20161215Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 7956
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR DEFERRAL )
AND RECOVERY OF COSTS ASSOCIATED )
WITH PARTICIPATION IN AN ENERGY )
IMBALANCE MARKET. ) ___________________ )
CASE NO. IPC-E-16-19
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Brandon Karpen, Deputy Attorney General, and in response to the Notice of
Modified Procedure and Notice of Comment Deadline issued in Order No. 33627 on October 14,
2016, in Case No. IPC-E-16-19 to submit the following comments.
BACKGROUND
Procedural History
On August 19, 2016, Idaho Power Company filed an Application requesting that the
Commission: (1) make a finding that Company participation in the proposed Energy Imbalance
Market could net customers long-term benefits; (2) authorize a deferral account to track
necessary incremental costs associated with participation; and (3) allow the Company to recover
estimated costs from customers in a future rate proceeding. Application at 1.
On September 13, 2016, the Commission issued a Notice of Application and set a
deadline of October 4, 2016, for interested parties to petition for intervention. Three parties filed
timely petitions and were granted intervention: the Industrial Customers of Idaho Power; the
STAFF COMMENTS 1 DECEMBER 15, 2016
Snake River Alliance; and the Idaho Conservation League. Staff conferred with the parties, who
agreed to the use of Modified Procedure, with a comment deadline of December 15, 2016, and a
reply deadline of January 5, 2017.
Energy Imbalance Market
An Energy Imbalance Market (EIM) pools generation of interconnected electricity
producers within a region, and dispatches those resources with the goal of accurately matching
production with demand. An EIM operates on a nearly real-time basis with multiple participants.
More conventional long-term two-party contracts deliver energy in hourly blocks.
In November 2014, the California Independent System Operator (CAISO) and PacifiCorp
formed the western EIM. Id. at 1-2. The western EIM is a five-minute market administered by
CAISO. The market utilizes an automatic model to identify the least-cost energy resources to
resolve real-time energy imbalance. Id. According to the Company, the western EIM "focuses
solely on real-time imbalances and allows EIM entities to retain all balancing responsibilities and
transmission provider duties." Id. at 2. Participants in the EIM bid resources into the market,
and the operator dispatches those resources based on marginal price for energy imbalances
factoring in load and available generation. Id. The current EIM participants are CAISO, NV
Energy, Inc., PacifiCorp, Puget Sound Energy, and Arizona Public Service Company.
With its Application, the Company states that it intends to begin participating in the
western EIM in April 2018. The Company claims that the western EIM will benefit customers
through "economic efficiency ... , savings due to diversity of loads and variability of resources
within the expanded [EIM] footprint, reduced operational risk ... , and ability to better support
the integration ofrenewable resources." Id. According to the Company, participation in the
EIM could result in net power supply expense savings of $4.1 to $5.1 million per year. Id. at 4.
STAFF REVIEW
Staffs evaluation of the Company's request to participate in the EIM and defer costs for
later recovery is based primarily on Idaho Power's estimate of benefits associated with
participation in the EIM. Staff recognizes that the estimate of EIM benefits are assumption
driven and there is concern that the benefits may not materialize as forecasted. The conclusions
and recommendations in these comments reflect those concerns.
STAFF COMMENTS 2 DECEMBER 15, 2016
In summary, Idaho Power is proposing to participate in a sub-hourly regional EIM, which
will require a unique investment and changes in traditional system operation. Participation costs
appear to be best estimates, and will be refined as more information is obtained and will
eventually reflect actual cost subject to Commission review. Staff believes that operating
efficiencies will improve as the Company gains experience actively participating in the EIM.
Staff understands the uncertainty and limitations of estimating benefits derived through
modelling but ultimately agrees that the Company's approach to calculating potential benefits is
conservative and reasonable under the circumstances.
Staff also considered other factors in reaching its conclusions, including: ( 1) intangible
benefits the Company identified in its Application; (2) similar cases where the Company has
requested pre-authorization and ratemaking treatment of future investments; and (3) the size of
the investment and the ability to acquire capital for financing.
