were up
6% and customer growth was 2%. Growth in the average number of residential
customers added $3 million to revenues. Volume increases, primarily due to
weather, added $6 million to revenues and price increases in Oregon added $2
million to revenues. The Utah rate order reduced residential revenues by $9
million.
Commercial revenues were down $1 million, or 1%. Excluding the impact of the
Montana sale, commercial revenues were up $2 million, energy volumes were up
6% and customer growth was 2%. Increased commercial customers added $4 million
to
<PAGE>16
revenues. Volume increases added $4 million to revenues and price increases in
Oregon added $2 million to revenues. The Utah rate order reduced commercial
revenues by $9 million.
Industrial revenues decreased $7 million, or 4%. Excluding the impact of the
Montana sale, industrial revenues were down $5 million, energy volumes were
flat and average customers declined 4%. The Company has participated in open
access pilot programs in Oregon that reduced revenues $3 million. Under these
programs, customers were allowed to choose service by another utility, with no
franchise rights to that customer, for a specific time period. These are not
ongoing programs and revenues gained or lost under these programs are not
expected to continue beyond 1999. Increased irrigation usage added $2 million
to industrial revenues. The Utah rate order reduced industrial revenues by $4
million.
Wholesale sales decreased $252 million. The decrease in revenues was driven by
a 59% decline in energy volumes. Lower short-term and spot market wholesale
energy volumes decreased revenues by $271 million. Related energy prices
averaged $20 per MWh in the quarter, a 5% increase over the prior year. The
higher prices for these sales added $20 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.
See Note 4 regarding regulation of domestic electric operations' utility
properties.
Operating Expenses
Total operating expenses decreased $233 million, or 27%. This decrease was
primarily attributable to decreased purchased power expense due to the decline
in wholesale sales.
Purchased power expense was $227 million, a decrease of $241 million. The
lower expense was primarily due to a 13.8 million MWh decrease in short-term
firm and spot market energy purchases which decreased purchased power expense
$278 million. Short-term firm and spot market purchase prices averaged $20 per
MWh in the quarter versus $18 per MWh in 1998, an 11% increase. The increase
in purchase prices increased costs $36 million.
<TABLE>
Short-Term and Spot Market Sales and Purchases
______________________________________________
<CAPTION>
1999 1998
____ ____
<S> <C> <C>
Total sales volume (thousands of MWh) 5,964 19,278
Average sales price ($/MWh) $ 20.30 $ 19.30
_______ _______
Revenues ($, millions) $ 121 $ 372
Total purchase volume (thousands of MWh) 6,230 20,047
Average purchase price ($/MWh) $ 20.49 $ 18.43
_______ _______
Expenses ($, millions) $ 128 $ 369
_______ _______
Net ($, millions) $ (7) $ 3
======= =======
</TABLE>
Fuel expense was up $5 million, or 5%, to $104 million in 1999. Thermal
generation was up 3% to 11.4 million MWh. The average cost per MWh increased
to $9.11 from $8.91 in the prior year due to increased generation at plants
with higher fuel costs. The shift in generation resulted from unscheduled
plant outages and overhauls at plants with lower fuel costs.
Other operations and maintenance and administrative and general expenses
<PAGE>17
remained flat at $199 million. Implementation of the Company's new SAP
software operating environment in 1999 resulted in changes in classification
of costs between operations and maintenance and administrative and general
expenses.
Other operations and maintenance expense increased $25 million, or 21%, to
$139 million. Increased tree trimming added $2 million to expenses, increased
materials and contracts primarily relating to overhaul costs added $5 million,
and increased labor added $2 million. In addition, operations and maintenance
was up $15 million due to costs reclassified from administrative and general
upon conversion to SAP in January 1999.
Administrative and general expenses decreased $25 million, or 29%, to $60
million. This decrease was primarily due to a reduction in labor and employee
related costs of $10 million, a reduction in Year 2000 costs of $2 million and
a reduction in outside services costs of $2 million. In addition,
administrative and general was down $15 million due to costs reclassified to
operations and maintenance upon conversion to SAP in January 1999. These
decreases were partially offset by a $3 million increase in costs relating to
the implementation of the Company's new SAP software operating environment.
Depreciation and amortization expense increased $3 million, or 3%, to $102
million due to a $7 million increase relating to additional plant in service,
partially offset by a $4 million reduction from lower rates.
Other Income and Expense
Domestic electric operations interest expense was down $14 million as a result
of lower debt balances. The lower debt balances were due to dividends received
from Holdings in October 1998 and January 1999 that were used to pay down
intercompany debt owed to Holdings and some external debt. Other expense was
up $9 million primarily due to $8 million in ScottishPower merger costs. This
increase was partially offset by increased interest income of $2 million as a
result of the dividends received from Holdings, some of which were invested in
interest bearing investments.
