20090929final_order_no_30904.pdf

Office of the Secretary
Service Date
September 29, 2009
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER FOR
APPROVAL OF AN ENERGY COST
ADJUSTMENT MECHANISM (ECAM)ORDER NO. 30904
CASE NO. P AC-08-
On October 23, 2008, PacifiCorp dba Rocky Mountain Power (Rocky Mountain
Power; Company) filed an Application with the Idaho Public Utilities Commission
(Commission) requesting approval of an energy cost adjustment mechanism (ECAM). The
Company s proposed ECAM tracks annual deviations in variable power supply costs from
normalized power supply costs embedded in base rates and surcharges or credits customers the
accumulated balance over the subsequent year.
On November 5, 2008, the Commission issued a Notice of Application and
established a November 28, 2008, intervention deadline. The parties to this proceeding are:
PacifiCorp; Commission Staff; Monsanto Company; and Idaho Irrigation Pumpers Association
Inc. (IIPA), (collectively Parties). On June 29, 2009, the Parties filed an ECAM Stipulation as a
proposed settlement in the case. IDAP A 31.01.01.272-276.
The Commission in this Order approves the terms of the Settlement Stipulation
authorizes an ECAM for Rocky Mountain Power and partially grants lIP A's Petition for
Intervenor Funding. We find the Settlement to be fair, just and reasonable and in the public
interest.
Energy Cost Adjustment Mechanism - Application
As reflected in Rocky Mountain Power s Application, net power supply costs
represent a large portion of the Company s total revenue requirement and are subject to a high
degree of volatility largely outside of the Company s control. Some of the factors cited by the
Company causing this volatility include changes in retail load, hydro conditions, wind
generation, market prices, third-party wheeling expenses, and natural gas and coal fuel expenses.
Because the Company depends on both the electricity and natural gas markets to balance its
system and meet load requirements, fluctuations in the markets invariably impact the Company
net power supply cost. Coal expenses, the Company states, which were previously relatively
ORDER NO. 30904
stable, are now affected by changes in commodity costs due to contract reopeners, and even the
captive mine costs may change significantly in today s environment due to the rapid escalation
of the costs of mining equipment and supplies. An ECAM, the Company contends, would
provide safeguards to customers and give the Company an opportunity to recover the net power
costs that are prudently incurred to serve those customers.
The Company notes that general rate cases in Idaho utilize historical test years with
known and measurable adjustments under the Commission s rules and requirements. The use of
static test period data, the Company contends, cannot accurately reflect the volatility in net
power costs that the Company is currently experiencing, a variability that includes both sharp
increases and decreases.
Rocky Mountain Power s proposed ECAM is designed to allow the Company to
collect or credit the difference between the actual net power costs (NPC) incurred to serve
customers in Idaho and the amount collected from customers in Idaho through rates set in
general rate cases. On a monthly basis, the Company will compare the actual system net power
costs (Actual NPC) to the net power costs embedded in rates from the most recent general rate
case (Base NPC), and defer the difference in a balancing account. An ECAM rate will be
calculated annually to collect from or credit to customers the accumulated balance over the
subsequent year.
The ECAM is designed to recover the sum of all components of net power costs as
traditionally defined in the Company s general rate cases and modeled in its power supply model
GRID. The mechanism addresses only power cost expenses and does not include any costs
associated with fixed cost recovery (i., capital investment in rate base). Specifically, Base NPC
will include costs typically booked to the following Federal Energy Regulatory Commission
(FERC) accounts:
Account 447 - Sales for resale, excluding non-GRID transmission services
and on-system wholesale sales
Account 501 - Fuel, steam generation; excluding fuel handling, start-up
fuel/gas, diesel fuel, residual disposal and other non-GRID items
(Start-up fuel is accounted for separately from the primary fuel for steam
power generation plants. Start-up costs are not accounted for separately for
natural gas plants, and therefore all fuel for natural gas plants is included in
the determination of both Base NPC and Actual NPC.
ORDER NO. 30904
Account 503 - Steam from other sources
Account 547 - Fuel, other generation
Account 555 - Purchased power, excluding BP A residential exchange credit
pass-through if applicable
Account 565 - Transmission of electricity by others (wheeling)
Actual costs booked to the above accounts will be subject to review by the Commission and
other parties in each of the Company s applications prior to inclusion in the ECAM surcharge.
STIPULATION AND PROPOSED SETTLEMENT
On June 29, 2009, the Company, Staff, lIP and Monsanto filed an ECAM
Stipulation with the Commission as a proposed settlement of the case. IDAP A 31.01.01.272-
276. The Parties contend that the Stipulation terms and conditions represent a fair, just and
reasonable compromise of the issues raised in this proceeding and that the Stipulation is in the
public interest. The Parties recommend that the Commission approve the Stipulation and all of
its terms and conditions.
