<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Date of report (date of earliest event reported):
April 21, 1998
PACIFICORP
(Exact name of registrant as specified in its charter)
State of Oregon 1-5152 93-0246090
(State of Incorporation) (Commission (I.R.S. Employer
File No.) Identification No.)
700 N.E. Multnomah, Suite 1600, Portland, Oregon 97232-4116
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(503) 731-2000
No Change
(Former Name or Former Address, if changed since last report)
<PAGE>2
Item 5. OTHER EVENTS
Information contained in news releases of PacifiCorp issued on
April 21, 1998 and April 30, 1998 concerning the receipt of a Utah allocation
order and the termination of the Company's bid to acquire The Energy Group,
respectively, is incorporated herein by reference. Also filed as an exhibit
hereto are the Utah Allocation Order and information contained in a news
release of the Company issued on May 5, 1998.
Item 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS
(c) Exhibits.
99(a) PacifiCorp news release issued April 21, 1998.
99(b) Utah Allocation Order.
99(c) PacifiCorp news release issued April 30, 1998.
99(d) PacifiCorp news release issued May 5, 1998.
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
(Registrant)
By: RICHARD T. O'BRIEN
__________________________________
Richard T. O'Brien
Senior Vice President and
Chief Financial Officer
Date: May 6, 1998
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION PAGE
_______ ___________ ____
<S> <C> <C>
99(a) PacifiCorp news release issued April 21, 1998.
99(b) Utah Allocation Order.
99(c) PacifiCorp news release issued April 30, 1998.
99(d) PacifiCorp news release issued May 5, 1998.
</TABLE>
<PAGE>
EXHIBIT 99(a)
_____________________________________________________________________________
PACIFICORP NEWS RELEASE
_____________________________________________________________________________
Scott Hibbs, for investors, (503) 731-2123
Dave Eskelsen, for media, (801) 220-2447
April 21, 1998
PACIFICORP RECEIVES UTAH ALLOCATION ORDER
PORTLAND, Oregon - PacifiCorp (NYSE: PPW) announced today that it has
received an order from the Utah Public Service Commission changing the method
for allocating costs among the seven states with retail customers served by
PacifiCorp.
The existing allocation method was established eight years ago after the
1989 merger between PacifiCorp and Utah Power by a task force of state and
federal regulators from each of the company's jurisdictions and company
officials.
In today's order, the Utah PSC directed that their state's electric
prices be based on a method that allocates all costs evenly over the company's
seven state jurisdictions without regard to whether the costs were incurred
before or after the 1989 merger. The existing method allocated pre-merger
costs to the company of origin and post-merger costs on a system-wide basis.
The PSC ordered that the method change be phased in over five years
through a straight line method.
The PSC order indicates that Utah customer prices could be reduced by
approximately $50 to $60 million per year once the order is fully phased in on
January 1, 2001. However, the company and the PSC are continuing to discuss
the new allocation method and have agreed that the impact on customer prices
must be determined in a general rate case.
Filing of a majority of the testimony in the case will be completed by
early June, with hearings scheduled for October and November. A final order
is expected near the end of 1998.
Background to Allocation Order and General Rate Case
____________________________________________________
In early 1997, the Division of Public Utilities (DPU) and the Committee
of Consumer Services (CCS) in Utah filed a joint petition with the Utah PSC
requesting the PSC to commence proceedings to establish new rates for Utah
customers. The DPU and the CCS suggested changes to the allocation method and
the company's authorized return on equity, as well as certain other accounting
adjustments.
Subsequently in March 1997, the Utah Legislature passed a bill that
created a legislative task force to study electric restructuring and customer
choice issues in the State of Utah. The bill precluded the PSC from holding
hearings on rate changes and froze prices at January 31, 1997 levels until May
1998, but allowed for retroactive price changes.
The company agreed to an interim price decrease to Utah customers of
$12.4 million annually beginning on April 15, 1997.
<PAGE>
Page 2 - PacifiCorp Receives Utah Allocation Order
April 21, 1998
In November 1997, the Task Force recommended that further study was
needed and that no legislation be proposed in the 1998 session for the
deregulation of electric utilities.
During 1997, the PSC did proceed with hearings on the proper method to
be used in allocating costs among the company's seven jurisdictions that
resulted in the order issued on April 16.
###
<PAGE>
EXHIBIT 99(b)
- BEFORE THE PUBLIC SERVICE COMMISSION OF UTAH -
------------------------------------------------
In the Matter of a Proceeding to Establish ) DOCKET NO. 97-035-04
An Allocation Methodology to Separate ) ____________________
PacifiCorp's Assets, Expenses and Revenues )
Between Various States ) REPORT AND ORDER
________________
------------------------------------------------
ISSUED: April 16, 1998
______________________
______________________________________________________________________________
SHORT TITLE
ADOPTION OF AN INTERJURISDICTIONAL ALLOCATION METHOD FOR PACIFICORP
______________________________________________________________________________
SYNOPSIS
________
The Commission herein orders the adoption of the Rolled-In
allocation method with a lump-sum addition for merger fairness that will end
January 1, 2001, following a five-year phase-out period. A scheduling
conference is established for April 30, 1998, at 9:00 am.
<PAGE>
DOCKET NO. 97-035-04
-ii-
TABLE OF CONTENTS
_________________
I. PROCEDURAL HISTORY............................................... 1
II. BACKGROUND....................................................... 1
III. POSITIONS OF PARTIES............................................. 7
A. PACIFICORP................................................... 7
B. THE DIVISION OF PUBLIC UTILITIES............................. 8
C. THE COMMITTEE OF CONSUMER SERVICES........................... 9
D. THE UTAH FARM BUREAU FEDERATION.............................. 9
IV. STATEMENT OF ISSUES.............................................. 10
V. DISCUSSION, FINDINGS AND CONCLUSIONS............................. 11
A. The Merger Fairness Adjustment............................... 11
B. The Number Of Years The Merger Fairness
Adjustment Is Required..................................... 15
C. The Dollar Magnitude Of The Adjustment....................... 17
D. Implementing The Adjustment In Coming Years.................. 18
E. Accounting And Reporting..................................... 19
VI. ORDER............................................................ 19
<PAGE>
DOCKET NO. 97-035-04
-iii-
APPEARANCES
Edward A. Hunter and
John M. Eriksson For Pacificorp
of Stoel Rives
Raymond W. Gee " Utah Farm Bureau
of Kirton & McConkie
Michael L. Ginsberg " Division of Public Utilities
Assistant Attorney General
Kent Walgren " Committee of Consumer Services
Assistant Attorney General
Brian Burnett " Sunnyside Cogeneration Associates
of Callister, Nebeker & McCullough
Gary A. Dodge " Energy Strategies, Inc. and Utah
of Kimball, Parr, Waddops, Electric Deregulation Group
Brown & Gee
<PAGE>
DOCKET NO. 97-035-04
-1-
I. PROCEDURAL HISTORY
On March 26, 1997, the Division of Public Utilities (DPU or Division)
filed a request for a formal proceeding "to establish a procedure to allocate
assets, revenues and expenses between Utah and other Pacificorp
jurisdictions." The Commission determined that further proceedings were
necessary to consider the Division's request. The Commission commenced this
Docket for consideration of the request, giving notice of Commencement of
Agency Action on April 3, 1997. At a scheduling conference held April 10,
1997, the Division, the Committee of Consumer Services (Committee), Pacificorp
(Company or Pacificorp), Utah Farm Bureau Federation (Farm Bureau) and
Sunnyside Cogeneration Associates (Sunnyside) entered appearances in this
docket. Energy Strategies, Inc. (ESI) and Utah Electric Deregulation Group
(UEDG) sought intervention on July 21, 1997. The Commission issued a
scheduling order on July 14, 1997, establishing intervention dates, testimony
filing dates (subsequently modified by stipulation of the parties) and
hearings dates. The Division, the Committee, and Pacificorp filed direct
testimony on October 24, 1997, and rebuttal testimony on November 25, 1997.
Hearings were held December 9 - 12, 1997. Post-hearing briefs or memoranda
were filed January 16, 1998, by the Division, the Committee, the Farm Bureau
and Pacificorp.
II. BACKGROUND
The issues in this Docket begin with the 1989 merger of two utilities
having differing cost-of-service1 structures. Utah Power and Light Company, a
baseload, coal-fired thermal generation system with strategically important
transmission plant, had higher cost of service than did Pacific Power and
Light Company, its lower cost, hydropower-based merger partner. Utah and the
other six states with jurisdiction over the newly merged company informally
agreed that it would be unfair for electric service rates in any state to rise
solely because of the merger. This
[FN]
_______________
1 The utility's "costs" or "cost of service" is the total of operating
expenses plus taxes plus depreciation plus capital costs incurred to provide
utility service. Though there are differences in a rate case, for present
purposes we use the terms "cost of service" and "revenue requirement"
interchangeably.