<PAGE>18
Comparison of the six-month periods ended June 30, 1999 and 1998
________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Revenues
Residential $ 404.6 $ 406.5 $ (1.9) -
Commercial 318.4 321.8 (3.4) (1)
Industrial 320.5 338.7 (18.2) (5)
Other 14.9 15.3 (0.4) (3)
_______ _______ _______
Retail sales 1,058.4 1,082.3 (23.9) (2)
Wholesale sales and
market trading 484.0 994.8 (510.8) (51)
Other 37.1 31.5 5.6 18
_______ _______ _______
Total 1,579.5 2,108.6 (529.1) (25)
Operating expenses 1,242.4 1,844.8 (602.4) (33)
_______ _______ _______
Income from operations 337.1 263.8 73.3 28
Interest expense 135.7 161.8 (26.1) (16)
Minority interest and other (5.2) (6.9) 1.7 25
Income taxes 83.8 40.8 43.0 105
_______ _______ _______
Net income 122.8 68.1 54.7 80
Preferred dividend requirement 9.6 9.6 - -
_______ _______ _______
Earnings contribution $ 113.2 $ 58.5 $ 54.7 94
======= ======= =======
Energy sales (millions of kWh)
Residential 6,562 6,456 106 2
Commercial 6,021 5,916 105 2
Industrial 9,682 9,977 (295) (3)
Other 314 319 (5) (2)
______ ______ _______
Retail sales 22,579 22,668 (89) -
Wholesale sales and
market trading 18,845 44,792 (25,947) (58)
______ ______ _______
Total 41,424 67,460 (26,036) (39)
====== ====== =======
Residential average usage (kWh) 5,320 5,225 95 2
Total customers (end of
period) 1,446,500 1,451,503 (5,003) -
</TABLE>
Revenues
Total domestic electric operations revenues decreased $529 million, or 25%,
from 1998. This decrease was primarily attributable to a $511 million decrease
in wholesale revenues. The sale of the Company's Montana service area in
November 1998 decreased revenues $21 million, while the Utah rate order
reduced revenues by $32 million.
Residential revenues were down $2 million. Excluding the impact of the Montana
sale, residential revenues were up $8 million, energy volumes were up 4% and
customer growth was 2%. Growth in the average number of residential customers
added $8 million to revenues. Volume increases, primarily due to weather,
added $10 million to revenues and price increases in Oregon added $3 million
to revenues. The Utah rate order reduced residential revenues by $13 million.
Commercial revenues were down $3 million, or 1%. Excluding the impact of the
Montana sale, commercial revenues were up $3 million, energy volumes were up
4% and customer growth was 3%. Increased commercial customers added $9 million
to revenues. Volume increases added $4 million to revenues and price increases
in Oregon added $3 million to revenues. The Utah rate order reduced commercial
revenues by $13 million.
Industrial revenues decreased $18 million, or 5%. Excluding the impact of the
<PAGE>19
Montana sale, industrial revenues were down $13 million, energy volumes were
down 2% and average customers declined 4%. Decreased energy volumes due to the
cyclical nature of industrial customer usage drove a $6 million decrease in
revenues. The Company has participated in open access pilot programs in Oregon
that reduced revenues $4 million. Increased irrigation usage added $2 million
to industrial revenues. The Utah rate order reduced industrial revenues by $6
million.
Wholesale sales decreased $511 million, or 51%. The decrease in revenues was
driven by a 58% decline in energy volumes. Lower short-term and spot market
wholesale energy volumes decreased revenues by $536 million. Related energy
prices averaged $20 per MWh in 1999, a 3% increase over the prior year. The
higher prices for these sales added $27 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.
Other revenue increased $6 million, or 18%, due to increased wheeling revenue.
See Note 4 regarding regulation of domestic electric operations' utility
properties.
Operating Expenses
Total operating expenses decreased $602 million, or 33%. This decrease was
primarily attributable to decreased purchased power expense due to the decline
in wholesale sales and the $113 million pretax special charge in 1998 for the
workforce reduction.
Purchased power expense decreased $490 million, to $436 million. The lower
expense was primarily due to a 26.4 million MWh decrease in short-term firm
and spot market energy purchases which decreased purchased power expense $523
million. Short-term firm and spot market purchase prices averaged $20 per MWh
in 1999 versus $19 per MWh in 1998, a 5% increase. The increase in purchase
prices increased costs $29 million.
<TABLE>
Short-Term and Spot Market Sales and Purchases
______________________________________________
<CAPTION>
1999 1998
____ ____
<S> <C> <C>
Total sales volume (thousands of MWh) 11,683 38,177
Average sales price ($/MWh) $ 20.31 $ 19.53
_______ _______
Revenues ($, millions) $ 237 $ 746
Total purchase volume (thousands of MWh) 11,326 37,681
Average purchase price ($/MWh) $ 19.67 $ 19.02
_______ _______
Expenses ($, millions) $ 223 $ 717
_______ _______
Net ($, millions) $ 14 $ 29
======= ========
</TABLE>
Fuel expense was up $2 million, or 1%, to $223 million in 1999. Thermal
generation was down 1% to 24.2 million MWh. The average cost per MWh increased
to $9.22 from $9.06 in the prior year due to increased generation at plants
with higher fuel costs. The shift in generation resulted from unscheduled
plant outages and overhauls at plants with lower fuel costs. Hydroelectric
generation increased 10% compared to 1998 due to favorable water conditions.
Other operations and maintenance and administrative and general expenses was
$384 million, a decrease of $3 million. Implementation of the Company's new
SAP software operating environment in 1999 resulted in changes in
classification of costs between operations and maintenance and administrative
and general expenses.
<PAGE>20
Other operations and maintenance expense increased $27 million, or 12%, to
$252 million. Increased tree trimming added $5 million to expenses and
increased materials and contracts primarily relating to overhaul costs added
$5 million. In addition, operations and maintenance was up $15 million due to
costs reclassified from administrative and general upon conversion to SAP in
January 1999.
Administrative and general expenses decreased $30 million, or 18%, to $133
million. This decrease was primarily due to a reduction in labor and employee
related costs of $22 million and a reduction in Year 2000 costs of $2 million.
