ON29034.pdf

Office of the Secretary
Service Date
June 7, 2002
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF P ACIFICORP DBA UTAH POWER &
LIGHT COMPANY FOR APPROVAL OF
CHANGES TO ITS ELECTRIC SERVICE
SCHEDULES.
) CASE NO. PAC-02-
ORDER NO. 29034
On January 7, 2002, PacifiCorp dba Utah Power & Light Company (PacifiCorp;
Company) filed an Application with the Idaho Public Utilities Commission (Commission)
requesting approval of proposed electric service schedules. The Company s Application has four
parts: 1) a proposed Schedule 34 - Bonneville Power Administration (BPA) Exchange Credit
distribution; 2) a proposed electric service schedule adjusting rates to bring customer classes
closer to cost-of-service (CaS); 3) a proposed Power Cost Surcharge ($38 million including
carrying charges); and 4) a proposed Rate Mitigation Adjustment (RMA) designed so that no
customer classes would have an increase during the two-year period ofthe surcharge.
The Commission ordered that the BP A exchange credit be implemented on February 1
2002, while the remaining issues were considered. On April 11 , 2002, a Stipulation and
Settlement was filed by PacifiCorp, Monsanto Company, the Idaho Irrigation Pumpers
Association and the Commission Staff regarding all other issues. The proposed settlement: 1)
limits recovery of excess power costs to $25 million; 2) accelerates the remaining two years of the
PacifiCorp/ScottishPower merger credit and reduces the excess power costs by $2.3 million; 3)
establishes a Power Cost Surcharge designed to recover excess power supply costs of $22.
million over a two-year period; 4) restructures the irrigation tariff schedules to provide firm
power; and 5) adjusts revenue responsibility to bring the irrigators closer to cost of service.
We recognize at the outset the size of both the BP A credit for qualifying residential
and small farm customers and the amount of excess power supply costs the Company has asked to
recover are extraordinarily large. We find that the magnitude of each, however, derives from a
common set of circumstances, i., prolonged drought, natural gas price increases, the regional
demand for electricity, power supply shortages and California market flaws. All of these factors
contributed to the extraordinarily high wholesale market prices of power realized in the Northwest
during 2000-2001 which in turn contributed to the BPA exchange settlement.
ORDER NO. 29034
In this Order, the Commission reaffirms its preVIOUS authorization of the BP
Exchange Credit distribution. After reviewing the record, we also approve as fair, just and
reasonable the proposed Stipulation and Settlement with one modification. The Commission
determines that Nu-West is a contract customer and not subject to the Power Cost Surcharge. We
further award the Idaho Irrigation Pumpers Association and Tim Shurtz intervenor funding.
Finally, we direct PacifiCorp to provide each customer with a one time credit of $20.00 for failure
to provide the individual customer notice required by Rule 102 of the Commission s Customer
Information Rules. IDAPA 31.21.02.102.
I. THE BPACREDIT
The Company s Application was processed in two parts. The first dealt with the BPA
credit and was processed using Modified Procedure, i., pursuant to written submission rather
than hearing. IDAPA 31.01.01.201-204. The second part dealt with the Company s request to
recover through a Power Cost Surcharge $38 million in excess net power supply costs accrued
during the period November 2000 through October 2001 and to implement other proposed
changes.
The BP A credit was approved in Interlocutory Order No. 28946 and became effective
February 1 , 2002. The BP A credit is a distribution of exchange benefits negotiated by Northwest
utilities and state regulatory Commissions in a May 2001 Settlement Agreement with the BP
As contemplated by the 1980 Pacific Northwest Electric Power Planning and Conservation Act
the credit passes the benefits of the Federal Columbia River Power System to PacifiCorp
qualifying residential and small farm customers in eastern Idaho.
The dollar amount of the 2001 BP A credit is by any measure extraordinary and far
exceeds historical levels. Facing the same volatile and high-priced market as everyone else in the
Northwest, BP A chose to offer an additional financial settlement rather than go to the market to
buy ever more expensive power to serve its commitments. PacifiCorp s quick action in accepting
the financial settlement resulted in an additional $11.5 million, or a 50% increase in benefits for its
Idaho customers. No other Idaho electric utility was able to secure this additional level of benefit
for its customers because the market prices for power fell and BP A withdrew the settlement offers.
This settlement came about as a result of the very same market conditions that were responsible
for PacifiCorp s unprecedented level of purchased power expenses.The chaotic market
ORDER NO. 29034
conditions underlie both the large size of the current BP A credit and the huge energy costs
accumulated in the deferred accounts.
The 2001 BP A financial settlement provides $34 million in benefits to qualifying
customers for the first year, and $35.2 million in the second year. To account for four months of
accrued credit (October 1 , 2001 through February 1 , 2002), the rate for residential customers the
first year was set to distribute 16 months of a normal year s benefit, or $40.6 million. The first
year BP A credit for small farm customers was based on a 12-month distribution because the
irrigation season is largely completed by October 1 each year.
Exchange benefits for PacifiCorp are historically allocated 43% to residential
customers and 57% to small farm customers. That was the allocation proposed and accepted in
the interlocutory Order. The BP A credit implemented in February reduced residential customers
base rates by an average of 44% and reduced small farm irrigation base rates by 63%.
Commission Findings: The Commission reaffirms its Order No. 28946 approving the
distribution of the BP A credit. The BP A credit will continue to be reflected as a separate line item
on a customer s bill. The BP A credit in its full amount remains intact and is unaffected by our
Order today.
The Commission would be remiss, however, if it failed to note that the size of the
present BP A credit may create in customers an artificial or false sense of security. This exchange
benefit is temporary and customers would be wise to explore options to reduce their future load
requirements with conservation and demand side management (DSM) measures. In doing so they
will be prepared when the BP A credit no longer includes the additional financial benefit resulting
from the volatile wholesale market.
We now turn to the remainder of the Company s filing including the cost-of-service
(CaS) study, proposed Power Cost Surcharge and rate mitigation adjustment (RMA).
II. PROCEDURAL HISTORY
On February 5 2002, the Commission issued a Notice setting a prehearing conference
on February 19, 2002. It also notified the public and other parties that the Commission Staff
intended to pursue a settlement of the remaining issues presented in this case and set the first
settlement conference to follow the prehearing conference. Commission Rules of Procedure 271-
280, IDAPA 31.01.01.271-280.
ORDER NO. 29034
A. Parties
The following parties of record participated in settlement negotiations and hearing:
PacifiCorp James F. Fell, Esq.
Stoel Rives LLP
Monsanto Company Randall C. Budge, Esq.
Racine, Olson, Nye, Budge & Bailey
Idaho Irrigation Pumpers
Association
Eric L. Olsen, Esq.
Racine, Olson, Nye, Budge & Bailey
Tim Shurtz Pro Se
Commission Staff Scott Woodbury, Esq.
The following additional party was granted late intervenor status and participated only
at hearing:
Nu-West Industries Conley Ward, Esq.
Givens Pursley LLP
B. Identification of Issues
Following the prehearing and settlement conferences, the Commission on February 26
issued a Notice identifying the following matters as continuing to be "at issue" in this case. The
issues to be addressed in this case were:
Company cost-of-service study w/related adjustments to rate design.
The revenue ramifications of the Company s filing.
Power costs PacifiCorp is seeking to recover.
Rate mitigation adjustment.
Whether the Company s attempted recovery of excess power costs
incurred in 200012002 violates Merger Approval Condition No.
Reference Case No. PAC-99-, Order No. 28213 , page 31 issued
November 15, 1999, i.
, "
following the merger, PacifiCorp shall not seek
a general rate increase effective prior to January 1 , 2002"; see also Order
No. 28213 , page 31 , fn. 22 "our Order imposes the additional condition of
a rate moratorium for approximately two years. PacifiCorp is entitled to
seek a rate increase to be effective in year three if it can prove that its
revenue requirement is deficient."
ORDER NO. 29034
Whether it was appropriate (and perhaps prudent) for PacifiCorp to enact
economic curtailments of usage (Company imposed interruptions of
power) as opposed to the alternative purchase of high cost power.
The presence of interruptible load, and the Company s treatment of same.
A review of Company sales contracts executed in 200012001.
The timing of the loss of the Company s Hunter coal generation plant in
2000-2001 and related cause(s) therefore.
The treatment of irrigators (i., previously interruptible, now proposed to
be firm).
The treatment of special contract customers (previously system customers
now proposed to be situs).
On February 26, 2002, the Commission issued another Notice that established alternate
hearing schedules; a May hearing date should the parties be successful in reaching a settlement;
and a July hearing date if the parties were unsuccessful in reaching a settlement agreement, if the
settlement agreement failed to resolve all issues, or if the settlement agreement was not accepted
by the Commission.
C. The Stipulation and Proposed Settlement
On April 11 , 2002, a Stipulation and Proposed Settlement was filed by PacifiCorp, the
Staff, the Idaho Irrigation Pumpers Association (IIP A) and Monsanto Company (collectively
referred to as the "Settlement Parties ). Exh. 20; See Stipulation and schedules attached to this
Order. Although he participated in and attended the settlement conferences, Intervenor Tim
Shurtz did not sign the Stipulation. The submitted Stipulation, in part, contains the following
language:
'114. Pursuant to the Commission s identification of issues and Notice of
Settlement Conference in this matter, the parties have engaged in discussions
with a view toward resolving PacifiCorp s Application in this case.
'115. PacifiCorp has claimed and sought recovery of approximately $38 million
in excess net power costs, including carrying charges, incurred during the
period November 1 , 2000 through October 31 , 2001 (the "excess power
costs ). The Commission Staff proposed recovery be limited to approximately
$21 million after adjustments for the Hunter 1 outage, wholesale contract
costs, load growth, and jurisdictional allocation. Both IIP A and Monsanto
asserted that: (1) recovery of excess power supply costs is barred by reason of
ORDER NO. 29034
the ScottishPower-PacifiCorp Merger Approval Condition No.(footnote
omitted); (2) power supply costs associated with the Hunter Plant failure are
not recoverable because they were incurred subsequent to the deferral Order;
(3) any Hunter-related costs properly deferred should be equitably shared as a
result of maintenance issues; (4) costs associated with certain wholesale
contracts were imprudently incurred and not recoverable; (5) thorough review
and approval of the Company s cost-of-service studies was required before
rates could be shifted among the customer classes. IIP A also challenged the
Company s BP A credit allocation, the proposed RMA, and the elimination of
irrigation A-C rate schedules. The Company disagreed and presented
further information in response to the positions advanced by the Parties. The
Company asserted that all of its Excess Power Costs were prudently incurred
and are properly recoverable.