</FN>
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DOCKET NO. 97-035-04
-2-
could happen to the lower-cost Pacific Northwest states if traditional
cost-of-service ratemaking on a single-system basis were to produce higher
rates there, and lower rates in the Utah Power states, than would have
resulted had no merger occurred. All viewed the merger as an organizational
change necessary to capture the anticipated benefits of single system planning
and operation, in which all states were expected to share, once the two
companies became one. The merging companies assured each state that these
benefits would be large enough so rates should be lower but would never be
higher in each state with the merger than without it, obviating the need for a
________________________________
method to apportion costs as a prerequisite for approving the merger.
Following approval of the merger, the concept of "merger fairness"
arose. It means that state ratemaking processes must take special
transitional steps to recognize the state jurisdictional ratemaking
implications of the different cost-of-service structures of the two former
companies. Otherwise, each state might not realize the lower rates in the
magnitudes that the merging companies gave it reason to expect. Since then,
the form these special steps have taken in Utah is to alter, in ways that are
the subject of this Docket, the standard method for determining Utah
jurisdictional revenue requirement. That is, the alterations are to prevent
undue cost shifting from the Utah jurisdiction to the pre-merger Pacific Power
states.
To explain, we first describe the standard method that otherwise would
have applied to PacifiCorp, as a merged company, from 1989 on. We also
describe how the standard method has been altered in order to achieve merger
fairness, both as seven-state regulatory staff agreements to guide
PacifiCorp's regulatory filings in each state, and in Utah as a result of our
decisions in general rate case Docket No. 90-035-06, Phase I Report and Order
issued December 7, 1990.
It is essential to recognize that PacifiCorp provides electric service
in several states, but plans, operates and incurs costs to provide that
service as an integrated, single utility system. No one disputes that this is
the most efficient way to conduct its utility business; that, in other words,
operation as separate divisions in its geographically dispersed service
territory would increase system cost of service by giving up the benefit of an
integrated operation.
<PAGE>
DOCKET NO. 97-035-04
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As the first ratemaking step, integrated system cost-of-service must be
apportioned to each state jurisdiction. The apportioned amount of total
___________
system cost of service is the basis of the revenue requirement which each
state designs rates to recover. Determining the proper apportionment method
is the principal subject of this Docket.
When each state uses the same apportionment method to obtain its share
of system costs, the sum of state revenue requirements, all else equal, is
expected to equal the revenue requirement or cost of service of the entire
integrated system. This gives the Company the opportunity to be "made whole."
Though the Company always bears the risk that the sum of the parts may not
equal the whole,2 it clearly is interested in having all states use the same
method.
A description of the apportionment process begins with the recognition
that cost of service is recorded as historical or embedded accounting
information in the Uniform System of Accounts (USOA). This information is the
basis for the apportionment process, which either directly assigns or
__________
allocates the amounts in each USOA account to each state. Costs that are
_________
solely the responsibility of a single state, such as for distribution plant,
are directly assigned to the state. Costs that are incurred jointly or in
common to serve more than one and perhaps all states cannot be directly
assigned but must be allocated to each state. Through direct assignment and
_________
allocation, total cost of service is apportioned to the states.
The standard apportionment method has three steps, called
functionalization, classification, and allocation.3 The analytical basis for
these steps depends upon the
[FN]
_______________
2 The merging company asserted that it and only it bears this risk in
order to argue, successfully as it turned out, that apportionment need not be
undertaken in Utah's merger approval proceedings because under any reasonable
apportionment method Utah could be assured of benefiting from the merger.
Report and Order issued September 28, 1988 in Docket No. 87-035-27.
3 The analyst must decide the function -- production, transmission,
distribution, or general -- of each account to which dollars are booked
("functionalization"). A second decision classifies -- as demand, energy, or
customer -- the reason for which the cost is incurred ("classification"). The
third decision selects the formula or factor by which the test-period dollar
__________________
amounts in the functionalized and classified accounts that cannot be directly
_______
assigned are allocated to each state jurisdiction ("allocation"). All three
decisions are based on a considered view of the current demands faced by, and
the engineering-economics of, the integrated utility system. In this Docket,
parties present Joint Exhibit I, which is an algebraic description of each
allocation factor. Joint Exhibit II shows the
</FN>
<PAGE>
DOCKET NO. 97-035-04
-4-
characteristics of current demand for service throughout the total service
territory, the engineering-economics of the system, and the principle of
cost-causation. "Cost causation" means that costs incurred to provide service
to a jurisdiction should be recovered from that jurisdiction only. By
correctly employing these steps, the intent is to apportion system cost of
service in a manner to achieve equitable and efficient results.
In past discussions (for example, in Report and Order, Phase I, Docket
No. 90-035-06), the Commission referred to the standard apportionment method
as the "single-system, rolled-in method." The parties now agree on the
functionalization, classification and allocation decisions of which that
method is composed.4
In Docket No. 90-035-06, the Commission altered the results of a
single-system, rolled-in revenue requirement to achieve merger fairness in the
following way. In Phase I of that Docket, the Company, supported by the
Division and opposed in certain respects by the Committee, proposed an ad hoc
apportionment approach called the "Consensus Method."5 The Commission
declined to accept the proposal, but, based on record evidence, chose to
retain the conventional
[FN]
_______________
functionalization, classification and allocation decisions for each USOA
account. With one minor exception, these decisions are not in dispute.
4 The term "rolled-in" refers to conventional embedded, average-cost
ratemaking, and means that utility plant enters cost of service at original
cost less accumulated depreciation and, based on the characteristics of
current demand for service, is assigned and allocated in the conventional way
__________________________
(note 3) to each jurisdiction. This describes the "single-system, rolled-in
apportionment method" and distinguishes it from proposed approaches which, by
maintaining separate Utah and Pacific divisions, would directly assign major
portions of collectively used plant, based on the characteristics of demand
for service at the time the plant was built, to these hypothetical divisions.
_______________________________
The divisionally assigned amounts would subsequently be allocated to
jurisdictions.
5 Immediately after the merger was consummated in 1989, meetings to
address the problem of interjurisdictional "allocations" began between
PacifiCorp and regulatory staff from each state in its service territory. The
group, called "PITA," or PacifiCorp Interjurisdictional Task Force on
Allocations, has met at least once each year since. Early labors produced the
Consensus Method, which consisted of 10 adjustments or steps away from the
Rolled-In method in an attempt to yield merger fairness. Chief among these
steps were the direct assignment to "divisions" (the pre-merger service
territories of Pacific Power and Utah Power) of pre-merger plant and creation
of two unallocable "endowments" of these divisions. One endowment consists of
the assignment to divisions of hydro capacity and energy; the other,
assignment to divisions of pre-merger wheeling and remaining existing capacity
(REC) transmission revenues. When in about 1993 PITA judged the Consensus
Method no longer capable of producing merger fairness, the group adopted a new
method called "Accord."
</FN>
<PAGE>
DOCKET NO. 97-035-04
-5-
single-system, fully rolled-in method to calculate jurisdictional revenue
requirement. The Commission used this as a starting point, and added to it a
lump-sum amount in order to meet the objective of merger fairness. This
amount was derived by comparing the results of the Rolled-In and Consensus
Methods. Thus, the Commission ordered an addition or transfer to Utah
jurisdictional revenue requirement equal in amount to the difference between
Utah revenue requirement calculated by the Rolled-In method and by the
Consensus Method. Numerically, $72.74 million was added to the 1990 Rolled-In
revenue requirement of $530.02 million to ensure merger fairness. This was
not a cost-based transfer.6 The rates approved in Phase II of that Docket
were designed to recover the larger, adjusted revenue requirement of $602.76
million. Importantly, the record showed that the approved revenue requirement
was still less than Utah Power's would have been, had it remained an unmerged,
stand-alone utility.
Though the Commission refused to adopt the Consensus Method itself, it
felt justified in using its numerical result because it was derived in a fair
and open, deliberative way by regulatory staff members from each PacifiCorp
state. Our investigative staff, the Division, was well represented.
In a key decision, the Commission stated that the $72.74 million
addition to Utah's Rolled-In revenue requirement was a maximum amount and
ordered it to be eliminated over a number of years -- the stated goal was 10
years, with caveats concerning depreciation of pre-merger plant and retention
by divisions of endowments. (See note 5.) The Commission acknowledged that
more than ten years might be allowed if subsequent analysis showed that these
caveats were legitimate and should extend the period. At that future point,
the determination of revenue requirement and ratemaking would be based on
single-system, rolled-in cost of service without further merger-fairness
adjustment.
Another key point, which arises again in the present Docket, is the test
by which merger
[FN]
_______________
6 Report and Order issued December 7, 1990, paragraph 5, pages 13-14.
PacifiCorp argues that the direct assignment to divisions (the pre-merger
service territories of Utah Power and Pacific Power) of pre-merger plant is a
cost-based departure from standard apportionment practice.
