20160819Anderson Direct.pdf

PECEIVED
'.!QI C.A\1r.19 Pl 4:53 ,. IO .1 J ,)
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
DEFERRAL AND RECOVERY OF COSTS
ASSOCIATED WITH PARTICIPATION
IN THE ENERGY IMBALANCE MARKET.
CASE NO. IPC-E-16-19
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
KATHLEEN ANDERSON
1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company") .
A. My name is Kathleen Anderson. My business 4
5 address is 1221 West Idaho Street, Boise, Idaho 83702. I
6 am employed by Idaho Power as the Transmission and Energy
7 Scheduling Leader in the Load Serving Operations
8 Department.
9
10
Q.
A.
Please describe your educational background.
In December of 2000, I received a Bachelor of
11 Administration degree in Finance from Boise State
12 University in Boise, Idaho. In September of 2005, I earned
13 a Master of Business Administration degree from the
14 University of Phoenix.
15 Q. Please describe your work experience with
16 Idaho Power.
17 A. In 2005, I was hired as a Business Analyst in
18 Idaho Power's Delivery Finance Department. My primary
19 responsibilities included reviewing and granting credit to
20 entities wishing to conduct business under the Company's
21 Open Access Transmission Tariff ("OATT"). In addition, I
22 provided analyst support to the Company's Grid Operations
23 Department, assisting with budgeting and other financial
24 and accounting duties. In 2006, I transferred to the Grid
25 Operations Department as an Operations Analyst and was
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Idaho Power Company
1 responsible for all contractual obligations of the
2 Company's OATT. In 2009, I became the System Operations
3 Leader in the Grid Operations Department and oversaw all
4 day-ahead and real-time activity conducted under the OATT,
5 as well as all transmission contracts administered by the
6 Grid Operations and Load Serving Operations Departments.
7 In 2015, I was promoted to the Transmission and Energy
8 Scheduling Leader where, in addition to my current duties,
9 I assumed the oversight responsibility of the day-ahead
10 balancing operators.
11 Q. What is the purpose of your testimony in this
12 case?
13 A. My testimony in this case will describe an
14 Energy Imbalance Market ( "EIM") and the costs and benefits
15 associated with Idaho Power's participation in the western
16 EIM.
17
18
19
Q.
A.
I. ENERGY IMBALANCE MARKET
Please describe an energy market.
An energy market facilitates the bilateral
20 trading of energy between two parties by matching
21 generation with load to maintain frequency of the grid.
22 Purchases and sales, or trades, are typically executed for
23 the mid-term (month or week), near-term (day), hour-ahead
24 (next few hours), or real-time (current operating hour) and
25
ANDERSON, DI 2
Idaho Power Company
1 can be traded in blocks of 24 hours, heavy load (16 hours),
2 or light load (8 hours).
What is an energy imbalance? 3
4
5
Q.
A. Simply put, when the supply of energy does not
equal the demand, energy imbalance occurs. Deviations in
6 supply and demand occur in every hour, resulting in a
7 mismatch between available electricity versus what is
8 needed by consumers. To manage these energy imbalances
9 within its Balancing Area ("BA"), Idaho Power relies on
10 dispatches of internal resources and extra reserves.
11 Q. Are there other ways of solving energy
12 imbalance?
13 A. Yes. In addition to managing imbalances
14 within the Company's BA, Idaho Power has the opportunity to
15 participate in an EIM and use neighboring grids and
16 resources to help balance supply and demand more
17 efficiently and cost-effectively.
Please describe an EIM. 18
19
Q.
A. An EIM solves sub-hourly imbalances through an
20 automated five-minute energy dispatch service across a
21 broader footprint with more deployable resources available,
22 providing a more efficient method for maintaining balance.
23 It allows participants to buy and sell power closer to when
24 the electricity is consumed, in increments as small as
25 every five minutes, and allows system operators real-time
ANDERSON, DI 3
Idaho Power Company
1 visibility across neighboring grids, strengthening grid
2 reliability.
Q. How does an EIM operate? 3
4 A. All BAs begin the hour with matched generation
5 and forecasted load. As imbalances occur within the hour,
6 resources within the EIM area can voluntarily provide bids
7 to dispatch their facilities to manage these imbalances.
8 The market operator of the EIM will automatically look
9 across the expanded EIM region to determine the least-cost
10 dispatch order and issue an operating target for each
11 participating resource, resulting in the most economical
12 bids available to meet these imbalances. The real-time
13 optimization process determines the least-cost mix of
14 resources and dispatches them to resolve these imbalances
15 while also respecting limits on the transmission system to
16 alleviate overloads or congestion.
17 Q. Does Idaho Power have the option of
18 participating in an EIM?
19
20
A. Yes, Idaho Power has the option of
participating in the western EIM. Idaho Power's BA is
21 connected to PacifiCorp East and West and NV Energy, Inc.'s
22 BAs, all of whom participate in and provide a direct tie to
23 the western EIM.
24
25
ANDERSON, DI 4
Idaho Power Company
1 Q. Are there any other organized markets Idaho
2 Power could participate in that perform the same or a
3 similar function as the western EIM?
4 A. No , not adjacent to the Company's BA . Idaho
5 Power is a member of the Northwest Power Pool , which was
6 attempting to form a voluntary generation dispatch market
7 in the region but ended that initiative when a number of
8 its members instead joined the western EIM . None of the
9 other organized markets provide a direct tie to Idaho
10 Power 's BA.
11 Q. Could Idaho Power maintain its current
12 practice for solving energy imbalance?
13 A. Yes , Idaho Power could continue to dispatch
14 resources from within its BA and continue to carry
15 additional reserves to manage energy imbalances . However,
16 this approach restricts the available generation resources
17 for other purposes , potentially resulting in higher costs
18 for customers relative to EIM participation. In addition ,
1 9 the Company is at the limits of system integration
20 capabilities given the proliferation of existing
21 intermittent Public Utility Regulatory Policies Act of 19 78
22 (PURPA) wind and anticipated solar generation beginning in
23 2016 , making the current self-management of energy
24 imbalance even more complex .
25
ANDERSON , DI 5
Idaho Power Company
1 Q. How does continuing to carry additional
2 reserves restrict the available resources for other
3 purposes?
4 A. Carrying additional reserves to manage energy
5 imbalance restricts the available resources for purposes
6 such as serving load with potentially lower-cost resources
7 or bilateral off-system energy sales. As the number of
8 western EIM participants grows, the potential for Idaho
9 Power to transact bilaterally decreases in real time as the
10 Company moves closer to each operating hour. Consequently,
11 Idaho Power must carry additional reserves or procure
12 energy to reliably meet load. Prior to the advent of the
13 western EIM, Idaho Power typically had the ability to
14 procure energy for reserves 40 minutes from the start of
15 the next operating hour. As more participants have entered
16 the western EIM, fewer resources are available for Idaho
17 Power's energy imbalance management, resulting in decreased
18 liquidity in the real-time market for up to two hours prior
19 to the next operating hour time horizon.
20 Q. What is the impact of decreased bilateral
21 liquidity on Idaho Power's operations?
22 A. The further away from the operating hour the
23 balancing is completed, the less accurate the forecast,
24 resulting in an increase in regulatory-required reserves
25 held by the BA due to the uncertainty. The outcome of the
ANDERSON, DI 6
Idaho Power Company
1 increase in purchases and decrease in off-system sales is
2 increased Net Power Supply Expense ("NPSE") for customers.
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4
Q.
A.
Please describe the western EIM.
The western EIM is a voluntary energy
5 imbalance market service that was implemented by the
6 California Independent System Operator ("CAISO") and
7 PacifiCorp on November 1, 2014. Since then, NV Energy,
8 Inc., entered the market and both Puget Sound Energy and
9 Arizona Public Service Company will enter on October 1,
10 2016. As the market operator, CAISO has opened its
11 advanced market systems by extending its existing
12 infrastructure, offering EIM services to other BAs. The
13 western EIM allows other participants to leverage the
14 benefits of real-time balancing while also maintaining all
15 of their existing authority.
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17
Q.
A.
Who governs the western EIM?
When the western EIM was established, it was
18 managed by CAISO's Board of Governors ("CAISO Board").
19 However, as the number of EIM entities grew, the need for
20 an EIM governing board became apparent. Effective July 1,
21 2016, the CASIO Board appointed five members to the newly
22 created EIM Governing Body who are financially independent
23 from market participants and selected by a nominating
24 committee made up of representatives from the following
25 sectors: EIM entities, participating transmission owners,
ANDERSON, DI 7
Idaho Power Company
1 suppliers and marketers of generation , publicly-owned
2 utilities , the body of state regulators , the EIM
3 Transitional Committee , the ISO Board of Governors, and
4 public interest and consumer advocate groups . Although the
5 CAISO Board approved the initial five members, Governing
6 Body members will approve future nominations . The EIM
7 Governing Body will have delegated authority over the
8 western EIM market rules .
9 In addition , the governance structure established an
10 advisory body comprised of regulators in states that
11 participate in the real-time market , creating a periodic
12 stakeholder forum to discuss regional issues. In addition
13 to the EIM Governing Body, CAISO and all EIM participants
14 are required to include as part of their Federal Energy
15 Regulatory Commission ("FERC") filed OATT an attachment
16 that incorporates the general provisions , roles and
17 responsibilities , operations , and compliance details
18 specific to participation in an EIM. Public utilities
19 defined under the Federal Power Act have the authority to
20 provide transmission services under their OATT . Further ,
21 the Energy Policy Act of 2005 granted FERC increased
22 statutory authority to implement mandatory transmission and
23 network reliability standards , as well as enhanced
24 oversight of power and transmission markets. FERC provides
25 jurisdiction over the sale of transmission capacity and
ANDERSON , DI 8
Idaho Power Company
1 wholesale electricity and regulates transmission services
2 provided under a utility's OATT, including participation in
3 an EIM when applicable.
4 Q. Does FERC require any other filings prior to
5 entering into an EIM?
6
7
A. Yes . Idaho Power currently has market-based
rate authority for transactions in its BA. FERC grants
8 market -based rate authority to sellers who demonstrate they
9 lack or have adequately mitigated horizonta l and vertical
10 market power, approving the seller's market-based rate
11 tariff. Absent market-based rate authority, an energy
12 seller must bid resources into the market at the determined
13 default energy bid. As a participant in the EIM, Idaho
14 Power would be required to file a request with FERC to
15 evaluate whether it has market-based rate authority in the
16 EIM market. FERC will determine if Idaho Power's market
17 rates are just and reasonable and if it can charge market-
18 based rates for energy sale transactions in the EIM market.
19 Q. Would Idaho Power be impacted if the Company
20 does not obtain market-based rate authority within the
21 western EIM?
22 A. If FERC determined Idaho Power had market
23 power and did not obtain market-based rate authority, it
24 would not have a material impact to Idaho Power's
25 customers. Instead, the Company would bid resources in the
ANDERSON, DI 9
Idaho Power Company
1 market at the determined default energy bid for that
2 resource. But, as a participant, a utility is paid the
3 settled market price for the energy bid into the market
4 whether it operates under market-based rate authority or a
5 default energy bid.
6 Q. As a participant in the western EIM, does a
7 utility lose autonomy over its generating resources?
8 A. No. EIM participants maintain operational
9 control over their generating resources, retain all their
10 obligations as a BA, and must still comply with all
11 regional and national reliability standards. Also, BAs
12 remain responsible for procurement or self-provision of
13 reserves and other ancillary services and participation in
14 the western EIM does not change North American Electric
15 Reliability Corporation and Western Electricity
16 Coordinating Council responsibilities for resource
17 adequacy, reserves, or other BA reliability-based functions
18 for a utility.