Based upon the settlement discussions among the parties, as a compromise of
the disputes in this case, and for other consideration as set forth below, the
parties agreed to the following terms:
TERMS OF THE STIPULATION
'II 6. PacifiCorp shall be allowed to recover, through a surcharge and the
acceleration of the "Merger Credit " as described below, $25 million for
Excess Power Costs.
'117. As a result of the Commission s Order ("Merger Order ) in the
ScottishPower merger case (Case No. PAC-99-01), customers have received
since January 2000 a credit of approximately $1.6 million per year from
PacifiCorp that has been reflected as a line item on customers' bills pursuant to
Electric Service Schedule No. 99 (the "Merger Credit"). If PacifiCorp were to
continue such credit for the full four-year period reflected in the Merger Order
there would be approximately $2.3 million, on a present value basis, remaining
to be credited to customers. The parties agree that in order to offset
PacifiCorp s Excess Power Costs, the merger credit and Electric Service
Schedule No. 99 shall be accelerated and credited to reduce the Excess Power
Cost recovery from $25 million to $22.7 million.
'118. PacifiCorp shall be allowed to implement a power cost surcharge (the
PCS") designed to recover $22.7 million over a 24-month period beginning
May 15 , 2002 and ending May 14, 2004.... A true-up.. . may be implemented
over a 12-month period immediately following the 24-month PCS recovery
period to reflect any under- or over-collection of the total authorized PCS
amount.
Stipulation pp. 2-
ORDER NO. 29034
As reflected in the filed testimony of parties supporting the Stipulation, the proposed
settlement incorporated implementation of the Schedule 34 BP A credit, recovery of extraordinary
power supply costs with a rate mitigation adjustment, a modified revenue requirement across
customer classes and changes in the Schedule 10 irrigation class rate design. Tr. pp. 305, 307.
The proposed settlement also incorporated a modified irrigation class revenue requirement that
brings the irrigators closer to their cost of service. The effect of this change permits a reduction in
rate increases to other customer classes that would otherwise occur due to power supply cost
recovery. Tr. pp. 305 , 316. The impact of the power supply cost recovery is reduced by applying
what is termed a rate or revenue mitigation adjustment (RMA) to various customer classes and
spreading recovery over two years with a third year true-up. The resultant proposed changes in
rates over those in effect in 2001 are a 34% decrease for Schedule 6A general service customers; a
28.2% decrease for residential customers; a 28% decrease for irrigation customers; and a
maximum 4% increase for Schedules 6, 9, 10 and 13 commercial and industrial customers. See
Stipulation Attachment B, Table BB2.
D. Public Hearing
To further the Commission s review of the Application and proposed settlement the
Commission directed that parties prefile testimony in support or opposition to the Application and
Settlement. To promote public participation in this case, the Commission also scheduled an
evidentiary technical hearing, public workshops, public hearings, and provided an opportunity for
written comment. Pursuant to Notice, public hearings were held in Rigby and Preston on May 6
and 7, 2002 to take customer testimony in this case. The hearings were preceded by public
workshops where the Company and Staff made independent presentations and answered
questions. The evidentiary hearing was also held on May 7 to hear testimony from the parties
both supporting and opposing the settlement. In addition to the parties of record, many former and
sitting Idaho Legislators attended the hearings.
The Commission has reviewed and considered the record in this case including: the
proposed Stipulation and Settlement Agreement, the transcript of proceedings and exhibits, and
the filed comments of customers and parties. We acknowledge that most customers providing
testimony opposed the settlement for a number of reasons. We have carefully considered their
testimony in our decision and address those concerns in greater detail below.
ORDER NO. 29034
1. The Settlement Process. The proposed settlement was criticized as being the result
of a process that failed to provide an early opportunity for public participation. Some customers
contend that the public was not consulted and that their opinions were not sought out. It is
important to note, the Commission finds, that the record does not support such criticism. This
Commission sought public input from the very beginning of this case with its initial Notice of
Application and solicitation of comments and invitation to intervene. (January 16, 2002.) The
Notice was served on every city and chamber of commerce in PacifiCorp s service area. An
additional opportunity presented itself with Commission Notices of Prehearing and Settlement
Conferences. The Stipulation was filed with the Commission on April 11 and hearings and
workshops were scheduled for eastern Idaho in early May. With each Order and Notice the
Commission issued a press release. The Commission, however, cannot control how local media
outlets choose to treat our press releases.
Under Commission procedural rules, settlement negotiations of parties by their very
nature are confidential.IDAPA 31.01.01.271-280.As is the case with the Court Rules
confidentiality promotes the open and frank discussion of issues and is intended to promote a just
and speedy resolution to disputes. Although the discussions are confidential, participation is open
to the Company, all intervenors and the Staff. It is not a process that is intended to be an open
public forum. The post-hearing comments filed by Monsanto and the Idaho Irrigation Pumpers
Association give some insight into the settlement process in this case. Relevant excerpts from
those comments are as follows:
Monsanto
Monsanto is mindful of the fact that this Commission has allowed Idaho Power
and A vista to recover excess power supply costs incurred under similar
circumstances.
While the cost of service studies and methodologies presented by PacifiCorp
were not adopted or accepted by Staff or intervenors, a Rate Mitigation
Adjustment (RMA) was used to accomplish cost shifts among the customer
classes in a manner perceived to be a fair and equitable shift in the general
direction of cost-of-service. (It was) the parties' reasonable belief and
anticipation that the Commission likely would make a similar cost shift had the
case been concluded through contested hearing. By the Stipulation. the parties
achieved a known and certain result. eliminated risks. and avoided the time
and expense of a contested hearing. As in any compromise. the opportunity of
achieving a better result was foregone. while the risks of a worse result
avoided.
ORDER NO. 29034
Monsanto Post-Hearing Comments p. 3 (emphasis added).
Irrigators
The Irrigators have actively participated in the settlement negotiations that
have led up to the presentation of the Stipulation.
The agreed upon net recovery of approximately $22.7 million in excess power
costs is reasonable and appropriate given the risks of a less favorable result
the Irrigators ' limited resources , and in light of other settlements reached in
other jurisdictions on this issue.
Although PacifiCorp s cost of service studies and methodologies were not
accepted by Staff, the Irrigators or Monsanto, the Irrigators agreed to the RMA
(Rate Mitigation Adjustment) in light of (1) the historical perception that the
class as a whole was under cost of service and (2) the practical realization that
the Commission would make such a shift if the matter was resolved through a
contested hearing. The Irrigators want to stress the ability to make such an
adjustment was only made possible in the aggregate by the extraordinary BP A
exchange credit available to this class.
Irrigator Comments pp. 1-3 (emphasis added).
The Commission is convinced that in appropriate cases negotiated settlement when
found reasonable is a preferred outcome. It is certainly often a better use of party and Commission
resources. In this case there appeared to be credible arguments on both sides of the issues and
inconclusive results in other jurisdictions. All this led to the uncertainty and perceived risks of
going to hearing recognized by Monsanto and the Irrigators. Thus the opportunity existed for
reciprocal concessions and a reasonable resolution of the issues without contracted litigation.
The Commission Rules contain procedural safeguards for proposed settlements. As
reflected in Commission Rule 275 , proponents of a proposed settlement carry the burden of
showing that the settlement is reasonable, in the public interest, or otherwise in accordance with
law or regulatory policy. IDAP A 31.01.01.275. Pursuant to Rule 276, the Commission is not
bound by settlements. This Commission reserved making judgment as to the reasonableness
the Settlement until after the public hearings concluded and the record was closed.
2. The Company s Private Representations. The comment heard most often from
customers at the public hearings was that the Company s attempt to recover November 2000 -
October 2001 power costs breaks a promise made during the time of the ScottishPowerl
ORDER NO. 29034
PacifiCorp merger. More specifically, many commentors recalled that PacifiCorp promised not to
raise rates for a period of three to five years. As one customer stated "a promise is a promise - a
contract is a contract - its called integrity and when a person or a company breaks or tries to break
a promise or a contract, you can no longer trust that person or company.Tr. p. 453. Although
this promise was reportedly made by PacifiCorp s CEO in "behind the scenes" private discussions
with eastern Idaho Legislators (Tr. p. 58) and in newspaper advertisements by the utility, (Tr. pp.
44,45), it was not part of the Company s merger filing before the Commission. Thus, it was not
part of the testimony or record that the Commission was permitted to consider. Nor were these
promises disclosed to the Commission following issuance of the Merger Order - it was not raised
by any party or person in a request for reconsideration or clarification. Idaho Code ~ 61-626
(Reconsideration); IDAP A 31.01.01.325 (Clarification). Because no one placed this fact in the
record, we are constrained to base our findings on the record before us. Idaho Code ~ 61-629;
Mountain View Rural Tele. Co. v. Interstate Utilities Co.55 Idaho 86 38 P.2d 40 (1934). While
this Commission can appreciate the anger of the Company s customers, we are bound by our
previous Orders and the evidence of record that those decisions rested upon.
It appears the private meeting at a cabin between elected officials and utility
representatives led to a public misinterpretation of Merger Condition No.2. Tr. pp. 435-37. From
this meeting those elected officials in attendance appear unanimous in their conclusion that utility
officials made significant promises regarding future treatment of expenses. The Commission has
no reason to discount those perceptions. However, because these promises from the cabin meeting
were never made known to the Commission and placed in the merger case record, they were not
considered then and we are legally unable to consider them now. It is important to distinguish that
while it is entirely appropriate for elected officials to meet with utility representatives to discuss
the status of an ongoing case before the Commission, the opposite is true for Commissioners. The
Commission as a quasi-judicial body must confine its decision to the record produced at hearing.
Failing to do so we violate procedural due process of law. Amendment 14, U.S. Constitution;
Idaho Historic Preservation Council v. Boise City Council 134 Idaho 651 , 8 P .3d 646 (2000).