</FN>
<PAGE>
DOCKET NO. 97-035-04
-6-
fairness is adjudged. The proposed Consensus Method was based on a
merger-benefit distribution test. This required a comparison of forecast
merged company operations with forecast, hypothetical operations of the
no-longer existing, unmerged former Pacific Power and Utah Power utilities.
The net result of this comparison, if positive, was termed "merger benefit."
The idea of the test was to aid in designing a method to apportion system cost
of service by splitting merger benefits roughly 50/50 between two divisions,
defined as the service territories of the pre-merger companies, and shared
pro-rata among the state jurisdictions in each. The fair result, the 50/50
benefit split, would be achieved by adjusting the jurisdictional revenue
requirement used in general rate cases and in all reports to state regulators
of merged-company operations.
The analysis of hypothetical benefits was of concern as early as the
September 28, 1988 Report and Order approving the merger (Docket No.
87-035-27). There, the Commission cautioned against its use. (See, for
example, Report and Order, p. 65, paragraph 12.) Though the Commission agreed
with the need for merger fairness, and as a result that Utah's jurisdictional
revenue requirement in rate cases following the merger should be greater, for
a period of years, than that indicated by conventional single-system, fully
rolled-in cost-of-service apportionment, the Commission was skeptical that
this result could or should be maintained into the future using a benefits
distribution test. In the rate case, the Commission rejected the merger
benefit test as a measure of fairness. The measure adopted uses a lump-sum
transfer, based on a divergence from, or an increment to, fully rolled-in
revenue requirement.
In that Docket, however, the Order did not fix the date at which the
fairness adjustment, as a lump-sum transfer decreasing from $72.74 million,
would end. The rate-case record was insufficient for that purpose. At the
time, the parties expected to revisit the issue in a subsequent rate case,
when the newly merged entity would have an operating history upon which to
rely.
In summary, key decisions in that case are that the Commission
recognized integrated, single-system operation of the merged company as the
goal. Testimony affirmed it was already an operations reality. Accordingly,
and in consequence of good theory and practice, the
<PAGE>
DOCKET NO. 97-035-04
-7-
Commission determined that cost-recovery should be based on the same
integrated system, rolled-in cost-of-service premise. The Commission also
inaugurated divergence from single-system, rolled-in revenue requirement as
the measure of merger fairness in place of the proposed
distribution-of-benefits test.7
III. POSITIONS OF PARTIES
The general problem for this Docket is the adoption of an apportionment
method that meets the merger fairness objective as well as other standard
ratemaking objectives and is the basis for just and reasonable rates. The
effort in this Docket to define an appropriate method is simplified somewhat
because, as noted above, the standard functionalization, classification, and
allocation decisions are not in dispute. Determination of a numerical revenue
requirement for the Utah jurisdiction, however, awaits a general rate case.
Four parties provide testimony or argument on these subjects.
A. PACIFICORP
The Company proposes the "Modified Accord" method. Under this method,
merger fairness is attained by assigning the costs of pre-merger plant to
divisions of origin, defined as the service territory of either Utah Power or
Pacific Power, pre-merger, and then allocated to the respective jurisdictions
within each division. This divisional assignment of pre-merger plant is to
continue over the remaining depreciable life of the plant, or until
approximately 2015. The
[FN]
_______________
7 Even though the Commission did not adopt the Consensus Method in
Docket No. 90-035-06, PITA continued to work on the same sort of approach and
continued to rely on a merger-benefit test. In 1993, when this test showed
the Consensus Method was producing unfair results to the jurisdictions of the
pre-merger Pacific Power, PITA adopted a new but similar approach called the
"Accord Method" which shifted additional costs to the jurisdictions of the
pre-merger Utah Power. Accord has been used since for regulatory filings in
Utah and the other states. Now, in the present Docket, the Company proposes a
"Modified Accord Method." We have not ruled on the appropriateness of either
the Accord or Modified Accord methods. The Division has been a signatory
party to PITA agreements to use Consensus and Accord, and, as the record in
the present Docket shows, did not break with PITA on this sort of approach
until mid-1996. The Committee, which attended most of the PITA meetings, did
not sign the agreements; nor did our advisory staff, who attended for
informational purposes only.
</FN>
<PAGE>
DOCKET NO. 97-035-04
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costs of post-merger plant are allocated directly to all jurisdictions, as is
the case under the Rolled-In method. In addition, a modified "hydro
endowment" directly assigns to divisions, to be credited to the jurisdictions
within the division, an adjustment to fuel expenses to reflect the value of
divisional hydro generation. During the hearing, the Company proposed to
terminate the divisional hydro endowment by January 1, 2001. Given this, the
fairness adjustment is expected to end near 2015, when assignment of
pre-merger plant is no longer a material factor.
The Company proposes to implement the Modified Accord method in its
semi-annual reports of operations to the Commission. These reports would
reflect the movement toward the Rolled-In method, and the gradual elimination
of the fairness adjustment, as pre-merger plant depreciates and with the
removal of the hydro adjustment beginning in 2001. The Company states that
its proposal does not address the impacts that might occur as a result of
future legislative changes in the regulation of electric utilities, but
indicates it will neither propose nor support any action at the state
legislature which does not assure implementation of this apportionment
proposal.
B. THE DIVISION OF PUBLIC UTILITIES
The Division recommends reaching the Rolled-In method by phasing-out the
fairness adjustment over a five-year period, 1996-2000. In its view, the
five-year period is fair both to PacifiCorp's shareholders and to ratepayers
in Utah and other states. The amount that is added to Utah jurisdictional
revenue requirement to attain merger fairness, assuming 1997 is the test year
in the next general rate case, would be four-fifths of the difference between
the Rolled-In and the Modified Accord method proposed by the Company in this
proceeding. Thereafter, the fairness amount would decrease by one-fifth
annually, reaching zero at year-end 2000. That is to say, these amounts would
no longer be dependent on a comparison of two apportionment methods. At the
end of 2000, the fairness adjustment would terminate and all ratemaking
thereafter would use the Rolled-In method. The Division recommends a
requirement that the April 1997 semi-annual report of PacifiCorp reflect all
decisions in this case.
<PAGE>
DOCKET NO. 97-035-04
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The Modified Accord method allocates non-fuel operations and maintenance
expenses based on the relative amount of plant apportioned to a jurisdiction,
and thus reflects the divisional assignment of pre-merger plant, while fuel
expenses are allocated directly to jurisdictions based on relative usage. In
the event the Commission accepts the Company's proposal to divisionally assign
pre-merger plant, the Division proposes that non-fuel operations and
maintenance expenses be allocated, like fuel, on the basis of relative usage.
The Company should be required to file all future semi-annual reports
using the Rolled-In method with an explicit lump-sum addition to the Utah
revenue requirement for merger fairness. The lump-sum addition decreases over
five years. In the event a general rate case is held, the Utah revenue
requirement is to be based on the appropriate amount for the year that is
under study. The Division believes there is no automatic mechanism by which
rates can be adjusted to match the movement to the Rolled-in method; only
through a general rate case can rates be adjusted.
C. THE COMMITTEE OF CONSUMER SERVICES
The Committee advocates that we order use of the Rolled-In method at the
first opportunity. The only reason not to do so is possible unfairness to
UP&L's shareholders. In examining this, the Committee states that for nearly
a decade Utah ratepayers have protected PacifiCorp's shareholders from the
risk that all jurisdictions would not use the same apportionment method, a
risk shareholders assumed at the time of the merger. The Committee testifies
that even on these grounds there is no need to continue the merger fairness
adjustment to jurisdictional revenue requirement. There is no need for a
transfer and subsequent phase-out.
In the event the Commission accepts the Company's proposal to
divisionally assign pre-merger plant, the Committee proposes that the revenues
from excess production (sales for resale) be apportioned to the jurisdiction
bearing the cost responsibility for the excess capacity, rather than the
current method which assigns Utah the costs of excess capacity but allocates
the revenues system-wide.
<PAGE>
DOCKET NO. 97-035-04
-10-
The Committee proposes that all semi-annual reports would be filed using
the Rolled-In method, and the Rolled-In method would be used whenever a
general rate case is held.
D. THE UTAH FARM BUREAU FEDERATION
In its final brief, the Farm Bureau recommends adoption of the Rolled-In
method without an adjustment for merger fairness. If the Commission adopts
the five-year elimination of the fairness adjustment as proposed by the
Division, then the divergence from the Rolled-In method should be calculated
using the Modified Accord method, since PacifiCorp has agreed to the Modified
Accord method, regardless of the position of the other states.