Based on its analysis, Staff concludes that the overall potential long-term benefits to
customers will likely outweigh the incremental cost of joining the EIM. However, given the
relatively small amount of benefits, the level of uncertainty, and other factors described above,
Staff believes the most reasonable approach is to authorize the Company to establish a deferral
account; and to track actual costs incurred rather than estimated costs as proposed by the
Company. These prudently incurred costs should not be authorized for recovery until offsetting
benefits are also included in rates. Details of Staff's cost-versus-benefit analysis, intangible
benefit analysis, cost recovery methods, and recommendations are provided below.
Cost Versus Benefit
Staff thoroughly reviewed the Company's quantification of costs and benefits used to
determine the economic viability of joining the EIM. This included a review of the production
cost model and methods used to determine the amount of financial benefit that could potentially
be realized. Staff also reviewed the upfront and operational costs required for the Company to
participate in the EIM including the basis for forming its estimates. Finally, Staff reviewed the
Company's net present value (NPV) revenue requirement impact used to show the amount of
savings customers may realize when netted against the cost of participation.
STAFF COMMENTS 3 DECEMBER 15, 2016
Benefit Model Analysis
Idaho Power contracted with Energy and Environmental Economics, Inc. (E3) to conduct
a study of the impact of, and potential savings from Idaho Power's participation in the EIM. Due
to the complexity of the electricity system, E3 performs simulations in an attempt to realistically
model how the system will operate. Staff recognizes that there are inherent challenges in
calculating and verifying the benefits that an EIM can generate. To mitigate uncertainty, Staff
evaluated several factors including: the overall approach used to conduct the study and to
quantify benefits; the appropriateness of the model and modeling methodology relative to the
study's objectives; the validity of the model and the assumptions used to reflect system
operations with and without an EIM; and the consultant's experience and level of expertise.
Staff concluded that the benefit model is reasonable and likely provides a conservative
approximation of benefits if the Company participates in the EIM.
In broad terms, E3 derived an annual benefit amount by simulating the bulk power
system of the western interconnection for the year 2020 through two separate model runs: an
EIM case and a business-as-usual (BAU) case (without Idaho Power's participation in the EIM).
E3 derived a relative benefit amount by calculating the difference in the Company's share of net
power costs between the two model runs. E3 repeated these runs using four different scenarios
in order to test the sensitivity and impact of different variables on the benefit amount: (1) a
baseline scenario; (2) a higher renewable buildout scenario; (3) an early coal retirement scenario;
and ( 4) a scenario with a reduced amount of utilities participating in the EIM. 1 Staff requested
an additional scenario with higher gas prices ($4.25/MMBTU vs. $3.27/MMBTU in baseline
scenario) and therefore higher electricity prices to see its effect on cost savings. The benefit
results are summarized in the table below.
1 A detailed description of each scenario can be found on page 7 of Exhibit 4 of Kathleen Anderson's direct
testimony.
STAFF COMMENTS 4 DECEMBER 15, 2016
Scenario Savings to Idaho Power
Baseline Scenario $4.5 million annually
High Renewable Portfolio Standard Case $5.1 million annually
Early Coal Retirement $4.1 million annually
Arizona Public Service Company and Portland $4.2 million annually
General Electric Company not participating in
EIM
Higher Gas Price $5 .0 million annually
One of the values of performing sensitivity scenarios is to validate the model. For
example, several studies2 have shown that EIM savings generally increase when the penetration
of variable renewable generation or gas prices are higher, which E3 's results have shown.
However, the results also show that benefits are expected to be lower if there are early coal
retirements or less participation in the EIM.
For example, in an early coal retirement scenario, Idaho Power would need to rely more
on its gas and hydro resources to meet load which would leave less available capacity to sell into
the imbalance market. Similarly, EIM benefits would be lower than expected if there were fewer
market participants to purchase Idaho Power's available generation, or for Idaho Power to
purchase lower cost generation to meet its own imbalance needs. Thus, the model's results and
the relative change in benefit amounts from modeling the scenarios align with what Staff would
otherwise expect.