19 Q. You stated that participation in the western
20 EIM may potentially lower power supply costs due to an
21 expected reduction in the need for reserves and increased
22 efficiency of the transmission system. Are there other
23 benefits the western EIM can provide its participants?
24 A. Yes, the western EIM helps participants by
25 utilizing all resources within the EIM footprint and helps
ANDERSON, DI 10
Idaho Power Company
1 mitigate the intermittent nature of renewable energy. For
2 example, if a utility is generating excess solar, rather
3 than backing down its own baseload resources, the market
4 operator can use that western EIM participant's output to
5 serve customers in other participants' service territories
6 and vice versa, allowing the use of a reduced carbon
7 emission resource valued at the market price.
8 In addition, western EIM participants enhance
9 reliability for customers through broader visibility across
10 grids and with better planning and management of
11 congestions across more of the region's transmission
12 system. Currently, Idaho Power experiences significant
13 congestion on the Northwest to Idaho path during the late
14 spring through summer operational periods. This congestion
15 is often the result of unscheduled flow on the system.
16 When flows on the path are high, Idaho Power must sometimes
17 curtail energy scheduled on that path to maintain system
18 reliability. Curtailing of energy purchases made by Idaho
19 Power for load service to its customers can increase NPSE
20 as a higher cost resource may be required to serve
21 customers. In an EIM, resources are dispatched such that
22 congestion on transmission paths is reduced while also not
23 dispatching resources into already congested areas,
24 providing enhanced reliability and minimizing curtailments
25 of energy scheduled on those paths. Because participants
ANDERSON, DI 11
Idaho Power Company
1 are required to enter the operating horizon balanced, the
2 resources utilized to meet imbalances are dispatched to
3 avoid constraints, potentially providing additional
4 operating benefits to customers.
5 Q. You indicated the western EIM is expected to
6 provide cost savings to CAISO and four other utilities,
7 benefiting consumers in eight western states. Would the
8 addition of participants in the western EIM hinder the cost
9 savings existing participants are experiencing?
10 A. No. The CAISO approach is scalable, meaning
11 that new entities can be added incrementally when they are
12 ready, bringing benefits to both new customers and existing
13 customers of the western EIM.
14 Q. How does added participation bring benefits to
15 participants of the western EIM?
16 A. As fluctuations in supply and demand occur,
17 the market system will automatically find the best resource
18 from across the larger region to meet immediate power
19 needs. This activity optimizes the interconnected high-
20 voltage system as market systems automatically manage
21 congestion on transmission lines, helping maintain
22 reliability while also supporting the integration of
23 intermittent renewable resources and avoiding curtailing
24 excess supply by sending it to where demand can use it.
25
ANDERSON, DI 12
Idaho Power Company
1 The wider the geographic area, the better the benefits
2 participants of the western EIM are expected to receive.
3 Q. As of October 1, 2016, the western EIM
4 participants will include PacifiCorp, NV Energy, Inc.,
5 Puget Sound Energy, and Arizona Public Service Company.
6 Are there any other utilities that have announced plans to
7 join the western EIM?
8 A. Yes. Portland General Electric Company
9 announced its participation with operations expected to
10 begin in October 2017 and, contingent upon necessary
11 regulatory approvals, Idaho Power has signed an
12 implementation agreement with CAISO ("Agreementu), bringing
13 the total to six utility participants in addition to CAISO
14 and its participants, while several others are currently
15 exploring participation in the market. A copy of the
16 Agreement is provided as Exhibit No. 3. Under the
17 Agreement, CAISO will provide energy imbalance services to
18 Idaho Power by extending and modifying its existing real-
19 time market system effective April 2018. On June 28, 2016,
20 FERC accepted the Agreement for filing.
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22
II. IDAHO POWER'S PARTICIPATION IN THE WESTERN EIM
Q. Please explain Idaho Power's decision to enter
23 into the Agreement with CAISO for participation in the
24 western EIM.
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ANDERSON, DI 13
Idaho Power Company
1 A. Idaho Power's decision to enter into the
2 Agreement was based on the results of a benefits study that
3 indicated participation in the western EIM real-time energy
4 market could result in efficiencies that translate into
5 NPSE savings for the Company's customers. Idaho Power's
6 customers are expected to see benefits from the market,
7 including lower NPSEs, better visibility for system
8 operations in the Western Interconnection, and improved
9 integration of intermittent renewable resources.
10 Q. Please describe the benefits study performed
11 for Idaho Power.
12 A. In the fall of 2015, Idaho Power engaged
13 Energy and Environmental Economics, Inc. ("E3") to perform
14 an economic benefits study of Idaho Power's participation
15 in the western EIM. The study, Idaho Power Company Energy
16 Imbalance Market Analysis, is included as Exhibit No. 4 to
17 my testimony. The focus of the analysis performed was to
18 provide consistent, conservative estimates of NPSE savings
19 to Idaho Power to be used for evaluation of participation
20 in the EIM. To do so, E3 used a production simulation
21 model that compared the Company's real-time generation
22 costs as an EIM participant, as well as any power supply
23 related revenues or costs from transactions with other EIM
24 participants, against a scenario in which Idaho Power was
25
ANDERSON, DI 14
Idaho Power Company
1 not a participant in the western EIM , or a business as
2 usual case .
3 Q. How does a production simulation model
4 estimate economic benefits for a utility?
5 A. E3 used PLEXOS , a sub-hourly production cost
6 model that simulates bulk power system operations by
7 minimizing the variable cost of operating the system
8 subject to a number of constraints . For Idaho Power 's
9 participation , the software simulated sub-hourly operations
10 in the Western Interconnection for the year 2020 and
11 assumed seven western EIM participants , those that are
12 either currently part i cipating in or who have announced
13 plans to join the western EIM . PLEXOS uses a three -stage
14 sequential simulation process to model day-ahead , hour-
15 ahead , and real -time operations to represent the different
16 time horizons of actual power system operations .
17 To quantify sub-hourly dispatch savings from I daho
18 Power 's participation in the western EIM, E3 first ran a
19 real -time business as usual case that held energy transfers
20 between non-participating BAs (including Idaho Power) equal
21 to the scheduled levels from the hour -ahead simulation .
22 The business as usual run also allowed the western EIM
23 participants to transact with other EIM participating BAs
24 in the same real -time market , subject to transmission
25 transfer limits , in order to replicate a scenario that
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Idaho Power Company
1 would exist if Idaho Power was not a participant of the
2 western EIM. Next, E3 took the results from the business
3 as usual case and allowed the Company to transact power
4 within the hour with other western EIM participants. The
5 difference between the two scenarios resulted in western
6 EIM-wide savings due to increased flexibility and decreased
7 real-time production costs for the region ("Base
8 Scenariou). E3 then divided the benefits between Idaho
9 Power and the other western EIM participants based on the
10 change in their generation costs and their net purchases
11 and sales in real time through the western EIM.
12 Q. Does E3's analysis assume Idaho Power will
13 obtain its market-based rates as a participant in the
14 western EIM?
15 A. As described earlier in my testimony, a
16 utility is paid the market price for its generation bid
17 into the market whether it operates under market-based rate
18 authority or a default energy bid. The benefits analysis
19 performed by E3 values energy at the estimated cost of
20 production as determined by the utility, using a
21 conservative approach to estimate the cost of production
22 that would apply under either scenario.
23 Q.
24 Base Scenario.
25
Please describe the assumptions used in the
ANDERSON, DI 16
Idaho Power Company
1 A. The Base Scenario described above included
2 renewable resource development to meet current Renewable
3 Portfolio Standards ("RPSu) and projected renewable build
4 out for 2020 . It assumed a 33 percent RPS for Cal ifornia ,
5 a 15 percent renewable penetration for Idaho Power, and an
6 average 15 percent renewable share for other Northwest BAs.
7 Q. Were any additional scenarios analyzed besides
8 the Base Scenario?
9 A. Yes. E3 ran three alternative scenarios that
10 assume (1) Arizona Public Service Company and Portland
11 General Electric Company have not joined the EIM by 2020;
12 (2) the following early coal retirements: Va lmy 1, Valmy
13 2, Reid Gardner 4, Navajo 1, San Juan 2 , and San Juan 3
14 ("Early Coal Retirement Scenariou); and (3) a higher
15 renewable penetration in the west, including a 40 percent
16 RPS for California , a 20 percent renewable penetration for
17 Idaho Power, and an average 20 percent renewable share for
1 8 other Northwest non-western EIM participants' BAs (High RPS
19 Scenario).
20 Q. What are the NPSE savings that resulted from
21 each scenario?
22 A. The Base Scenario resulted in sub-hourly
23 dispatch cost savings for Idaho Power's participation in
24 the western EIM of $4.5 million per year, while the
25 alternative scenarios resulted in a range of estimated
ANDERSON, DI 17
Idaho Power Company
1 savings per year between $4 .1 and $5 .1 million. More
2 detail on each scenario can be found in Exhibit No. 4 to my
3 testimony.
4 Q. You mentioned that in addition to lower costs,
5 participation in the western EIM may reduce the need to
6 hold additional flexible reserves and result in a more
7 efficient use of the transmission system, enhancing
8 reliability. Has E3 quantified the savings that would
9 result from those added benefits?
10 A. No . The study does not quantify any potential
11 customer reliability benefits from western EIM
12 participation, which are difficult to quantify but may be
13 substantial if participation ultimately assists
14 participants in avoiding a major outage for customers , nor
15 does it quantify savings arising from the flexibility
16 reserve reductions , which could further reduce NPSE .
17 Q. How will Idaho Power quantify and demonstrate
18 the benefits achieved as a participant in the western EIM?
19 A . On a quarterly basis , CAISO releases its
20 Quantifying EIM Benefits report that quantifies the
21 estimated gross benefits achieved by western EIM
22 participants for the previous calendar quarter . The
23 methodology used to estimate quarterly benefits is
24 described in CAISO 's EIM Quarterly Benefit Report
25
ANDERSON , DI 18
Idaho Power Company
1 Methodology document , included as Exhibit No . 5 to my
2 testimony.
3 Q. Please describe the methodology CAISO uses to
4 estimate quarterly benefits .
5 A. CAISO determines the total EIM benefit by
6 calculating the cost savings of the EIM dispatch as
7 compared to a counterfactual without EIM dispatch . The
8 counterfactual dispatch meets the real -time load imbalance
9 in each BA without allowing for transfers among neighboring
10 EIM BAs. Exhibit No. 5 to my testimony describes in detail
11 the methodology used each quarter to estimate participant
12 benefits .
13 Q. What is included in the quarterly Quantifying
14 EIM Benefits report provided to participants by CAISO?
15 A . The quarterly report quantifying EIM benefits
16 includes the estimated gross benefits by EIM participant
17 and quarter. The report also describes any significant
18 contributions to the EIM benefits that were experienced by
19 participants . Included as Exhibit No . 6 to my testimony is
20 CAISO 's 2016 quarter two report , dated July 28, 2016 . As
21 can be seen in the report , the western EIM benefits for the
22 second quarter of 2016 are estimated to be $23 .60 million ,
23 bringing the total benefits to $88.19 million since
24 expansion of the rea l-time market to BAs outside of CAISO.
25 As a participant in the western EIM, Idaho Power's benefits
ANDERSON, DI 19
Idaho Power Company
1 would be calculated and identified in CAISO's quarterly
2 report.
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6
III. COSTS ASSOCIATED WITH IDAHO POWER'S PARTICIPATION
IN THE WESTERN EIM
Q. Are there any costs associated with
7 participation in the western EIM?
