20020110Decision Memo.pdf

DECISION MEMORANDUM
TO:COMMISSIONER KJELLANDER
COMMISSIONER SMITH
CO MMISSI 0 NER HANSEN
JEAN JEWELL
RON LAW
LOUANN WESTERFIELD
BILL EASTLAKE
TONYA CLARK
DON HOWELL
DAVE SCHUNKE
RICK STERLING
RANDY LOBB
LYNN ANDERSON
GENE FADNESS
WORKING FILE
FROM:SCOTT WOODBURY
DATE:JANUARY 10, 2002
RE:CASE NO. PAC-02-01 (PacifiCorp)
ELECTRIC SERVICE SCHEDULE NO. 34-BP A EXCHANGE CREDIT
PROPOSED ELECTRIC SERVICE SCHEDULES (W/COST OF SERVICE)
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 the Company s proposed electric service schedules. Included in the
Company s filing is a related Cost-or-Service (CaS) study, a proposed Schedule 34-BPA
Exchange Credit distribution, a proposed PCA surcharge ($38M) and a proposed Rate Mitigation
Adjustment (RMA).
BACKGROUND
PacifiCorp in its Application represents that the Company s Idaho revenue
requirement was last changed in Case No. UPL-90-, a case in which the revenue requirement
was reduced pursuant to stipulation. In that case, the Company states that class Cost-or-Service
(COS) was also addressed. The Company contends that class Cost-or-Service has not been
reviewed in a case in Idaho since that time.
DECISION MEMORANDUM
On November 2 2000 the Company reports that it filed an Application in Idaho for
approval to defer excess net power costs incurred from November 1 2000 through October 31
2001. Reference Case No. P AC-00-05. In Order No. 28630, the Commission approved the
Company s request for deferred accounting of excess net power cost. Pursuant to that authority,
PacifiCorp reports that it has deferred approximately $37 million in excess net power costs
attributable to Idaho.
In May 2001 PacifiCorp reports that it entered into a Settlement Agreement with the
Bonneville Power Administration (BP A Settlement) regarding the residential exchange benefits
to be provided by BP through September 30, 2006. The BP A Settlement, the Company
contends, will provide approximately $34 million in benefits to Idaho customers in 2002.
COMPANY PROPOSAL
PacifiCorp s proposal in this case consists of four elements:
I. PCA surcharge
A surcharge would be added to the customers' bills to recover the $38 million in
excess power costs incurred by the Company during the deferral period. This surcharge would
last over a two year period, with the level ofthe surcharge decreasing for the second year.
Under the Company s proposed Power Cost Adjustment (PCA), the Company will
recover $38 million in excess power costs over a two-year period in which 70%, or $27 million
is recovered in the first year and the remaining 30%, or $11 million is recovered in the second
year.This 70/30 split, the Company contends, is designed in conjunction with the Rate
Mitigation Adjustment to achieve the goal of customer classes not seeing any price increases as a
result of these changes in either year.
Because the excess power costs are energy related, the Company proposes to collect
them through a cents per kilowatt adjustment (PCA) based on customers service voltage levels.
The PCA rates are obtained by dividing the total excess power costs by the total kilowatt hours at
the generator and then adding an adjustment for voltage losses. The PCA will be applied to all
customer classes and to all energy usage.
2. Cost of Service-Rate Adjustment
In addition, the proposal includes adjusting rates by class to bring them closer to the
actual cost to serve each class. The adjustment, the Company contends, is a reapportionment of
the existing revenues and will not result in an increase of the revenues collected in total.
DECISION MEMORANDUM
One significant change in the Company s class Cost-of-Service study is a change in
the status of interruptible and other large special contract customers from system allocation to
state situs customers.
Based on the Cost-of-Service (COS) study presented, the Company proposes to
redesign its rates so that all customer classes fall within 5% of their cost of service. The cost of
service redesign will be fully implemented in the first year and has been designed, the Company
contends, to be revenue neutral; that is, the Company s total revenues will be unchanged as a
result of this rate design.
3. Schedule 34-BP A Exchange Credit
The third aspect of the Company s proposal is an increase in the Bonneville Power
Administration credit to the recently settled amount. The Bonneville Power Administration
(BP A) residential and irrigation exchange credit is a mechanism to provide benefits to qualifying
customers of investor-owned utilities (like Utah Power) from the Federal Columbia River
Hydroelectric system and satisfaction of BP A's obligations under the Northwest Power Act of
1980. The credit is available only to residential and small farm customers and is provided to the
Company s customers in Idaho through electric service Schedule No. 34. In recent years the
benefits have been allocated 43% to residential customers and 57% to irrigation customers. The
previous exchange agreement with BPA expired in 2001 , and a new agreement (the 2001
Settlement) was entered into to provide a continuation of exchange benefits. In its 2001 rate
case, BP A proposed an alternative to the traditional exchange. The alternative was to provide
investor-owned utilities (IOUs) the option to purchase actual power or rights to power through a
subscription process. IOUs that chose subscription did so as a settlement oftheir exchange rights
for this period. The subscription was further split between actual power and a monetary portion
that was calculated as a difference between BPA's price and BPA's forecasted market price.