Like the Committee, the Farm Bureau proposes to require all semi-annual
reports to be filed using the Rolled-In method, and the Rolled-In method would
be used whenever a general rate case is held. The Farm Bureau recommends that
if "gradualism" of the sort proposed by the Division is adopted, the
application should not be to a cost method but instead to rate adjustments in
the context of a general rate case.
IV. STATEMENT OF ISSUES
The standard single-system apportionment method, that which we refer to
as the Rolled-In method, is not in dispute here. All parties agree its
functionalization, classification and allocation aspects are correct as
presented in Joint Exhibit 2. Its allocation factors are readily derived from
the algebraic expressions in Joint Exhibit 1. Given this, the first and major
issue we face is how, in ratemaking and regulatory reporting, to maintain
merger fairness. In addition to the Rolled-In method, the other two
approaches advocated on the record are lump-sum transfer (deviation from
Rolled-In) and use of the Modified Accord method. The second issue is how
long the alteration of jurisdictional revenue requirement to achieve merger
fairness must continue. The third issue is how to determine the correct
dollar amount of the adjustment necessary each year as required for merger
fairness. The fourth issue is how to actually implement the adjustment in
coming years, if expected institutional changes in the industry and
<PAGE>
DOCKET NO. 97-035-04
-11-
in regulation occur. The final issue is the appropriate accounting for and
regulatory reporting of cost of service, given a merger fairness adjustment.
In our view, all other issues raised by parties are subordinate to these or to
the particular position each party advocates. Of those which arise in the
context of a party's position, there may be some we need not reach as we
resolve the five key issues.
V. DISCUSSION, FINDINGS AND CONCLUSIONS
But for merger fairness, the search for an appropriate apportionment
method would be limited to the conventional functionalization, classification,
and allocation decisions. These would be based upon the current usage
characteristics of an integrated single-system, rolled-in, utility operation,
assuming the operation is sound in all engineering and economic aspects.
Merger fairness is not the typical regulatory concern with an equity
objective, to be met through cost-based rates, but a departure due to the
merging of two utilities' differing cost structures. The Commission's first
ruling on this subject, in Docket No. 90-035-06, left questions of
interpretation and of timing. We resolve these now.
A. THE MERGER FAIRNESS ADJUSTMENT
The principal fairness objective of the Company is securing an agreement
among the states to adopt a common method of cost allocation to be uniformly
applied by the states as the basis for reporting and ratemaking. An
interstate agreement provides the Company a reasonable and fair opportunity to
recover all of its costs of providing service, and minimizes the risk to
shareholders of unrecovered costs.
The general definition of fairness used by PITA is that "no jurisdiction
should experience a higher revenue requirement with the merger than had the
merger not occurred."8 For use as a guideline in evaluating and selecting
among alternative allocation methods, PITA has adopted a
[FN]
_______________
8 Rodger Weaver, Direct Testimony, pg. 11.
</FN>
<PAGE>
DOCKET NO. 97-035-04
-12-
more specific definition of fairness. This working definition of fairness is
a result approximating an equal sharing by divisions of the accumulated net
cost reductions made possible by the merged company relative to the costs that
would otherwise be incurred to the present by two hypothetical, stand-alone,
unmerged companies. As all parties here, and state representatives at PITA,
now agree, this definition uses a calculation of benefits which depends upon
completely unreliable stand-alone analysis. The definition therefore has been
abandoned.
In a June 1997 meeting, PITA adopted a new definition of fairness to
guide its evaluation of allocation methods. This definition states a fair
method "is one which appropriately balances durable pre-merger costs and
revenue considerations with traditional rolled-in cost allocation."9 It does
not address benefit sharing as a future guideline for evaluating allocation
methods and assumes allocations to date are fair. It also calls for future
decisions to be based on divisional assignment of pre-merger plant,
adjustments to fuel expenses to recognize divisional hydro endowments, and
finally a balanced approach toward traditional rolled-in allocation.
The Division, the Committee, and the Utah Farm Bureau all state that
fairness is obtained by the use of a method that relates current cost to
current use, i.e., the Rolled-In method. Any method which purposely raises
Utah's cost responsibility above that obtained under the Rolled-In method does
so explicitly as a fairness adjustment to benefit other jurisdictions. In the
short term, to fairly mitigate impacts on the Pacific states, the Division
proposes to end the fairness adjustment begun in 1990 with a five-year
transition from the Modified Accord method, as that method was presented by
the Company in this Docket, to the Rolled-In method. Both the Committee and
the Utah Farm Bureau claim it is no longer necessary to maintain any
adjustments to the Rolled-In method.
There are two competing views of fairness. The Company, PITA, and the
Pacific states, once viewed fairness as a fair sharing of merger benefits
relative to stand-alone results. Although they have abandoned the merger
fairness measure, the Company continues to argue that fairness
[FN]
_______________
9 PacifiCorp Exhibit 2R.5. PITA Meeting Minutes, Las Vegas, Nevada,
June 9-10, 1997, p. 7.
</FN>
<PAGE>
DOCKET NO. 97-035-04
-13-
does not require sharing of pre-merger plant and hydro resources. The
Division, the Committee, and the Utah Farm Bureau all view fairness as a fair
transition to a uniform sharing of all costs.
These competing views of fairness are likewise supported by two
competing interpretations of the principle of cost causality. The Company
considers pre-merger plant to be caused by pre-merger loads, and states such
plant does not change as a result of current or future company decisionmaking
or current customer loads. Therefore, the Company contends, cost causation
supports the assignment of pre-merger plant to divisions on an historical
basis. The Division and the Committee assert the joint use of pre-merger
plant in integrated operations to serve aggregate loads requires its costs to
be shared among jurisdictions based on current usage characteristics, as is
traditional in cost allocation. Thus they contend cost causation supports a
uniform allocation of pre-merger as well as post-merger plant to jurisdictions
based on current use.
We conclude that the basis of cost apportionment is cost causation
reflecting the characteristics of current rather than historical usage. This
is the traditional meaning given the cost-causation principle. In the 1990
Order, the Commission affirmed that principle by rejecting a proposal to
partition plant on a historical basis. Nothing in this record causes us to
change this decision. In addition, we agree with the reasons the Division
enumerated in this Docket to support that position: (1) Current use of
existing plant is cost causative since current loads require facilities to
continue to operate; (2) PacifiCorp serves an aggregate load and resources are
not devoted to the exclusive use of a particular customer group; (3) cost
causation is dynamic not static in that it reflects current relative use of
shared plant; (4) divisional assignment of shared plant violates the principle
of direct assignment which requires exclusive not shared use; and (5) the FERC
requires it for wholesale and transmission transactions. An
historical-use-based cost apportionment method results in a form of vintage
pricing. Vintage pricing has not been accepted in this jurisdiction, and the
Division asserts it can result in absurd outcomes.
The Company argues that once it makes an investment decision, it is
beyond the scope of further decisionmaking. To the contrary, providing
utility service is not a riskless economic
<PAGE>
DOCKET NO. 97-035-04
-14-
activity. The Company must continually reevaluate and make economic choices
based on how existing plant, relative to available alternatives, meets current
and expected future loads. For all these reasons, it is obvious to us that
patterns of current, not historical, usage cause current costs to be incurred.
We further conclude that the view of fairness presented by the Company,
which depends upon direct assignment of jointly used plant, must be rejected.
The definition of merger fairness we accept is a deliberate transition or
phasing-out of a lump-sum addition to Rolled-In revenue requirement. Thus, we
reaffirm the definition of merger fairness adopted in the 1990 Order.
We note inherent difficulties with the Modified Accord method proposed
by the Company. Divisional assignment of pre-merger plant violates the
matching principle inherent in cost allocations. By directly assigning
jointly used plant, but sharing all revenues derived from the use of that
plant, a mismatch occurs, as the Committee testifies. Typically, expense
accounts are allocated based on the allocated amounts of plant to which the
expenses are related. When pre-merger plant is directly assigned, the effect
is to shift expenses to the division to which the plant is assigned. This
again mismatches current service demands and resulting costs incurred, a point
the Division raises. Another example of this sort of inconsistency is found
in the treatment of Qualifying Facilities. The costs of these resources are
uniformly shared by all jurisdictions rather than directly assigned to
jurisdictions of origin, even though contracts were entered before the merger.
By contrast, pre-merger purchase power and sales contracts were divisionally
assigned since the pre-merger Pacific states used them to meet their load
requirements to a greater extent than did the Utah division states. This
policy was later changed by PITA to one of uniform sharing among all
jurisdictions. The result of these PITA decisions about contracts increases
Utah's cost responsibility, even though the only reason for such treatment is
PITA's end-result driven notion of fairness, which lends itself to ad hoc
adjustment. An argument, based on consistency, is that pre-merger purchase
and sales contracts and Qualifying Facilities should be directly assigned
rather than allocated system wide. The result would decrease Utah's cost
responsibility.