Had a Commissioner been in attendance at such a meeting, without providing sufficient notice
all the parties in the case, that Commissioner s action could constitute a dereliction of duty and be
grounds for dismissal. With that said, under the circumstances surrounding the meeting at the
ORDER NO. 29034
cabin and the promises reportedly made, this Commission could not legally use that information to
formulate its decision either then or now.
What seems to have compounded the confusion over the interpretation of Merger
Condition No.2 is that when the Commission issued its Order in the merger case, this condition
appears to have mirrored some of the perceived promises made at the cabin meeting. Apparently,
the existence of Merger Condition No.2 led some to conclude that the Company s promises to
elected officials had been incorporated fully into the Commission s Order. But this, as was
mentioned previously, is not the case.For the Commission to have done so would have
incorporated into our Order an inappropriate ex parte or off the record communication. What the
Commission intended with Condition No.2 was clearly articulated in the merger Order. That
condition, coupled with the merger credit, was intended solely to result in a rate reduction that
would last through January 1 , 2002. The word "freeze" was never used in that Order and there
was no mention of expenses during the moratorium being disallowed for future recovery. In fact
that condition clearly anticipated that rates could go up after January 1, 2002. Furthermore, the
only way for a rate increase to have been effective on January 1 , 2002 is if non-merger expenses
that were incurred during the moratorium period were included. It is indeed unfortunate for
everyone involved that the events of the meeting at the cabin have contributed to this
misinterpretation of Condition No.
3. Merger Condition No.. This Commission addressed Merger Condition No.
pursuant to a Petition for Clarification in this case filed by the Intervenor Tim Shurtz. Order No.
28998 issued April 12, 2002. This issue was raised repeatedly in public comments, so we will
address it again. Merger Approval Condition No.2 stated:
At a minimum, ScottishPower shall not seek a general rate increase for its
Idaho service territory effective prior to January 1 2002.
Case No. PAC-99-, Order No. 28213 p. 8. The Commission findings explained at page 31:
As a final and irrefutable measure to ensure that rates will not increase as
result of the merger, we hereby impose the additional condition (Merger
Approval Condition No.2) that following the merger, PacifiCorp shall not
seek a general rate increase effective prior to January 1 , 2002. This literally
guarantees that PacifiCorp s customers will see an immediate rate reduction
lasting at least two years through the combination of the merger rate credit and
the moratorium on general rate increases imposed herein.
In our prior Order No. 28998 , we provided the following clarification:
ORDER NO. 29034
On November 15, 1999 , after nearly a year of investigation and numerous
hearings, the Commission issued Order No. 28213 approving the merger of
PacifiCorp with Scottish Power. Many issues and concerns were raised in the
course of that proceeding, notably service quality and rates. Approval of the
merger was subject to 46 conditions to address the concerns raised and ensure
that the public interest was served by approval of the merger. Merger
Condition No.2 set forth above was included to prevent the Company from
increasing customer rates for any reason prior to January 1. 2002. Thus
customers were guaranteed a two-year period of rate stability, and Commission
oversight to prevent any merger related increases was enhanced.
On November 1 , 2000, PacifiCorp filed an Application for deferred
accounting order. Extraordinarily high wholesale market prices outside the
control of the Company were resulting in actual costs for the Idaho jurisdiction
that greatly exceeded Idaho s allocated share. Intervenors in that case argued
that the application should be dismissed because its approval would violate
conditions imposed by the merger Order. The Commission found that
authorization of deferred accounting for these expenses was only a mechanism
to preserve them for future consideration. not a guarantee of future recovery
and would not result in a rate increase prior to January L 2002 . Approval of
PacifiCorp s request for a deferred accounting order, we found, was not a
violation of the merger condition that no rate increase should be requested to
be effective prior to that date. Our decision simply provided PacifiCorp the
opportunity to request and litigate the recovery of such costs in the future.
On January 2, 2002, PacifiCorp filed this case. One of the matters now at
issue is the recovery of the costs that were deferred pursuant to our earlier
Order. Intervenor Shurtz has requested that we clarify why consideration of
the deferred amounts is not a violation of the Merger Conditions prohibiting
rate increases before January 1 , 2002. The answer is clear from an
examination of the language of the condition imposed. PacifiCorp was
prohibited from seeking a general rate increase effective prior to J anuarv 1.
2002. It did not seek any increase in rates to be effective before 2002.
therefore the Company has fulfilled that condition The Commission
specifically found in Order No. 28630 that deferred accounting was
appropriate for the unanticipated and extraordinarily high power costs
experienced as a result of the wholesale market.That deferral preserved those
expenses for consideration now. We do not decide whether, or how much, if
any, of those expenses should be passed on to customers. We do find that
there is not and can not be a violation of Merger Condition No.2 if those costs
are approved for recovery, either as part of a settlement or otherwise.
Order No. 28998 pp. 2-3 (emphasis added).
ORDER NO. 29034
The power cost expenses the Company seeks to recover in this case are not merger
related expenses. Nor, as was suggested by some customers and Intervenor Tim Shurtz, are they
the result of any "learning curve" or a result of a foreign company learning the ropes in the
Northwest energy market. It was not a lack of experience that caused PacifiCorp to incur these
power cost expenses. Similar expenses were incurred by nearly every utility in the western
interconnection, both public and private, including Idaho Power Company and Avista Utilities.
Tr. p. 329.The price spike in the wholesale market in late 2000 through mid-2001 was
unprecedented and was clearly not foreseen or anticipated by anyone at the time of the
ScottishPower/PacifiCorp merger.
The Commission did not intend by imposing Merger Condition No.2 that PacifiCorp
and its shareholders be required to solely bear the costs associated with a subsequent and
unforeseen series of events that triggered a run-up of extraordinary costs. We ensured a period of
rate stability for eastern Idaho customers, many of whom were opposed to the merger that we
approved. We provided the Company s customers with a tangible benefit of rate stability for two
years-a benefit they have received and a benefit the Farm Bureau recognized was of value. Tr.
pp. 379 405 406. Moreover, the requested power costs were extraordinary, simply meaning that
they were unforeseen and out of the ordinary. Indeed, the drought conditions and the
unprecedented market prices for wholesale power were well out of the ordinary.
Mr. Shurtz, in response to Commission questioning, stated that although he believes
the Company under Merger Condition 2 could file a rate case on January 1 2002, it could not use
a test year or expenses from the moratorium period. Tr. pp. 375, 376. Mr. Shurtz s interpretation
is incorrect from both a regulatory and an equity or fairness standpoint. Agricultural Products
Corp. v. Utah Power Light 98 Idaho 23, 26 557 P.2d 617 619 (1976). It would be unfair to
the Company and would deny customers the benefit of using the most recent test year information
for determining the Company s load/resources profile and establishing authorized expenses. As
explained in our Orders, the Commission finds that the Company would have been permitted to
file a rate case in 2001 as long as rates did not change or become effective prior to January 1
2002. Tr. p. 379.
It was also suggested by Intervenor Tim Shurtz and by other customers that before any
monIes are paid to PacifiCorp, the Company should be required to file a general rate case.
General rate cases can result in rate increases as well as decreases (Tr. p. 447), and also in a
ORDER NO. 29034
realignment of customer class revenue responsibility. As a matter of regulatory oversight, we note
that the Staff performs an audit of PacifiCorp s accounts and operations every three years. The
nature and extent of the audit is as if the Company had filed for a general rate case. The purpose
of Staffs audit is to determine if the Company is over-earning and to assess whether its rates
continue to be just and reasonable.
PacifiCorp provides a utility service to the public pursuant to a Certificate of Public
Convenience and Necessity that obligates the Company to provide service regardless of cost and
to charge only rates approved by this Commission. Idaho Code ~~ 61-307 and 61-313. This is a
constraint that does not apply to unregulated businesses. In this case, the Commission authorized
a deferral accounting mechanism for extraordinary power costs incurred by PacifiCorp between
November 2000 through October 2001 to acquire adequate resources to meet its service
obligation. As a regulatory body this Commission has a dual obligation, one to the utility to
ensure that the utility is allowed such rates as will produce sufficient funds to meet necessary
maintenance and operating expenses, and to provide it with an opportunity to earn a fair and
reasonable return on the value of its property devoted to the public service. On the other hand, the
Commission has an obligation to customers to ensure that the service they receive is adequate, safe
and reliable and that rates they pay are fair, just and reasonable. Idaho Code ~~ 61-301; 61-302;
Grindstone Butte Mutual Canal Co. v. Idaho PUC 102 Idaho 175 627 P.2d 804 (1981).
4. Hunter Plant Failure. Several commentors argued that the Company be prohibited
from recovering the power costs due to the Hunter plant outage. As reflected in testimony, the
reason for failure of the Company s Hunter Unit No.1 Generation facility on November 24 2000
has not been determined with any certainty, neither in this case nor in any jurisdiction in which the
issue has been litigated. Tr. pp. 241 242. The Company states it knows answers to the questions
what, where and when; but not why. The evidence, it states, is gone. The Company contends that
operating practices and maintenance was not a contributing factor.Tr. pp. 243, 244. The
generation unit, it notes, was recently overhauled in 1999. Tr. p. 246. A customer states "the
Company built it, the Company operated it, the Company maintained it - It wasn t an act of God.
It was a mechanical failure. They have to take responsibility for that." Tr. p. 442.
That the failure of Hunter caused the Company to go to market for replacement power
is undisputed. The question is: Should there be a sharing of responsibility in costs? The proposed
settlement does not attempt to assign blame or allocate a specific percentage of sharing for Hunter.
ORDER NO. 29034
The settlement provides a negotiated recovery figure and not a road map to determine how the
figure was determined. Any attempt by this Commission to allocate to Hunter a portion of the
difference between the Company Application for $38 million to the settlement amount of $25
million is, we find, a meaningless exercise. We note only that Staff in its initial negotiating
position recommended a 25% discount ($2.97 million) of the approximate $11.9 million Hunter
costs included in the $38.3 million of the power supply costs the Company is seeking to recover.