The modeling provides further value by aiding understanding in how the risk of future
circumstances could impact potential savings. The model evaluated potential benefits in
scenarios involving increased coal plant retirements, increased renewable generation, higher gas
prices, or the possibility that other utilities may no longer participate. Given there are relatively
small changes in the savings amounts in each of these scenarios compared to the baseline
scenario, Staff believes that a future change in circumstances due to these factors will not
significantly affect the economic viability of the project.
2 See EIM Benefit Assessments, available at:
https ://www.caiso.com/informed/Pages/EIM Overview/Default. aspx
STAFF COMMENTS 5 DECEMBER 15, 2016
However, modeled benefit results need to be weighed against risks from unanticipated
factors. A $4.5 million benefit amount is less than 2% of the Company's $234 million in Idaho
allocated actual net power cost according to last year's power cost adjustment (PCA). Staff
believes that small, unforeseen change in circumstances could erase such a small benefit amount.
Notwithstanding that concern, Staff believes the conservative approach taken by E3 and the
Company help mitigate the small power cost savings and much of the uncertainty in determining
benefits. Staff believes the following assumptions make the study results conservative:
1. Valuing energy at the estimated cost of production instead of using market-based
rates;
2. Modest gas price and renewable penetration rate assumptions;
3. No inclusion of quantified benefits for improved reliability or reduced reserves;
4. No inclusion of benefits that may result in the day-ahead or hour-ahead market from
better EIM visibility across the system;
5. No inclusion of maintenance benefits from reduced ramping of thermal units;
6. The use of ten-minute time steps in the model instead of the 5-minute dispatches that
are actually used in the EIM that should reduce potential variation in the model.
7. Modeling of hydro units constrained to monthly and daily budgets from actual
generation data during a normal water year.
Staff concludes that by employing conservative assumptions and modeling approaches, the study
produces quantified benefits that are modest yet sufficient to cover the proposed level of
investment.
In evaluating E3 's level of expertise, Staff found that they have substantial experience
performing similar benefit studies for PacifiCorp, Puget Sound Energy, Arizona Public Service,
NV Energy, and Portland General Electric Company, all utilities in the WECC that are actively
participating or planning to participate in the EIM. In all cases, E3 used PLEXOS, a proprietary
sub-hourly production cost modeling software widely used by utilities, regulators and system
operators to model power markets. Because of this experience, E3 has been able to leverage its
model from past projects to conduct Idaho Power's benefit study. Staff believes the repetition
and layers of additional review have likely resulted in methodology improvements and more
robust results.
STAFF COMMENTS 6 DECEMBER 15, 2016
Cost Analysis
The Company provided cost estimates for two purposes: (1) to perform a cost/benefit
analysis; and (2) to book expense in a deferral account for future recovery. In its Application,
Idaho Power requested the Commission to issue an order "authorizing the Company to recover,
in a future rate proceeding, the estimated incremental costs of joining the EIM." Application
at 5. Staff analyzed the estimated incremental costs of joining the EIM and has concluded that
the basis used to establish the estimates are sound and a good approximation of actual cost for
purposes of the cost/benefit analysis. However, Staff believes they lack rigor and certainty for
determining recovery through rates, as described further below.
The cost of participating in the EIM include both upfront and ongoing annual costs as
summarized in the following table :
Cost Summary (millions $) Upfront Costs Ongoing Annual Costs
Startup Expense 1.73
Software Integration Cost 7.88
Metering Investment 1.48
Labor for Operations 0.836
CAISO Market and Software Cost 0.786
Total 11.09 1.622
The Company estimates about $11 million in total upfront cost and $1.6 million in annual
ongoing cost. Staff requested a breakdown, description, and basis for each of the estimates.
Other than a contract for project management services, Staff found almost all of the cost figures
were based on projections and on scopes of work to be determined later. From the perspective of
cost versus benefit, Staff concluded that a reasonable margin of error in estimated cost will not
drastically effect the outcome of the analysis.
However, Staff believes it is not appropriate to use these cost estimates for rate recovery.