<PAGE>
DOCKET NO. 97-035-04
-15-
We conclude that the PITA effort to promote merger fairness through ad
hoc adjustment of cost apportionment has unintended and inconsistent
consequences. These, once recognized, may require further ad hoc adjustment
in order to retain the fair result, a problem now compounded for PITA because
a clear standard by which merger fairness can be gauged no longer exists. As
a Division witness states, ". . . in an era when all allocation decisions
were being made on the basis of a merger benefit sharing ratio, any discovery
of distortion of one allocation factor would have resulted in a need to
distort others. In that environment, detailed analysis was not a justifiable
use of resources."
The Division testifies that the Modified Accord method is unfair to Utah
in that it prevents or materially slows the movement to Rolled-In allocations.
Both the Farm Bureau and the Committee recommend immediate adoption of
Rolled-In allocations, thereby eliminating the need for any other method. We
conclude that the Modified Accord method should not be adopted since it rests
on a flawed view of cost causality and risk bearing, employs a definition of
merger fairness we herein and once again reject, and, due to the use of
divisional assignments and other ad hoc adjustments, does not consistently
apply cost apportionment principles.
B. THE NUMBER OF YEARS THE MERGER FAIRNESS ADJUSTMENT IS REQUIRED.
The Company argues that a fairness adjustment is required until
pre-merger plant is materially depreciated, or approximately 2015, based on
its view of historical cost causation. On the other hand, the Committee
argues no further adjustment for merger fairness is necessary because Utah
customers have already more than adequately met any reasonable fairness
requirement by paying $547 million more in rates between 1990 and 1996 than
would have been required under Rolled-In revenue requirement. The Committee
also argues that PITA methods have more than adequately protected the Pacific
states through inconsistency between divisional assignment of pre-merger plant
and shared treatment of the sales-for-resale revenues derived from that plant.
The Division recommends that phasing out an adjustment over a five-year period
will help to assure fair outcomes for Utah customers, while protecting
shareholders and
<PAGE>
DOCKET NO. 97-035-04
-16-
the customers of other states from undue adverse impacts of a sudden change in
apportionment methods. For support, the Division testifies that amounts
phased-out during this period will not harm shareholders because the Company
has the ability to file rate increase applications during this period in other
jurisdictions. The Division asserts that many jurisdictions are and have been
underearning. Moreover, it argues that the effect on other jurisdictions
would in any case be small, ranging from but .06 to one percent of revenue
requirement.
We have rejected the Company's view of historical cost causation. The
remaining consideration in support of an adjustment period until 2015 is
whether that is required to be fair to shareholders and the Pacific states, as
a non-cost-based transition to the Rolled-In method. The Committee argues
against going to 2015 because it believes an immediate move to Rolled-In
revenue requirement if fair to shareholders and the other states. We are
unable to evaluate arguments, such as the Committee's, that what has
transpired since the 1990 case has resulted in unfair outcomes. First, we
have adopted no cost-apportionment method but Rolled-In. Second, though the
Consensus and Accord methods have not been approved, they have been used as
the basis for reports on Company performance. Third, accepting the Committee's
recommendation would shorten the transition to the Rolled-In method that the
Commission established in the 1990 Order. The Division's recommended
five-year transition period accommodates the gradualism characteristic of
long-standing ratemaking objectives. Commonly, pricing of individual services
employs gradualism in the interest of rate stability. Here, the principle is
advocated to ameliorate potential adverse impacts of a sudden change in
apportionment methods. In addition to challenges of unfairness by the
Company, however, the Committee criticizes the Division's proposal, noting
that the five-year phase-out might cost Utah ratepayers as much as $100
million. The Division responds that this amount cannot be demonstrated
because cost apportionment is an uncertain process, plus rate stability is
better served by an incremental approach rather than sudden, large
adjustments.
"Fairness" is a qualitative concept for which an objective standard does
not exist. In this Docket, parties do not agree what fairness requires. The
Division offers a five-year movement to
<PAGE>
DOCKET NO. 97-035-04
-17-
Rolled-In as fair; the Committee believes it fair to go to Rolled-In
immediately; the Company says fairness requires that this move occur only
after many years and perhaps, absent some measure of materiality, not until
2015. They each offer little basis for these differences of opinion except a
judgment of what is fair to the Company's shareholders and to its customers in
Utah and other states.
In the 1990 Docket, we said a transfer to Utah revenue requirement of
approximately $72 million met the merger fairness obligation. Thus, in 1990,
our standard of merger fairness was a transfer of this magnitude, to be
eliminated over a period of years. We based this on the judgment of the
states, expressed through the working group, PITA. The fairness standard we
accepted was a measured divergence from Rolled-In. In considering the subject
for 1996, all that remains is the measure of fairness calculated as divergence
_______
from Rolled-In revenue requirement; we do not have a new standard of fairness.
________
The Division now advocates divergence from Rolled-In as a measure of fairness,
consistent with our 1990 Order.
The Company offers what it represents to be a new PITA standard:
maintenance of endowments and the direct assignment to divisions of pre-merger
plant until it depreciates away, subject to the effect of post-merger
investment and to a judgment about materiality. In contrast to the 1990
Docket, however, the basis for offering it, agreement of the PITA member state
staffs, is not present. Indeed, the Division, a key member, does not agree.
Two states, California and Montana, move to direct access this year, mooting
their concern. The Division testifies that four of seven states no longer
approve of the hydro endowment. In short, divergence from Rolled-In revenue
requirement remains the only reasonable approach. In the absence of a
consensus about what fairness requires, the Company's proposal appears to be
an effort to preserve the status quo and lengthen the lump-sum transfer
period.
To avoid sudden impacts as we move forward, we conclude the Division's
proposed five-year elimination period, of those presented to us on the record,
is the most reasonable and fair. We reject the Committee's proposal as too
abrupt. We reject the Company's proposal for reasons given above. Moreover,
it is imperative that we move to Rolled-In more swiftly than the
<PAGE>
DOCKET NO. 97-035-04
-18-
Company proposes. In 1990, when the Commission established a 10-year goal,
the world was a different place. The setting of the 10-year objective was
fortuitously accurate considering changed conditions. Since then, Congress
passed the Energy Policy Act of 1992 that furthered the move to deregulate
aspects of the electric industry. Circumstances have minimized Utah's
transmission endowment that was originally part of the merger cost-allocation
plan. Over time, the stand-alone merger benefit measurement, to which we have
already referred in this Order, has become useless. And, finally, the state
legislature has begun a study to deregulate electric generation in Utah. In
that environment, a long-term fairness transfer will not be sustainable.
Hence, the fairness adjustment, as a lump-sum transfer, shall end January 1,
2001.
C. THE DOLLAR MAGNITUDE OF THE ADJUSTMENT
The Division and the Company agree that the amount of the fairness
adjustment must be determined in a general rate case, as a divergence between
the Rolled-In and Modified Accord methods. They differ in that the Division
would phase-out the divergence over five years; the Company would retain it
until the two methods coincide in about 2015. The record shows a 1996
divergence of $51.4 million using the Division's adjusted results of Company
operations for that year. The Company uses the prototype model, the basis for
evaluation by PITA, to develop an estimate of $58 million using the Accord
method and $56.5 million using the Modified Accord method, for 1996. In both
methods, the divisional assignment of pre-merger plant accounts for $42.5
million of the total deviation between methods; the remaining difference is in
the value of the hydro endowment. These are indications of magnitude of the
adjustment borne by Utah ratepayers in that year.
We note the record shows that the Division broke with PITA in mid-1996,
when it found that the movement to Rolled-In revenue requirement, with a
divergence calculated using the Accord method, was too slow. We have rejected
the Modified Accord method based on the record in this case. We have
determined that the Committee's proposal to move immediately to rolled-in
revenue requirement is too abrupt. We are unable to determine, on the
currently developed
<PAGE>
DOCKET NO. 97-035-04
-19-
record, the reasonableness of the Committee's position that Utah has already
met its fairness burden and no additional merger fairness adjustment is
warranted. As a result of these determinations, the Commission is unable to
adopt a method that establishes the dollar amount of the lump-sum merger
fairness adjustment that is to be phased out over five years. There may be
other options which should be considered, but are not on this record, e.g., a
straight line reduction of the $72.4 million adjustment made in the December,
1990, Report and Order in Docket No. 90-035-06, that ends January 1, 2001.
We will direct the parties to appear at a April 30, 1998, 9:00 a.m.,
scheduling conference to schedule further proceedings to enable the Commission
to adopt a reasonable method by which the lump-sum merger fairness adjustment
may be calculated.