Staff Exh. 102. It is important to note that the Hunter costs in the Company s filing include only
the net costs above and beyond what would have occurred had Hunter operated normally, i., the
replacement energy costs. No capital costs associated with repair of the Hunter plant that were
subject to insurance or the deductible are included in the $38.3 million the Company requested.
Tr. pp. 250, 251.
In summary this Commission hopes that our discussion of the above issues provides
the Company s customers with a better understanding of what this Commission can consider in
making its decisions and the nature of the obligations we must fulfill both to the utility and to its
customers. We also hope that we have provided customers with some insight as to the difference
between a private and regulated company. PacifiCorp is obligated to provide its customers with
power. That obligation is a service requirement. The Company cannot just choose to turn off the
switch. But neither is it provided carte blanche as to how it operates and what it charges. This
Commission provides regulatory oversight. We require the Company to prove its case and in
making our decision we consider all evidence in the record.
We next turn to the remaining issues.
E. Power Supply Costs
In Order No. 28630 (Case No. P AC-00-5) the Commission unanimously authorized
PacifiCorp to defer excess net power costs resulting from increases in the electric market price
commencing November 1 , 2000 through October 31 , 2001. In our Order we stated:
Although the Commission approval of PacifiCorp s Application for a deferred
accounting order will allow the Company the opportunity to seek recovery of
these costs, it does not guarantee future recovery of any deferred amounts.
The Company must ask for recovery in a separate, future proceeding where the
Commission will review the prudency of any deferred amounts to determine
whether the Company is entitled to recover them from its customers.
Order No. 28630 p. 6. The Company now seeks recovery of deferred power costs in this case.
ORDER NO. 29034
The total amount of extraordinary power supply costs incurred by the Company and
attributable to the Idaho jurisdiction is $49 million. However, $11 million of those costs were
incurred prior to November 1 , 2000 and are therefore outside the authorized period of deferral. As
a result, the Company s shareholders bear the full responsibility for those costs and they will not
be passed on to customers. The Stipulation and Proposed Settlement includes recovery of $25
million (65%) of the $38 million in power supply costs and carrying charges requested by
PacifiCorp. Tr. pp. 260; 257, 258. When viewing the Company s total power purchases, the
Settlement represents a 50/50 sharing between customers and the utility.
In assessing the power supply costs in this filing, Staff stated that it evaluated the
normalized power supply costs allocated to the Idaho jurisdiction, the deferral period accrual
amounts, the impact of wholesale power sales contracts, and the ramifications of the Hunter plant
failure.Tr. p. 307.As reflected in filed testimony, the generation resources available to
PacifiCorp during the authorized accrual period was affected by the second worst water year on
record (Tr. p. 219), and the loss ofthe Company s Hunter generating plant on November 24 2000.
The decrease in system generation forced the Company to look off-system (i., the western
wholesale market) for replacement power. The replacement resources available to PacifiCorp to
serve its load obligations, the Company states, were power purchases from the market at
extraordinarily high prices.
Intervenor Shurtz urged the Commission to deny recovery of these costs in large part
attributing them to mismanagement and inexperience. He stated that ratepayers should not be
penalized for the Company s "growing pains." Tr. p. 360.
Commission Findings: Based on our review of the testimony filed in this case by
PacifiCorp and Commission Staff and the supporting comments of Monsanto and the Irrigators
the Commission finds with relative certainty that the proposed power supply cost settlement
amount of $25 million is fair, just and reasonable. While not specifically broken out into cost
components, this amount is nevertheless comprised of Idaho s jurisdictional share of excess net
power costs incurred by PacifiCorp during the authorized deferral period. Although the public has
expressed a need to know how the $25 million was calculated, we recognize and accept that the
amount is a result of a negotiated settlement. From the Company s perspective there was no
specific delineation of costs. Tr. p. 296. Considered by the parties were the Company s short-
term power purchases, wholesale power contracts, strategies in serving load, load growth, and
ORDER NO. 29034
individual assessments to the probability of a party prevailing on a challenge of imprudence. Tr.
pp. 298-300. Because we believe the settlement amount to be reasonable and in the public
interest, we accept the $25 million settlement figure and forego the uncertainty that would
otherwise accompany a full evidentiary hearing on the issues. The parties in their negotiating
process have arrived at a number that they all feel is reasonable, but each one may have a different
basis in looking at the costs for why they feel that it is reasonable. We feel with certainty that
many of the disallowances identified by Staff (Hunter 1 outage, wholesale contract costs, load
growth and jurisdictional allocation) are included in the final Settlement figure.
F. Acceleration of Merger Credit and Power Cost Surcharge
The proposed settlement reduces the impact of the power supply cost by accelerating
the remaining two years of the Schedule 99 merger credit - a calculated present value of $2.
million. Tr. pp. 265, 314. The resulting power cost surcharge is thus designed to recover not $25
million, but $22.7 million over a 24-month period beginning May 15 , 2002 and ending May 14
2004. The power cost surcharge will be implemented as a line item charge on a customer s billing
through electric service Schedule 93 , with a potential third-year true-up. Tr. p. 265. Under
Schedule 93 , a cents per kilowatt hour surcharge will be assessed on a customer s monthly
metered usage as determined by the Voltage Level at which a customer takes service.
Commission Findings: The Commission finds the proposed Schedule 93 surcharge
and method of collection to be reasonable. The Commission further agrees with the Settlement
Parties that the use of the Schedule 99 merger credit to reduce the amount of power cost surcharge
to customers is not an elimination or loss of the credit but is instead an acceleration of the credit.
We find this to be of substantial benefit and value to customers and approve of the propose change
in merger benefit delivery and related accounting. Additionally, this accelerated treatment helps
insure the likelihood that customers who were taking service at the time of the merger actually
benefit from the credit. With acceleration of the credit, the present line item for the Schedule 99
merger credit on a customer s billing will be eliminated.
G. Customer Class Revenue Requirement
and Rate Mitigation Adjustment (RMA)
Commission Staff states that its objective in settlement negotiations and allocating
the revenue requirement to customer classes was to create a package that appropriately applied the
ORDER NO. 29034
BP A credit, equitably distributed power supply cost recovery responsibility, and ultimately,
moved the irrigation class closer to perceived cost of service. Tr. p. 315.
The Settlement Parties propose that the Rate Mitigation Adjustment (RMA) in the
Stipulation will be reflected as a line item charge on customers' bills through electric service
Schedule 94. Tr. pp. 263, 264. In year one, the RMA applies only to commercial, industrial and
lighting customers. In year two , the RMA continues and will apply to all customer classes. No
customer class will receive a price increase in year two. Irrigation customers in year two will see
an average additional rate decrease of 11 %. In year three and subsequent years, the RMA may
continue subject to termination provisions contained in the Stipulation. The Settlement Parties
have agreed that upon the earlier of: (1) the expiration of the current electric service Schedule 34
BP A Exchange Credit; or (2) the adoption by the Commission of a cost-of-service study for
PacifiCorp and the subsequent implementation for all customers of the approved cost of service
study by any lawful method, the electric service Schedule 94 RMA will be terminated. Tr. p. 269.
Intervenor Shurtz argued that it was inappropriate to consider the RMA in the absence
of a general rate case. Tr. p. 360. He stated that the RMA was "an arbitrary and unequal way of
mitigation costs to all classes of consumers.Id.
Commission Findings: The distribution of power cost recovery and realignment of
the irrigation class cost-of-service without a significant increase to any class, we find, was only
made possible by what the stipulating parties recognized to be an extraordinarily large BP A credit
to small farms. Given the facts of this case, the Commission finds the proposed allocation method
for Company recovery of deferred excess power costs to be fair, just and reasonable. We also find
reasonable the proposed Schedule 94 Rate Mitigation Adjustment (Exh. 20; Stipulation
Attachment D) and commend the Irrigators for their willingness to participate in a voluntary
realignment of cost of service and related assumption of revenue responsibility. Rather than an
arbitrary distribution, we find this realignment is of benefit to all other customer classes. In Order
No. 23508 issued January 18 , 1991 , the Commission noted that the irrigation class provided one of
the lowest returns of all the customer classes. It is appropriate to reduce that disparity in this case.
H. Rate Design-Irrigation Class
As reflected in the proposed Stipulation, the rate structure for all customer classes
except the irrigation class remains unchanged. The rate design proposal for the irrigation class is
an elimination of the separate A, B and C firm and interruptible schedules in favor of a single
ORDER NO. 29034
revenue-neutral, firm service rate. Exh. 20; Stipulation Attachment C. The proposed service
charges and demand charge are calculated as the average of the three current rate options
proportioned for the amount of usage under each of the three rate options. The Settlement Parties
also proposed to modify the energy rate component from a two-block, declining rate to a three-
block, declining rate. The three-block energy charge is designed to more closely track cost of
service while giving more uniform price signals to all irrigation customers. Tr. pp. 271 272.
Recognizing that some irrigators use energy at levels not eligible for the BP A credit
(e., Schedule 10 - Irrigation Season Rate C), larger irrigation customers on a case-by-case basis
may still be able to obtain individual interruptible or load-control contracts for the 2002 irrigation
season. PacifiCorp agreed to interruptible contracts with not more than 15 large irrigators (defined
as irrigators having an individual meter registering more than 500 kilowatts during the last 12
months) on a first come - first serve basis. Tr. pp. 272, 273. PacifiCorp has agreed to work with
irrigators to develop an optional load control program beginning with the 2003 irrigation season
and has committed to file such a program with the Commission no later than January 31 , 2003.
Commission Findings: The Commission finds the proposed Stipulation changes for
the Electric Service Schedule 10 - Irrigation and Soil Drainage Pumping Power Service tariff
(Exh. 20; Stipulation Attachment C) to be fair, just and reasonable. We specifically note that the
Irrigators strongly supported this proposal. We encourage the Company to work with irrigators in
the manner proposed and expect it to follow through on its commitments.
L Nu-West Modification
At hearing, the Commission granted Nu-West Industries' Petition to Intervene out of
Under the proposed settlement and stipulation, Nu- West would be treated as a tarifftime.
customer and allocated a share of the power costs the Company seeks to recover. The power cost
surcharge allocated to Nu- West is $936 000. After giving effect to a rate mitigation adjustment to
Nu-West of $777 000, the net effect is a $159 000 per year rate increase for Nu-West in each of
the next two years.