As reflected in the Stipulation and by way of background, the parties recite the
following:
On October 23 , 2008 , Rocky Mountain Power filed an Application
Application ) seeking approval of an Energy Cost Adjustment Mechanism
ECAM"). Rocky Mountain Power s proposed ECAM is designed to defer
the difference between Base net power costs set during a general rate case and
collected from customers in their retail rates and Actual net power costs
incurred by the Company to serve retail customers. The calculation of the
deferral would be on a monthly basis by comparing the monthly Base net
power cost ("NPC") rate in dollars per megawatt-hour to the Actual NPC rate
also in dollars per megawatt-hour. The resulting monthly NPC differential
rate would be applied to actual Idaho retail load to calculate the NPC
differential for deferral. The net power costs of $982 million, as stipulated
and approved in Rocky Mountain Power s general rate Case No. PAC-08-
, Order No. 30783, will be the base NPC for the ECAM until re-set in the
next general rate case.
The germane terms of the Stipulation are as follows:
~4.Parties agree that the design, format and accounts of the ECAM shall be
as set forth in the Company s Application in Case No. PAC-08-08 and
as to be described in more detail by the Company in its Stipulation
supporting testimony. The Parties further agree that the ECAM is to be
ORDER NO. 30904
effective July I , 2009, provided the Commission has issued an order
approving the ECAM consistent with the terms in the Stipulation.
~5.Parties agree that the ECAM will include a symmetrical sharing band
wherein when there is a difference between Actual NPC and Base NPC
customers pay (if there is an increase in NPC) or receive (if there is a
decrease in NPC) 90 percent of the difference, and the Company is
responsible for the remaining 10 percent.
~6.Parties agree that the annual deferral period to be used in the ECAM will
be December I to November 30, and that annually, on February the
Company will file an application with the Commission to adjust the
surcharge or surcredit ("ECAM Rate ) effective April I each year
refunding or collecting the ECAM deferred balance from the prior
deferral period.
~7.Parties agree that a symmetrical load growth adjustment rate (LGAR) of
$17.48 per MWh will be applied to the incremental load from the base
load established in Case No. PAC-08-, and that the LGAR and base
load will be updated each time Base net power costs are updated in a
general rate case.
~8.Parties recognize that the Company has made significant investments in
renewable generation projects that are not yet being recovered in Idaho
rates and that these projects provide significant benefits to customers
through the ECAM. Therefore from the effective date of the ECAM to
the effective date of rates in the next rate case, the Parties agree that the
ECAM will include a renewable generation investment offset
adjustment. The adjustment recognizes that actual power costs have
been reduced by power generated from these renewable generation
projects, but that the costs of these projects are not yet being recovered
in Idaho rates. The adjustment will be based on $55.00 per MWh, as
calculated in (Settlement Stipulation) Attachment multiplied by the
actual MWh output generated by the renewable resources that were not
included in rate base in Rocky Mountain Power s Case No. PAC-08-
07.
~9.Parties further agree that a carrying charge equal to the Commission-
approved customer deposit rate will be applied symmetrically to the
monthly ECAM deferred balance.
~l O. In the event the Company intends to seek an increase to the ECAM rate
exceeding seven (7) percent, the Company agrees to meet with the Staff
and interested parties to discuss the underlying drivers of such a change
at least 30 days prior to filing an application with the Commission for
approval of the change to the ECAM rate.
ORDER NO. 30904
~ll. The Company agrees to work with the Parties to develop rates thatreflect line losses and that distinguish transmission, primary and
secondary voltage delivery service in the implementation of the ECAM
rates. A technical conference will be convened by August 15 , 2009 to
begin discussions on a methodology and will use line loss information
from the 2008 general rate case (PAC-08-07) as a starting point for
the discussions. In the event an agreement on rate design for the ECAM
rate is not reached by April I , 2010, the ECAM rate will be applied to all
schedules and customers on a flat kWh usage basis until an agreement is
reached or a method is ordered by the Commission.
~12. The Company agrees to hold a risk management hedging seminar to
educate Parties about the Company s risk management practices and
hedging strategies.
~13. In recognition for and as a result of the implementation of the ECAM
with an adjustment for renewable generation projects not yet in rate base
as specified in (Stipulation) Paragraph 8 above, the Company agrees not
to file a general rate case prior to May 2010.
~14. The Parties agree that SO2 sales made after June 30, 2009 will be
included as an offset to the ECAM deferral with the same 90%/1 0%
sharing band explained above in (Stipulation) Paragraph 5. The Parties
further agree that sales made prior to such date will continue to be
amortized over fifteen years consistent with current practice as reflected
in Case No. PAC-06-04 (Larson Direct Testimony, Exh. pp. 3.6 and
1.).
~15. The Company s filed Case No. PAC-08-07 included an annual level
of amortization of three regulatory liabilities for West Valley lease
administrative and general expense merger commitment, and the gain on
the sale of the Goose Creek transmission line which reduced the revenue
requirement used in establishing the current base rates. The current rates
will continue until new rates are set at the end of 20 I 0 or later and, as aresult, customers continue to receive the benefit of the amortization
rates until that time. As of December 31 , 20 I 0, an unamortized balance
of $156 434 for the Goose Creek sale will remain on the Company
books and records. The Parties stipulate and agree that upon
Commission approval of this Stipulation the Company will credit the
ECAM deferral for the Goose Creek sale in the amount of $156 434.