D. IMPLEMENTING THE ADJUSTMENT IN COMING YEARS
We requested the parties to include in their post-hearing briefs their
positions on how to implement, over time, the parties' proposed methods. All
parties agreed that whatever determination was made by the Commission, it
would not be reflected in rates actually paid by customers until rates could
be modified in a general rate case proceeding. As we have determined that a
merger fairness adjustment is to be phased out over a five-year period,
beginning in 1996, we remain interested in exploring how rate design may be
able to account for such differing levels over time. We will take up the
matter in the pending Pacificorp general rate case, Docket No. 97-035-01. We
are interested in exploring the use of >formula rates', see, e.g., State of
Mississippi, ex rel. Edwin Lloyd Pittman, et al v. Mississippi Public
Service Commission, 538 So. 2d 367 (Miss., 1989) and State of North Carolina
ex rel. Utilities Commission, et al v. Rufus L. Edmisten, 230 S.E. 2d 651
(N.C., 1976). It appears formula rates may be applicable because the changing
levels of formula items will vary precisely, over the rate effective period,
due to the Commission's determinations and not due to errors in forecasting or
estimating future changes when setting the rates.
<PAGE>
DOCKET NO. 97-035-04
-20-
E. ACCOUNTING AND REPORTING
The Company shall report results of operations using the Rolled-In
method. The fairness adjustment, as a divergence from Rolled-In that is
phased out over the five-year period, 1996 -2000, shall be included as an
increment to revenue requirement in the 1997 semi-annual report. For these
reporting and ratemaking purposes in Utah, the Company shall immediately
eliminate all accounting associated with methods proposed but not adopted in
Utah. The record shows that the Division insists this be done both to clarify
and simplify reporting and ratemaking here, and to prevent unintended
consequences. It is clear from the record that ad hoc adjustments can and do
have unintended consequences. When these occur, other, equally ad hoc
responses may be required. We wish to eliminate that possibility with this
Order. The Farm Bureau joins in recommending this course. Finally, the sub
accounts made necessary by the divisional responsibilities that are the basis
of the unapproved methods introduce both accounting and regulatory auditing
complexities we believe are unnecessary. They waste scarce regulatory
resources to no purpose.
VI. ORDER
Wherefore, we order as follows:
1. Pacificorp shall file with the Commission, on or before May 8, 1998,
the algebra of the Rolled-In allocation factors and a table of the
functionalization, classification and allocation decisions, by USOA account,
for the Rolled-In method. These will be used for regulatory reporting
purposes and the pending general rate case in Docket No. 97-035-01.
2. Utah regulatory reports and calculations shall use the Rolled-In
allocation methodology and the lump-sum merger fairness adjustment as
determined herein. Until the lump-sum merger fairness adjustment amount is
determined by the Commission, Pacificorp may use a merger fairness adjustment
amount which it believes is reasonable. The amount shall be an explicit
<PAGE>
DOCKET NO. 97-035-04
-21-
lump-sum merger fairness adjustment to rolled-in results, consistent with this
report and order, and not expressed through an alternative method.
3. The lump-sum merger fairness adjustment shall be phased out through
a five-year straight line method/reduction, beginning January 1, 1996 and
ending January 1, 2001.
4. Pacificorp's accounting records, system of accounts and accounting
methodology for Utah regulatory purposes shall comply with the determinations
of the Commission made in this Report and Order, eliminating all methods
inconsistent with the determinations made herein.
5. The parties shall appear at a scheduling conference set for Tuesday,
April 30, 1998, 9:00 a.m., Fourth Floor, Room No. 426, Heber M. Wells State
Office Building, 160 East 300 South, Salt Lake City, Utah.
In compliance with the Americans with Disabilities Act, individuals
needing special accommodations (including auxiliary communicative aids and
services) during this April, 28, 1998, conference should notify Julie Orchard,
Commission Secretary, at 160 East 300 South, Salt Lake City, Utah, 84111,
(801)530-6713, at least three working days prior to the hearing.
<PAGE>
DOCKET NO. 97-035-04
-22-
DATED at Salt Lake City, Utah, this 16th day of April, 1997.
/s/ STEPHEN F. MECHAM, Chairman
____________________________________
(SEAL) /s/ CONSTANCE B. WHITE, Commissioner
____________________________________
/s/ CLARK D. JONES, Commissioner
____________________________________
Attest:
/s/ JULIE ORCHARD
______________________________
Commission Secretary
<PAGE>1
EXHIBIT 99(c)
_____________________________________________________________________________
PACIFICORP NEWS RELEASE
_____________________________________________________________________________
Scott Hibbs, for investors, (503) 731-2123
Dave Kvamme, for media, (503) 464-6272
April 30, 1998
PACIFICORP WILL END ITS PURSUIT OF THE ENERGY GROUP
PORTLAND, Oregon - PacifiCorp (NYSE: PPW) said today it will not
increase its revised offer to acquire The Energy Group (NYSE/LSE: TEG), ending
its pursuit of TEG.
"PacifiCorp's 820 pence per share offer for TEG represents a full price,
including the value of synergies to be obtained from TEG's U.S. coal
business," said Fred Buckman, PacifiCorp President and Chief Executive
Officer. "We do not see acceptable financial returns available for PacifiCorp
shareholders at prices in excess of 820 pence per share."
The decision to end its pursuit of TEG does not change the company's
strategic direction, Buckman said. "We will vigorously pursue other
opportunities, both domestic and international, as part of PacifiCorp's
strategic objective of becoming a premier global energy provider."
Buckman reiterated that PacifiCorp's strategic future is embedded in the
strength of its competitive integrated utility system in the western U.S., a
rapidly expanding U.S. energy marketing and trading business, a growing
competitive energy business in Australia, and a strong balance sheet and cash
position.
"We will aggressively look for opportunities to expand on our core
strengths in fuels management, power generation and distribution, and energy
marketing and trading," Buckman said. "We will use our balance sheet strength
to invest prudently in new opportunities at attractive return levels or to
return capital to our investors as appropriate through potential share
repurchase activity."
PacifiCorp will record a $86 million pre-tax charge to first quarter
1998 earnings 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, that had been deferred pending the outcome of the transaction. The
company expects to record, in the second quarter, a potential gain on the sale
of 46 million TEG shares currently held by the company.
"The costs associated with pursuing the acquisition of TEG, while
significant, are dwarfed by the added shareholder value that we fully
anticipated at our announced bid levels," Buckman said. "Our disappointment
in not completing this acquisition will strengthen our resolve in identifying
and executing value enhancing transactions for our shareholders."
<PAGE>
Buckman said, "The future of our company is bright. We are proud of our
accomplishments and our continued discipline in evaluating strategic options.
We remain quite optimistic about our ongoing position of strength in the
industry and our ability to deliver superior returns to our shareholders."
PacifiCorp, one of the lowest-cost electricity producers in the United
States, is a multinational energy company with 1.4 million retail electric
customers in the western United States and 550,000 customers in the State of
Victoria, Australia.
PacifiCorp, which has more than 10,000 megawatts of generation capacity,
also is the largest investor-owned bulk power marketer in the western U.S. and
is an active electricity and gas marketer in the eastern U.S.
###
<PAGE>1
EXHIBIT 99(d)
_____________________________________________________________________________
PACIFICORP NEWS RELEASE
_____________________________________________________________________________
Scott Hibbs: (503) 731-2123
May 5, 1998
PACIFICORP REPORTS FIRST QUARTER 1998 FINANCIAL RESULTS; RESULTS OF WORK
FORCE REDUCTION
PORTLAND, Oregon - PacifiCorp (NYSE: PPW) today reported first quarter
1998 earnings on common stock of $104 million, or $0.35 per share, excluding a
charge of $70 million, or $0.24 per share, associated with the Company's U.S.
work force reduction, and a charge of $54 million, or $0.18 per share,
associated with the Company's terminated bid for The Energy Group, PLC
("TEG"). Including these charges, the Company reported a loss on common stock
of $20 million, or $0.07 per share.
In the first quarter of 1997, the Company reported earnings on common
stock of $115 million, or $0.39 per share, which included $18 million, or
$0.06 per share, from the Company's telecommunications operations that were
sold in December of 1997.
The earnings contribution from the Company's Domestic Electric
Operations totaled $76 million in the quarter, excluding the cost of the work
force reduction. The first quarter 1997 earnings contribution from Domestic
Electric Operations was $75 million. Higher sales to commercial and
industrial customers contributed to the increase in earnings. The combined
rate of growth in non-fuel operations and maintenance and general and
administrative costs was reduced to one percent in the quarter.
On January 12, 1998, the Company announced a series of initiatives aimed
at reducing costs in its U.S. electric business, including the elimination of
an estimated 600 jobs through a combination of voluntary early retirement and
special severance in its operations and general administrative groups. Over
950 employees accepted the early retirement program and after limited
refilling of certain positions, the Company expects a net reduction of
approximately 700 positions. A majority of the employees accepting early
retirement left the Company in April 1998.
The Company recorded a pretax charge of $113 million in the first
quarter relating to the workforce reduction program. PacifiCorp expects to
realize approximately $50 million of annual pretax cost savings starting in
the second quarter of 1998 as a result of the program.