8 A. Yes, participation in the western EIM will
9 require both upfront and ongoing incremental costs,
10 software integration costs, and metering investments.
11
12
Q.
A.
Please describe the incremental costs.
Under the Agreement with CAISO, the Company is
13 required to pay a fixed implementation fee totaling
14 $540,000, subject to completion of six specific milestones,
15 to compensate for costs attributable to CAISO's effort to
16 configure its real-time market systems to incorporate Idaho
17 Power into the western EIM. The implementation fee is
18 comprised of six $90,000 payments that coincide with
19 CAISO's project milestones that will occur between the time
20 the Agreement was signed and the time Idaho Power becomes
21 an active participant in the western EIM. In addition to
22 the implementation fee, the Company anticipates start-up
23 costs associated with the issuance of a Request for
24 Information/Proposal, outside consulting and legal counsel,
25 and the hiring of six full-time employees dedicated
26 entirely to upfront and ongoing EIM activities. Idaho
ANDERSON, DI 2 0
Idaho Power Company
1 Power anticipates approximately $1.73 million in upfront
2 incremental costs prior to an April 2018 western EIM
3 entrance date.
4 Q. What software integration costs result from
5 participation in the western EIM?
6 A. Software integration costs represent more than
7 half of the expected capital costs as participation in the
8 western EIM will require software and system interfaces
9 that allow for transacting with CAISO. Because Idaho Power
10 does not have sufficient internal expertise with the CAISO
11 market, the Company has engaged a system integrator that
12 will provide consulting services throughout the integration
13 process. In addition to the costs of utilizing a system
14 integrator, Idaho Power will be required to procure a bid-
15 to-bill system, which is anticipated to be a hosted
16 solution. The bid-to-bill system will allow submission of
17 offers into the market as well as the use and receipt of
18 large amounts of data required for the purpose of energy
19 settlements.
20 Q. How much does Idaho Power estimate it will
21 spend on software integration to enable the Company to
22 participate in the western EIM?
23 A. Idaho Power anticipates spending approximately
24 $7.88 million on software integration.
25
ANDERSON, DI 21
Idaho Power Company
1 Q. Please describe the investments in metering
2 equipment the Company will be required to make prior to
3 participation in the western EIM.
4 A. The majority of the meters on Idaho Power's
5 generating units cannot provide the data granularity that
6 will be required for CAISO settlement purposes. The
7 Company will examine all existing meters and determine
8 whether or not they meet CAISO's requirement for providing
9 five-minute, 15-minute, or 60-minute data and update as
10 necessary. In addition, Idaho Power has identified a few
11 instrument transformers feeding these generation meters and
12 some instrument transformers at several power plant
13 locations that are not revenue quality and will need to be
14 replaced.
15 Q. Will revenue quality meters be required on
16 generation units that Idaho Power chooses not to be
17 available for dispatch in the western EIM?
18 A. Yes. Even though Idaho Power will identify
19 which Company-owned generating units will be considered
20 participating units and available for dispatch in the
21 market and which will be non-participating units, CAISO
22 requires that both are able to provide interval data but at
23 different levels of granularity.
24 Q. What is the Company's estimate of the total
25 costs of all required metering investments?
ANDERSON, DI 22
Idaho Power Company
1 A. Idaho Power estimates investing approximately
2 $1.48 million in required metering equipment for
3 participation in the western EIM.
4 Q. Does the benefits study performed by E3 factor
5 in the costs Idaho Power expects to incur as a participant
6 in the western EIM?
7 A. No. Company witness Mr. Tatum has performed a
8 revenue requirement analysis that describes the net impact
9 of the upfront and ongoing costs and NPSE benefits
10 associated with participation in the western EIM and the
11 Company's proposed accounting treatment of those costs.
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Q.
A.
IV. CONCLUSION
Please summarize your testimony.
Idaho Power currently manages energy
15 imbalances within its BA. However, participation in the
16 western EIM to manage supply and demand could result in
17 lower costs due to the reduction in the need for reserves
18 and the efficient use of the transmission system, while
19 also helping to reduce carbon emissions and more
20 efficiently use and integrate intermittent renewable
21 energy. Absent Idaho Power's participation in the western
22 EIM, market liquidity in the bilateral real-time market
23 will likely continue to decline and additional reserves
24 will likely need to be maintained, resulting in increased
25 NPSE for the Company's customers. It is estimated that
ANDERSON, DI 23
Idaho Power Company
----------------------------------·-------·--·----···---
1 Idaho Power's participation in the western EIM would result
2 in sub-hourly dispatch cost savings of $4 .1-$5 .1 million
3 per year, resulting in a lower-priced energy imbalance
4 management option .
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A.
Does this complete your testimony?
Yes, it does .
ANDERSON, DI 24
Idaho Power Company
1 ATTESTATION OF TESTIMONY
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4 ss .
5 County of Ada
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I, Kathleen Anderson , having been duly sworn to
testify truthfully , and based upon my personal knowledge ,
state the following:
I am employed by Idaho Power Company as the
Transmission and Energy Scheduling Leader in the Load
Serving Operations Department and am competent to be a
witness in this proceeding.
I declare under penalty of perjury of the laws of
the state of Idaho that the foregoing pre-filed testimony
and exhibits are true and correct to the best of my
information and belief .
DATED this 19th day of August 2016.
,cwi----
Kathleen Anderson
23 SUBSCRIBED AND SWORN to before me this 19th day of
24 August 2016.
25
26
27
28
29
Notary
Residing at : Boise , Idaho
My commission expires : 02/04/2021
ANDERSON , DI 25
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION .
CASE NO. IPC-E-16-19
IDAHO POWER COMPANY
ANDERSON, DI
TESTIMONY
EXHIBIT NO. 3
ENERGY IMBALANCE MARKET
IMPLEMENTATION AGREEMENT
This Implementation Agreement ("Agreement") is entered into as of April 6, 2016, by
and between Idaho Power Company, an Idaho corporation ("IPCO"), and the California
Independent System Operator Corporation, a California nonprofit public benefit
corporation ("ISO"). IPCO and the ISO are sometimes referred to in the Agreement
individually as a "Party" and, collectively, as the "Parties."
RECITALS
A. WHEREAS, IPCO has determined there is an opportunity to secure benefits for
IPCO's customers through improved dispatch and operation of IPCO's generation fleet
and through the efficient use and continued reliable operation of existing and future
transmission facilities and desires to participate in the energy imbalance market
operated by the ISO ("EIM");
B. WHEREAS, the ISO has determined there are benefits to ISO market
participants through greater access to energy imbalance resources in real-time and
through the efficient use and reliable operation of the transmission facilities and markets
operated by the ISO, and desires to expand operation of the EIM to include IPCO;
C. WHEREAS, IPCO acknowledges that the rules and procedures governing the
EIM are set forth in the provisions of the ISO tariff as filed with the Federal Energy
Regulatory Commission ("FERC") and that participation in the EIM requires
corresponding revisions to IPCO's Open Access Transmission Tariff ("IPCO Tariff") and
the execution of associated service agreements; and
D. WHEREAS, the Parties are entering into this Agreement to set forth the terms
upon which the ISO will timely configure its systems to incorporate IPCO into the EIM
("Project") on or before April 1, 2018 (" Implementation Date").
NOW THEREFORE, in consideration of the mutual covenants contained herein, and of
other good and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the Parties agree as follows:
AGREEMENT
1. Effective Date and Term .
(a) This Agreement shall become effective upon the date the Agreement is
accepted, approved or otherwise permitted to take effect by FERC, without condition or
modification unsatisfactory to either Party ("Effective Date").
(b) In the event FERC requires any modification to the Agreement or imposes
any other condition upon its acceptance or approval of the Agreement, each Party shall
have ten (10) days to notify the other Party that any such modification or condition is
1 Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson , IPC
Page 1 of 17
unacceptable to that Party. If no Party provides such notice, then the Agreement, as
modified or conditioned by FERC, shall take effect as of the date determined under
Section 1 (a). If either Party provides such notice to the other Party, the Parties shall
take any one or more of the following actions: (i) meet and confer and agree to accept
any modifications or conditions imposed by such FERC order; (ii) jointly seek further
administrative or legal remedies with respect to such FERC order, including a request
for rehearing or clarification; or (iii) enter into negotiations with respect to
accommodation of such FERC order, provided however, if the Parties have not agreed
to such an accommodation within thirty (30) days after the date on which such FERC
order becomes a final and non-appealable order, such order shall be deemed an
adverse order and the Parties shall have no further rights and obligations under the
Agreement.
(c) The term of the Agreement ("Term") shall commence on the Effective Date
and shall terminate upon the earliest to occur of (1) the date FERC permits all
necessary revisions to the IPCO Tariff to take effect and the service agreements under
such tariff and the ISO tariff necessary for the commencement of IPCO's participation in
the EIM have taken effect; (2) termination in accordance with Section 2 of this
Agreement; or (3) such other date as mutually agreed to by the Parties (''Termination
Date").
(d) This Agreement shall automatically terminate on the Termination Date and
shall have no further force or effect, provided that the rights and obligations set forth in
Sections 5 and 6 shall survive the termination of this Agreement and remain in full force
and effect as provided therein.
2. Termination.
(a) The Parties may mutually agree to terminate this Agreement in writing at
any time. In addition, either Party may terminate this Agreement in its sole discretion
after conclusion of the negotiation period in Section 2(b) or as provided in Section 2(d)
or 2(e) as applicable.
(b) If either the ISO or IPCO seeks to unilaterally terminate this Agreement, it
must first notify the other Party in writing of its intent to do so ("Notice of Intent to
Terminate") and engage in thirty (30) days of good faith negotiations in an effort to
resolve its concerns. If the Parties successfully resolve the concerns of the Party
issuing the Notice of Intent to Terminate, the Party that issued such notice shall notify
the other Party in writing of the withdrawal of such Notice ("Notice of Resolution").
(c) At the time the Notice of Intent to Terminate is provided, or any time
thereafter unless a Notice of Resolution is issued, IPCO may provide written notice
directing the ISO to suspend performance on any or all work on the Project for a
specified period of time ("Notice to Suspend Work"). Upon receipt of a Notice to
Suspend Work, the ISO shall: (1) discontinue work on the Project; (2) place no further
orders with subcontractors related to the Project; (3) take commercially reasonable
actions to suspend all orders and subcontracts; (4) protect and maintain the work on the
2
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 2 of 17
Project; and (5) otherwise mitigate IPCO's costs and liabilities for the areas of work
suspended. The ISO will not invoice IPCO pursuant to Section 4(c) of this Agreement
for any milestone payment following the issuance of a Notice to Suspend Work. To the
extent a Notice of Resolution is issued pursuant to Section 2(b), the Notice to Suspend
Work in effect at the time shall be deemed withdrawn and the ISO shall be entitled to
invoice IPCO for any milestone completed as specified in Section 4(c) of this Agreement
and IPCO shall pay such invoice pursuant to Section 4.
(d) Any time after thirty (30) days from the date of the Notice of Intent to
Terminate under Section 2(b), issued by either Party, and prior to the date of a Notice of
Resolution, the ISO may terminate this Agreement by providing written notice to IPCO
that it is terminating this Agreement (''Termination Notice") effective immediately. The
ISO may terminate this Agreement under the terms of this Section 2(d) at its sole
discretion for any reason.
(e) Any time after 30 days from the date of the Notice of Intent to Terminate
under Section 2(b), issued by either Party, and prior to the date of a Notice of
Resolution, IPCO may terminate this Agreement by providing written notice to the ISO
that it is terminating this Agreement ("Termination Notice") effective immediately. IPCO
may terminate this Agreement under the terms of this Section 2(e) at its sole discretion
for any reason.