Accordingly, the Parties agree that the Company can write off the
remaining balances of the regulatory liabilities after this transfer and
upon Commission approval of the Stipulation.
ORDER NO. 30904
On July 16, 2009, the Commission issued a Notice of Stipulation and Proposed
Settlement and Scheduling in Case No. P AC-08-08. The deadline for filing testimony in
support of the Settlement Stipulation by stipulating parties was July 31 , 2009. The deadline for
filing written comments by the public and interested parties was August 14, 2009.
Testimony supporting the Stipulation was filed by J. Ted Weston, Manager of Idaho
Regulatory Affairs for PacifiCorp dba Rocky Mountain Power; Randy Lobb, Utilities Division
Administrator for Commission Staff; and Anthony J. Yankel on behalf of Idaho Irrigation
Pumpers Association, Inc. Monsanto Company, although a signator to the Stipulation, filed no
testimony.
Rocky Mountain Power
Supporting testimony on behalf of Rocky Mountain Power was filed by its Manager
of Regulatory Affairs, J. Ted Weston. A description of the purpose of the Energy Cost
Adjustment Mechanism and the accounts and types of costs that are to be included carry forward
from the Company s Application to the Stipulation and Mr. Weston s testimony. Included with
the Company s supporting testimony is an example of the ECAM deferral calculation. Company
Exh. 4, attached. The ECAM deferral will be calculated on a monthly basis by comparing the
actual system net power costs (Actual NPC) on a dollars per megawatt-hour basis to the net
power costs embedded in rates from the Company s most recent general rate case (Base NPC).
Actual NPC will be calculated using all components of net power costs as traditionally defined in
the Company s general rate cases. The actual monthly system NPC will be divided by the
system load for that month to calculate the Actual NPC dollars per megawatt-hour rate and that
rate is then compared to the Base NPC rate to determine the NPC differential. The ECAM rate
will be updated annually to collect from or credit to customers the accumulated balance over the
subsequent year. The parties agree that the ECAM will include a symmetrical 90%
(customer)/1 0% (Company) sharing band.
Base NPC will be determined and approved in general rate case proceedings based on
total Company net power costs. Initially, a Base NPC of $982 million as stipulated to and
approved in Order No. 30783 from Case No. PAC-08-, the Company s most recent general
rate case, will be used for the ECAM, until reset in the Company s next general rate case. The
monthly net power costs from the most recent general rate case will be divided by the monthly
ORDER NO. 30904
normalized load used to determine those net power costs to express the costs on a dollar per
megawatt-hour basis.
In addition to the comparison of Actual to Base net power costs, two additional
components are included in the ECAM, a load growth adjustment rate (LGAR) and a credit for
any SO2 allowance sales. The LGAR is a symmetrical adjustment to offset any over or under
collection of the Company s production-related revenue requirement as growth-related load
changes occur. The Load Growth Adjustment Rule (LGAR) is set at $17.48 per megawatt-hour
(MWh) to reflect the Commission-approved production-related costs embedded in rates. The
LGAR and base load will be updated each time Base NPC are updated in a general rate case.
The load growth adjustment is calculated by subtracting Idaho s base load which is the load from
the most recent general rate case from actual Idaho load. The difference is multiplied by the
LGAR of$17.48 and the product is the load growth adjustment.
The parties agree also that SO2 sales made after June 30, 2009, will be included as an
offset to the ECAM deferral. The parties further agree that sales made prior to such date will
continue to be amortized over 15 years consistent with current practice as reflected in Case No.
PAC-06-04 (Larsen Direct Testimony, Exhibit pp. 3.6 and 3.1). Calculation of the Idaho
SO2 offset is reflected in Exhibit No.4 of the ECAM template as more particularly described in
Weston supporting testimony, pp. 8-
The ECAM Stipulation also contains an agreement to account for the energy benefits
of new renewable generation resources that are online but not yet included in base rates. Parties
recognize that these projects provide significant benefits to customers through the ECAM.
Therefore, from the effective date of the ECAM to the effective date of rates in the next rate
case, parties agree that the ECAM will include a renewable generation investment offset
adjustment (Renewable Resource Adder). The adjustment recognizes that Actual NPC have
been reduced by power generated from these renewable generation projects. The adjustment will
be based on $55 per megawatt-hour, as calculated in Stipulation supporting testimony Exhibit 5
multiplied by the actual megawatt-hour output generated by the renewable resources. In
recognition for, and as a result of, the implementation of the ECAM with an adjustment for
renewable generation projects not yet in rate base, the Company has agreed not to file a general
rate case prior to May 2010. This rate stability and assurance of no rate increase prior to April
, 20 I 0, the effective date of the ECAM rate, is another key customer benefit.