In addition, administrative and general was down $15 million due to costs
reclassified to operations and maintenance upon conversion to SAP in January
1999. These decreases were partially offset by a $9 million increase in costs
relating to the ongoing implementation of the Company's new SAP software
operating environment.
Depreciation and amortization expense increased $2 million, or 1%, to $199
million due to $10 million of costs attributable to increased plant in
service, partially offset by an $8 million reduction from lower rates.
Other Income and Expense
Domestic electric operations interest expense was down $26 million as a result
of lower debt balances. The lower debt balances were due to the dividends
received from Holdings that were used to pay down intercompany debt owed to
Holdings and some external debt. Other expense was up $6 million primarily due
to $8 million in ScottishPower merger costs and $11 million in decreased
emission allowance sales. These increases were partially offset by increased
interest income of $6 million as a result of the dividends received from
Holdings, some of which was invested in interest bearing investments. Income
tax expense was $84 million, an increase of $43 million due to the increase in
pretax income.
<PAGE>21
Australian Electric Operations
______________________________
Comparison of the three-month periods ended June 30, 1999 and 1998
__________________________________________________________________
<TABLE>
<CAPTION>
Change Due Change % Change
to Currency Due to Due to
1999 1998 Translation Operations Operations
____ ____ ___________ __________ __________
(Dollars in Millions)
<S> <C> <C> <C> <C> <C>
Powercor Earnings Contribution
Revenues
Powercor area $109.0 $112.3 $ 4.4 $ (7.7) (7)
Outside Powercor area
Victoria 17.8 20.0 0.7 (2.9) (15)
New South Wales 17.6 16.9 0.8 (0.1) (1)
Queensland 0.6 - - 0.6 *
Australian Capital
Territory 0.3 - - 0.3 *
_____ _____ _____ _____
145.3 149.2 5.9 (9.8) (7)
Other 15.1 7.9 0.2 7.0 89
_____ _____ _____ _____
Total 160.4 157.1 6.1 (2.8) (2)
Operating expenses 130.9 127.6 4.7 (1.4) (1)
_____ _____ _____ _____
Income from operations 29.5 29.5 1.4 (1.4) (5)
Interest expense 14.4 14.4 0.6 (0.6) (4)
Equity in (income)/losses
of Hazelwood 1.9 1.2 0.2 0.5 42
Other (income)/expense (0.3) 3.4 - (3.7) (109)
Income taxes 4.4 3.9 0.2 0.3 8
_____ _____ _____ _____
Earnings contribution $ 9.1 $ 6.6 $ 0.4 $ 2.1 32
===== ===== ===== =====
Powercor energy sales (millions of kWh)
Powercor area 1,711 1,867 (156) (8)
Outside Powercor area
Victoria 549 590 (41) (7)
New South Wales 528 508 20 4
Queensland 15 - 15 *
Australian Capital Territory 8 - 8 *
_____ _____ _____
Total 2,811 2,965 (154) (5)
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Currency Exchange Rates
The currency exchange rate for converting Australian dollars to U. S. dollars
was 0.65 in the second quarter of 1999 as compared to 0.63 in 1998, a 3%
increase. The effect of this change in exchange rates increased both revenues
and costs by $6 million in the second quarter of 1999.
The following discussion excludes the effects of the higher currency exchange
rates in 1999.
Revenue
Australia's revenues decreased $3 million, or 2%. This decrease was driven by
a decline in energy volumes sold of 154 million kWh, or 5%, resulting in a $7
million decline in revenues.
Energy volumes sold to contestable customers outside Powercor's franchise area
were flat and decreased prices reduced revenues $2 million compared to the
second quarter of 1998. Inside Powercor's franchise area, revenues decreased
$8
<PAGE>22
million primarily due to a 156 million kWh decrease in energy sold. Volumes
were down due to the loss of a few large contestable industrial customers.
Other revenues increased $7 million, largely due to the recognition of an $8
million contract settlement received from the Australian government, partially
offset by $3 million associated with Tariff H contracts recognized in the
second quarter of 1998.
Operating Expenses
Purchased power expense increased $3 million, or 4%, to $73 million. Higher
average prices increased power costs by $5 million. Prices for purchased power
averaged $25 per MWh in the second quarter of 1999 compared to $23 per MWh in
the second quarter of 1998. This price increase was the result of a contract
dispute between Powercor and one of its power suppliers in Australia. The
power supplier did not meet its contractual obligation to deliver power to
Powercor at the agreed upon rate, which forced Powercor to purchase power on
the open market at a higher rate than last year. This price increase was
partially offset by decreased purchase volumes that reduced expenses $3
million.
Year to date, the contract dispute with the power supplier has resulted in $15
million of higher purchased power costs and $2 million in legal fees. Powercor
has brought suit to enforce the contract and recover its damages. Although the
ultimate financial outcome of the litigation cannot be determined at this
time, the Company believes it will be favorable as all costs incurred for
replacement power and legal fees have been expensed as incurred.
Depreciation decreased $2 million, or 12%, to $13 million due to an increase
in asset lives resulting from a recent engineering study and upon
recommendation from regulatory authorities in Australia.
Other operating expenses decreased $2 million, or 5%, to $45 million. An
increase in the number of customers inside Powercor's franchise area serviced
by other energy suppliers resulted in higher network revenues of $5 million.
Maintenance decreased $3 million in the second quarter of 1999 primarily due
to the second quarter of 1998 including costs relating to the replacement of
the faulty switches associated with a product recall. Administrative and
general increased $5 million primarily due to restructure costs, increased
salaries and legal fees associated with the disputed purchase power contracts.