(f) In the event this Agreement is terminated by either or both of the Parties
pursuant to its terms, this Agreement will become wholly void and of no further force
and effect, without further action by either Party, and the liabilities and obligations of the
Parties hereunder will terminate, and each Party shall be fully released and discharged
from any liability or obligation under or resulting from this Agreement as of the date of
the Termination Notice provided in Section 2(d) or 2(e), as applicable, notwithstanding
the requirement for the ISO to submit the filing specified in Section 2(g).
Notwithstanding the foregoing, the rights and obligations set forth in Sections 5 and 6
shall survive the termination of this Agreement and remain in full force and effect as
specified in Sections 5 and 6, and any milestone payment obligation pursuant to Section
4(c) that arose prior to the Termination Notice in accordance with Section 2(d) or 2(e)
shall survive until satisfied or resolved in accordance with Section 11.
(g) The Parties acknowledge that the ISO is required to file a timely notice of
termination with FERC. The Parties acknowledge and agree that the filing of the notice
of termination by the ISO with FERC will be considered timely if the filing of the notice of
termination is made after the preconditions for termination have been met, and the ISO
files the notice of termination within ten (10) days after the Termination Notice has been
provided by either the ISO in accordance with Section 2(d) or IPCO in accordance with
Section 2(e). This Agreement shall terminate upon acceptance by FERC of such a
notice of termination.
3
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 3 of 17
3. Implementation Scope and Schedule.
(a) The Parties shall complete the Project as described in Exhibit A, subject to
modification only as described in Section 4(e) below.
(b) The Parties shall undertake the activities described in Exhibit A with the
objective of completing the Project and implementing the EIM no later than the
Implementation Date, including all milestones listed under Exhibit A for the
Implementation Date, subject to modification only as described in Section 3(c) below.
(c) Either Party may propose a change in Exhibit A or the Implementation
Date to the other Party. If a Party proposes a change in Exhibit A or the Implementation
Date, the Parties shall negotiate in good faith to attempt to reach agreement on the
proposal and any necessary changes in Exhibit A and any other affected provision of
this Agreement, provided that any change in Exhibit A, or any change to the
Implementation Date, must be mutually agreed to by the Parties. The agreement of the
Parties to a change in Exhibit A, or a change to the Implementation Date, shall be
memorialized in a revision to Exhibit A, which will then be binding on the Parties and
shall be posted on the internet web sites of the ISO and IPCO, without the need for
execution of an amendment to this Agreement. Changes that require revision of any
provision of this Agreement other than Exhibit A shall be reflected in an executed
amendment to this Agreement and filed with FERC for acceptance.
(d) At least once per calendar month during the Term, the Parties' Designated
Executives, or their designees, will meet telephonically or in person (at a mutually
agreed to location) to discuss the status of the performance of the tasks necessary to
achieve the milestones in Exhibit A and the continued appropriateness of Exhibit A to
ensure that the Project can meet the Implementation Date. For purposes of this
section, "Designated Executive" shall mean the individual identified in Section 8(g), or
her or his designee or successor.
4. Implementation Charges, Invoicing and Milestone Payments.
(a) As itemized in Section 4(c) below, IPCO shall pay the ISO a fixed fee of
$540,000 for costs incurred by the ISO to implement the Project ("Implementation Fee"),
subject to completion of the milestones specified in Section 4(c) and subject to
adjustment only as described in Section 4(b).
(b) The ISO will provide prompt written notice to IPCO when the sum of its
actual costs through the date of such notice and its projected costs to accomplish the
balance of the Project exceed the Implementation Fee. The Implementation Fee shall
be subject to adjustment only by mutual agreement of the Parties if the Parties agree to
a change in Exhibit A, or a change to the Implementation Date, in accordance with
Section 3(c) and the Parties agree that an adjustment to the Implementation Fee is
warranted in light of such change.
(c) Upon completion of the milestones identified in Exhibit A, the ISO shall
invoice IPCO for the Implementation Fee as follows:
4
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 4 of 17
i. $90,000 upon the Effective Date as further described in Section 1 of this
Agreement and Exhibit A as Milestone 1;
ii. $90,000 upon deployment into the ISO test environment of the full network
model database that includes the topology of the IPCO system as further
described in Exhibit A as Milestone 2;
iii. $90,000 upon ISO promotion of market network model including IPCO
area to non-production system with IPCO connection and data exchange
data in advance of market simulation as further described in Exhibit A as
Milestone 3;
iv. $90,000 upon commencement of EIM market simulation as further
described in Exhibit A as Milestone 4;
v. $90,000 upon start of parallel operations as further described in Exhibit A
as Milestone 5; and
vi. $90,000 upon the Implementation Date as further described in Exhibit A
as Milestone 6.
(d) Following the completion of each milestone identified in Section 4(c)(i)
through (v), the ISO will deliver to IPCO an invoice which will show the amount due,
together with reasonable documentation supporting the completion of the milestone
being invoiced. IPCO shall pay the invoice no later than forty-five (45) days after the
date of receipt. Any milestone payment past due will accrue interest, per annum,
calculated in accordance with the methodology specified for interest in the FERC
regulations at 18 C.F.R. § 35.19a(a)(2)(iii) (the "FERC Methodology").
(e) If a milestone has not been completed as described in Section 4(c)(i), (ii),
(iii), (iv), or (v) and in Exhibit A, as Exhibit A may have been modified in accordance with
Section 3(c), the Parties shall negotiate in good faith an agreed upon change to the
Project Delivery Dates (as defined in Exhibit A) consistent with Section 3(c) such that
the timing of milestone payments in Section 4(c) can be adjusted to correspond to the
updated Exhibit A.
(f) If IPCO disputes any portion of any amount specified in an invoice
delivered by the ISO in accordance with Section 4(c), IPCO shall pay its total amount of
the invoice when due, and identify the disputed amount and state that the disputed
amount is being paid under protest. Any disputed amount shall be resolved pursuant to
the provisions of Section 11 . If it is determined pursuant to Section 11 that an
overpayment or underpayment has been made by IPCO or any amount on an invoice is
incorrect, then (i) in the case of any overpayment, the ISO shall promptly return the
amount of the overpayment (or credit the amount of the overpayment on the next
invoice) to IPCO; and (ii) in the case of an underpayment, IPCO shall promptly pay the
amount of the underpayment to the ISO. Any overpayment or underpayment shall
include interest for the period from the date of overpayment, underpayment, or incorrect
5
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 5 of 17
allocation, until such amount has been paid or credited against a future invoice
calculated in the manner prescribed for calculating interest in Section 4(d).
(g) All costs necessary to implement the Project not provided for in this
Agreement shall be borne separately by each Party, which in the case of the ISO will be
recovered through rates as may be authorized by its regulatory authorities.
(h) All milestone payments required to be made under the terms of this
Agreement shall be made to the account or accounts designated by the Party which the
milestone payment is owed, by wire transfer (in immediately available funds in the lawful
currency of the United States).
5. Confidentiality.
(a) All written or oral information received from the other Party in connection
with this Agreement (but not this Agreement after it is filed with FERG) necessary to
complete the Project and marked or otherwise identified at the time of communication
by such Party as containing information that Party considers commercially sensitive or
confidential shall constitute "Confidential Information" subject to the terms and
conditions herein.
(b) If IPCO publicly releases IPCO's Confidential Information in connection
with a public process or a regulatory filing, or if the ISO publicly releases the ISO's
Confidential Information in connection with a public process or a regulatory filing, then
the information released shall no longer constitute Confidential Information; provided,
however, that Confidential Information disclosed under seal (or in such other manner as
to be treated confidentially) in connection with a regulatory filing shall retain its status as
Confidential Information under this Agreement. In addition, Confidential Information
does not include information that (i) is or becomes generally available to the public other
than as a result of disclosure by either Party, its officers, directors, employees, agents,
or representatives; (ii) is or becomes available to such Party on a non-confidential basis
from other sources or their agents or representatives when such sources are not known
by such Party to be prohibited from making the disclosure; (iii) is already known to such
Party or has been independently acquired or developed by such Party without violating
any of such Party's obligations under this Section 5; (iv) is the subject of a mutual
written agreement between the Parties, including an agreement evidenced through an
exchange of electronic or other communications, with regard to information for
discussion at any stakeholder meetings or during the stakeholder process or with any
regulatory authority; or (v) is the subject of a mutual written agreement between the
Parties, including an agreement evidenced through an exchange of electronic or other
communications, to allow for such disclosure and designation as non-confidential or
public information on a case-by-case basis in accordance with Section 10 of this
Agreement.
(c) The Confidential Information will be kept confidential by each Party and
each Party agrees to protect the Confidential Information using the same degree of
care, but no less than a reasonable degree of care, as a Party uses to protect its own
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Case No. IPC-E-16-19
K. Anderson, IPC
Page 6 of 17
confidential information of a like nature. Notwithstanding the preceding sentence, a
Party may disclose the Confidential Information or portions thereof to those of such
Party's officers, employees, partners, representatives, attorneys, contractors, advisors,
or agents who need to know such information for the purpose of analyzing or performing
an obligation related to the Project. Notwithstanding the foregoing, a Party is not
authorized to disclose such Confidential Information to any officers, employees,
partners, representatives, attorneys, contractors, advisors, or agents without
(i) informing such officer, employee, partner, representative, attorney, contractor,
advisor, or agent of the confidential nature of the Confidential Information and (ii)
ensuring that such officer, employee, partner, representative , attorney, contractor,
advisor, or agent is subject to confidentiality duties or obligations to the applicable Party
that are no less restrictive than the terms and conditions of this Agreement. Each Party
agrees to be responsible for any breach of this Section 5 by such Party or a Party's
officers, employees, partners, representatives, attorneys, contractors, advisors or
agents, subject to the limitations set forth in Section 6 below.
(d) In the event that a Party is required by a court of competent jurisdiction or
regulatory authority (by law, rule , regulation, order, deposition, interrogatory, request for
documents, data request issued by a regulatory authority, subpoena, civil investigative
demand or similar request or process) to disclose any of the Confidential Information,
such Party shall (to the extent legally permitted) provide the other Party with prompt
written notice of such requirement so that the other Party may seek a protective order or
other appropriate remedy and/or waive compliance with the terms of this Section 5. In
the event that such protective order or other remedy is not obtained, the disclosing
Party hereby waives compliance with the provisions hereof with respect to such
Confidential Information. In such event, the Party compelled to disclose shall (i) furnish
only that portion of the Confidential Information which, in accordance with the advice of
its own counsel (which may include internal counsel), is legally required to be furnished,
and (ii) exercise reasonable efforts to obtain assurances that confidential treatment will
be accorded the Confidential Information so furnished.
(e) Notwithstanding the foregoing, the Parties acknowledge that they are
required by law or regulation to report certain information that could embody
Confidential Information from time to time, and may do so from time to time without
providing prior notice to the other Party. Such reports may include models, filings, and
reports of costs, general rate case filings, cost adjustment mechanisms, FERG-required
reporting, investigations, annual state reports that include resources and loads,
integrated resource planning reports, reports to entities such as FERC, the North
American Electric Reliability Council ("NERC"), Western Electricity Coordinating Council
("WECC"), or similar or successor organizations, or similar or successor forms, filings,
or reports, the specific names of which may vary by jurisdiction, along with supporting
documentation. Additionally, in regulatory proceedings or investigations in all state and
federal jurisdictions in which they may do business, the Parties will from time to time be
required to produce Confidential Information, and may do so without prior notice using
its business judgment in compliance with all of the foregoing and including the
appropriate level of confidentiality for such disclosures in the normal course of business.