First, Staff believes that the cost estimates fall short of the "known and measureable" standard.
See Idaho Code §61-502. This is based on the Company's lack of prior experience operating in
an EIM-like market and because cost estimates were developed without complete scopes of work
and use of a rigorous bidding process. Second, the Commission reserves the right to review
prudently incurred actual cost unless the investment is under special circumstances. See Idaho
STAFF COMMENTS 7 DECEMBER 15, 2016
Code §61-503. Providing cost pre-approval removes the incentive for the Company to
implement a project in a prudent least-cost manner by removing the possibility of non-recovery
of imprudently incurred actual cost. Accordingly, Staff recommends deferral of costs until
actual costs can be determined and reviewed for prudency.
Revenue Requirement Net Impact Analysis
The Company's revenue requirement net impact analysis is used to determine the
financial viability of the project. It calculates the impact to the Company's revenue requirement
based on proposed implementation costs and benefits and costs quantified in the E3 baseline
scenario. Staff reviewed the analysis to ensure it was accurate and augmented it to better
understand the payback period. Staff found that the analysis was reasonably accurate showing
positive net benefits (negative revenue requirement impact) in approximately five years with a
total net benefit of $4.4 million over ten years. A copy of Staffs modified version of the
analysis is provided as Attachment A to these comments.
Intangible Benefits
As previously mentioned, several intangible benefits were not included in the benefit
analysis. Two of these are described in more detail below: reduced congestion, and reduced
reserves and improved reliability. Although difficult to quantify now, these benefits could
become significant in the future, especially if developments dynamically transform electricity
wholesale markets across the west. Developments include enhanced ability to comply with
potential state and federal environmental regulations, an EIM with widespread participation, and
the potential formation of a WECC-wide regional transmission organization (RTO).
Benefits from Reduced Congestion
Staff has concluded that EIM benefits from the elimination of curtailments due to
congested flow paths is very small at this time. Idaho Power claims that the EIM provides a
benefit by eliminating curtailment on congested flow paths during late spring to summer, when
maintaining system reliability requires higher cost resources to meet Idaho Power customer load.
The EIM accomplishes this by avoiding resource dispatch into already congested areas due to
broader visibility across the grid and better planning and management of congestion across more
of the region's transmission system. (Anderson Direct at 11-12). However, based on Staffs
STAFF COMMENTS 8 DECEMBER 15, 2016
analysis of curtailment events over the past year, the potential annual savings to Idaho Power is
not material.
Staff based its assessment on a Company production request response that provided a list
of curtailed energy purchases attributable to transmission path congestion over the past year.
From this, Staff determined potential benefits from reduction in curtailment of the type that the
EIM could resolve. Staff observed that the total dollar amount of energy that was curtailed was
only about $5,000. Even if the price ofreplacement energy was double the amount that was
curtailed, this would only amount to about a $5 ,000 annual savings. Staff further observed that
most curtailments occurred during winter and early spring which were resolved using Company
hydropower when it is more abundant and inexpensive. Curtailments during late spring and
summer months were also replaced by Company hydro generation, and were thus more
expensive because they, "[create] less opportunity and 'fuel ' for generation in the future."
(Company Response to Staff Production Request No. 7). However, only about a third of the
total curtailed energy for the year occurred during late spring and summer months which
contradicts Company claims that this is when most congestion occurs. (Anderson Direct
at 11-12).
In Company Response to Staff Production Request No. 7, the Company also provided
data showing about a 70% reduction in WECC-wide tag curtailments due to unscheduled flow
events since 2014 when the EIM was first implemented. Although there appears to be reductions
of curtailments from congestion across the region possibly attributable to an EIM, Staff believes
that the incremental potential savings specific to Idaho Power's balancing area is very small at
this time.