Nu-West argued that under its 1998 Service Agreement (July 1 , 1998 - December 31
2001' Exh. 501), its rates were fixed during the term of the Agreement , and neither PacifiCorp nor
the Commission was authorized to alter these rates except upon an extraordinary showing that the
rate is "so low as to adversely affect the public interest - as where it might impair the financial
ability of the public utility to continue its service, cast upon other consumers an excessive burden
ORDER NO. 29034
or be unduly discriminatory.Citing Agricultural Products Corporation v. Utah Power Light
98 Idaho 23, 29 557 P.2d 617 (1976). No such showing, as to the unreasonableness of the then
existing contract rates or that the then existing contract was unreasonable vis-a.-vis the public
interest, Nu- West stated, has been made or even attempted in this case.
Nu-West also insisted that it relied on the Company s original proposal in this case -
no increase to any customer class. Tr. p. 345. The Commission s Notice, however, apprised Nu-
West that "the rates and charges of all customers, including those governed by special contract, are
at issue and subject to change.It was during settlement negotiations, Nu- West states, that it
became vulnerable to an increase. Tr. p. 345. Nu-West did not participate in the settlement
conferences.
Commission Findings: The Commission finds that Nu- West had legal notice of
proceedings in this case and technically could have participated. We nevertheless find merit in its
assertion and the nature of the contract service received under its 1998 Service Agreement with
PacifiCorp. Consequently, we find that it would be inappropriate to include Nu-West in the
proposed power cost surcharge.
PacifiCorp at hearing (Tr. p. 348) and in post-hearing filed Exhibit 25 (Option 3 tables
BB1-BB3) recommended that in the event that Nu-West is excluded from the power cost
surcharge, the amount allocated to Nu-West be collected from tariff customers during the 12-
month true-up period. PacifiCorp clarified that it will not recover any carrying charges or earnings
on the Nu- West amount deferred for collection during the true-up period. The Commission finds
the Company proposed Exhibit 25 Option 3 to be acceptable and reasonable. The Option 3 tables
BB 1- BB3 illustrating the impact of our decision have been inserted into the Stipulation attached to
this Order.
III. INTERVENOR FUNDING
The Commission received timely applications for intervenor funding in this case from
both the Idaho Irrigation Pumpers Association and from Mr. Shurtz. IDAPA 31.01.01.161-170.
Tim Shurtz requests an award of $10 173; the Irrigators seek an award of $32 378. Both
applications satisfy the procedural requirements of Commission Rule 162.
ORDER NO. 29034
1. Tim Shurtz requests intervenor funding in the following amount:
Tim Shurtz 152 hours at $40 per hour
Travel meals and miscellaneous expense
Legal (Alva Harris) 20 hours at $125/hour
Assistant (Gilbert Dayley) 15 hours at $40/hour
Clerical Assistant 12 hours at $25/hour
TOTAL
$ 6 080.
$ 693.
$ 2 500.
$ 600.
$ 300.
$10 173.
Mr. Shurtz noted that his position differed from Staff and other parties in that he
contended the Company s requested recovery of excess power costs was prohibited by Condition
2 of the Merger Agreement. He also contended the Hunter outage was the responsibility of the
Company. Finally, he argued that piecemeal ratemaking was wrong and that the Company
recovery should be required to file a general rate case before authorizing. Mr. Shurtz felt that
without his participation as an intervenor, the public would have remained largely uninformed and
would not have participated in this case.
PacifiCorp opposes Mr. Shurtz s application for intervenor funding, contending that
such an award cannot be made if the Commission approves the Stipulation because the law
requires that an intervenor make a material contribution to the Commission s decision.
2. The Irrigators request intervenor funding in the following amount:
Legal 117.9 hours at $135 - $150/hour
Travel, meals, lodging, etc.
Consulting fees (Tony Yankel) 152 hours at $1O0/hour
TOTAL
$16 107.
$ 1 071.68
$15.200.
$32 378.
The Irrigators stated that by their participation they sought to limit the Company
recovery of its claimed excess power supply costs to only those that were prudently incurred and
properly recoverable. Of utmost importance to the Irrigators were the rate spread and rate design
aspects of this case. By way of the Stipulation, the Irrigators agreed to: (1) the revision of the
ABC tariff schedule to that of a firm rate; and (2) to use of a modified rate mitigation adjustment
(RMA) feature that has the effect of making a substantial move for the irrigation class toward cost
of service and redistributing the revenues to the benefit of the other customer classes to principally
mitigate the effect of the Company s excess power supply costs.
Commission Findings: The Commission s decision whether to award intervenor
funding and in what amount is controlled by Idaho Code ~ 61-617 A and Rule 165 of the
Commission s Rules of Procedure. IDAPA 31.01.01.165. We find that both intervenors
ORDER NO. 29034
contributed materially to our decision in this case. While we did not ultimately agree with the
recommendations of Mr. Shurtz in this case, that is not a prerequisite to an award of intervenor
funding. We appreciate Mr. Shurtz s efforts to be involved in ourprocess. It is the policy ofthis
Commission to offer a reasonable opportunity for a variety of interests to present their positions
before the Commission. Mr. Shurtz s Petition for Clarification helped to define the applicability
of Merger Condition No.2. We further find the Irrigators participation and involvement in the
settlement process to be critical to the fashioning of what we find to be a reasonable and equitable
solution to this Company s recovery of excess power costs and the recognition of class cost of
servIce.
Pursuant to Rule 165 the total award for all intervening parties combined shall not
exceed $25 000 in any proceeding. Based on our review of the intervenors ' relative contributions
to our decisions in this case, we find it reasonable to award the Irrigators $22 500 and Tim Shurtz
500. The intervenor funding award shall be recovered from all customer classes. This amount
may be deferred until the next general rate proceeding or in another appropriate case.
IV. FAILURE TO PROVIDE NOTICE TO CUSTOMERS
An issue raised in the public hearings was the adequacy and sufficiency of the public
notice, specifically what attempts were made to notify customers of the Company s Application.
Some customers indicated they learned of the Commission s hearings only serendipitously and did
not get informed until it was too late to study, prepare and testify. Nu- West also raised the issue
of adequate notice.
The Commission finds notice to customers of impending changes in rates and charges
to be a serious matter. While this Commission provides public notice of utility applications
procedure, scheduling and hearings, and provides press releases regarding same to the media, we
have no control over actual media coverage.
Idaho Code ~ 61-307 establishes a requirement that schedules with the proposed
changes in rates and services be filed with the Commission and kept open for public inspection.
The Company reports that its filing was made available for public inspection at the Company
offices in Rexburg, Preston, Shelley, and Lava Hot Springs, Idaho. The Company claims it has
met the statutory notice requirement. In reviewing the official record in this case, we agree.
However, this does not complete our inquiry.
ORDER NO. 29034
Rule 102 of the Commission s Utility Customer Information Rules requires a utility to
provide each customer with individual notice (through bill stuffers or an additional comment page
with the customer s bill) of a utility s application for a general or tracker rate change. IDAP A
31.21.02.102. Our Rule requires that the customer notice shall make it clear that the application is
a proposal, subject to public review and a Commission decision. It shall also inform customers
that a copy of the utility s application is available for public review at the offices of the both the
Commission and the utility. Id. The Commission finds that the Company s Application in this
case is of such nature that Rule 102 notice was required. The Commission is informed in this case
by a letter received by Commission Staff on May 15 , 2002 that the Company acknowledges that it
failed to comply with the Rule 102 customer notice requirement.
Rule 102 also requires that the utility issue a press release containing the same
information presented in the customer notices to all newspapers, radio and television stations
listed on the Commission s news organization list for the utility. The press release is to be mailed
or delivered to media outlets simultaneously with filing of the Application and a copy of the press
release is to be filed with the application. Although the press release in this case was not filed
with the Application, the Commission is informed that on May 15, 2002 Commission Staff was
provided with a copy of the Company s January 7, 2002 press release.
While failure to comply with the Rule 102 notice requirements creates no due process
or other procedural rights in customers (IDAPA 31.21.02.102.05), we find it is a serious violation
of a Commission rule. Failure to provide the required individual notice potentially limits public
participation in our proceeding. See Idaho Code ~ 61-617 A( 1). This violation triggers
Commission powers to affect an appropriate remedy under the provisions of Title 61 , Chapter 7.
Idaho Code ~ 61-706 establishes a maximum penalty for each offense of $2 000 per
day. In this case the Commission finds that the lack of individual notice by the Company to each
of the Company s 54 386 customers constitutes a violation of Rule 102. Based on these facts, the
Commission could theoretically seek a civil penalty of $108 772 000. For failure to provide
notice, the Commission finds it reasonable to require the Company to provide each customer a
credit of $20.00 or a total of $1 087 720. This credit shall be provided to customers within 90
days of the date of this Order. The Company may prorate the credit over this 90-day period to
avoid cash flow concerns. Idaho Code ~~ 61-703; 61-501.
ORDER NO. 29034
In crafting this credit regarding notice failure, the Commission intends to send a strong
signal to the Company that it needs to be more responsible in its communication with customers.
Not only must it comply with regulatory requirements, but it should strive to ensure that a
consistent message is conveyed in its filings with this Commission, in its media and marketing
efforts, and in its efforts to influence public officials.
V. CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over PacifiCorp dba Utah
Power & Light Company, an electric utility, and the issues presented in Case No. P AC-02-
pursuant to Idaho Code, Title 61 , the Commission s Rules of Procedure (IDAPA 31.01.01.000
seq.and the Commission s Utility Customer Information Rules (IDAP A 31.21.02).
ORDER
In consideration of the foregoing and as more particularly described above and
detailed in the attached Stipulation and schedules that accompany this Order, IT IS HEREBY
ORDERED that the Stipulation and proposed settlement submitted by PacifiCorp, Commission
Staff, the Idaho Irrigation Pumpers Association and Monsanto Company, with the exception of the
power cost surcharge allocated to Nu- West Industries, be and hereby is approved, and that in
accordance therewith
PacifiCorp is allowed to recover, through a surcharge and the acceleration
of the Electric Service Schedule No. 99 "Merger Credit " $25 million for
excess power costs.