7
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Case No. IPC-E-16-19
K. Anderson , IPC
Page 7 of 17
(f) Each Party is entitled to seek equitable relief, by injunction or otherwise, to
enforce its rights under this Section 5 to prevent the release of Confidential Information
without bond or proof of damages, and may seek other remedies available at law or in
equity for breach of this provision, subject to the limitations set forth in Section 6 below.
(g) Upon written request by a Party, the other Party shall promptly return to
the requesting Party or destroy all Confidential Information it received, including all
copies of its analyses, compilations, studies or other documents prepared by or for it,
that contain the Confidential Information in a manner that would allow its extraction or
that would allow the identification of the requesting Party as the source of the
Confidential Information or inputs to the analysis. Notwithstanding the foregoing,
neither Party shall be required to destroy or alter any computer archival and backup
tapes or archival and backup files (collectively, "Computer Tapes"), provided that such
Computer Tapes shall be kept confidential in accordance with the terms of this
Agreement.
(h) Nothing in this Agreement shall be deemed to restrict either Party from
engaging with third parties with respect to any matter and for any reason, specifically
including the EIM, provided Confidential Information is treated in accordance with this
Section 5.
(i) This Section 5, Confidentiality, applies for two years (24 months) after the
Termination Date or the date of any expiration or termination of this Agreement.
6. Limitation of Liability; Indemnity.
(a) The Parties acknowledge and agree that, except as otherwise specified in
Section 4(f) of this Agreement, neither Party shall be liable to the other Party for any
claim, loss, cost, liability, damage or expense, including any direct damage or any
special, indirect, exemplary, punitive, incidental or consequential loss or damage
(including any loss of revenue, income, profits or investment opportunities or claims of
third party customers), arising out of or directly or indirectly related to such other Party's
decision to enter into this Agreement, such other Party's performance under this
Agreement, or any other decision by such Party with respect to the Project.
(b) Each Party shall indemnify, defend and hold harmless each of the other
Party and its officers, directors, employees, agents, contractors and sub-contractors,
from and against all third-party claims, judgments, losses, liabilities, costs, expenses
(including reasonable attorneys' fees) and damages for personal injury, death or
property damage, to the extent caused by the negligence, willful misconduct, or breach
of this Agreement of the indemnifying Party, its officers, directors, agents, employees,
contractors or sub-contractors related to this Agreement; provided, that this
indemnification shall be only to the extent such personal injury, death or property
damage is not attributable to the negligence or willful misconduct related to this
Agreement or breach of this Agreement of the Party seeking indemnification, its officers,
directors, agents, employees, contractors or sub-contractors. The indemnified Party
shall give the other Party prompt notice of any such claim. The indemnifying Party, in
8
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 8 of 17
consultation with the indemnified Party, shall have the right to choose competent
counsel, control the conduct of any litigation or other proceeding, and settle any claim,
provided that any such settlement shall not impose costs upon the indemnified Party.
The indemnified Party shall provide all documents and assistance reasonably requested
by the indemnifying Party.
(c) The rights and obligations under this Section 6 shall survive the
Termination Date and any expiration or termination of this Agreement.
7. Representation and Warranties.
(a) Representations and Warranties of IPCO. IPCO represents and warrants
to the ISO as of the Effective Date as follows:
(1) It is duly formed, validly existing and in good standing under the
laws of the jurisdiction of its formation.
(2) It has all requisite corporate power necessary to own its assets and
carry on its business as now being conducted or as proposed to be conducted under
this Agreement.
(3) It has all necessary corporate power and authority to execute and
deliver this Agreement and to perform its obligations under this Agreement, and the
execution and delivery of this Agreement and the performance by it of this Agreement
have been duly authorized by all necessary corporate action on its part.
(4) The execution and delivery of this Agreement and the performance
by it of this Agreement do not: (i) violate its organizational documents; (ii) violate any
governmental requirements applicable to it; or (iii) result in a breach of or constitute a
default of any material agreement to which it is a party.
(5) This Agreement has been duly and validly executed and delivered
by it and constitutes its legal, valid and binding obligation enforceable against it in
accordance with its terms, except as the same may be limited by bankruptcy, insolvency
or other similar laws affecting creditors' rights generally and by principles of equity
regardless of whether such principles are considered in a proceeding at law or in equity.
(6) All material governmental authorizations in connection with the due
execution and delivery of this Agreement, have been duly obtained or made prior to the
date hereof and are in full force and effect.
(b) Representations and Warranties of the ISO. ISO represents and warrants
to IPCO as of the Effective Date as follows:
(1) It is duly formed, validly existing and in good standing under the
laws of the jurisdiction of its formation.
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Case No. IPC-E-16-19
K. Anderson, IPC
Page 9 of 17
(2) It has all requisite corporate power necessary to own its assets and
carry on its business as now being conducted or as proposed to be conducted under
this Agreement.
(3) It has all necessary corporate power and authority to execute and
deliver this Agreement and to perform its obligations under this Agreement, and the
execution and delivery of this Agreement and the performance by it of this Agreement
have been duly authorized by all necessary corporate action on its part.
(4) The execution and delivery of this Agreement and the performance
by it of this Agreement do not: (i) violate its organizational documents; (ii) violate any
governmental requirements applicable to it; or (iii) result in a breach of or constitute a
default of any material agreement to which it is a party.
(5) This Agreement has been duly and validly executed and delivered
by it and constitutes its legal, valid and binding obligation enforceable against it in
accordance with its terms, except as the same may be limited by bankruptcy,
insolvency, regulatory authority, or other similar laws affecting creditors' rights generally
and by principles of equity regardless of whether such principles are considered in a
proceeding at law or in equity.
(6) All material governmental authorizations in connection with the due
execution and delivery of, and performance by it of its obligations under this Agreement,
have been duly obtained or made prior to the date hereof and are in full force and effect.
8. General Provisions.
(a) This Agreement, including Exhibit A to this Agreement, constitutes the
entire agreement between the Parties, and supersedes any prior written or oral
agreements or understandings between the Parties, relating to the subject matter of this
Agreement; provided, that nothing in this Agreement shall limit, repeal, or in any manner
modify the existing legal rights, privileges, and duties of each of the Parties as provided
by any other agreement between the Parties, or by any statute or any other law or
applicable court or regulatory decision by which such Party is bound .
(b) This Agreement may not be amended except in writing hereafter signed
by both of the Parties; provided, however, the Parties may mutually agree to changes in
Exhibit A in accordance with Section 4(e).
(c) Any waiver by a Party to this Agreement of any provision or condition of
this Agreement must be in writing signed by the Party to be bound by such waiver, shall
be effective only to the extent specifically set forth in such writing and shall not limit or
affect any rights with respect to any other or future circumstance.
(d) This Agreement is for the sole and exclusive benefit of the Parties and
shall not create a contractual relationship with, or cause of action in favor of, any third
party.
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Case No. IPC-E-16-19
K. Anderson, IPC
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(e) Neither Party shall have the right to voluntarily assign its interest in this
Agreement, including its rights, duties, and obligations hereunder, without the prior
written consent of the other Party, which consent may be withheld by the other Party in
its sole and absolute discretion. Any assignment made in violation of the terms of this
Section B(e) shall be null and void and shall have no force and effect.
(f) In the event that any provision of this Agreement is determined to be
invalid or unenforceable for any reason, in whole or part, the remaining provisions of
this Agreement shall be unaffected thereby and shall remain in full force and effect to
the fullest extent permitted by law, and such invalid or unenforceable provision shall be
replaced by the Parties with a provision that is valid and enforceable and that comes
closest to expressing the Parties' intention with respect to such invalid or unenforceable
provision.
(g) Whenever this Agreement requires or provides that (i) a notice be given by
a Party to the other Party or (ii) a Party's action requires the approval or consent of the
other Party, such notice, consent or approval shall be given in writing and shall be given
by personal delivery, by recognized overnight courier service, email or by certified mail
(return receipt requested), postage prepaid, to the recipient thereof at the address given
for such Party as set forth below, or to such other address as may be designated by
notice given by any Party to the other Party in accordance with the provisions of this
Section 8(g):
lfto IPCO:
Idaho Power Company
1221 W. Idaho Street
Boise, Idaho 83702
Attention: Tessia Park, Vice President of Power Supply
E-mail: [e-mail]
If to the ISO:
California Independent System Operator Corporation
250 Outcropping Way
Folsom, CA 95630
Attention: Petar Ristanovic, Vice President, Technology
E-mail: [e-mail]
Each notice, consent or approval shall be conclusively deemed to have been given (i)
on the day of the actual delivery thereof, if given by personal delivery, email sent by
5:00 p.m., or overnight delivery, or (ii) date of delivery shown on the receipt, if given by
certified mail (return receipt requested). It is the responsibility of each Party to provide,
in accordance with this Section, notice to the other Party of any necessary change in
the contact or address information herein.
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Case No. IPC-E-16-19
K. Anderson, IPC
Page 11 of 17
(h) This Agreement may be executed in one or more counterparts (including
by facsimile or a scanned image), each of which when so executed shall be deemed to
be an original, and all of which shall together constitute one and the same instrument.
(i) Nothing contained in this Agreement shall be construed as creating a
corporation, company, partnership, association, joint venture or other entity with the
other Party, nor shall anything contained in this Agreement be construed as creating or
requiring any fiduciary relationship between the Parties. No Party shall be responsible
hereunder for the acts or omissions of the other Party.
0) The decision to execute an EIM service agreement and participate in the
EIM remains within the sole discretion of IPCO and the decision whether to continue to
offer EIM services (subject to Sections 1 (c) and 2) remains within the sole discretion of
the ISO.
(k) Nothing in this Agreement shall preclude a Party from exercising any
rights or taking any action (or having its affiliates take any action) with respect to any
other project.
(I) Unless otherwise expressly provided, for purposes of this Agreement, the
following rules of interpretation shall apply: (i) any reference in this Agreement to gender
includes all genders, and the meaning of defined terms applies to both the singular and
the plural of those terms; (ii) the insertion of headings are for convenience of reference
only and do not affect, and will not be utilized in construing or interpreting, this
Agreement; (iii) all references in this Agreement to any "Section" are to the
corresponding Section of this Agreement unless otherwise specified; (iv) words such as
"herein," "hereinafter," "hereof," and "hereunder" refer to this Agreement (including
Exhibit A to this Agreement) as a whole and not merely to a subdivision in which such
words appear, unless the context otherwise requires; (v) the word "including" or any
variation thereof means "including, without limitation" and does not limit any general
statement that it follows to the specific or similar items or matters immediately following
it; and (vi) the Parties have participated jointly in the negotiation and drafting of this
Agreement and, in the event an ambiguity or question of intent or interpretation arises,
this Agreement shall be construed as jointly drafted by the Parties and no presumption
or burden of proof favoring or disfavoring any Party will exist or arise by virtue of the
authorship of any provision of this Agreement.
(m) The above-stated recitals are incorporated into and made a part of this
Agreement by this reference to the same extent as if these recitals were set forth in full
at this point.
9. Venue. Venue for any action hereunder shall be FERC, where subject to its
jurisdiction, or otherwise any state or federal court with jurisdiction.