Benefits from Reduced Reserves and Improved Reliability
Idaho Power's participation in the EIM may hold significant benefits in the form of
reduced reserves by sharing balancing resources across a wider footprint. The Company did not
try to quantify the potential financial benefits to reliability and reduction of reserves in its benefit
calculation. Staff agrees that separating the benefits between participating Balancing Authorities
(BA) would be difficult. However, Staff believes the importance of this benefit should not be
underestimated for three reasons: (1) Idaho Power is approaching the limit in integrating
renewable resources into its system; (2) the Company may be required to carry additional
reserves as bilateral market liquidity decreases from increased EIM participation by other
STAFF COMMENTS 9 DECEMBER 15, 2016
utilities; and (3) there is the potential for reduction in wind and solar integration charges due to
increased diversity and sharing of balancing resources.
First, Idaho Power asserts that its capability to integrate variable resources is at its limit.
(Anderson Direct at 5). According to the Company, current and future renewable generation
portfolio is as shown in the table below.
Renewable Installed Current (as of Future Signed Total
Nameplate Capacity 10/26/16) Contracts installed
(MW) within 1 Year
Wind Power 678 56 734
Solar Power 50 234 284
Total 728 290 1018
Idaho Power stated in its 2013 Wind Integration Study report in Case No. IPC-E-13-22
that dispatchable thermal and hydro generation will reach its limit to provide balancing reserves
beyond 800 MW of wind generation penetration especially during periods of low demand. If
true, the Company will be close to its stated limit by the end of next year and may be over its
functional limit with the amount of additional solar generation that has interconnected since then
and wasn't included in the study. Given that Idaho Power is required to take all additional Public
Utility Regulatory Policies Act of 1978 (PURP A) generation, the Company may at times need to
increase curtailment or be at risk for reduced reliability.
One method to address some of the need for reserves is through an EIM. Because an
EIM can quickly dispatch generation across a larger footprint, it can reduce the need for the
Company to use its own resources to resolve imbalances leaving more of its own capacity to
provide regulation reserves. In a National Renewable Energy Laboratory (NREL) study of the
western interconnection, it showed that an EIM operating in the Northern Tier Transmission
Group (NTTG) footprint could reduce average net reserves by one third; and for a WECC-wide
EIM footprint, the reduction could be as much as one half and still operate reliably.3 In addition,
E3 in a previous study for Pacific Gas and Electric (PGE) estimated a $0.8 million savings from
flexibility of reserves by joining an EIM. (Exhibit 4, Anderson Direct at 7).
3 National Renewable Energy Laboratory (2011), Flexibility Reserve Reductions from an Energy Imbalance Market
with High Levels of Wind Energy in the Western Interconnection, pp. 35-38.
STAFF COMMENTS 10 DECEMBER 15, 2016
A second consideration is the impact of increased EIM participation on bilateral markets
for reserves. According to the Company, it must carry additional reserves because there are
fewer resources available in the bilateral market that the Company has typically used to resolve
hour-ahead imbalances. (Anderson Direct at 6). This could be a result of differences in EIM
timing requirements which require offers to be made earlier than bilateral trade deadlines.
(Company Response to Staff Production Request No. 11). If the reduction in reserves is
correlated to the expansion of the EIM, Staff believes that utilities that do not participate could
incur increased power costs in the long term.
Finally, there is the potential for reduction in wind and solar integration charges by
joining an EIM. Staff has previously commented "that downward pressure on integration costs
will occur as forecasting improves, as shorter real-time markets develop (e.g., intra-hour trading,
15-minute scheduling, five minute dispatch), as energy imbalance markets develop, and as new
technologies evolve, including energy storage." See Case No. IPC-E-13-22, Staff Comments at
6. Reduced wind and solar integration charges would be a benefit to renewable energy providers
having spillover effects in the form of economic development in local communities where they
are located but would not result in a benefit to Idaho Power customers.
Although direct benefits for reduced reserves were not included in the financial benefit
calculation, Staff believes it is an important consideration and should not be discounted given the
relative amount ofrenewables in Idaho Power's system, the potential for reduced bilateral
market liquidity requiring additional reserves, and the possible opportunity for lower wind and
solar integration charges.