Other Income and Expense
Other expense decreased $4 million primarily due to a reserve recorded in 1998
relating to a product recall. Powercor is in the process of negotiating
recovery from the product's manufacturer.
<PAGE>23
Comparison of the six-month periods ended June 30, 1999 and 1998
________________________________________________________________
<TABLE>
<CAPTION>
Change Due Change % Change
to Currency Due to Due to
1999 1998 Translation Operations Operations
____ ____ ___________ __________ __________
(Dollars in Millions)
<S> <C> <C> <C> <C> <C>
Powercor Earnings Contribution
Revenues
Powercor area $212.2 $228.8 $ (1.1) $(15.5) (7)
Outside Powercor area
Victoria 35.9 40.9 (0.2) (4.8) (12)
New South Wales 37.0 37.1 (0.1) - -
Queensland 1.1 - - 1.1 *
Australian Capital
Territory 0.7 - - 0.7 *
_____ _____ _____ _____
286.9 306.8 (1.4) (18.5) (6)
Other 20.5 12.8 (0.1) 7.8 61
_____ _____ _____ _____
Total 307.4 319.6 (1.5) (10.7) (3)
Operating expenses 243.1 249.3 (1.1) (5.1) (2)
_____ _____ _____ _____
Income from operations 64.3 70.3 (0.4) (5.6) (8)
Interest expense 28.8 30.2 (0.1) (1.3) (4)
Equity in losses of Hazelwood 5.6 4.2 - 1.4 33
Other (income)/expense (0.4) 3.0 - (3.4) (113)
Income taxes 10.8 12.2 (0.1) (1.3) (11)
_____ _____ _____ _____
Earnings contribution $ 19.5 $ 20.7 $ (0.2) $ (1.0) (5)
===== ===== ===== =====
Powercor energy sales (millions of kWh)
Powercor area 3,377 3,664 (287) (8)
Outside Powercor area
Victoria 1,135 1,190 (55) (5)
New South Wales 1,107 1,083 24 2
Queensland 28 - 28 *
Australian Capital Territory 16 - 16 *
_____ _____ _____
Total 5,663 5,937 (274) (5)
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Currency Exchange Rates
The currency exchange rate for converting Australian dollars to U.S. dollars
was 0.64 in 1999 as compared to 0.65 in 1998. The effect of this change in
exchange rates lowered both revenues and costs by $2 million.
The following discussion does not include the effects of the lower currency
exchange rate in 1999.
Revenue
Australia's revenues decreased $11 million, or 3%. This decrease was driven by
a decline in energy volumes sold of 274 million kWh, or 5%, resulting in a $7
million decline in revenues.
Energy volumes sold to contestable customers outside Powercor's franchise area
were up 12 million kWh and added $1 million in revenues due to customer gains
in Queensland and the Australian Capital Territory. Decreased prices reduced
revenues $4 million compared to 1998. Inside Powercor's franchise area,
revenues decreased $16 million primarily due to a 287 million kWh decrease in
energy sold. Volumes are down due to the loss of a few large contestable
industrial customers.
<PAGE>24
Other revenues increased $8 million due to the recognition of an $8 million
contract settlement received from the Australian government and $2 million
from construction projects for customers who own their own distribution
assets, including other distribution businesses in Australia. These increases
were partially offset by $5 million associated with Tariff H contracts
recognized in the second quarter of 1998.
Operating Expenses
Purchased power expense increased $7 million, or 5%, to $132 million. Higher
average prices increased power costs by $12 million. Prices for purchased
power averaged $23 per MWh in 1999 compared to $21 per MWh in 1998. This price
increase was the result of the contract dispute between Powercor and one of
its power suppliers in Australia. This price increase was partially offset by
decreased purchase volumes that reduced expenses $5 million.
Other operating expenses decreased $13 million, or 25%, to $40 million.
Decreased rates resulted in lower network fees of $2 million and an increase
in the number of customers inside Powercor's franchise area serviced by other
energy suppliers resulted in higher network revenues of $11 million.
Maintenance decreased $3 million primarily because 1998 included costs
relating to the replacement of the faulty switches associated with a product
recall.
Administrative and general increased $5 million primarily due to restructure
costs, increased salaries and legal fees associated with the disputed purchase
power contracts.
Other Income and Expense
Other expense decreased $3 million primarily due to a reserve recorded in 1998
relating to the product recall described above.
The Company recorded losses in 1999 of $5 million compared to losses of $4
million in 1998 on its equity investment in the Hazelwood power station.
<PAGE>25
Other Operations
________________
Comparison of the three-month periods ended June 30, 1999 and 1998
__________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution
PFS $ 3.1 $ 0.9 $ 2.2 *
Holdings and other
TEG costs - 7.9 (7.9) (100)
Other 0.2 5.8 (5.6) (96)
_____ _____ _____
$ 3.3 $ 14.6 $(11.3) (77)
===== ===== =====
<FN>
*Not a meaningful number.
</FN>
</TABLE>
Other operations reported earnings of $3 million, or $0.01 per share, in the
quarter compared to earnings of $15 million, or $0.05 per share, in the same
period a year ago. On June 2, 1998, a subsidiary of Holdings sold
approximately 46 million shares of TEG stock and recorded an after-tax gain of
$10 million, or $0.03 per share. In April 1998, the Company incurred a loss of
$2 million, or $0.01 per share, relating to the closing of foreign currency
options associated with the terminated bid for TEG.