PacifiCorp is allowed to implement a power cost surcharge (PCS) designed
to recover $22.7 million over a 24-month period to begin the day following
the service date of this Order. The PCS is to be implemented as a line item
charge on a customer s bill through Electric Service Schedule No. 93.
The Schedule 93 PCS is to be separately tracked and accounted for and a
true-up surcharge may be implemented over a 12-month period
immediately following the 24-month PCS recovery period to reflect any
under- or over-collection of the total authorized PCS amount.
The power cost surcharge allocated by the Stipulation to Nu-West
Industries is to be collected from tariff customers during the 12-month
Schedule 93 PCS true-up period (reference Exhibit 24-0ption 3 Tables
BB1-BB3).
ORDER NO. 29034
The revenue obligations of the various customer classes (except for Nu-
West Industries, described above) is to be spread among the classes in the
manner described in Stipulation Attachment B.
Electric Service Schedule No.1 0 for Irrigators is amended as set forth in
Stipulation Attachment C.
The Rate Mitigation Adjustment (RMA; Stipulation Attachment D) is
approved as described and set forth in the Stipulation and is to be reflected
as a line item charge on customers bills through electric Service Schedule
94.
IT IS FURTHER ORDERED that Tim Shurtz is awarded intervenor funding in the
amount of $2 500. The Idaho Irrigation Pumpers Association, Inc. is awarded intervenor funding
in the amount of $22 500. PacifiCorp is directed to pay these amounts within twenty-eight (28)
days pursuant to Rule 165.02 of the Commission s Rules of Procedure, IDAPA 31.01.01.
IT IS FURTHER ORDERED that PacifiCorp for failure to provide the individual
notice required by Rule 102 of the Commission s Customer Information Rules (IDAPA
31.21.02.102) is hereby directed to provide each customer a credit of $20.00 within 90 days of the
service date of this Order. If the Company fails to make this credit, then the Commission shall
request that the Attorney General institute an action to recover $1 087 720 as a civil penalty as
authorized by law.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) or in interlocutory Orders previously issued in this Case No. P AC-02-
may petition for reconsideration within twenty-one (21) days of the service date of this Order with
regard to any matter decided in this Order or in interlocutory Orders previously issued in this Case
No. PAC-02-1. Within seven (7) days after any person has petitioned for reconsideration, any
other person may cross-petition for reconsideration. See Idaho Code ~ 61-626.
ORDER NO. 29034
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this ti...
day of June 2002.
;;;;1D ENT
O1dL iJ
MARSHA H. SMITH, COMMISSIONER
See separate concurring and dissenting
opinion of Commissioner Hansen
DENNIS S. HANSEN, COMMISSIONER
ATTEST:
fJ!:it C mmission Secretary
bls/O:PACE0201 sw7
ORDER NO. 29034
CONCURRING AND DISSENTING OPINION
OF COMMISSIONER DENNIS S. HANSEN
ORDER NO. 29034
CASE NO. PAC-02-
I respectively concur in Parts I and III, partially concur in Part and dissent as to
Part II of the Order.
Consistent with my dissent in Order No. 28998, I disagreed with the decision
allowing PacifiCorp to recover extra costs it may have incurred during the rate moratorium. I
still strongly agree with the prior dissenting opinion. However, based on the Commission
ruling in Order No. 28630, we allowed the Company to petition the Commission for deferred
costs during the moratorium period.
Here again, I must dissent from the Order approving the $25 million settlement. I
understand that the deferred amount the Company seeks during the moratorium occurred at a
time of high prices in the electricity market. I also realize losing the Hunter unit cost PacifiCorp
a considerable amount of money to replace that power. However, I believe PacifiCorp has other
costs that are declining that would help to offset some of the deferral amount, which was
contemplated in the merger stipulation. Merger savings were supposed to reduce costs.
After reviewing our Rules of Procedure for consideration of a negotiated settlement
(Rule 274, 275 and 276), I believe it is the Commissioners who retain the responsibility of
making the final judgment of whether the proposed settlement is "fair, just and is in the public
interest."
Rule 275 makes clear that proponents of a proposed settlement
, "
carry the burden of
showing that the settlement is reasonable." Rule 276 notes that the Commission is not bound by
settlements and "will independently review" any settlement proposed. IDAP A 31.01.01.275-
276.
This is where I feel the problem lies in this case. It is my opinion that this settlement
hides issues that perhaps ought to be aired before the settlement is declared to be in the public
interest.
In my opinion, neither PacifiCorp nor other parties adequately justify the details of
the $25 million in deferred costs agreed to in the settlement, when they presented their settlement
proposal to the Commission. Therefore, detailed evidence was lacking which would allow me to
CONCURRING AND
DISSENTING OPINION
make a reasoned decision that it was "reasonable and in the public interest." PacifiCorp made no
explanation of how the 65 percent of deferred cost was configured. The Commission was told
only that the $25 million settlement was 65 percent of the total $38 million deferral.
The failure of the Hunter plant which provides much of Idaho s power was really not
addressed. I find it very unusual that in 18 months the Company has not been able to determine
the cause of the failure, yet in testimony they maintain that PacifiCorp s operating or
maintenance practices or procedures did not contribute to or in any way cause the failure. Also, I
find it interesting in its comments that Staff concluded "PacifiCorp had some responsibility in
the failure and should share responsibility for a portion of extraordinary costs." Without more
detail, I cannot judge how that responsibility is being shared.
The question not answered is: How much, if any, of the Hunter failure is included in
the $25 million settlement? No one seems to know the answer, including the Commission.
Evidence was also presented in a letter to the Commission from Jim Smith of Monsanto
Company. The letter indicated that PacifiCorp could have done more to reduce the high-cost of
power purchases by interrupting power to Monsanto Company, its largest customer. That could
have made a considerable amount of power available at below the prevailing market price at that
time.
Other questions not answered in the settlement agreement nor in the hearings are:
How much of the $25 million is related to hydro conditions in Idaho? How much is related to
increased wholesale power business? How much to honoring wholesale contracts? How much
concerns load growth in the Idaho service area? How much is related to poor Company business
decisions? I need to see some evidence on these issues to make a justifiable decision.
Another area of concern is that the public, in my opinion, was not given proper notice
of these proposed settlement negotiations. As addressed in Part IV of the Order most of the
public had little time to properly prepare and study the effect it may have on them. In my
judgment this violation warranted a larger credit. I cannot, in all honesty, determine that this
settlement is in the public interest when so very little information was provided to the
Commission regarding what constitutes the settlement.
As it now stands, this Order simply accepts what PacifiCorp, Commission Staff
Monsanto Company (whose rates are unaffected by this case), and irrigation customers have
CONCURRING AND
DISSENTING OPINION
agreed to in this settlement. I believe this settlement amount was taken out of the hands of the
Commission and I cannot accept this proposal on blind faith.
In conclusion, the Commission lacks sufficient evidence about the many important
issues that were specifically called for in the Order approving the deferred accounting treatment.
If provided, this evidence would enable me to make a decision whether the request to allow the
Company to recover such extraordinary costs is just, reasonable, fair and in the public interest.
The customers who are now being asked to pay this recovery cost thought that in the merger they
would be protected from just such an event. Without pertinent details, I cannot assure these
customers that this recovery is fair, just, and reasonable or in the public interest. Consequently, I
must respectfully dissent.
CONCURRING AND
DISSENTING OPINION
John M. Eriksson
STOEL RIvEs LLP
201 South Main Street, Suite 1100
Salt Lake City, Utah 84111
Telephone: [phone]
Facsimile [phone]
Mary S. Hobson
STOEL RIvEs LLP
101 South Capitol Blvd., Suite 1800
Boise, Idaho 83702-5958
Telephone: [phone]
Facsimile [phone]
Attorneys for PacifiCorp
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
In the Matter of the Application of
ACIFICORP dba Utah Power & Light
Company for Approval of Changes to Its
Electric Service Schedules
CASE NO. PAC-02-
STIPULATION
This stipulation ("Stipulation ) is entered into by and among PacifiCorp, doing business
as Utah Power & Light Company ("PacifiCorp" or the "Company"), the Idaho Public Utilities
Commission Staff ("Staff'), the Idaho Irrigation Pumpers Association ("IIP A") and Monsanto
Company ("MoI,lSanto ) (collectively referred to as the "Parties
I. INTRODUCTION
The tenns and conditions of this Stipulation are set forth herein. The Parties agree
that this Stipulation represents a fair, just and reasonable compromise of the issues raised in this
proceeding and that this Stipulation is in the public interest. The Parties, therefore, recommend
that the Public Utilities Commission ("Commission ) approve the Stipulation and all of its terms
and conditions. Reference IDAPA 31.01.01.272, 274.
ATTACHMENT
Case No. PAC-02-
Order No. 29034
TI. BACKGROUND
On November 1 2000, PacifiCorp fIled an Application in Case No. PAC-00-
. for approval to defer excess net power costs incurred from November 1 2000 through October
2001. In Commission Order No. 28630, the Commission approved the Company s request
for deferred accounting of excess net power costs. Pursuant to deferral authority, the Company
deferred approximately $37 million in excess net power costs attributable to Idaho.
November 24, 2000, PacifiCorp experienced an outage at its Hunter 1 generating unit. The
Hunter 1 unit became fully operational on May 8, 2001. The outage of the Hunter 1 unit
increased the Company s net power costs.
On January 7, 2002, PacifiCorp fIled the Application in this case seeking to
recover the deferred excess net power costs, with carrying charges, amounting to approximately
$38 million over a two-year period. The Company further proposed electric service schedules
that would adjust rates to bring customer classes closer to the cost of serving the respective
classes and to implement an increase to the Electric Service Schedule No. 34 BP A exchange
credit to reflect the increased benefit from a settlement with the Bonneville Power
Administration regarding residential exchange benefits. Further, the Company proposed a Rate
Mitigation Adjustment (") designed to result in no customer classes receiving an increase
during the two-year period of the surcharge for the recovery of the deferred excess net power
costs.
Pursuant to the Commission s Identification ofIssues and Notice of Settlement
Conference in this matter, the Parties have engaged in discussions with a view toward resolving
PacifiCorp s Application in this case.