Methods of Cost Recovery
Idaho Power seeks to defer its incremental costs related to participation in the western
EIM to allow the Company to match benefits customers receive with the costs incurred by the
Company. The Company proposes that deferral of the Idaho jurisdictional share of these start-up
and associated incremental labor costs to a regulatory asset continue until no earlier than April
2018, or the time at which such costs can be amortized into customer rates. Idaho Power also
proposes an amortization period of ten years to ensure that annual revenue requirements will
only reflect positive net benefits. Idaho Power also seeks assurance that the upfront costs
STAFF COMMENTS 11 DECEMBER 15, 2016
required to participate in the western EIM are eligible for recovery when requested.4 The
Company claims that absent the ability to recover the up-front and ongoing costs, it will suffer
negative financial impacts. See Tatum Direct at 12-16. The Company states that absent deferral
the estimated negative financial impact would total $9.1 million on a net present value basis for
the 2016-2025 forecast period. See Company Exhibit 2. For that same period, the Company
estimates customers would receive an estimated $19.3 million on a net present value basis
through reduced Net Power Supply Expense benefits flowed through the Power Cost
Adjustment.
Staff recommends that the Commission authorize a deferral of the start-up and
incremental costs associated with joining the western EIM during the start-up period. Staff
believes that the long-term benefits of the program will likely outweigh the cost. Since the
customers will be the recipient of the benefits, it is appropriate for customers to also bear the
costs, and that a deferral account is the appropriate mechanism to capture the initial costs until
such time as the benefits begin to flow to customers.
The Company anticipates incremental labor costs of approximately $836,000 associated
with the addition of six full-time employees required for the Company's participation in the
western EIM. In addition, there will be ongoing market and hosted software fees of
approximately $786,000 per year upon joining the western EIM, beginning in April 2018. The
Company estimates that these O&M expenses for 2018 will be $1.39 million, and for 2019 and
2020 will be $1.62 and $1.67 million, respectively. The Company proposes deferral of the Idaho
jurisdictional share of incremental labor associated with employees dedicated entirely to EIM
activities until customer rates are adjusted to reflect the annual amortization of the requested
deferral balance.
Staff proposes that the Company cease booking costs to the deferral account at the earlier
of when the Company requests recovery of EIM costs and the deferral balance, or the end of
2018. After the go-live date to participate in the EIM, these costs are similar to any other O&M
cost that may be included for recovery in a rate proceeding. The existing rate case process will
allow the Company the opportunity to recover these costs. Therefore, Staff believes that
continuing to book the ongoing incremental O&M costs, including the incremental labor costs, in
4 Because timing of a future general rate case is unknown, the Company may propose an interim rate recovery
method in order to appropriately match the level of cost recovery with the provision of customer benefits.
STAFF COMMENTS 12 DECEMBER 15, 2016
the deferral account past the go-live event would not be prudent. Recognizing the timing of rate
proceedings may differ from the go-live date of April 2018, Staff recommends December 2018
be the latest possible deferral month.
Staff agrees with the Company that the initial costs should be amortized over a ten-year
period. Although the Company asserts that the participation in the EIM is "indefinite," Staff
believes that using a ten-year amortization period will result in a proper matching of costs and
benefits. This is bolstered by the Company's NPV revenue requirement cost/benefit analysis
which reflects positive net benefits over a ten-year period.
The estimated capital costs are predominately the software integration cost of $7.88
million. Normally these costs would be amortized over seven years. However, the metering
investment of $1.48 million costs are recorded in FERC accounts that are normally depreciated
over 25 or 34 years, depending on the FERC account. Staff believes that a ten-year amortization
period represents a good blend of the varying depreciation periods. Staff believes that customers
will not be harmed by a ten-year amortization period.
The Company proposes that the deferred amounts be recorded to FERC Account 182.3,
Other Regulatory Assets, and that the amortization of the deferral be recorded to FERC Account
407.3, Regulatory Debits. Staff concurs with this proposal.
The Company has also requested a carrying charge be applied to the deferral at the
customer deposit rate, and once amortization begins, that a carrying charge at the Commission
approved rate of return be applied to the unamortized balance. Staff proposes that no carrying
charge apply during the deferral period. Once amortization begins, Staff proposes that a carrying
charge be applied to only the capital portion of the unamortized balance at the Company's
overall rate of return.