Earnings from the Company's Australian Electric Operations were $14
million in the first quarter of 1998, compared to $21 million in the same
quarter last year. Earnings in the quarter were reduced by $2 million as the
result of unfavorable fluctuations in the currency exchange
<PAGE>2
rate. Earnings in the first quarter of 1997 were benefited by adjustments
totaling $7 million associated with the renegotiation of certain industrial
customer contracts. Unfavorable fluctuations in currency exchange rates
partially offset the benefit of higher sales to commercial and industrial
customers in the quarter.
"We are pleased with the sales growth in both our U.S. and Australian
electric businesses," said Fred Buckman, PacifiCorp president and chief
executive officer. "We are also encouraged that the rate of growth in
non-fuel operating costs and general and administrative expenses has slowed.
We are continuing our efforts to further reduce these costs and improve
earnings in our U.S. business."
<PAGE>3
FIRST QUARTER 1998 EARNINGS ANALYSIS
DOMESTIC ELECTRIC OPERATIONS
EARNINGS CONTRIBUTION
Domestic Electric Operations earnings contribution was $76 million, or $0.25
per share, excluding the $70 million charge related to the work force
reduction, as compared to $75 million, or $0.25 per share, in the first
quarter of 1997. Higher commercial and industrial energy sales contributed to
the increase in earnings.
The significant increase in wholesale sales added only modestly to earnings,
as margins on new wholesale sales remain thin.
Including the work force reduction charge, Domestic Electric Operations'
earnings contribution in the first quarter of 1998 was $6 million, or $0.02
per share.
REVENUES
Total Domestic Electric Operations revenues increased $284 million, or 36
percent, from the first quarter of 1997 to $1.1 billion. This increase was
primarily attributable to a $269 million increase in wholesale revenues.
Residential revenues were down $1 million to $232 million. Energy sales
volumes decreased 2 percent. Growth in the average number of residential
customers of 3 percent added $6 million to revenues. This increase was more
than offset by volume decreases due to warmer weather and other usage changes,
which lowered revenues by $6 million, and lower Utah rates that decreased
revenues by $1 million.
Commercial revenues were up $11 million, or 7 percent, to $161 million.
Energy sales volumes increased 7 percent over the prior year. Increased usage
by existing commercial customers added $8 million to revenues and a 2 percent
increase in commercial customers added $5 million. Warmer weather in 1998
decreased revenues by $2 million and lower Utah rates decreased revenues by
$1 million.
Industrial revenues increased $8 million, or 5 percent, to $163 million. A 3
percent increase in energy sales volumes drove a $4 million increase in
revenues. Revenues in 1997 were reduced by billing adjustments of $6 million
for certain industrial customers.
Wholesale volumes continued to expand with the active markets. The
$269 million increase in revenues was driven by energy volumes that more than
doubled in 1998 to a total of 22.4 million mWh. Higher short-term and spot
market wholesale energy volumes increased revenues by $239 million. Related
energy prices averaged $20 per mWh in the quarter, a 25 percent increase over
the prior year. The higher prices for these sales added $21 million to
revenues in the quarter. Higher long-term volumes and prices added $9 million
to revenues.
<PAGE>4
As previously reported, the Company is reviewing the Utah Public Service
Commission (PSC) order that changes the method for allocating costs among its
seven state service territory. This order indicates that Utah prices could be
reduced by approximately $50 million to $60 million per year once fully phased
in on January 1, 2001. However, the Company and the PSC are continuing to
discuss this new allocation order and agreed that the impact on prices must be
determined in a general rate case expected later in 1998.
OPERATING EXPENSES
Total operating expenses increased $385 million, or 64 percent, to
$981 million in the quarter. This increase was primarily attributable to
increased purchased power expense to serve the expanding wholesale market and
the cost for the work force reduction.
Purchased power expense increased $255 million, to $459 million. The higher
expense was primarily due to a 10.7 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 $233 million.
Short-term firm and spot market purchase prices averaged $20 per mWh in the
quarter versus $14 per mWh in 1997, a 36 percent increase. The increase in
purchase prices added $13 million to costs. Higher volumes and prices
relating to long-term firm purchased power contracts added $4 million and $3
million, respectively, to purchased power costs.
Fuel expense was up $6 million, or 5 percent, to $123 million. Thermal
generation was up 12 percent to 13.4 million mWh, resulting in a decrease of
6 percent in the average cost per mWh to $9.73. Hydroelectric generation
decreased 7 percent compared to the first quarter of last year due to less
favorable water conditions.
Net power costs in the quarter were $7.12 per mWh, compared to $7.98 per mWh
in the first quarter of 1997, an 11 percent decrease. 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 decrease in net
power cost was attributable to increased sales through the wholesale markets
of 1.1 million mWh of the Company's generation that was in excess of its
retail load requirements.
Depreciation and amortization expense increased $9 million, or 10 percent, to
$98 million. Higher depreciation rates that were implemented in the fourth
quarter 1997 added $4 million to expense and increased plant in service added
$5 million.
Other operations and maintenance expense decreased $3 million, or 3 percent,
to $111 million. Steam plant maintenance expense decreased $2 million due to
overhaul timing differences. Distribution plant maintenance expense decreased
$1 million due to recognition of storm damage expense in 1997.
Administrative and general expenses increased $5 million, or 7 percent, to $78
million primarily due to timing of employee related costs, partially offset by
lower outside service expense.
<PAGE>5
OTHER INCOME/EXPENSE
Domestic Electric Operations interest expense was up $6 million to $80 million
as a result of higher debt balances. The higher interest was due to capital
contributions made to PacifiCorp Group Holdings Company (Holdings) relating to
the acquisition of TPC Corporation (TPC) in April 1997. Income tax expense
declined $41 million, to $8 million, due to the decline in pretax income.
AUSTRALIAN ELECTRIC OPERATIONS
<TABLE>
AUSTRALIAN ELECTRIC OPERATIONS FIRST QUARTER RESULTS (In millions):
____________________________________________________
<CAPTION>
Change Change
Due to Due to
1998 1997 Currency Operations
____ ____ ________ __________
<S> <C> <C> <C> <C>
Australian Electric Operations:
______________________________
Revenues $162 $183 $(27) $6
Purchased power (58) (69) 10 1
Depreciation and amortization (15) (18) 2 1
Other operating expenses (48) (41) 8 (15)
___ ___ _ ___
Income from operations 41 55 (7) (7)
Equity in losses of Hazelwood (3) (3) 1 (1)
Interest expense (16) (18) 2 -
___ ___ _ _
Income before income taxes 22 34 (4) (8)
Income taxes (8) (13) 2 3
__ ___ _ _
Earnings contribution $14 $21 $(2) $(5)
=== === === ===
</TABLE>
EARNINGS CONTRIBUTION
The Company's Australian Electric Operations contributed earnings of
$14 million, or $0.05 per share, in the first quarter of 1998, compared to
$21 million, or $0.07 per share in 1997. The first quarter 1997 earnings
included adjustments associated with renegotiating certain Tariff H
industrial customer contracts that added $7 million, or $0.02 per share, to
earnings. Excluding the impact of currency exchange rate fluctuations and the
1997 Tariff H adjustment, the Company's Australian Electric Operations
reported $2 million of increased earnings contribution over 1997.
The currency exchange rate for converting Australian dollars to U. S. dollars
was 0.67 in the first quarter of 1998 as compared to 0.78 in 1997, a 14
percent decrease in the quarter. The effect of this change in exchange rates
lowered revenues by $27 million and costs by $25 million in the first quarter
of 1998.
<PAGE>6
The following discussion excludes the effects of the lower currency exchange
rate in 1998.
REVENUE
Australia's revenues increased $6 million, or 3 percent, to $162 million.
Excluding $11 million of revenue in 1997 relating to Tariff H contracts,
revenues would have increased $17 million, or 10 percent due to a .6 million
mWh, or 23 percent, increase in energy sales, which added $21 million to
revenues. Declining prices reduced revenues by $3 million.
Energy volumes sold to contestable customers outside Powercor's franchise area
were up .6 million mWh and added $22 million to revenues due to customer gains
in New South Wales and $4 million due to customer gains in Victoria. Lower
prices for these sales reduced revenues by $3 million in 1998. Inside
Powercor's franchise area, revenues decreased $5 million due to a 64 million
kWh decrease in energy sold.
Other revenues decreased $12 million, to $5 million, largely as a result of
$11 million associated with Tariff H contracts.
OPERATING EXPENSES
Purchased power expense decreased $1 million, or 2 percent, to $58 million.
Lower average prices reduced power costs by $17 million. Prices for purchased
power averaged $23 per mWh in the first quarter of 1998 compared to $28 per
mWh in the first quarter of 1997. The decrease was offset in part by a 23
percent increase in purchased power volumes that added $16 million to costs.