Results from other operations for the quarter were reduced by approximately $7
million, or $0.02 per share, in decreased interest income as the result of
cash dividends of $500 million paid in October 1998 and $660 million paid in
January 1999 by Holdings to domestic electric operations. This cash had been
invested by Holdings in interest bearing investments prior to the dividends.
Other energy development activities incurred losses of $7 million, or $0.02
per share, in the second quarter of 1998. In October 1998, the Company
announced its intention to dispose of these businesses.
<PAGE>26
Comparison of the six-month periods ended June 30, 1999 and 1998
________________________________________________________________
<TABLE>
<CAPTION>
%
1999 1998 Change Change
____ ____ ______ ______
(Dollars in Millions)
<S> <C> <C> <C> <C>
Earnings contribution (loss)
PFS $ 2.8 $ 7.5 $ (4.7) (62)
Holdings and other
TEG costs - (45.6) 45.6 100
Other 1.2 13.6 (12.4) (91)
_____ _____ _____
$ 4.0 $(24.5) $ 28.5 116
===== ===== =====
</TABLE>
Other operations reported income of $4 million, or $0.01 per share, compared
to a loss of $25 million, or $0.09 per share, in the same period a year ago.
The increase in earnings was primarily due to an $86 million pretax ($54
million after-tax) charge in 1998 for costs associated with the Company's
terminated bid for TEG, partially offset by a $16 million pretax ($10 million
after-tax) gain on the sale of TEG shares.
Results from other operations were reduced by approximately $18 million, or
$0.06 per share, in decreased interest income as the result of the cash
dividends paid by Holdings to domestic electric operations. This cash had been
invested by Holdings in interest bearing instruments prior to the dividends.
PFS reported income of $3 million in 1999 compared to $8 million in 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 had earnings of $1 million in 1999
compared to a loss of $12 million in 1998. This reduction in losses was the
result of the decision to exit these development businesses in October 1998.
<PAGE>27
FINANCIAL CONDITION -
For the six months ended June 30, 1999:
OPERATING ACTIVITIES
Net cash flows provided by continuing operations were $399 million
during the period compared to $359 million in the first six months of 1998.
The $40 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 $277 million in 1999 compared with $332 million
in 1998. Construction expenditures decreased $23 million in 1999 primarily due
to the construction of the Synfuels plant in 1998. Investments in and advances
to affiliated companies-net was down $19 million because the first quarter of
1998 included PFS's investment in Covol Technologies, Inc., the company that
developed the technology licensed by Synfuels.
On May 10, 1999, the utility partners who own the 1,340 MW coal-fired
Centralia Power Plant announced their intention to sell the plant and the
adjacent coal mine owned by the Company to TransAlta for $554 million. The
sale is subject to regulatory approval and is expected to close during the
first half of 2000. The Company operates the plant and owns a 47.5% share. The
Company expects to realize a gain on the sale, but the amount will not be
determined until the regulatory approval process has been completed.
CAPITALIZATION
At June 30, 1999, PacifiCorp had approximately $156 million of
commercial paper and uncommitted bank borrowings outstanding at a weighted
average rate of 6.2%. These borrowings are supported by $700 million of
revolving credit agreements. At June 30, 1999, the consolidated subsidiaries
had access to $726 million of short-term funds through committed bank
revolving credit agreements. Subsidiaries had $438 million outstanding under
bank revolving credit facilities. At June 30, 1999, the Company and its
subsidiaries had $553 million of short-term debt classified as long-term debt
as they have the intent and ability to support short-term borrowings through
the various revolving credit facilities on a long-term basis. The Company and
its subsidiaries have intercompany borrowing arrangements providing for
temporary loans of funds between parties at short-term market rates.
INTEREST RATE EXPOSURE
The Company's market risk to interest rate change is primarily related to
long-term debt with fixed interest rates. The Company uses interest rate
swaps, forwards, futures and collars to adjust the characteristics of its
liability portfolio. This strategy is consistent with the Company's capital
structure policy that provides guidance on overall debt to equity and variable
rate debt as a percent of capitalization levels for both the consolidated
organization and its principal subsidiaries. Based on the Company's overall
interest rate exposure, the estimated potential one-day loss in fair value as
a result of near-term change in interest rates, within a 95% confidence level
using historical interest rate movements based on the VAR model, was $38
million at June 30, 1999.
<PAGE>28
YEAR 2000
The Company's Year 2000 project has been underway since mid-1996. A
standard methodology of inventory, assessment, remediation and testing of
hardware, software and equipment was implemented. The main areas of risk are
in: power supply (generating plant and system controls); information
technology (computer software and hardware); business disruption; and supply
chain disruption. The first two areas of risk are within the Company's own
business operations. The others are areas of risk the Company might face from
interaction with other companies, such as critical suppliers and customers.
The Company's plan was to successfully identify, correct and test its existing
critical systems by July 1, 1999, and to require all new hardware or software
acquired by the Company to be vendor certified Year 2000 ready before it is
installed.
The Company completed its testing and remediation on all critical
systems and met the July 1, 1999 milestone to be ready for the year 2000.
Following months of successful preparation and testing the Company has
finished advancing the system clocks in all thermal generating units and
substations to dates beyond March 1, 2000. The Company will reset the dates on
equipment during the second quarter of 2000. By operating in the year 2000
now, the Company is demonstrating confidence in its Year 2000 preparation and
plans to conduct business as usual on January 1, 2000. This also reduces any
risks inherent in the end-of-year and leap year date turnovers to producing
and delivering electric power.