ORDER NO. 30904
The balancing account and ECAM rates serve as a true-up mechanism to recover or
credit the differences between base NPC and actual NPC. The monthly under or over recovery
will accumulate in the balancing account and accrue a carrying charge equal to the
Commission s most recently approved customer deposit rate. On an annual basis the
accumulative deferred balance in the balancing account will be converted to a Schedule 94
ECAM rate expressed on a cents-per-kilowatt-hour basis for projected Idaho sales for the next 12
months of the ECAM recovery period.
The parties to the Stipulation recognized that the Company s filed Case No. PAC-
08-07 included an annual level of amortization of three regulatory liabilities which reduced the
revenue requirement used in establishing the current base rates, i., (1) the West Valley lease
(2) administrative and general expense merger commitment, and (3) the gain on the sale of the
Goose Creek transmission line. The current rates will continue until new rates are set at the end
of 20 10 or later and as a result customers will continue to receive the benefit of the amortization
in rates until that time. As of December 31 , 20 10, an unamortized balance of $156,434 for the
Goose Creek sale will remain on the Company s books and records. The Stipulation specifies
that upon Commission approval thereof, the Company will credit the ECAM deferral for the
Goose Creek sales in the amount of $156 434. Accordingly, the parties agree that the Company
can write off the remaining unamortized balances of these regulatory liabilities.
The Idaho tariff and tariff contract loads are separated to isolate the tariff customer
share from the contract tariff customers (Monsanto and Agrium) because tariff contract loads are
not subject to any ECAM surcharges/surcredits until January 1 2011. Reference Case No. PAC-
07-, Order No. 30482. The tariff contract customers' loads will be included in the Idaho
ECAM cost deferral calculation beginning January I , 2011 , and will be subject to the ECAM
rate from that date forward. Any ECAM balance at December 31 , 2010, would be isolated from
the balance calculated beginning January I , 2011 , to assure these tariff contract customers have
no impact on the ECAM deferral prior to the end of the service agreement.
The ECAM deferral period will be December I through November 30. An annual
application to adjust the ECAM rate will be filed with the Commission on February I. Parties
and Commission Staff would then review the application, and assuming the application is
approved, the ECAM rate would then be updated and effective April I. The initial deferral
period for the first year of the ECAM will be July I through November 30 2009.
ORDER NO. 30904
The Company is working with other parties to the Stipulation to design rates that
reflect line losses and distinguish between transmission, primary and secondary voltage delivery
service. The Company also agrees to hold a risk management hedging seminar to educate parties
about the Company s risk management practices and hedging strategies.
Commission Staff
Supporting testimony on behalf of Commission Staff was filed by Randy Lobb
Utilities Division Administrator. Mr. Lobb states that the proposed ECAM in this case is very
similar to the Power Cost Adjustment (PCA) mechanisms approved by the Commission for
Idaho Power Company and A vista Corporation. The mechanism tracks four primary power
supply accounts: (1) Generation fuel expense, (2) Market purchase power expense, (3) Surplus
energy sales revenue, and (4) Variable transmission expense.
Staff supports the Settlement establishing the ECAM because, Staff contends, it is
now equitable to do so and as designed reasonably balances the interest of PacifiCorp (Rocky
Mountain Power) shareholders and Idaho retail customers. PacifiCorp s resource portfolio, Staff
notes, has expanded to include a much larger portion of natural gas-fired generation. The
Company s portfolio also consists of 30% hydropower and increased wind generation. Given the
variability of hydro-generation and wind generation along with the volatility in natural gas and
electric market prices, Staff believes the Company s variable power supply cost exposure is
similar to that of other electric utilities that have Power Cost Adjustment (PCA) mechanisms in
Idaho.
In addition to customers benefiting when variable power supply costs are less than
normalized costs included in base rates, Staff believes that the ECAM could have customer
benefits even if variable power supply costs are above normal. For example, more timely
recovery of variable power supply costs between rate cases may reduce the frequency of general
rate cases. It may also reduce the need for a forecasted test year in general rate case filings.
Finally, as more of PacifiCorp s state jurisdictions adopt ECAMs, borrowing costs should
decline even in the face of increased infrastructure and investment.
Staff in its supporting comments cites the similarities and differences between the
existing PCA mechanisms of A vista and Idaho Power. Many of the proposed ECAM terms, it
states , are identical. For example, the mechanism compares base net power costs for the same
expense and revenue accounts established in the utility s last rate case to actual net power costs
ORDER NO. 30904
incurred on a monthly basis. Like Avista s PCA, the difference is then accumulated in a deferral
account with interest at the customer deposit rate for true-up once a year.
The proposed ECAM also contains a load growth adjustment calculated in a manner
similar to that of existing PCAs. Once the deferral amount is known, it is spread over the
expected annual energy consumption for the next year. Any deferred amount over- or under-
recovered remains in the deferral account for subsequent true-up during the next ECAM period.
Finally, the mechanism contains a 90%/10% sharing percentage as does the Avista PCA to align
the interest of the Company and its customers and assure that power supply costs are as cost-
effective as possible.