PacifiCorp has claimed and sought recovery of approximately $38 million in
excess net power costs, including carrying charges, incurred during the period November 1 , 2000
through October 31 , 2001 (the "Excess Power Costs"). The Commission Staff proposed
recovery be limited to approximately $21 million after adjustments for the Hunter 1 outage
wholesale contract costs, load growth, and jurisdictional allocation. Both lIP A and Monsanto
asserted that: 1) recovery of excess power supply costs is barred by reason of the ScottishPower -
PacifiCorp Merger Approval Condition No. 2 ; 2) power supply costs associated with the Hunter
plant failure are not recoverable because they were incurred subsequent to the deferral Order; 3)
any Hunter related costs properly deferred should be equitably shared as a result of maintenance
issues; 4) costs associated with certain wholesale contracts were imprudently incurred and not
recoverable; 5) thorough review and approval of the Company s cost-of-service studies was
required before rates could be shifted among the customer classes. lIP A also challenged the
Company s BP A credit allocation, the proposed RMA, and the elimination of irrigation A - B - C
rate schedules. The Company disagreed and presented further information in response to the
positions advanced by the Parties. The Company asserted that all of its Excess Power Costs were
prudently incurred and are properly recoverable.
Based upon the settlement discussions among the Parties, as a compromise of the
disputes in this case, and for other consideration as set forth below, the Parties agree to the
following terms:
III. TERMS OF THE STIPULATION
PacifiCorp shall be allowed to recover, through a surcharge and the acceleration
of the "Merger Credit," as described below, $ 25 million for Excess Power Costs.
As a result of the Commission s order ("Merger Order ) in the ScottishPower
merger case (Case No. PAC-99-1), customers have received since January 2000 a credit of
approximately $1.6 million per year from PacifiCorp that has been reflected as a line item on
customers' bills pursuant to Electric Service Schedule No. 99 (the "Merger Credit"). If
1 Merger Approval Condition No.2 provides: At a minimum, ScottisbPower shall not seek a
general rate increase for its Idaho service territory effective prior to January 1,2002." Case No. PAC-
99-, Order No. 28213, p. 8. With respect to that Condition, in its fIDdings the Commission stated: "As a
final and irrefutable measure to ensure that rates will not increase as a result of the merger, we hereby
. impose the additional condition (Merger Approval Condition No.2) that following the merger, PacifiCorp
shall not seek a general rate increase effective prior to January 1 , 2002. This literally guarantees that
PacifiCorp s customers will see an immediate rate reduction lasting at least two years through the
combination of the merger rate credit and the moratorium on general rate increases imposed herein." Case
No. PAC-E-9901, Order No. 28213, p. 31.
PacifiCorp were to continue such credit for the full four-year period reflected in the Merger
Order, there would be approximately $2.3 million, on a present value basis, remaining to be
credited to customers.2 The Parties agree that in order to offset PacifiCorp s Excess Power
Costs, the merger credit and Electric Service Schedule No. 99 shall be accelerated and credited to
reduce the Excess Power Cost recovery from $25 million to $22.7 million.
PacifiCorp shall be allowed to implement a power cost surcharge (the "PCS"
designed to recover $22.7 million over a 24-month period beginning May 15, 2002 and ending May
2004. The PCS will be implemented as a line item charge on customers' bills through Electric
Service Schedule No. 93 , attached hereto as Attachment A. As reflected in Attachment A, the
Parties have agreed that the PCS recovery should be tracked and that a true-up surcharge may be
implemented over a 12-month period immediately following the 24-month PCS recovery period to
reflect any under- or over-coJlection of the total authorized PCS amount.
The Parties agree that the revenue obligations of the various customer classes
shall be spread among the classes in the manner described in Attachment B. The Parties further
agree that Electric Service Schedule No.1 0 shall be redesigned in accordance with Attachment
C. In response to concerns from the IIP A concerning the loss of the Schedule 10, Irrigation
Season Rate C and its associat~d load control benefits, PacifiCorp agrees that it is willing to
discuss individual intelTUptibility or load control contracts for the 2002 irrigation season with not
more than 15 large irrigators3 on a first come - fIrSt served basis upon individual request of a
member of said class of irrigators for such discussion. PacifiCorp also agrees that it will work
with the IIP A and the irrigators as a class to develop an optional load control program for the
2003 irrigation season and thereafter that would allow an irrigator to participate in such program
2 Under the tenDS of the Merger Order, PacifiCorp can avoid the $1.6 million dollar credit during
the last two years, Le., 2002 through 2003, to the extent that cost reductions related to the merger are
reflected in rates.
3 For purposes of paragraph 9 of this Stipulation
, "
large irrigators" are defined as irrigators
having an individual meter registering greater than 500 kW demand during the last 12 months.
on an annual basis. PacifiCorp shall file its proposed optional load control program with the
Commission no later than January 31 2003.
The Parties also agree that the RMA will be implemented as a line item charge on
customers' bills through Electric Service Schedule No. 94 , attached hereto as Attachment D. The
Parties further agree that upon the earlier of (1) the expiration of the current Electric Service
Schedule No. 34 BP A exchange credit or (2) the adoption by the Commission of a cost of service
study for PacifiCorp and the subsequent implementation for all customers of said approved cost
of service study by any lawful method by the Commission or PacifiCorp, Electric Service
Schedule No. 94 will be tenninated.
10.The Parties agree that this Stipulation represents a compromise of the positions of
the Parties in this case. Other than the above referenced positions and any testimony filed in
support of the approval of this Stipulation, and except to the extent necessary for a Party to
explain before the Commission its oWll statements and positions with respect to the Stipulation,
all negotiations relating to this Stipulation shall be treated as confidential.
11.The Parties submit this Stipulation to the Commission and recommend approval
in its entirety pursuant to IDAP A 31.01.01.274. Parties shall support this Stipulation before the
Commission, and no Party shall appeal any portion of this Stipulation or Order approving the
same. If this Stipulation is challenged by any person not a party to the Stipulation, the Parties to
this Stipulation reserve the right to cross-examine witnesses and put on such case as they deem
appropriate to respond fully to the issues presented, including the right to raise issues that are
incorporated in the settlements embodied in this Stipulation. Notwithstanding this reservation of
rights, the Parties to this Stipulation agree that they will continue to support the Commission
adoption of the terms of this Stipulation.
12.In the event the Commission rejects any part or all of this Stipulation, or imposes
any additional material conditions on approval of this Stipulation, each Party reserves the right,
upon written notice to the Commission and the other Parties to this proceeding, within 15 days of
the date of such action by !he Commission, to withdraw from this Stipulation. In such case, no
Party shall be bound or prejudiced by the terms of this Stipulation, and each Party shall be
entitled to seek reconsideration of the Commission s order, file testimony as it chooses, cross-
examine witnesses, and do all other things necessary to put on such case as it deems appropriate.
13.The Parties agree that this Stipulation is in the public interest and that all of its
terms and conditions are fair, just and reasonable.
14.No Party shall be bound, benefited or prejudiced by any position asserted in the
negotiation of this Stipulation, except to the extent expressly stated herein, nor shall this
Stipulation be construed as a waiver of the rights of any Party unless ,such rights are expressly
waived herein. Execution of this Stipulation shall not be deemed to constitute
acknowledgment by any Party of the validity or invalidity of any particular method, theory or
principle of regulation or cost recovery, and no Party shall be deemed to have agreed that any
method, theory or principle of regulation or cost recovery employed in arriving at this Stipulation
is appropriate for resolving any issues in any other proceeding in the future. Without limiting the
generality of the' foregoing, nothing in this Stipulation, and nothing asserted in the negotiation of
this Stipulation, shall be the basis of waiver or estoppel in Case No. PAC-Ol-16 (Monsanto).
No findings of fact or conclusions of law other than those stated herein shall be deemed to be
implicit in this Stipulation.
15.The obligations of the Parties under this Stipulation are subject to the
Commission s approval of this Stipulation in accordance with its terms and conditions and
upon such approval being upheld on appeal by a court of competent jurisdiction.
Respectfully submitted this day of April, 2002.
PacifiCorp
02-
of record
Idaho Public Utilities Commission Staff
Scott D. Woodbury. its attorney of
record
Idaho Irrigation Pumpers Association
Eric L. Olsen, its attorney of record
Monsanto Company
Randall C. Budge, its attorney of record
04/09/02 14:44 U208 334 3762 IDAHO PUt 141 002
15.The obligations of the Parties under this Stipulation are subject to the
Commission s approval of this Stipularion in accordance with its terms and conditions and
upon such approval being upheld on appeal by a court of competent jurisdiction.
Respectful1y submitted this day of April. 2002.
PacifiCorp
Brinn Kelley-Siel. its attorney of record
Idaho Public Utilities Commission Staff
Scott D. Woodbmy. its attorn
record ~/M'/~~
Idaho Irrigation Pumpers Association
Eric L. Olsen, its attorney of record
Monsanto Company
RaJ1n~l1 C. Budge, its attorney of record
~~-~~~ ~~.~~
"M'- .,.......
'-"-'-"-",.,..~, ~----
15.The obligations of the Parties under this Stipulation are subject to the
Commission s approval of this Stipulation in accordance with its terms and cOnditions and upon
such approval being upheld on appeal by a court of competent jurisdiction.
Respectfully submitted this Jd!!:.. day of Ap~ 2002.
PacifiCorp
Brinn Kelley-Sicl. its attorney of record
Idaho Public Utilities Commission Staff
Scott D. Woodbury, its attorney of record
Idaho Irrigation Pompers Association
'I !rjo-z-
Monsanto Company
(!,
'I-8-
Randall C. Budge. its atto of record
CERTIFICATE OF SERVICE
I hereby certify that on this
C)t\\.day of April, 2002, a true and correct copy of the
foregoing was served on the following via U.S. mail:
Scott Woodbury
Deputy Attorney General
Idaho Public Utilities Commission
O. Box 83720
Boise, ID 83720-0074
Eric Olsen
Racine, Olson, Nye, Budge & Bailey
O. Box 1391
201 E. Center
Pocatello, ID 83204-1391
Anthony J. Yankel
29814 Lake Road
Bay Village, OR 44140
Randall C. Budge
Racine, Olson, Nye, Budge & Bailey
O. Box 1391
201 E. Center
Pocatello, ID 83204-1391
James R. Smith
Senior Accounting Specialist
Monsanto Company
O. Box 816
Soda Springs, ID 83276
Mr. Tim Shurtz
411 South Main
Firth, Idaho 83236
Attachment A
utah
nmuJlr
I.P.C. No. 28 Original Sheet No. 93
UTAH POWER & LIGHT CO:MP ANY
ELECTRIC SERVICE SCHEDULE NO. 93
STATE OF IDAHO
POWER COST SURCHARGE
A V AllABILITY: At any point on the Company s interconnected system.