BP A expected to need to purchase additional resources in order to serve that portion of the
subscription that was delivered as actual power. Faced with the potential of very high costs for
these additional resources, PacifiCorp agreed to forego its right to actual power for an overall
financial settlement of its exchange benefits. The resulting financial settlement provides $34
million in benefits to qualifying Idaho customers for the first year and $35.2 million in the
second year. This level, the Company reports, is substantially higher than historical levels. The
Company proposes to allocate the settlement amounts between the residential and the irrigation
DECISION MEMORANDUM
customers in the same manner as the prior exchange agreement (i.43% to residential
customers and 57% to irrigation customers).
PacifiCorp is requesting that the BP A credit be implemented immediately even if
other aspects of the filing are suspended. BP A increased its credit effective October 1 , 2001.
PacifiCorp contends that it has a contractual obligation to pass the credit through to its customers
in a timely manner. Consequently, the Company is proposing that Schedule 34, the BP A credit
be approved for a February 01 2002 effective date.
PacifiCorp proposes to have the anticipated four months' worth of credit (for the
period from October 1 until the new credit level is implemented in rates) for residential
customers included in the first year s credit rate. In other words, the rate for the first year will be
set to distribute 16 months worth of a normal year s amount for residential customers. The total
amount of BP A credit the Company proposes to distribute to qualifying customers in year one is
$40.6 million. At the end of the first year, the rate will be reset to match a normal 12 months
worth of credit. The Company proposes no adjustment for the four-month lag for irrigation
customers. Irrigation usage, the Company contends, is largely completed by October
Irrigation payments, the Company also contends, fluctuate significantly year-to-year due to
differences in irrigation usage during the irrigation season.
4. Rate Mitigation Adjustment (RMA)
Finally, the Company is proposing a rate mitigation adjustment. The rate mitigation
adjustment is a pricing mechanism that the Company proposes on a policy basis. The filing
consists of several elements that will each have the effect to increase or decrease individual
customer s rates.The rate mitigation adjustment assures that when summed together no
customer class will receive a rate increase during the two year power cost amortization period
and those that qualify for the BP A credit will see a significant decrease.
The combination of the Cost-of-Service redesign, the PCA and the BP A credit, the
Company contends, results in changes to most customer prices and in some cases increases
occur.The RMA is designed to offset those changes and to balance revenues so that no
customer class will see a price increase in the first two years. The RMA is also designed to
maintain greater price stability by minimizing price fluctuations from year to year.
The RMA is a surcharge or surcredit applied on a cents per kilowatt basis to each rate
schedule. It has been designed to mitigate and moderate price impacts that may occur and to
DECISION MEMORANDUM
achieve the goal that customer classes receive no price increase for the next two years. In fact
most customers will see significant price decreases in both year one and year two. In year one
residential customers will see an average price decrease of 8%. Irrigation customers on average
will also see a price decrease of 8% while, overall, commercial and industrial customers will see
a decrease of3%. Lighting customers will see an overall decrease of9%.
In year two under the Company s proposal, the residential customer class will see a
decrease of 15% from prices at the end of year one. Irrigation customers will also see an average
decrease of 15%, while commercial and industrial customers overall see a decrease of 4% from
prices in effect at the end of year one. Lighting customers overall will see a decrease of another
15%.
In the third year, the Company contends, prices will continue to decline. Residential
prices will decrease by 19%. The irrigators will see a decrease of 21 % while commercial and
industrial customers will see, overall, a decrease of 6%. Lighting customers will see, overall, a
decrease of 17%. The following table summarizes these percentages.
Customer Class Year One Year Two Year Three
Residential (7.8%)(14.6%)(18.8%)
General Service
Schedule 6
Schedule 9
Schedule 23 (7.1 %)(6.2%)(5.0%)
Irrigation
Schedule 10 (7.8%)(14.6%)(21.2%)
Commercial & Industrial Total (2.8%)(4.4%)(5.7%)
Lighting (8.5%)(14.9%)(17.3%)
Commission Decision
Staff recommends that the Commission process that portion of the Company
Application with respect to the Schedule 34-BP A credit under Modified Procedure with a
comment deadline of January 24th. This will enable the Commission to consider the matter at its
January 28th decision meeting and if approved, would allow implementation of the credit by the
Company requested February 1 st date.
Regarding the remainder of the Company s Application, Staff recommends that the
Commission enter an Order of suspension and establish an intervention deadline. Once the
DECISION MEMORANDUM
players are determined, a pre-hearing conference can be set (if required) or nGtice of further
scheduling including discovery and Staff/Intervenor file dates can be issued. Does the
Commission agree with the proposed procedure and scheduling? If not, what is the
Commission s preference?
Scott Woodbury
vld/M:PAC-O2-
DECISION MEMORANDUM