While there are similarities, Staff notes that there are also differences. For example
the comparison between base power supply costs and actual power supply costs is made on a
cost per kilowatt-hour basis. Staff believes that comparing power supply costs on a kilowatt-
hour basis reduces the effect of load growth and limits the necessary size of the load growth
adjustment.
The proposed ECAM also contains two elements of a temporary nature. The first
element is that the ECAM will apply only to Idaho tariff customers because Nu-West (or
Agrium) and Monsanto are served under special contracts approved by the Commission through
2010. (Duvall Direct, pp. 8-) Staff supports the exclusion noting that any Idaho jurisdictional
power supply costs subject to recovery (or disbursement) through the ECAM will be prorated to
remove power supply costs associated with special contract loads. The other temporary
provision is the Renewable Resource Adder, ~ 8. This adjustment will be made to actual ECAM
power supply costs until completion of the new general rate case.
With the assistance of the Company, Staff performed an analysis with a backcast to
estimate the effect of the ECAM on the Company s Idaho rates for the period January through
May 2009. Company Exh. 4, attached. The backcast showed the components ofthe ECAM and
the amounts that accumulated over the five-month period. It showed that the single largest
deferral component was the Renewable Resource Adder. The Renewable Resource Adder is a
temporary ECAM component that allows the Company to recover the fixed costs of new wind
generation until those costs are included in base rates in the Company s next general rate case.
The Renewable Resource Adder is an appropriate ECAM cost, Staff contends, because the
power supply cost benefits of new wind generation are automatically captured in the ECAM.
ORDER NO. 30904
New wind generation reduces fuel costs and purchased power costs and increases secondary
sales revenues. Requiring the shareholders to pay the fixed costs while passing nearly all the
benefits on to customers, Staff contends, is an inequitable ratemaking practice. The second
largest ECAM component was the net power cost deferral. The other two ECAM components
were SO2 credits and interest. If the backcast level of deferral continued for 12 months the
deferral amount would be approximately $2.6 million. The Company s current approved annual
revenue requirement for tariffed customers is $147.8 million. The rate increase would be about
1.8%. The Company s actual power supply costs, Staff notes, may vary significantly from year
to year.
Idaho Irrigation Pumpers Association, Inc.
Supporting testimony for the lIP A was submitted by Anthony J. Yankel. lIP A notes
that the ECAM proposed in Idaho is different from the energy cost adjustment mechanisms of
the Company in its other jurisdictional states. Although it seems somewhat of an administrative
burden for the Company to have four or five different power cost adjustment clauses, lIP A states
that each Commission is thus able to have a power cost adjustment mechanism that fits its own
unique circumstances and requirements. lIP A contends that it is appropriate to have an ECAM
where a utility sells and/or buys a great deal of energy in the market, and where market prices
can widely fluctuate. An energy cost adjustment mechanism may be of value in adjusting the
utility s rates on more of a real time basis in order to follow costs that are being incurred on the
system. This is generally the case with PacifiCorp, lIP A contends, where a large percentage of
the Company s load is served by not only its own generation, but by purchased power as well
while at the same time, the Company also sells a great deal of power into the markets.
Commenting on the variance in the Company s net power costs over the last few
years, lIP A states that in the Company s 2007 general rate case the Company filed for a test year
net power cost of approximately $862 million. In the 2008 general rate case it filed for a test
year net power cost that was $120 million greater or $982 million. Its actual new power costs for
the 12 months ended December 31 , 2008, were $118 million greater than the 2008 test amount
or $1.1 billion.
lIP A notes that the symmetrical sharing band for Idaho Power recently raised from
90% up to 95%. lIP contends that this is appropriate because Idaho Power and Rocky
Mountain Power are not the same. Idaho Power has to function in the same volatile energy
ORDER NO. 30904
market as does the Company, but Idaho Power has the additional volatility of being a
predominantly hydro system. For now, lIP A states, a 90% sharing mechanism is more
appropriate for Rocky Mountain Power than a 95% sharing mechanism.
lIP A states that a stay-out provision preventing the Company from filing a general
rate case prior to May I , 20 I 0 was not just an important element of the Stipulation - rather
without this provision, lIP A states any offer by the Company would have been a no starter. That
being said, the Irrigators note that irrigators saw also the reasonableness of including a renewable
generation investment offset adjustment to recognize the Company s lease investment in wind
generation.
One other major issue in which the Irrigators took particular interest pertained to the
Company s original proposal to treat all sales the same on a kilowatt-hour basis by adding any
surcharge or refund to customers on an equal cents-per-kilowatt-hour basis as a result of the
ECAM. The Irrigators (as well as Monsanto Company) took the position that such treatment is
in contrast to the way costs are incurred, rates are designed, and costs are allocated. It is a well
accepted premise, the Irrigators contend, that a kilowatt-hour for sale at the secondary
distribution level is not equivalent to a kilowatt-hour for sale at the primary distribution or
transmission level. There are losses involved, with more losses taking place at the secondary
level than at the primary or transmission level. If the Company incurs fewer losses to serve a
primary or a transmission customer than it does to serve a customer on the secondary distribution
system, then the Irrigators contend that those customers should not pay the same rate for the
ECAM adjustment. Losses are built into the cost of fuel, purchase power, etc., found in base
rates, and Irrigators contend they should also be incorporated into the ECAM adjustment.