Staff is opposed to a carrying charge. In this case, Staff is confident that the ability to
defer the costs for future recovery will provide sufficient benefit to the Company over normal
accounting statement without a carrying charge. Additionally, Staff believes that not having a
carrying charge could further incent the Company to minimize costs. If normal ratemaking
treatment was followed, the Company would expense the Operation and Maintenance (O&M)
costs in the year in which they occur, and the capital costs would be booked to plant in service
and depreciation at the Commission approved rates would begin when the plant is placed in
service. In the next general rate case, the prudently incurred ongoing O&M costs would be built
into rates, and the prudently incurred undepreciated capital items would be added to rate base to
STAFF COMMENTS 13 DECEMBER 15, 2016
earn a return. Allowing the Company to defer these costs preserves all the initial costs for future
recovery from customers. Once amortization begins, Staff believes that receiving a carrying
charge only on the capital portion of the deferral balance more closely follows traditional
ratemaking treatment.
Finally, as previously discussed, the Company has requested that the Commission
authorize the Company to recover in a future rate proceeding the estimated incremental costs of
joining the EIM. Because estimated costs can vary, Staff believes prudency review of actual
costs should be determined in a future case. At that time, actual recovery of prudently incurred
costs would be determined.
STAFF RECOMMENDATIONS
Staff recommends that the Commission acknowledge the potential for long-term benefits
associated with the Company's participation in the Energy Imbalance Market. In addition, Staff
recommends the following:
1. The Commission approve an Accounting Order authorizing deferral of incremental
costs associated with participation in the Energy Imbalance Market and for deferrals
to cease by December 2018.
2. The Company utilize the proposed accounts with the incremental EIM costs charged
to Account 182.3 (Other Regulatory Assets) and the amortization charged to Account
407.3 (Regulatory Debits).
3. The Commission authorize an amortization period of ten years.
4. The Commission authorize no carrying charge during deferral.
5. During amortization, the Commission authorize a carrying charge to be applied only
to the capital portion of the unamortized deferral balance at the Company's current
rate of return.
6. The Commission allow recovery of actual costs in a future rate proceeding only after
a thorough review to ensure costs are reasonable and prudently incurred.
STAFF COMMENTS 14 DECEMBER 15, 2016
Respectfully submitted this
Technical Staff: Mike Louis
Terri Carlock
Barbara Romano
Kathy Stockton
Yao Yin
i:umisc/comments/ipce l 6.19bktcmlbryy comments
STAFF COMMENTS
day of December 2016.
15 DECEMBER 15, 2016
Idaho Power Company
EIM Participation
Idaho Jurisdictional Revenue Requirement
RATE BASE 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
1 Electric Plant in Service
2 Intangible Plant 0 0 5,220,884 7,541,278 7,541,278 7,541,278 7,541,278 7,541,278 7,541,278 7,541,278
3 Production Plant 0 0 979,649 1,415,048 1,415,048 1,415,048 1,415,048 1,415,048 1,415,048 1,415,048
4 Total Electric Plant in Service 0 0 6,200,533 8,956,326 8,956,326 8,956,326 8,956,326 8,956,326 8,956,326 8,956,326