10. Communication. The Parties shall develop a communication protocol for the
dissemination of material information associated with the Project, which shall be
approved by IPCO and the ISO. Pursuant to the communication protocol, the individual
12
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 12 of 17
identified in Section B(g), or their designee or successor, shall provide reasonable
advance notice to the other Party of planned press releases, public statements, and
meetings with the public or governmental authorities in which material information
concerning the Project or IPCO's involvement will be shared. The Parties shall mutually
consult with each other as provided in the communication protocol prior to making such
public statements or disclosures; provided that nothing herein shall prevent, limit, or
delay either Party from making any disclosure required by applicable law or regulation,
subject to the provisions of Section 5 hereof. In the event either Party engages in
material unplanned communications about the Project that otherwise should have been
subject to this Section and the communication protocol, such Party shall provide notice
to the other Party as promptly as possible of the nature and content of such
communication.
11. Dispute Resolution. Unless otherwise provided herein, each of the provisions of
this Agreement shall be enforceable independently of any other provision of this
Agreement and independent of any other claim or cause of action. In the event of any
dispute arising under this Agreement, the Parties shall, to the extent practicable, first
attempt to resolve the matter through direct good faith negotiation between the Parties,
including a full opportunity for escalation to executive management within the Parties'
respective organizations. If the Parties are unable to resolve the issue within thirty (30)
days after such escalation of the dispute, then for matters subject to FERG jurisdiction
either Party shall have the right to file a complaint under Section 206 of the Federal
Power Act. For all other matters, then :
(a) To the fullest extent permitted by law, each of the Parties hereto waives
any right it may have to a trial by jury in respect of litigation directly or indirectly arising
out of, under or in connection with this Agreement. Each Party further waives any right
to consolidate, or to request the consolidation of, any action in which a jury trial has
been waived with any other action in which a jury trial cannot be or has not been
waived.
(b) If a waiver of jury trial is deemed by any court of competent jurisdiction to
not be enforceable for any reason, then to the fullest extent permitted by law, each of
the Parties hereto agrees to attempt to settle amicably through non-binding arbitration.
Notwithstanding the foregoing, either Party may seek provisional legal remedies if, in
such Party's judgment, such action is necessary to avoid irreparable damage or
preserve the status quo.
12. Third Party Agreements. The Parties may engage in discussions with third
parties, either jointly or unilaterally, to facilitate the Project. Each Party may adopt or
modify tariffs or enter into or modify binding agreements between such Party and third
parties to implement the approved terms and conditions of the Project or EIM as
necessary and appropriate.
13. Compliance. Each Party shall comply with all federal, state, local or municipal
governmental authority; any governmental, quasi-governmental, regulatory or
13
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 13 of 17
administrative agency, commission, body or other authority exercising or entitled to
exercise any administrative, executive, judicial, legislative, policy, regulatory or taxing
authority or power, including FERG, NERC, WECC; or any court or governmental
tribunal; in each case, having jurisdiction over either Party in connection with the
execution, delivery and performance of its obligations under this Agreement. This
Agreement is not intended to modify, change or otherwise amend the Parties' current
functional responsibilities associated with compliance with WECC and NERC Reliability
Standards; provided, however, the Parties may enter into separate mutually agreed to
arrangements to clarify roles and responsibilities associated with compliance with
WECC and NERC Reliability Standards in respect of this Agreement.
IN WITNESS WHEREOF, each of the Parties has caused its duly authorized officer to
execute this Implementation Agreement as of the date first above written.
IDAHO POWER COMPANY
By:
ame: Lisa Grow 0
Title: Sr. Vice President, Operations
CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION
By: ~ay: P~~
Name:Petar Ristanovic
Title: Vice President, Technology
14
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 14 of 17
EXHIBIT A: PROJECT SCOPE AND SCHEDULE
The Project consists of the activities and delivery dates identified in this Exhibit A,
implemented in accordance with the Agreement. The Parties have included a schedule
for the Implementation Date to coordinate their efforts required for completion of the
Project on a milestone track.
The Parties understand that input received from stakeholders during the course of
implementing the Project, conditions imposed or questions raised in the regulatory
approval process, and the activities of the Parties in implementing the Project may
cause the Parties to determine that changes in the Project are necessary or desirable.
Accordingly, this Exhibit A may be modified in accordance with Section 3(c) of the
Agreement.
Each Party is responsible for performing a variety of tasks necessary to achieve the
milestones on the scheduled dates specified in the table below ("Project Delivery
Dates") and shall plan accordingly. The Parties shall communicate and coordinate as
provided in the Agreement to support the planning and execution to complete the
Project.
Project Scope and Milestones
Detailed Project Management Plan -The Parties will develop and
initiate a final project management plan that describes specific
project tasks each Party must perform, delivery dates, project team
members, meeting requirements, and a process for approving
changes to support completion of the Project.
• Milestone 1 -This milestone is completed when the
Agreement has been made effective in accordance with
Section 1 of the Agreement.
Full Network Model Expansion -Full Network Model expansion
for IPCO and EMS/SCADA, including, proof of concept of
export/import of EMS data; complete model into the ISO test
environment; complete validation for all SCADA points from
IPCO; testing of the new market model; and validation of the
Outage and State Estimator applications.
1
Project
Delivery
Dates
supporting
April 2018
June 2016
July 2016
August 2017
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 15 of 17
• Milestone 2 -This milestone is completed upon modeling
IPCO into the ISO Full Network Model through the EMS
which will be deployed into a non-production test
environment using the ISO's network and resource modeling
process.
System Implementation and Connectivity Testing -System
requirements and software design, the execution of necessary
software vendor contracts, development of Market network model
including IPCO, allow IPCO to connect to a non-production test
system.
• Milestone 3 -ISO to promote market network model including
IPCO area to non-production system, and allow IPCO to
connect and exchange data in advance of Market Simulation.
K:onstruction, Testing and Training in Preparation for Market
~imulation -This task includes IT infrastructure upgrades, security
~esting, training, Day-in-life simulation, and functional testing.
• Milestone 4a -Start of Connectivity to ISO Testing, Interface
testing with minimum data requirements and functional
integration testing. ISO will make the test environment
available for PGE connectivity testing prior to the delivery date
assuming PGE has provided all requisite data and non-
production system availability does not conflict with ISO
production system Spring Release schedule.
• Milestone 4b -Begin 'Day in the Life' scenario testing
• Milestone 4c -Begin Structured Market simulation
Activate Parallel Operations -Beginning August 1, 2017, the ISO
will activate a parallel operation environment to practice production
grade systems integration as well as market processes and operating
procedures in anticipation of the impending IPCO activation as an
EIM Entity and to confirm compliance with the EIM readiness criteria
set forth in the ISO tariff.
• Milestone 5 -Start of parallel operations
2
August 2017
September
2017
September 2017
October 2017
September, 2017
October 2017
November 2017
January 2018
February 1,
2018
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 16 of 17
System Deployment and Go Live-Implementing the Project and
going live will include resource registration, operating procedures and
updates, execution of service agreements, completion of the IPCO
tariff process, applicable board approvals, the filing and acceptance
of service agreements and tariff changes with FERG, and completion
and filing of a readiness criteria certification in accordance with the
ISO tariff.
• Milestone 6 -This milestone is complete upon the first
production IPCO energy imbalance market trade date.
3
March 2018
April 1, 2018
Exhibit No. 3
Case No. IPC-E-16-19
K. Anderson, IPC
Page 17 of 17
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-16-19
IDAHO POWER COMPANY
ANDERSON, DI
TESTIMONY
EXHIBIT NO. 4
An IDACORP company
Idaho Power Company
Energy Imbalance Market Analysis
February 2016
Energy+Environmental Economics
Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 1 of 40
Idaho Power Energy Imbalance Market Analysis
Idaho Power Company
Energy Imbalance Market
Analysis
February 2016
© 2016 Copyright. All Rights Reserved.
Energy and Environmental Economics, Inc.
101 Montgomery Street, Suite 1600
San Francisco, CA 94104
415.391.5100
www.ethree.com
Prepared For:
Idaho Power Company
Prepared By:
Jack Moore, Sheridan Grant, Sharad Bharadwaj, and Brian Conlon
Energy and Environmental Economics, Inc. (E3)
Tao Guo, Guangjuan Liu, and Yannick Degeilh
Energy Exemplar
Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 2 of 40
Table of Contents
Executive Summary ........................................................................................ 1
1 Introduction .............................................................................................. 9
1.1 Context for Study .................................................................................. 9
1.2 Structure of this Report ...................................................................... 10
2 Study Assumptions and Approach .................................................... 11
2.1 Overview of Approach ........................................................................ 11
2.2 Sub-hourly Dispatch Benefits Methodology ................................... 12
2.2.1 Production Cost Modeling ................................................. 12
2.2.2 BAU Simulation ................................................................... 15
2.2.3 Western EIM Simulations .................................................. 16
2.3 Key Modeling Assumptions ............................................................... 16
2.3.1 Sub-hourly Dispatch ........................................................... 16
2.3.2 Real-time Transmission Transfer Capability ................. 17
2.3.3 Hurdle Rates ........................................................................ 18
2.3.4 Flexibility Reserve Requirements .................................... 20
2.4 Detailed Scenario Assumptions ....................................................... 22
2.4.1 Input Data ............................................................................. 22
2.4.2 Dispatch Savings Scenarios ............................................. 25
2.5 Methodology for Attributing Benefits to IPC and Other
Participants ........................................................................................... 27
Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 3 of 40
Idaho Power Energy Imbalance Market Analysis
3 Results ..................................................................................................... 30
3.1 Benefits to IPC .................................................................................... 30
3.2 Incremental Benefits to Current EIM Participants ........................ 31
3.3 EIM Results Discussion ..................................................................... 32
3.3.1 Base Scenario ..................................................................... 32
3.3.2 Alternative Scenarios ......................................................... 34
Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 4 of 40
Acronyms
APS Arizona Public Service Company
BA Balancing Authority
BAA Balancing Authority Area
BAU Business-as-usual
CAISO California Independent System Operator
DA Day-ahead
EIM Energy Imbalance Market
FERC Federal Energy Regulatory Commission
HA Hour-ahead
IPC Idaho Power Company
LMP Locational Marginal Price
NVE NV Energy
NWPP Northwest Power Pool
PACE PacifiCorp East
PACW PacifiCorp West
PGE Portland General Electric Company
PNNL Pacific Northwest National Laboratory
PSE Puget Sound Energy
WECC Western Electric Coordinating Council
Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 5 of 40
Executive Summary
Executive Summary
Over the past year, in an effort to increase operational efficiency and create cost
savings for IPC customers, Idaho Power Company (IPC) has been exploring
participation in the energy imbalance market (EIM) operated by the California
Independent System Operator (CAISO). As part of its assessment of
opportunities for regional coordination, IPC engaged Energy & Environmental
Economics, Inc. (E3), to analyze the potential economic benefits of IPC's
participation in the Western EIM. This report describes the results of our study.
The analysis uses production simulation modeling in PLEXOS to estimate IPC's
benefits resulting from participation in the EIM by comparing IPC's real-time
generation costs as an EIM participant, as well as any revenues or costs from
transactions with other EIM participants, against those of a business-as-usual
(BAU) case in which IPC does not participate in the EIM. To focus on the
incremental impact of IPC participation, the BAU case includes operations of a
"current EIM" consisting of the seven BAAs that were participating or had
announced plans to participate in the EIM at the start of this study. These BAAs
are listed in the table below.