Although the Stipulation does not specifically calculate the impact of losses on the ECAM
adjustment, the parties have committed to working together to develop such a rate/procedure. If
an appropriate procedure cannot be developed, the matter will be brought to the Commission
attention.
Commission Findings
The Commission has reviewed and considered the filings of record in Case No. PAC-
08-08 including the initial Application and supporting testimony of Greg Duvall, Director of
Long Range Planning and Net Power Costs. We have also reviewed and considered the
Stipulation (and proposed settlement) and supporting testimonies filed on behalf of the
ORDER NO. 30904
Company, the Irrigators, and Commission Staff. IDAPA 31.01.01.274-276. Settlements are
reviewed under Commission Rules of Procedure 274-276. We incorporate by reference the
submitted Stipulation (and proposed settlement) as if set forth herein in its entirety.
As reflected in the Commission s Rules, the Commission is not bound by any
settlement reached by the parties. RP 276. 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. RP 275. The Commission is to independently review any
settlement proposed to determine whether the settlement is just, fair and reasonable, in the public
interest, or otherwise in accordance with law or regulatory policy. The Commission may accept
the settlement, reject the settlement or state additional conditions under which the settlement will
be accepted. RP 276.
We find that the Stipulation represents a fair, just and reasonable compromise of the
issues presented in this case and that the Stipulation parties provide justification for authorizing
an ECAM for Rocky Mountain Power in Idaho. We find that approval of an ECAM is supported
by the volatility in the energy market and the changing character of the Company s resource
portfolio. Our comfort with the proposed ECAM of Rocky Mountain Power is strengthened by
our experience with the PCA mechanisms of Idaho Power and A vista. The proposed ECAM
contains a symmetrical 90/10 sharing band, a load-growth adjustment, a credit for SO2 sales, and
an interest multiplier for deferrals, each component contributing to the overall fairness of the
mechanism. We find the temporary inclusion of a renewable resource adder, the write-off of
specific regulatory liabilities and the exclusion of tariff contract loads to be reasonable
implementation adjustments. We find that customers will benefit from the Company
commitment not to file a general rate case before May 2010 and its agreements to work with
parties to design ECAM rates that reflect line losses and distinguish between transmission
primary and secondary voltage delivery service and to conduct a risk management hedging
semInar.
The Commission finds that the designed ECAM will send better price signals to the
Company s customers of the cost of power by adjusting their rates on a more current basis. The
symmetrical sharing band provides the Company an incentive to actively control its net power
costs. We find the agreed July 2009, date for initial recording of power supply cost deferrals
ORDER NO. 30904
to be reasonable. We also find that the annual ECAM filings will provide an opportunity for
interested parties to review and provide input on one of the Company s main cost drivers.
PETITION FOR INTERVENOR FUNDING
A Petition for Intervenor Funding in this case was filed by the Idaho Irrigation
Pumpers Association, Inc. in the amount of $22 157.24 (consisting of $17 849.14 consultant fees
(135 hours at $125 per hour and $974.14 postage and travel) and $4 308.10 legal fees (20.
hours at $185 per hour, 3 hours at $135 per hour and $147.60 postage and travel)).
Intervenor funding is available pursuant to Idaho Code ~ 61-617 A and Commission
Rules of Procedure 161-165. Section 61-617 A(1) declares that it is "the policy of (Idaho) to
encourage participation at all stages of all proceedings before this commission so that all affected
customers receive full and fair representation in those proceedings.The statutory cap for
intervenor funding that can be awarded in anyone case is $40 000. Idaho Code ~ 61-617 A(2).
Accordingly, the Commission may order any regulated utility with intrastate annual revenues
exceeding $3.5 million to pay all or a portion of the costs of one or more parties for legal fees
witness fees and reproduction costs not to exceed a total for all intervening parties combined of
$40 000.
Rule 162 of the Commission s Rules of Procedure provides the form and content
requirements for a Petition for Intervenor Funding. The petition must contain: (1) an itemized
list of expenses broken down into categories; (2) a statement of the intervenor s proposed finding
or recommendation; (3) a statement showing that the costs the intervenor wishes to recover are
reasonable; (4) a statement explaining why the costs constitute a significant financial hardship
for the intervenor; (5) a statement showing how the intervenor s proposed finding or
recommendation differed materially from the testimony and exhibits of the Commission Staff;
(6) a statement showing how the intervenor s recommendation or position addressed issues of
concern to the general body of utility users or customers; and (7) a statement showing the class
of customer on whose behalf the intervenor appeared.