The Company's Year 2000 project office continues to coordinate all Year
2000 activities throughout the corporation, as well as with suppliers and
business partners. This work will continue well into the first quarter of
2000 with full-time employees and contractors completing the final wrap-up of
the project. The following summarizes the status of the Year 2000 project as
of July 1, 1999.
Areas complete (as of July 1, 1999)
___________________________________
Computer Systems - Correct and Test
Computer Systems - Applications to replace
Electric Systems - Inventory
Electric Systems - Assessment
Electric Systems - Correct and Test
Initial Contingency planning
Areas to be completed Target Date for Completion Status
_____________________ __________________________ ______
Computer Systems - Desktop September 30, 1999 On schedule
Non-Critical Systems -
Enterprise wide September 30, 1999 On schedule
Continued compliance testing October 30, 1999 On schedule
Contingency planning September 30, 1999 On going
As the Company finalizes its Year 2000 readiness, the focus will shift
to a management program to maintain its Year 2000-ready status. This strategy
includes Year 2000 testing of all system modifications and qualifying all new
equipment as Year 2000 ready before it is purchased and installed.
<PAGE>29
The Company is actively working with its suppliers of products and
services to determine the extent to which the suppliers' operations, and the
products and services they provide, are Year 2000 ready. The Company believes
it has identified and assessed 100% of its critical third-party suppliers. The
Company's critical third-party vendors reported they would be Year 2000 ready
on or before the dates below:
Readiness Target Dates Percent of all Critical Third
(on or before) Parties Ready
12/31/1998 14%
03/31/1999 18%
06/30/1999 61%
09/30/1999 92%
12/31/1999 99%
(no Readiness Target Date reported) 1%
The Company is in contact with these third parties, and their Year 2000
readiness information is updated as required.
To the extent that these parties are considered mission-critical to the
business and experience Year 2000 problems in their systems, the mission-
critical business functions may be adversely affected. The Company plans to
mitigate this risk by developing and testing contingency plans throughout
1999.
As of December 31, 1998, the Company had no single retail customer that
accounted for more than 1.7% of its retail utility revenues and the 20 largest
retail customers accounted for 13.9% of total retail electric revenues. The
Company has not performed a formal assessment of its customers' Year 2000
readiness.
The Company's mining operations contingency plan calls for increased
stockpiles of fuel to be available to supply the generating plants.
The Company, the North American Electric Reliability Council ("NERC")
and the Western Systems Coordinating Council ("WSCC") are working closely
together to ensure the integrity of the interconnected electrical distribution
and transmission system in the Company's service area and the western United
States. NERC coordinates the efforts of the ten regional electric reliability
councils throughout the United States, while WSCC is focused on reliable
electric service in the western United States. These agencies require Year
2000 readiness for all interconnected electric utilities by July 1, 1999. The
Company has submitted its draft contingency plans to the WSCC as required by
NERC. The Company successfully participated in the NERC sponsored industry
preparedness 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.
<PAGE>30
4. Temporary loss of customer billing system. Customers on billing
cycles in the early part of the month may receive an estimated
billing that will be adjusted the following month.
5. Temporary loss of receivables processing system.
6. Temporary loss of automated payroll system. Employees will be
paid, but some automated functions must be performed manually.
7. Temporary loss of automated shareholder services systems.
Information must be available to be accessed manually while
automated systems are being restored.
To address this potential scenario and in cooperation with efforts by
NERC and WSCC, the Company plans to establish a precautionary posture for its
system leading into December 31, 1999. This is similar to the posture taken
when severe winter weather is anticipated in areas of its service territory.
Regional connections would be deliberately disconnected only during, or
immediately following, a system disturbance in order to prevent further
cascading outages and to facilitate restoration. Additional personnel will be
on hand at control centers. Facilities such as power plants and key major
substations will also have additional personnel standing by. Backup systems
will be serviced and tested, as appropriate, prior to the transition period.
Additional generation will be brought on line for the transition period as
needed.
The Company is continuing to expand its extensive microwave network in
1999. Because this system is self-controlled and has been undergoing extensive
analysis for Year 2000 readiness, the Company considers this a reliable
alternative to the public telephone network if needed. Emergency power systems
will be tested and made ready. In addition to the microwave system, the
Company has an extensive radio network. Through integration of the Company's
radio and microwave facilities, Company personnel can effectively "dial-up"
telephones throughout the Company's area. Radio units will be deployed at key
locations during the transition period. The Company is also planning to
station satellite telephones at system dispatching facilities and key power
plants.
The Company's payment processing system has been certified by the vendor
as Year 2000 ready. An emergency backup plan is being developed for deployment
in 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's systems to maintain
shareholder records, transfer stock, issue 1099 dividend statements and
process dividend payments are certified Year 2000 ready.
Powercor
________
Powercor has experienced schedule delays relating to Year 2000
remediation efforts in its customer information system (the "CIS"). Powercor
has developed a new schedule that indicates replacement and testing will be
completed in time for the CIS to be placed in service prior to the year 2000.
In the event the replacement system is not functional by the year 2000,
customers on billing cycles in the early part of the month may receive an
estimated billing that will be adjusted the following quarter.
<PAGE>31
Mining
______
Few Year 2000 impacts have been identified within the mining
subsidiaries. The Year 2000 project continues according to schedule. Legacy
business systems are being upgraded or replaced to address Year 2000 issues
and these efforts will be completed in October 1999.