© 2016 Energy and Environmental Economics, Inc. P a g e 1 1 1 Exhibit No. 4
Case No. IPC-E-16-19
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Idaho Power Energy Imbalance Market Analysis
Table 1: BAA Participants in EIM in BAU Case
Current EIM part1c1pants
for BAU Case
CAISO
PacifiCorp East (PACE)
PacifiCorp West (PACW)
NV Energy (NVE)
Puget Sound Energy (PSE)
Arizona Public Service (APS)
Portland General Electric (PGE)
Under the Base Scenario simulated for the year 2020, the analysis estimates
that EIM participation would produce $4.5 million in annual sub-hourly dispatch
cost savings for IPC. Under an alternative scenario with higher renewable
buildout in the region, EIM participation created $5.1 million in total sub-hourly
dispatch cost savings to IPC. Savings due to reduced flexibility reserves (from the
diversity provided by the EIM) were not estimated in this study, but would
provide savings in addition to the figures stated above. For example, in a
previous study E3 estimated that PGE would receive $0.8 million in savings due
to reduced flexibility reserves from joining the EIM.
Table 2. Annual Savings to IPC from Participation in EIM (2015$ million)
Scenario EIM Savings to IPC
Base Scenario $4.5
No APS orPGE $4.2
Early Coal Retirement $4.1
High RPS Case $5.1
Overall, this study estimates that participation in the EIM would produce
modest positive savings for IPC, and that savings from participation would be
Page IZI Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 7 of 40
Executive Summary
larger in the presence of larger renewable resource buildout. In addition to
savings to IPC, we also estimate that IPC participation in the EIM would produce
over $2 million in incremental savings for the current EIM participants.
Base Scenario savings to IPC are positive and modest due to a combination of
factors. Monthly 2020 gas prices came from OTC Global Holding Natural Gas
Forwards & Futures (provided by SNL) for selected hubs in the West region; the
average price for IPC area generators was $3.27 /MM BTU for 2020 (in 2015
dollars). These relatively low gas prices moderated the value of EIM flexibility to
IPC. Additionally, IPC's generator portfolio modeled for 2020 includes flexible
hydro resources that can respond quickly to changes in sub-hourly needs,
making IPC's flexibility needs lower than those of a utility without much flexible
generation.
The model's Base Scenario sets California's renewable build to meet a 33% RPS
target. Recently approved legislation raises that state's renewable portfolio
target to 40% by 2024 and 50% by 2030,1 in addition to customer-side
renewable resources such as rooftop solar. These developments may provide
increasing opportunities for EIM participants to purchase energy from California
in real time at a low cost.
The focus of this analysis is to provide consistent, conservative estimates of
operational cost savings to IPC for evaluation of participation in the EIM. The
study does not quantify potential benefits from improved dispatch in the hour-
1 See California Legislature, 2015:
https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill id=201520160SB350.
© 2016 Energy and Environmental Economics, Inc. P a g e 1 3 1 Exhibit No. 4
Case No. IPC-E-16-19
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Idaho Power Energy Imbalance Market Analysis
ahead (HA) market or day-ahead (DA) market, which may develop over time as
information produced by the EIM informs more efficient DA and HA trading. The
study also does not quantify any potential reliability benefits from EIM
participation, which are difficult to quantify but may be substantial if
participation ultimately assists participants in avoiding a major outage. The
study does not quantify potential cost impact on generator maintenance cost as
a result of reduced ramping of thermal units. The study does not compare the
savings to the incremental costs of joining an EIM. Finally, the study does not
estimate savings to IPC or other EIM participants arising from flexibility reserve
reductions due to load and variable resource diversity across the footprint.
EIM market discussion
The EIM is a balancing energy market that optimizes generator dispatch within
and between Balancing Authority Areas (BAAs) every 15 and 5 minutes.2 The
EIM can create real-time dispatch cost savings for EIM participants by: (1) using
software tools to identify sub-hourly transactions that produce an optimized
dispatch and minimize production costs, while respecting reliability limits; (2)
bringing this optimized dispatch down to a 5-minute interval level; and (3)
incorporating optimized real-time unit commitment of quick-start generation.
Additionally, by allowing BAs to pool load and generation resources on a sub­
hourly basis, the EIM can enable participants to reduce the number of units they
individually need to commit to provide flexibility reserves within the hour. In
2 For more information regarding the EIM, see
https://www.caiso.com/informed/Pages/EIMOverview/Default.aspx.
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Case No. IPC-E-16-19
K. Anderson , IPC
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Executive Summary
December 2011, the CAISO implemented a flexible ramping constraint in the
five-minute market optimization to maintain sufficient upward flexibility in the
system within the hour.3 Each generator chosen to resolve a constraint is
compensated at the marginal generator unit's shadow price, which reflects the
opportunity cost for production. The CAISO's calculation of flexible ramping
constraints for EIM participants is adjusted downward to reflect diversity of net
loads for all participants, subject to transmission constraints. The CAISO
determines flexible ramp constraint requirements for each EIM participant
based on the aggregate load, wind, and solar resource forecasts and expected
variability. By establishing the requirements based on the aggregate load and
resource profiles, the benefits of diversity can be reflected in the EIM flexibility
reserve requirements. The flexible ramping constraint in the EIM also
compensates resources for their contribution to meeting the flexibility
constraint. While pooling of flex reserves can reduce variable dispatch and
generator commitment costs over time as operators accumulate greater
experience with the EIM, participation in the EIM does not reduce the physical
generation capacity that a BA needs to serve peak loads and provide system
flexibility. Long-term capacity decisions are beyond the scope of this report and
are more appropriately examined using other analytical approaches and
modeling tools.
3 See CAISO, 2014: Flexible Ramping Constraint Penalty Price In the Fifteen Minute Market. Available at:
http://www.caiso.com/Documents/TechnicalBulletin-FlexibleRampingConstraintPenaltyPrice­
FifteenMinuteMarket.pdf. The CAISO is in the process of introducing a flexible ramping product, which would
allow economic bids to be submitted to procure upward and downward ramping capability.
https://www.caiso.com/Documents/RevisedDraftFinalProposal-FlexibleRampingProduct-2015.pdf.
© 2016 Energy and Environmental Economics, Inc. P a g e 1 5 1 Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
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Idaho Power Energy Imbalance Market Analysis
Modeling Approach
This study analyzes the impact of IPC participation in the EIM using the PLEXOS
production cost modeling software to simulate sub-hourly operations in the
Western Interconnection for the year 2020. Energy Exemplar provided technical
support to this study and implemented the sub-hourly production simulation
runs in PLEXOS. Savings were identified as sub-hourly dispatch benefits, which
realize the efficiency of optimized combined 15-and 5-minute dispatch and
real-time unit commitment between IPC and the current EIM footprint.
As a starting point, this study used the PLEXOS database developed by Pacific
Northwest National Laboratory (PNNL) for the Western Electricity Coordinating
Council's (WECC) Variable Generation Subcommittee (VGS) study from 2012-134
and revised as part of the NWPP Phase 1 EIM study from 2013.5 Similar to those
two studies, this analysis used a three-stage simulation process, including DA,
HA, and real-time simulations stages to represent the different time horizons of
actual power system operations. The DA and HA stages are simulated on an
hourly basis.
The initial dataset used for this study is the database used in E3's PGE EIM
Comparative Study: Economic Analysis Report6, which updated the database
4 See WECC, 2013, Balancing Authority Cooperation Concepts to Reduce Variable Generation Integration Costs in
the Western Interconnection: Intra-Hour Scheduling. Available at http://energyexemplar.com/wp­
content/uploads/publications/Balancing%20Authority%20Cooperation%20Concepts%20-%20lntra­
Hour",A;20Scheduling.pdf.
5 See Samaan, NA, et al., 2013, Analysis of Benefits of an Energy Imbalance Market in the NWPP. Available at:
http://www.pnnl.gov/main/publications/external/technical reports/PNNL-22877.pdf.
6 See E3, 2015, PGE EIM Comparative Study: Economic Analysis Report. Available at:
http://edocs.puc.state.or.us/efdocs/HAD/lcS6had152028.pdf
Pagel6 1 Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 11 of 40
Executive Summary
from E3's 2014 EIM study for Puget Sound Energy with input from PGE along
with representatives from several northwestern BAs. The 2014 PSE database
applied PSE-and CAISO-specific updates to the database originally developed
for the NWPP Phase 1 EIM analysis.
E3 quantified the sub-hourly dispatch savings from !PC's participation in the EIM
by (1) running a real-time BAU case that holds energy transfers between non­
participating BAs (which include IPC) equal to the scheduled levels from the HA
simulation but allowing EIM participants to transact with other participating BAs
in the same real-time market, subject to transmission transfer limits; and (2)
running EIM cases (starting from the same HA simulation as the BAU case) that
each allow IPC to transact power within the hour with other EIM participants.
The increased flexibility in the EIM cases produces a reduction in real time
production costs for the region, which represents the total societal EIM-wide
savings as a result of IPC participation. Benefits are then divided between IPC
and the current EIM participants based on the change in their generation cost
and their net purchases and sales in real time through the EIM.
Scenario Description
The Base Scenario of this analysis uses gas hub prices from OTC Global Holding
Natural Gas Forwards & Futures, which are $3.27 /MM Btu on average for 2020
(in 2015 dollars). The Base Scenario also includes renewable resource
development to meet current RPS targets and projected renewable buildout for
2020. This includes a 33% RPS for California, a 15% renewable penetration for
IPC, and an average 15% renewable share for other Northwest region BAAs not
participating in the EIM. We also analyzed alternative scenarios which model a
© 2016 Energy and Environmental Economics, Inc. P a g e 1 7 1 Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
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Idaho Power Energy Imbalance Market Analysis
higher renewable penetration in the west: a 40% RPS for California, a 20%
renewable share for IPC, and a 20% renewable share for the other Northwest
region BAAs not participating in the EIM.
Summary of results
The base scenarios analyzed through this conservative approach resulted in
modest positive sub-hourly dispatch cost savings in 2020 for IPC of $4.5 million
in the EIM. IPC participation also provides incremental savings to other EIM
participants. These savings are largely robust to the additional retirement of
regional coal generation or the absence of planned APS and PGE participation in
the EIM, with savings to IPC remaining above $4 million in all scenarios. A higher
RPS would result in larger benefits for IPC participation, estimated at $5.1
million per year.
Page I Si Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 13 of 40
Introduction
1 Introduction
Idaho Power Company (IPC) engaged E3 to analyze the potential economic
benefits of IPC's participation in the Western EIM. This study seeks to identify
the savings potential of IPC's participation in the Western EIM and includes a
parametric sensitivity analysis to test the robustness of savings results.
Sensitivity scenarios include early retirement of certain coal plants in the West,
altered participation of other BAs in the EIM, and the penetration level of
intermittent renewable resources.
1.1 Context for Study
Utilities throughout the WECC have been increasingly interested in exploring a
wider range of opportunities for improved coordination between neighboring
BAAs. These have included the
+ Western EIM (previously referred to as the CAISO EIM), which
allows for a voluntary 5-minute market. The EIM began operating in
November 2014 with PacifiCorp and CAISO as initial members. NV
Energy began participating in 2015. Puget Sound Energy and Arizona
Public Service have announced participation to begin in 2016.
Portland General Electric Company has announced participation to
begin in 2017.
© 2016 Energy and Environmental Economics, Inc. P a g e 1 9 1 Exhibit No. 4
Case No. IPC-E-16-19
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Idaho Power Energy Imbalance Market Analysis
+ Northwest Power Pool investigation of a SCED for real time sub­
hourly transactions, similar to an EIM, as well as other opportunities
to promote more active and liquid 15-minute trading in the region.
A number of studies have highlighted the benefits of improved regional
coordination, particularly in a context of higher renewable and intermittent
resources on the system. These types of resources incur higher variability and
forecast error for each BA, and without regional coordination each individual BA
would be forced to maintain higher flexibility to combat this increased
intermittency. IPC engaged E3 to conduct a comparative study of the impact and
potential savings from IPC participation in the EIM. E3, working with Energy
Exemplar, analyzed IPC participation using a three-stage zonal production
simulation model of the Western Interconnection in PLEXOS. This study was
done in close coordination with Energy Exemplar and IPC staff.