lIP A, a participant in settlement discussions and a signatory to the Stipulation, urges
the Commission to adopt the terms of the Stipulation. Although this case resulted in settlement
lIP A contends that it had to prepare as though it was a fully contested case. The expenses and
costs that lIP A seeks to recover were incurred, it states, in corresponding and collaborating with
ORDER NO. 30904
all the parties, and in gathering information, drafting and reVIeWIng documentation and
testimony, and negotiating changes to the Stipulation language.
lIP A represents that to support activities the organization relies solely upon dues and
contributions voluntarily paid by members and intervenor funding. Member contributions, it
states, have been falling, presumably due to the current depressed economy, increased operating
costs and the threats related to water right protection issues. lIP A represents that the costs
incurred for participating in this case constitute a financial hardship for the organization.
lIP A contends that it provided a unique perspective on a number of issues in this case
, (1) the "stay out" provision (~ 13) and the temporary inclusion of a negotiated dollar amount
($55/MWh) to provide the Company some recovery of its investment in renewable generation
projects (~ 8); and (2) on the issue of line losses and the distinction of taking service at the
primary, transmission and secondary level in determining how to spread ECAM adjustments in
the future (~ 11).
lIP A, appearing on behalf of the irrigation class of customers under Schedule 24
contends that its participation in the settlement discussions on the above two issues was a benefit
to all customer classes.
Commission Findings
Submitted for Commission decision in this case is a Petition for Intervenor Funding
filed by the Idaho Irrigation Pumpers Association ($22 157.24). The Commission has reviewed
the Petition and the record of proceedings.
Intervenor funding is available pursuant to Idaho Code ~ 61-617A (Award of Costs of
Intervention) and the Commission Rules of Procedure 161-165. Rule 162 of the Commission
Rules of Procedure provides the form and content requirements for petitions for intervenor
funding.
Pursuant to Idaho Code ~ 61-617 A(2), the Commission may order Rocky Mountain
Power to pay all or a portion of the costs of one or more parties for legal fees, witness fees, and
reproduction costs, not to exceed a total for all intervening parties combined of $40 000 in any
proceeding before the Commission. The total amount requested by the Irrigators is $22 157.24.
Idaho Code ~ 61-617 A includes a statement of policy to encourage participation by
intervenors at all stages of all proceedings before the Commission. The Commission determines
an award for intervenor funding based on the following considerations:
ORDER NO. 30904
(a)finding that the participation of the intervenor has materially
contributed to the decision rendered by the Commission; and
(b)A finding that the costs of intervention are reasonable in amount and
would be a significant financial hardship for the intervenor; and
(c)The recommendation made by the intervenor differed materially from
the testimony and exhibits of the Commission Staff; and
(d)The testimony and participation of the intervenor addressed issues of
concern to the general body of users or consumers.
Idaho Code ~ 61-617A.
We find that the Petition for Intervenor Funding in this case was timely filed and
satisfies all of the "procedural" and technical requirements set forth in the Commission s Rules
of Procedure and Idaho Code ~ 61-617 A.
In this case the Commission finds it reasonable to award the Irrigators their out-of-
pocket costs ($1 121.74) and a discounted amount for consultant and attorney fees. We do not
feel compelled to grant the full amount requested. In making an adjustment to IIPA's requested
intervenor funding amount in this case, we considered the nature of the proceedings, the filings
of record and the respective participation and contributions of Commission Staff and the
Irrigators to the Commission s decision. While we are able to recognize the Irrigators
contribution regarding the issue of line losses and level of service, we find little material
difference in its other recommendations from those of Staff. We award the Irrigators $16 898.
and find such award to be fair, just and reasonable. lIP A is a non-profit corporation representing
farm interests and relies solely upon dues and contributions voluntarily paid by members based
on acres irrigated or horsepower per pump. We appreciate the participation of the Irrigators in
this case and recognize their contribution to the ultimate resolution of issues.
The Commission finds that the intervenor funding award to the Irrigators is fair and
reasonable and will further the purpose of encouraging "participation at all stages of all
proceedings before the Commission so that all affected customers receive full and fair
representation in those proceedings.Idaho Code ~ 61-617A(1).
ORDER NO. 30904
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over PacifiCorp dba Rocky
Mountain Power, an electric utility, and the issues presented in Case No. P AC-08-08 pursuant
to Idaho Code, Title 61 , and the Commission s Rules of Procedure, IDAPA 31.01.01.000 et seq.
ORDER
In consideration of the foregoing and as more particularly described above, IT IS
HEREBY ORDERED and the Commission hereby approves the terms of the Settlement
Stipulation offered in this case, and in so doing approves an Energy Cost Adjustment Mechanism
for Rocky Mountain Power in Idaho. The Company is directed to file a Schedule 94 tariff
comporting with this Order.
IT IS FURTHER ORDERED and the Idaho Irrigation Pumpers Association, Inc.
Petition for Intervenor Funding is partially granted in the amount of $16 898.74. Reference
Idaho Code ~ 61-617 A. Rocky Mountain Power is directed to pay said amount to the Irrigators
within 28 days from the date of this Order. IDAPA 31.01.01.165.02. The Company shall
include the cost of this award of intervenor funding to the Irrigators as an expense to be
recovered in the Company s next general rate case proceeding from irrigation customer class.