The Company has incurred $17.1 million in costs relating to the Year
2000 project through June 30, 1999. The majority of these costs have been
incurred to repair software problems. The total cost of the Year 2000 project
is estimated at $26 to $30 million, which will be principally funded from
operating cash flows. This estimate does not include the cost of system
replacements that will be Year 2000 ready, but are not being installed
primarily to resolve Year 2000 problems. Year 2000 information technology
("IT") remediation costs amount to approximately 5% of IT's budget. The
Company has not delayed any IT projects that are critical to its operations as
a result of Year 2000 remediation work. No independent verification of risk
and cost estimates has been undertaken to date.
The dates on which the Company believes the Year 2000 project will be
completed and the expected costs and other impacts of the Year 2000 issues are
based on management's best estimates, which were derived utilizing numerous
assumptions concerning future events, including the availability of certain
resources, the completion of third-party modification plans and other factors.
There can be no assurance that these estimates will be achieved, or that there
will not be a delay in, or increased costs associated with, the Company's
implementation of its Year 2000 project.
______________________________________________________________________________
The condensed consolidated financial statements as of June 30, 1999 and
December 31, 1998 and for the three-and six-month periods ended June 30, 1999
and 1998 have been reviewed by Deloitte & Touche LLP, independent accountants,
in accordance with standards established by the American Institute of
Certified Public Accountants. A copy of their report is included herein.
<PAGE>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, 1999, and the related condensed
consolidated statements of income and retained earnings for the three- and
six-month periods ended June 30, 1999 and 1998 and related condensed
consolidated statements of cash flows for the six-month periods ended June 30,
1999. 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
August 9, 1999
<PAGE>33
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
______ ___________________________________________________
At the Company's annual meeting of shareholders on June 17, 1999,
the shareholders approved the ScottishPower merger. Votes cast by
common shareholders in relation to this matter are summarized as
follows:
<TABLE>
<CAPTION>
Against Or Abstentions And
For Withheld Broker Non-votes
___ __________ ________________
<S> <C> <C> <C>
207,506,780 27,051,938 3,429,939
</TABLE>
Preferred shareholder votes cast in relation to this matter are
summarized as follows:
<TABLE>
<CAPTION>
Against Or Abstentions And
For Withheld Broker Non-votes
___ __________ _________________
<S> <C> <C> <C>
2,197,613 8,403 8,973
</TABLE>
The shareholders ratified the appointment of Deloitte & Touche LLP
to serve as independent auditors of the Company for the year 1999.
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>
265,917,331 1,497,613 5,106,970
</TABLE>
The shareholders also elected two Class III Directors, each for
terms expiring at the Annual Meeting in the year 2002. 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 III
Nancy Wilgenbusch 264,046,341 8,474,464 -
Peter I. Wold 264,070,107 8,450,698 -
</TABLE>
The Directors whose terms continued and the years their terms
expire are as follows:
W. Charles Armstrong (Class I, 2000); C. Todd Conover (Class I,
2000); Nolan E. Karras (Class I, 2000); Kathryn Braun Lewis (Class
II, 2001); Keith R. McKennon (Class I, 2000); Robert G. Miller
(Class II, 2001); Alan K. Simpson (Class II, 2001); Verl R. Topham
(Class II, 2001).
At the Company's annual meeting, preferred shareholders voted to
increase the Company's unsecured debt limit. Votes cast in
relation to this matter are as follows:
<TABLE>
<CAPTION>
Against Or Abstentions And
For Withheld Broker Non-votes
___ ___________ ________________
<S> <C> <C> <C>
2,143,085 62,639 9,165
</TABLE>
<PAGE>34
Item 6. Exhibits and Reports on Form 8-K
______ ________________________________
(a) Exhibits.
Exhibit 12(a): Statements of Computation of Ratio of Earnings to
Fixed Charges.
Exhibit 12(b): Statements of Computation of Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends.
Exhibit 15: Letter re unaudited interim financial information.
Exhibit 27: Financial Data Schedule for the quarter ended
June 30, 1999 (filed electronically only).
(b) Reports on Form 8-K.
None
<PAGE>35
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
PACIFICORP
Date August 11, 1999 By ROBERT R. DALLEY
__________________________ ____________________________________
Robert R. Dalley
Controller and
Chief Accounting Officer
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION PAGE
_______ ___________ ____
<S> <C> <C>
Exhibit 12(a): Statements of Computation of Ratio of
Earnings to Fixed Charges.
Exhibit 12(b): Statements of Computation of Ratio of
Earnings to Combined Fixed Charges and Preferred Stock
Dividends.
Exhibit 15: Letter re unaudited interim financial
information.
Exhibit 27: Financial Data Schedule for the quarter
ended June 30, 1999 (filed electronically only).
</TABLE>
<PAGE>
<TABLE>
EXHIBIT (12)(a)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO FIXED CHARGES
<CAPTION>
Six Months
Ended
1994 1995 1996 1997 1998 June 30, 1999
____ ____ ____ ____ ____ _____________
(In Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense................... $ 302.0 $ 336.4 $ 415.0 $ 438.1 $ 371.7 $174.9
Estimated interest portion of
rentals charged to expense....... 5.6 4.5 4.1 6.6 5.7 4.5
Preferred dividends of
wholly owned subsidiary.......... - - 15.3 32.9 42.9 23.4
-----------------------------------------------------------------
Total fixed charges............ $ 307.6 $ 340.9 $ 434.4 $ 477.6 $ 420.3 $202.8
=================================================================
Earnings, as defined:*
Income from continuing operations.. $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7 $239.1
Add (deduct):
Provision for income taxes....... 209.0 192.1 236.5 111.8 59.1 92.8
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 5.7
Fixed charges as above........... 307.6 340.9 434.4 477.6 420.3 202.8
-----------------------------------------------------------------
Total earnings................. $ 900.7 $ 921.8 $1,084.8 $ 813.0 $ 658.7 $540.4
=================================================================
Ratio of Earnings to Fixed Charges... 2.9x 2.7x 2.5x 1.7x 1.6x 2.7x
=================================================================
<FN>
* "Fixed charges" represent consolidated interest charges, an estimated amount representing the interest
factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Earnings" represent
the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing
operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges,
(d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees.