Other operating expenses increased $15 million, or 37 percent, to $48 million.
Increased sales to contestable customers outside the Powercor service area
resulted in higher network fees of $16 million. This increase was offset in
part by higher network revenues of $3 million from customers inside Powercor's
franchise area serviced by other energy suppliers.
UNREGULATED ENERGY TRADING
EARNINGS CONTRIBUTION
The unregulated energy trading segment reported losses of $0.5 million in the
quarter as compared to a $1 million loss in the first quarter of 1997.
PacifiCorp Power Marketing, Inc. recorded electricity trading revenues of $498
million, a related gross margin of $2 million and break even results in the
first quarter of 1998 compared to revenues of $39 million, a gross margin of
$1 million and a net loss of $1 million in 1997.
TPC, acquired in April 1997, recorded natural gas trading revenues of
$318 million, a gross margin of $3 million and a net loss of $0.6 million in
1998.
<PAGE>7
OTHER BUSINESSES
EARNINGS CONTRIBUTION
Other operations reported a loss of $39 million in the quarter compared to
earnings of $2 million in the same period a year ago. The loss is 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 transaction.
Results from other operations for the quarter were benefited by approximately
$23 million in increased 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.
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 May 1, 1998, the Company received approximately $70 million in cash
proceeds in the initial closing for the sale of its affordable housing
properties. The completion of this sale is expected to occur in the near
future upon receipt of various consents. This sale transaction will not have
a material impact on the Company's 1998 earnings.
<PAGE>8
<TABLE>
PacifiCorp
and its Consolidated Subsidiaries
Summary Financial Information
(In Thousands, Except Per Share Amounts)
(Unaudited)
<CAPTION>
3 Months Ended March 31 $ %
1998 1997 Change Change
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
REVENUES
Domestic Electric Operations
(See next page) $ 1,077,000 $ 793,200 $ 283,800 36
Australian Electric Operations
(See next page) 162,500 183,400 (20,900) (11)
Unregulated Energy Trading (1) 815,600 38,900 776,700 *
Other Operations (2) 20,600 26,300 (5,700) (22)
-----------------------------------------------------
TOTAL 2,075,700 1,041,800 1,033,900 99
-----------------------------------------------------
EXPENSES
Domestic Electric Operations
(See next page) 981,200 596,500 384,700 64
Australian Electric Operations 121,700 128,500 (6,800) (5)
Unregulated Energy Trading (1) 816,300 40,400 775,900 *
Other Operations (2) 17,000 15,000 2,000 13
-----------------------------------------------------
TOTAL 1,936,200 780,400 1,155,800 148
-----------------------------------------------------
INCOME (LOSS) FROM OPERATIONS
Domestic Electric Operations 95,800 196,700 (100,900) (51)
Australian Electric Operations 40,800 54,900 (14,100) (26)
Unregulated Energy Trading (1) (700) (1,500) 800 53
Other Operations (2) 3,600 11,300 (7,700) (68)
-----------------------------------------------------
TOTAL 139,500 261,400 (121,900) (47)
Interest expense 94,300 106,000 (11,700) (11)
Other (income) expense 75,400 (3,400) 78,800 *
-----------------------------------------------------
Income from continuing operations
before income taxes (30,200) 158,800 (189,000) (119)
Income taxes (15,100) 56,100 (71,200) (127)
-----------------------------------------------------
Income from continuing operations (15,100) 102,700 (117,800) (115)
Discontinued operations (3) - 18,300 (18,300) (100)
-----------------------------------------------------
NET INCOME (15,100) 121,000 (136,100) (112)
Preferred dividend requirement 4,800 6,100 (1,300) (21)
-----------------------------------------------------
EARNINGS CONTRIBUTION (LOSS)
ON COMMON STOCK (4)
Domestic Electric Operations 5,600 74,600 (69,000) (92)
Australian Electric Operations 14,100 21,000 (6,900) (33)
Unregulated Energy Trading (1) (500) (1,000) 500 50
Other Operations (2) (39,100) 2,000 (41,100) *
-----------------------------------------------------
Continuing operations (19,900) 96,600 (116,500) (121)
Discontinued operations (3) - 18,300 (18,300) (100)
-----------------------------------------------------
TOTAL $ (19,900) $ 114,900 $ (134,800) (117)
=====================================================
Average common shares outstanding 297,059 295,393 1,666 1
EARNINGS PER COMMON SHARE - BASIC AND DILUTIVE
Domestic Electric Operations $ 0.02 $ 0.25 $ (0.23) (92)
Australian Electric Operations 0.05 0.07 (0.02) (29)
Unregulated Energy Trading (1) - - - -
Other Operations (2) (0.14) 0.01 (0.15) *
-----------------------------------------------------
Continuing operations (0.07) 0.33 (0.40) (121)
Discontinued operations (3) - 0.06 (0.06) (100)
-----------------------------------------------------
TOTAL $ (0.07) $ 0.39 $ (0.46) (118)
=====================================================
Dividends paid per common share $ 0.27 $ 0.27 $ - -
=====================================================
<FN>
* Not a meaningful number
</FN>
</TABLE>
<PAGE>9
<TABLE>
PacifiCorp
and its Consolidated Subsidiaries
Summary Financial Information
(Unaudited)
<CAPTION>
3 Months Ended March 31 $ %
1998 1997 Change Change
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
DOMESTIC ELECTRIC REVENUES (In thousands)
Residential $ 231,800 $ 233,100 $ (1,300) (1)
Commercial 161,400 150,200 11,200 7
Industrial 162,700 155,000 7,700 5
Other 7,600 7,800 (200) (3)
-----------------------------------------------------
Retail sales 563,500 546,100 17,400 3
Wholesale sales 499,100 229,700 269,400 117
Other 14,400 17,400 (3,000) (17)
-----------------------------------------------------
TOTAL $ 1,077,000 $ 793,200 $ 283,800 36
=====================================================
DOMESTIC ELECTRIC ENERGY SALES (Millions of kWh)
Residential 3,751 3,827 (76) (2)
Commercial 2,992 2,784 208 7
Industrial 4,891 4,745 146 3
Other 159 169 (10) (6)
-----------------------------------------------------
Retail sales 11,793 11,525 268 2
Wholesale sales 22,443 10,240 12,203 119
-----------------------------------------------------
TOTAL 34,236 21,765 12,471 57
=====================================================
DOMESTIC ELECTRIC EXPENSES (In thousands)
Fuel $ 122,700 $ 116,600 $ 6,100 5
Purchased power 458,700 203,900 254,800 125
Other operations and maintenance 110,600 113,700 (3,100) (3)
Depreciation and amortization 98,100 89,300 8,800 10
Administrative and general 78,000 73,000 5,000 7
Special charges 113,100 - 113,100 *
-----------------------------------------------------
TOTAL $ 981,200 $ 596,500 $ 384,700 64
=====================================================
AUSTRALIAN ELECTRIC REVENUES (In thousands)
Residential 48,600 58,500 (9,900) (17)
Commercial 53,300 49,300 4,000 8
Industrial 55,700 57,900 (2,200) (4)
-----------------------------------------------------
Energy sales 157,600 165,700 (8,100) (5)
Other 4,900 17,700 (12,800) (72)
-----------------------------------------------------
TOTAL $ 162,500 $ 183,400 $ (20,900) (11)
=====================================================
AUSTRALIAN ELECTRIC ENERGY SALES (Millions of kWh)
Residential 576 608 (32) (5)
Commercial 1,040 662 378 57
Industrial 1,356 1,150 206 18
-----------------------------------------------------
Total 2,972 2,420 552 23
=====================================================
March December $ %
1998 1997 Change Change
-----------------------------------------------------
<S> <C> <C> <C> <C>
CONSOLIDATED CAPITALIZATION (In thousands)
Common equity $ 4,250,000 $ 4,321,000 $ (71,000) (2)
Preferred stock 241,000 241,000 - -
Preferred securities of trusts holding
solely PacifiCorp debentures 341,000 340,000 1,000 -
Long-term debt 4,425,000 4,415,000 10,000 -
Short-term debt 725,000 555,000 170,000 31
-----------------------------------------------------
TOTAL $ 9,982,000 $ 9,872,000 $ 110,000 1
=====================================================
<FN>
* Not a meaningful number
</FN>
</TABLE>
(1) Unregulated Energy Trading includes the natural gas and wholesale
electricity trading activities of TPC Corporation, acquired in April
1997, and PacifiCorp Power Marketing, respectively.
(2) Other Operations includes the operations of PacifiCorp Financial
Services, Inc., Pacific Generation Company (sold Nov. 1997), and several
start-up phase ventures, as well as activities of PacifiCorp Group
Holdings Company.
(3) Represents the discontinued operations of Pacific Telecom, Inc., a
telecommunications subsidiary.
(4) Earnings contribution 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.