Idaho Code ~ 61-617A(3).
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code ~ 61-626.
ORDER NO. 30904
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this c:l9 r"
day of September 2009.
11.
8rDPTON, PRE DENT
MARSHA H. SMITH, COMMISSIONER
\~\~
MACK A. REDFO
ATTEST:
€l!:E Lt rlJe n . Jewell
ission Secretary
bls/O:PAC-08-08 sw3
ORDER NO. 30904
Rocky Mountain Power
Exhibit No.4 Page 1 of 1
Case No. PAC-e-Qa-O8
Witness: J. Ted Weston
Idaho ECAM Deferral (PAC-E.OS..oS)
Line
No.Jan~9 FelMl9 Mar~9 Apr~May~9
Base NPC Rate ($lMWh) - See footnote #1 below 14.13.11.18.15.
Total Company Adjusted Actual NPC ($)72.935.924 72,605.090 69,405,416 68,614 088 450,101
Actual Retail Load (MWh)255,917 579,857 700,251 254.657 4,424.642
Actual NPC ($lMWh)Line 4 = Line 2/ Line 3 13.15.14.16.17.
NPC Differential $IMWh Line 5 = Line 4. Line 1 (0.60)(2.10)
Actual Idaho Tariff Load (MWh)180,260 137,083 132,778 116,526 189,202
Actual Idaho Tariff Contract Load (MWh) . See footnote #2 below
. 8 NPC Differential for Deferral ($)Line 8 = Line 5. Lines 6+7 (95 981)269,163 441,421 (244,989)213,204
Base Load - (1) See footnote below 147,983 135,627 134,939 112,794 194,884
10 DIfference Base Load to Actual Load Line 10 = Line 6 + Line 7 - LIne 9 277 456 (2.161)732 (5,682)
11 Load Growth Adjustment Rate ($/MWH)$17.$17.$17.$17.$17.
12 Load Growth Adjusbnent Revenues Line 12 = Line 10 x Line 11 (214,600)(25 444)37,767 (65,239)99,328
13 S02 Allowances Sales (194 500)(173,141)
14 Idaho SE Factor 5865%5865%5865%5865%5865%
15 Idaho Allocation Line 15 = Line 13. x Line 14 (12,811)(11.404)
16 Idaho Tariff Customers Percent 57.9757%54.1625%56.1032%55.5323%70.5349%
17 Idaho 802 Offset LIne 17 = Line 15 x Line 16 (7.427)(6,333)
18 Total NPC Differential + LGA + S02 Line 18 = Line 8 + Line 12 + LIne 17 (318,008)243,719 479,189 (316,560)312,532
19 Customer / Company Sharing ratio 90.00%90.00%90.00%90.00%90.00%
20 Customer / Company Sharing (90/10)Line 20 = Line 18 x Line 19 (286,207)219,347 431,270 (284,904)281,279
21 Renewables Generation (MWhs)57,331 92,104 253 55,653 64.961
22 Renewable Adder Rate per MWh $55.$55.$55.$55.$55.
23 Total Renewable Resources Adder LIne 23 = LIne 21 x Line 22 153,205 065.720 183,915 060,915 572,855
24 Idaho SG Fador 0479%0479%0479%0479%0479%
25 Idaho Allocation Line 25 = Llna 23 x LIne 24 190,703 306.370 313 518 185,121 216,083
26 Idaho Tariff Customers Percent 57.9757%54.1625%56.1032%55.5323%70.5349%
27 Renewable Resources Adder Line 27 = Line 25 x Line 26 110,561 165,937 175,894 102,802 152,414
28 Recovery of DefemKI Balances
29 Deferred Balance ($)Line 29 = LIne 31
30 Projected Retail Sales (MWh)
31 ECAM Surcharge Rate (S/MWh)Line 31 = LIne 29/ Line 30
32 Actual Idaho Tariff Sales (MWh)
33 Actual Tariff Contract Sales (MWh)
34 Recovery of Defe~ (~Line 34 = Line 31 . Lines 32+33
35 Balancing Account ($)
36 Beginning Balance (175,793)209.520 817,539 636,647
37 lnaemental Deferral (286,207)219,347 431,270 (284,904)281,279
26 Ranewable Resources Adder 110,561 165,937 175894 102,802 152,414
27 Recovery Adjustment Line 27 = -LIne 34
29 Regulatory liability Write-off (Un-Amortized Balance at Jan2010)
30 Interest (146)855 211 1,422
31 Ei'ICling Balance ($)175,793 209,520 817,539 636 647 071,763
32 Interest Rate 00%00%00%UJO%2JJO%
(1) Base NPC Rate and Load from Case No. PAc-E;Q8-07 $982 million
(2) Customers served under tariff contracts 400 and 401 are not Impacted by the ECAM until January 1, 2011.
ATTACHMENT
ORDER NO. 30904
CASE NO. PAC-08-