APPLICATION: This Schedule shall be applicable to all , retail tariff Customers (including
Schedule 400 ~ Nu- West Industries Inc.) taking service under the terms contained in this Tariff.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bills shall have applied an amount equal to the product of all metered kilowatt-hours
multiplied by the following cents per kilowatt-hour as determined by the Voltage Level at which the
Customer takes service. The charges in the column labeled "Year I" shall be in effect for one year
beginning on the effective date of this tariff. The charges in the column labeled "Year 2" shall be in effect
for one year beginning at the end of Year 1. The Company shall track the total amount collected through
Year 1 and Year 2 and true up in Year 3. In Year 3, this surcharge may continue at a revised rate, subject to
subsequent Commission review and approval, in order to reflect any undercollection or overcollection of the
total authorized surcharge amount.
Voltage Level
Secondary - less than 2 300 volts
Primary - 2 300 to 44 000 volts
Transmission - over 44 000 volts
Year 1
8585 rt
8326 rt
8151
Year 2
0.4200 If,
0.4073
0.3988
Submitted Under Case No. PAC-E-02-
ISSUED: April 10, 2002 EFFECTIVE: May 15, 2002
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Attachment C
utah
HRLIUr
C. No. 28
Fifth Revised Sheet No. 10.
Canceling Fourth Revised Sheet No. 10.
UTAH POWER & LIGHT COMPANY
ELECTRIC SERVICE SCHEDULE NO.
STATE OF IDAHO
Irrigation and Soil Drainage Pumping Power Service
AVAILABILITY: At any point on the Company's interconnected system where there are facilities
of adequate capacity.
APPLICATION: This Schedule is for alternating current, single or three-phase electric service
supplied at the Company's available voltage through a single point of delivery for service to motors on
pumps and machinery used for irrigation and soil drainage.
IRRIGATION SEASON AND POST-SEASON SERVICE: The Irrigation Season is from June 1
to September 15 each year. Service for post-season pumping may be taken by the same Customer at the
same point of delivery and through the same facilities used for supplying regular irrigation pumping service
during months from September 16 to the following May 31.
(C)
MONTHLY BILL:
Irrie:ation Season Rate
Customer Service Charge:
Small Pumping Operations:
15 horsepower or less total connected horsepower
served through one service connection -
(N)
$10.17 per Customer
Large Pumping Operations:
16 horsepower or more total connected horsepower
served through one service connection -$30.33 per Customer (N)
(Continued)
Submitted Under Case No. P AC-02-
ISSUED: April 10, 2002 EFFECTIVE: May 15,2002
Attachment C
utah
gpI call
I.P.C. No. 28
Fifth Revised Sheet No. 10.
Canceling Fourth Revised Sheet No. 10.
ELECTRIC SERVICE SCHEDULE No. 10 - Continued
MONTHLY BILL: (Continued)(N)
Power Rate:$4.05 per kW for all kW
Energy Rate:5.4320~ per kWh for first 25 000 kWh
8024~ per kWh for the next 225,000 kWh
5000~ per kWh for all additional kWh
Power Factor: This rate is based on the Customer maintaining at all times a power factor
of 85% lagging, or higher, as determined by measurement. If the average power factor is
found to be less than 85% lagging, the power as recorded ,by the Company's meter will be
increased by 3/4 of 1 % for every 1 % that the power factor is less than 85%.
Minimum:The Customer Service Charge.(N)
Post-Season Rate
Customer Service Charge:
Energy Rate:
$16.17 per Customer
4.5059~ per kWh for all kWh
(C)
(I)
Minimum:The Customer Service Charge.
ADJUSTMENTS: All monthly bills shall be adjusted in accordance with Schedules 34, 93 and 94.(N)
(C) .
PAYMENT: All monthly service billings will be due and payable when rendered and will
considered delinquent if not paid within fifteen (15) days. An advance payment may be required of the
Customer by the Company in accordance with Electric Service Regulation No.9. An advance may be
required under any of the following conditions:
(1)the Customer failed to pay all amounts owed to the Company when due and
payable;
(2)the Customer paid an advance the previous season that did not adequately cover
bills for the entire season and the Customer failed to pay any balance owing by the
due date of the final billing issued for the season.
(Continued)
Submitted Under Case No. P AC-02-
ISSUED: April 10, 2002 EFFECTIVE: May 15 2002
Attachment C
utahom"
I.P.C. No. 28
Fifth Revised Sheet No. 10.
Canceling Fourth Revised Sheet No. 10.
ELECTRIC SERVICE SCHEDULE No. 10 - Continued
PAYMENT: (continued)(C)
An adequate assurance of payment (advance) may be required from a Customer who has filed bankruptcy.
Advances which may be required of the Customer may be paid with cash payment or guarantee, as required
by the Company, or with a letter of escrow acceptable to the Company from an authorized bank in the
Company's service area. This letter of escrow shall provide that upon tennination of service to the
Customer, the Company shall receive, upon demand, cash equal to the unpaid balance of the Customer s bill
which. is not disputed or the full amount of the advance, whichever is the lesser amount.
CONNECTION AND DISCONNECTION CHARGES: Company will not routinely season~lly
connect and disconnect service to irrigation pumps. However, upon oral or written request the Company
will connect and disconnect service at the beginning and end of Customer's pumping operation each year
without charge. Customer shall give Company at least two (2) weeks advance notice of the date
disconnection and connection of seasonal service is desired. The actual expense incurred for additional
connection and disconnection shall be paid by Customer. Customer shall give Company at least two (2)
weeks advance notice of the date any additional connection andlor an additional disconnection of service is
desired. Meters will not be read and bills will not be issued from November 1 to March 1 unless the
customer requests in writing a different ending or beginning point for billing. The bill issued in March will
include charges for any unbilled energy used during the period of November 1 to March 1.
POWER: The kW as shown by or computed from the readings of the Company s power meter for
the IS-minute period of Customer s greatest use during the month, adjusted for power factor as specified
determined to the nearest kW. Metered power demands in kilowatts which exceed one hundred and thirty
percent (130%) of the total connected horsepower served through one service connection will not be used
for billing purposes unless and until verified by field test in the presence of the Company to be the result of
normal pumping operations. If a demand in excess of 130% of connected horsepower is the result of
abnormal conditions existing on the Company s interconnected system or the Customer's system, including
accidental equipment failure or electrical supply interruption which results in temporary separation of the
Company and Customer's system, the billing demand shall be 130% of the connected horsepower. The
Customer may appeal the Company s billing decision to the Idaho Public Utilities Commission in cases of
dispute.
CONTRACT PERIOD: One year or longer.
(Continued)
Submitted Under Case No. P AC-02-
ISSUED: April 10, 2002 EFFECTIVE: May IS, 2002
Attachment C
utah
.. co!r
C. No. 28
Fifth Revised Sheet No. 10.4
Canceling Fourth Revised Sheet No. 10.4
ELECTRIC SERVICE SCHEDULE No. 10 - Continued
ELECTRIC SERVICE REGULATIONS: Service under this Schedule will be in accordance with
the tenns of the Electric Service Agreement between the Customer and the Company. The Electric Service
Regulations of the Company on file with and approved by the Idaho Public Utilities Commission, including
future applicable amendments, will be considered as fonning a part of anc~ incorporated in said Agreement.
Submitted Under Case No. PAC-O2-
ISSUED: April 10, 2002 EFFECTIVE: May 15,2002
Attachment D
utahRim"
C. No. 28 Original Sheet No. 94
UTAH POWER & LIGHT COMPANY
ELECTRIC SERVICE SCHEDULE NO. 94
STATE OF IDAHO
RATE MITIGATION ADJUSTMENT
A VAll.,ABILITY: At any point on the Company s interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service
under the t~rms contained in this Tariff.
MONTHLY Bll..L: In addition to the Monthly Charges contained in the Customer s applicable
schedule, all monthly bills shall have applied an amount equal to the product of all metered kilowatt-hours
multiplied by the following cents per kilowatt-hour. The prices in the column labeled "Year 1" shall be in
effect for one year beginning on the effective date of this tariff. The prices in the column labeled "Year 2"
shall be in effect for one year beginning at the end of Year 1. The prices in the column labeled "Year 3 and
Subsequent Years" shall be in effect beginning at the end of Year 2.
Year 1 Year 2 Year 3 and
Subsequent Years
SchedlJle 0000 rt (0.4029) rt (0.6972) rt
Schedule . (0.7272) rt (0.2902) rt 0000 rt
Schedule 0000 rt (0.3908) rt 0000 rt
Schedule (0.6944) rt 0000 rt (6.5972) rt
Schedule 0000 rt (0.7092) rt (6.3830) rt
Schedule (0.7457) rt (0.3196) .2486 rt
Schedule (0.7210) rt (0.3028) rt 0000 rt
Schedule 6497 rt 6497 rt 6497 rt
Schedule (0.7299) rt (0.7299) rt (8.0292) rt
Schedule 12 - Street Lighting (0.7295) rt (0.3127) rt (3.4914) rt
Schedule 12 - Traffic Signal (0.8929) rt (0.4464) rt (2.6786) rt
Schedule (0.7048) rt (0.2624) rt (0.6448) rt
Schedule (0.6633) rt (0.2258) rt (1.2871) rt
Schedule 23A 0000 rt (0.3905) (1.0557) rt
Schedule (0.8150) rt (0.3260) rt 0000 rt
Schedule 0000 rt (0.4019) rt (0.2412) rt
Schedule 400 - Nu-West (0.6764) rt (0.2603) rt 0000 rt
Submitted Under Case No. PAC-02-
ISSUED: April 10, 2002 EFFECTIVE: May 15, 2002