5 Less: Accumulated Depreciation 0 0 31,074 75,958 120,841 165,725 210,609 255,493 300,377 345,261
6 Less: Amortization of Other Plant 0 0 745,841 1,823,166 2,900,491 3,977,817 5,055,142 6,132,467 7,209,793 7,541,278
7 Net Electric Plant in Service 0 0 5,423,619 7,057,202 5,934,993 4,812,784 3,690,574 2,568,365 1,446,155 1,069,787
8 Less: Accumulated Deferred Income Taxes 0 0 634,133 1,347,521 1,505,159 1,528,077 1,283,277 903,926 523,310 273,253
9 Add: Conservation -Other Deferred Prag 0 0 0 0 0 0 0 0 0 0
10 TOTAL COMBINED RATE BASE 0 0 4,789,486 5,709,681 4,429,834 3,284,706 2,407,297 1,664,438 922,845 7%,533
NET INCOME
11 Operating Revenues
12 Sales Revenues 0 0 4,134,737 5,512,983 5,512,983 5,512,983 5,512,983 5,512,983 5,512,983 5,512,983
13 Operating Expenses
14 Operation and Maintenance Expenses 373,099 1,165,391 2,379,389 2,800,211 2,846,783 2,894,751 2,944,158 2,995,046 3,047,460 3,101,445
15 Depreciation Expenses 0 0 31,074 44,884 44,884 44,884 44,884 44,884 44,884 44,884
16 Amortization of Limited Term Plant 0 0 745,841 1,077,325 1,077,325 1,077,325 1,077,325 1,077,325 1,077,325 331,485
17 Taxes Other Than Income 0 0 30,684 44,542 44,765 44,989 45,214 45,440 45,667 45,895
18 Provision for Deferred Income Taxes 0 0 1,268,267 158,509 156,768 (110,931) (378,670) (380,031) (381,201) (118,912)
19 Federal Income Taxes (122,358) (382,190) (988,956) 297,090 283,294 505,753 727,775 712,226 696,010 679,116
20 State Income Taxes (23,505) (73,420) 2,563 (8,886) (11,329) 63,240 137,730 134,904 131,929 128,801
21 Total Operating Expenses 227,236 709,781 3,468,859 4,413,675 4,442,490 4,520,011 4,598,416 4,629,794 4,662,073 4,212,714
22 Operating Income (227,236) (709,781) 665,878 1,099,308 1,070,493 992,972 914,567 883,189 850,909 1,300,269
23 Add: IERCO Operating Income 0 0 0 0 0 0 0 0 0 0
24 Consolidated Operating Income (227,236} (709,781) 665,878 1,099,308 1,070,493 992,972 914,567 883,189 850,909 1,300,269
25 Authorized Rate of Return 7.86% 7.86% 7.86% 7.86% 7.86% 7.86% 7.86% 7.86% 7.86% 7.86%
26 Earnings Impact 227,236 709,781 (289,424) (650,527) {722,308) {734,794) (725,354) (752,364) (778,374) {1,237,661)
27 Net-to-Gross Tax Multiplier 1.642 1.642 1.642 1.642 1.642 1.642 1.642 1.642 1.642 1.642
28 Revenue Requirement 373,122 1,165,461 {475,235) (1,068,165) (1,186,030} (1,206,532) (1,191,030} {1,235,381} (1,278,090} (2,032,240)
29 [NPV OF REV REQ IMPACT -10 YRS $ {4,375,102)
n= 1 2 3 4 5 6 7 8 9 10
30 I NPV of REV REQ Impact over n years $ 345,931 $ 1,347,722 $ 968,994 $ 179,777 $ {632,667) $ (1,398,927) $ {2,100,221} $ {2,774,621) $ (3,421,492) $ {4,375,102)
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I.O
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 15TH DAY OF DECEMBER 2016,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF IN
CASE NO. IPC-E-16-19, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
JULIA A HILTON
REGULATORY DOCKETS
IDAHO POWER COMPANY
POBOX70
BOISE ID 83707-0070
E-mail: [e-mail]
[e-mail]
PETER J RICHARDSON
GREGORY MADAMS
RICHARDSON ADAMS PLLC
PO BOX 7218
BOISE ID 83 702
E-mail: [e-mail]
[e-mail]
KEN MILLER
SNAKE RIVER ALLIANCE
223 N 6TH ST STE 317
PO BOX 1731
BOISE ID 83701
E-mail: [e-mail]
MATT LARKIN
IDAHO POWER COMPANY
POBOX70
BOISE ID 83707-0070
E-mail: [e-mail]
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-mail: [e-mail]
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
710 N 6TH STREET
BOISE ID 83702
E-mail: [e-mail]
SECRETARY
CERTIFICATE OF SERVICE