</FN>
</TABLE>
<PAGE>
<TABLE>
EXHIBIT (12)(b)
PACIFICORP
STATEMENTS OF COMPUTATION OF RATIO
OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
Six Months
Ended
1994 1995 1996 1997 1998 June 30, 1999
____ ____ ____ ____ ____ _____________
(In Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges, as defined:*
Interest expense.................. $ 302.0 $ 336.4 $ 415.0 $ 438.1 $ 371.7 $174.9
Estimated interest portion of
rentals charged to expense.... 5.6 4.5 4.1 6.6 5.7 4.5
Preferred dividends of
wholly owned subsidiary....... - - 15.3 32.9 42.9 23.4
----------------------------------------------------------------
Total fixed charges......... 307.6 340.9 434.4 477.6 420.3 202.8
Preferred Stock Dividends,
as defined:*.................. 60.8 57.2 46.2 33.8 29.5 15.7
----------------------------------------------------------------
Total fixed charges and
preferred dividends....... $ 368.4 $ 398.1 $ 480.6 $ 511.4 $ 449.8 $218.5
================================================================
Earnings, as defined:*
Income from continuing
operations.................... $ 397.5 $ 402.4 $ 430.3 $ 232.8 $ 169.7 $239.1
Add (deduct):
Provision for income taxes.... 209.0 192.1 236.5 111.8 59.1 92.8
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 5.7
Fixed charges as above........ 307.6 340.9 434.4 477.6 420.3 202.8
----------------------------------------------------------------
Total earnings.............. $ 900.7 $ 921.8 $1,084.8 $ 813.0 $ 658.7 $540.4
================================================================
Ratio of Earnings to Combined Fixed
Charges and Preferred Stock
Dividends....................... 2.4x 2.3x 2.3x 1.6x 1.5x 2.5x
================================================================
<FN>
* "Fixed charges" represent consolidated interest charges, an estimated amount representing the interest
factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Preferred Stock
Dividends" represent preferred dividend requirements multiplied by the ratio which pre-tax income from
continuing operations bears to income from continuing operations. "Earnings" represent the aggregate of
(a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority
interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e)
undistributed income of less than 50% owned affiliates without loan guarantees.
</FN>
</TABLE>
<PAGE>
Deloitte &
Touche
__________ _____________________________________________________
Deloitte & Touche LLP Telephone:(503)222-1341
Suite 3900 Facsimile:(503)224-2172
111 S.W. Fifth Avenue
Portland, Oregon 97204-3642
Exhibit 15
August 9, 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
June 30, 1999 and 1998, as indicated in our report dated August 9, 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 June 30, 1999, is
incorporated by reference in Registration Statement Nos. 33-51277, 33-54169,
33-57043, 33-58461, 333-10885, and 333-45851, all on Form S-8; Registration
Statement No. 33-36239 on Form S-4; Registration Statement Nos. 33-62095 and
333-09115 on Form S-3; and Form F-4 No. 333-77877.
We also are aware that the aforementioned report, pursuant to Rule 436(c)
under the Securities Act of 1933, is not considered a part of the Registration
Statement prepared or certified by an accountant or a report prepared or
certified by an accountant within the meaning of Sections 7 and 11 of that
Act.
DELOITTE & TOUCHE LLP
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S
FORM 10-Q DATED JUNE 30, 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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 7917900
<OTHER-PROPERTY-AND-INVEST> 1748200
<TOTAL-CURRENT-ASSETS> 1053800
<TOTAL-DEFERRED-CHARGES> 396400
<OTHER-ASSETS> 1260200
<TOTAL-ASSETS> 12376500
<COMMON> 3245900
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 710400
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3956300
175000
66400
<LONG-TERM-DEBT-NET> 4438900
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 40700
<LONG-TERM-DEBT-CURRENT-PORT> 192000
0
<CAPITAL-LEASE-OBLIGATIONS> 27200
<LEASES-CURRENT> 100
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3479900
<TOT-CAPITALIZATION-AND-LIAB> 12376500
<GROSS-OPERATING-REVENUE> 1903500
<INCOME-TAX-EXPENSE> 92800
<OTHER-OPERATING-EXPENSES> 1504500
<TOTAL-OPERATING-EXPENSES> 1597300
<OPERATING-INCOME-LOSS> 306200
<OTHER-INCOME-NET> 15000
<INCOME-BEFORE-INTEREST-EXPEN> 321200
<TOTAL-INTEREST-EXPENSE> 174900
<NET-INCOME> 147400<F1>
9600
<EARNINGS-AVAILABLE-FOR-COMM> 137800<F1>
<COMMON-STOCK-DIVIDENDS> 160300
<TOTAL-INTEREST-ON-BONDS> 217900
<CASH-FLOW-OPERATIONS> 405400
<EPS-BASIC> 0.46
<EPS-DILUTED> 0.46
<FN>
<F1>NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDES
INCOME FROM DISCONTINUED OPERATIONS OF $1,100.
</FN>
</TABLE>