1.2 Structure of this Report
The remainder of this report is comprised of the following sections:
+ Section 2 describes the key study assumptions and methods used in
this analysis.
+ Section 3 presents the results of our analysis of IPC participation in
the Western EIM.
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Case No. IPC-E-16-19
K. Anderson, IPC
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Study Assumptions and Approach
2 Study Assumptions and
Approach
2.1 Overview of Approach
The Western EIM allows participating Western BAs to voluntarily participate in
CAISO's real-time energy market. EIM software dispatches generation across
participating BAAs every 15 and 5 minutes to solve imbalances, as well as
committing quick-start generation every 15 minutes using security constrained
unit commitment (SCUC). An important distinction between the EIM and a
Regional Transmission Organization is that in the EIM each participating BA
remains responsible for meeting its own operating reserve and planning reserve
requirements, and the EIM does not replace participating BAs' existing
operational practices for unit commitment and scheduling in advance of real­
time.
This study quantifies the benefit of sub-hourly dispatch capability using a three­
stage simulation process in PLEXOS consistent with the approach developed for
the WECC Variable Generation Subcommittee (VGS) and refined in PNNL's Phase
1 Report for the NWPP MC Initiative. This methodology is described in detail in
Section 2.4 below.
© 2016 Energy and Environmental Economics, Inc. Pagellll Exhibit No. 4
Case No. IPC-E-16-19
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Idaho Power Energy Imbalance Market Analysis
This study is designed to measure one principal type of benefits: sub-hourly
dispatch benefits. Today, each BA in the Western Interconnection outside ofthe
EIM typically dispatches its own internal generating resources to meet
imbalances within the hour, while holding real-time exchange with neighboring
BAs fixed to the hour-ahead schedule. The EIM can net energy imbalance across
participating BAs and economically dispatch generating resources across the
entire EIM footprint to manage the imbalance, resulting in operational cost
savings. IPC's participation in an EIM enables incremental dispatch efficiency
improvements relative to an EIM without IPC.
This study does not quantify savings associated with flexibility reserve
reductions. Pooling flex reserves can reduce variable dispatch and generator
commit costs, especially as operators accumulate greater experience with the
EIM. However, each BA still needs to serve peak loads and provide system
flexibility; thus, participation in the EIM does not reduce the physical generation
capacity that a BA needs. Long-term capacity decisions are beyond the scope of
this report and are more appropriately examined using other analytical
approaches and modeling tools.
2.2 Sub-hourly Dispatch Benefits Methodology
2.2.1 PRODUCTION COST MODELING
This study used PLEXOS, a sub-hourly production cost model, to estimate sub­
hourly dispatch benefits in 2020. PLEXOS, like other production cost models,
simulates bulk power system operations by minimizing the variable cost of
operating the system subject to a number of constraints. PLEXOS includes a
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three-stage sequential simulation process to model DA, HA, and real-time
operations, as shown in Figure 1 below.
Figure 1. PLEXOS Three-Stage Sequential Simulation Process
DA load, wind and
solar forecasts
HA load, wind and
solar forecasts
Actual 10-min load,
wind and solar
Real-Tlme
Production Costs
Contingency,
regulation and load
following reserves
Contingency,
regulation and load
following reserves
Contingency and
regulation reserves
The primary purpose of the DA simulation is to generate daily unit commitment
schedules for long-start units, while the HA simulation determines the HA
dispatch as well as hourly interchange schedules between BAs. During the real­
time simulation, the "actual" load, wind, and solar data are used to generate
dispatch, and flexibility reserves are "released" so that the capacity reserved
from the HA simulation is allowed to serve real-time imbalances. The DA, HA,
and real-time sequential simulation approach allows PLEXOS to differentiate
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operations for BAs participating or not participating in the EIM. When a BA is
not participating in a real-time market, then: (a) interchange is unconstrained
during the DA and HA simulations; and (b) during the real-time simulation, the
HA interchange schedule is locked down, resulting in the BA managing its
imbalances with its own generation.
In contrast, during the real-time simulation, BAs participating in the EIM can re­
dispatch generation and exchange power with the rest of the EIM footprint
during each of the 10-minute intervals, subject to transmission transfer
limitations, which are discussed in Section 2.3.2 below.
While the Western EIM operates down to a 5-minute level in practice, the most
validated sub-hourly WECC dataset available for this analysis includes 10-minute
intervals. Using the 10-minute intervals is a practical but conservative
compromise of modeling 15-minute optimization with higher EIM transfer
capability and modeling 5-minute optimization with potentially more limited
EIM transfer capability across paths limited by dynamic transfer limitations
across the California-Oregon lntertie (COi) and BPA network. In the final stage,
the RT simulation for this study is run with 10-minute intervals, using actual
wind, load, and solar output for each interval. While actual EIM operations are
on a 5-minute basis, a complete and validated PLEXOS dataset for 5-minute
simulation was not available at the time of this study. This study's use of 10-
minute time step in the real-time stage (to make use of the WECC VGS dataset)
produces EIM benefits results that we expect may be conservatively low, as the
10-minute time step reduces the amount of variation within the hour to a small
extent, slightly moderating the need for operational flexibility that an EIM could
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provide. Overall, however, we expect the 10-minute time step to capture the
majority of the real-time dispatch efficiency savings.
2.2.2 BAU SIMULATION
In the BAU case, IPC does not participate in the EIM, and must resolve its real­
time imbalances with internal generation only. IPC's real-time import and
exports are held fixed to the hour-ahead schedule.
Real-time sub-hourly interchanges are simulated among BAAs that are modeled
as existing participants in the Western EIM, reflecting the operational
efficiencies realized by the EIM before including IPC participation. In other
words, the Western EIM is assumed to be fully operating without IPC's
participation. As a result, savings and efficiencies associated with sub hourly
dispatch for each alternative are included in the system cost. These costs serve
as the "control" case to compare against the cases with IPC participation.
The BAU case includes operations of a "current EIM" consisting of the seven BAAs
that were participating or had announced plans to participate in the EIM at the
start of this study. The BAAs modeled as current participants in the EIM for the
BAU Case are listed in the table below.
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Table 3: BAA Participants in EIM in BAU Case
Current EIM part1c1pants
for BAU Case
CAISO
PacifiCorp East (PACE)
PacifiCorp West (PACW)
NV Energy (NVE)
Puget Sound Energy (PSE)
Arizona Public Service (APS)
Portland General Electric (PGE)
2.2.3 WESTERN EIM SIMULATIONS
The EIM cases simulate real-time dispatch with IPC participating in the Western
EIM. In each of these cases, intra-hour interchange between IPC and existing
EIM participants is allowed up to the assumed transmission transfer limits.
2.3 Key Modeling Assumptions
Three key modeling assumptions are important for understanding the results of
this study: (1) sub-hourly dispatch; (2) real-time transmission capability; and (3)
hurdle rates.
2.3.1 SUB-HOURLY DISPATCH
In existing operational practice, BAs in the Western Interconnection exchange
energy primarily on an hourly basis using hourly or multi-hour schedules, or
standardized energy products which include On-Peak, Off-Peak, and Flat energy
blocks. These products require long lead times between scheduling the
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transaction and actual dispatch.7 Within the hour, each BA resolves imbalances
by dispatching generating resources inside its BAA, without the assistance of
other BAs. By contrast, the EIM optimizes dispatch of available generating
resources in real time across all of the participating BAAs using 15-minute unit
commitment and 5-minute dispatch. These sub-hourly processes increase the
efficiency of resolving imbalances.
2.3.2 REAL-TIME TRANSMISSION TRANSFER CAPABILITY
Previous studies have indicated that transmission can constrain EIM benefits by
limiting the amount of power that can be transferred in real time between
participants. This study's transmission topology was built on that of E3's PGE
EIM study from 2015 and was updated with the help of IPC transmission
experts.
IPC's BM has direct connections with six other BMs: AVA, BPA, PACW, PACE,
NVE, and NWMT. IPC has significant transfer capability with both PACE and
PACW. In the BAU Scenario (without IPC participating) PACE and PACW were
assumed to have only 200 MW of east to west dynamic capability between
them available for incremental EIM transfers not scheduled in the hour ahead. A
zonal depiction of IPC's transmission interconnections is shown in Figure 2.
7 The Western EIM and AESO are the exceptions.
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Figure 2. Real-time Transfer Capabilities with IPC
2.3.3 HURDLE RATES
Within the Western Interconnection's bilateral markets, there are a number of
impediments to efficient trade of energy across BAA boundaries. These include:
+ The need, in many cases, for market participants to pay for the fixed
costs of the existing transmission system by redirecting or acquiring
additional point-to-point transmission service in order to schedule
transactions from one BAA to another;
+ The current tariff practice of requiring short-term transactions to
provide real power losses for each transmission provider system that is
utilized, in some cases resulting in multiple or "pancaked" loss
requirements that are added to the fixed costs described above; and
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+ Inefficiencies related to having illiquid bulk power and transmission
service markets and imperfect information, such as DA block trading
products, minimum transaction quantities of 25 MW, and the bilateral
nature oftransaction origination and clearing.
These real-world barriers to trade are reflected in production cost simulations
as "hurdle rates", which are applied as $/MWh price adders to energy transfers
on interfaces between BAAs. Hurdle rates are applied in the DA and HA cases to
inhibit power flow over transmission paths that cross BAA boundaries, to
represent these inherent inefficiencies and reduce economic energy exchange
between BAAs.
The EIM eliminates the barriers listed above during real-time operations by
performing security-constrained economic dispatch across the entire EIM
footprint, allowing more efficient (i.e., lower cost) dispatch. Our production
simulations in PLEXOS capture this effect by removing hurdle rates in real time.
Intra-hour exchanges among participants in the EIM are allowed during the real­
time simulation cases. The simulation does not allow incremental intra-hour
exchanges (beyond the HA schedule) between BAAs that are non-participants in
an EIM. The absence of hurdle rates in real time in this analysis is consistent
with the FERC-approved CAISO tariff amendment associated with the EIM.
In the DA and HA simulations, hurdle rates are maintained between all BAAs,
including between EIM participants. We believe this is a conservative
assumption regarding the expected adaptation of DA and HA markets based on
information identified by the EIM. In reality, we expect that BAs may adjust their
DA and HA scheduled transactions more efficiently over time based on learning
the dynamics of the real-time market results. This learning does not imply a shift
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away from DA and HA scheduling, but rather a more efficient and better
informed selection of scheduling levels for any hour based on learning from
real-time market participation. To the extent it can be realized, this opportunity
for learning and improved DA and HA efficiency is a non-quantified benefit that
would be additional to those quantified in this report.
In addition to the hurdle rates described above, charges for CO2 import fees
related to California Assembly Bill (AB) 32 are still applied to energy transfers
from BAs outside of California to California BAs. These charges are applied in all
cases, including real-time.
For interties among the current EIM participants, hurdle rates were applied to the
DA and HA cases, but removed during the real-time case runs for both the BAU
and EIM cases.
2.3.4 FLEXIBILITY RESERVE REQUIREMENTS
By pooling load and resource variability across space and time, total variability
of the combined net load for participants in the EIM footprint can be reduced,
decreasing the amount of flexibility reserves required to ensure reliable
operations. This reduces operating costs by:
• requiring fewer thermal generators to be inefficiently committed and
operated, and
• decreasing flex reserve requirements placed on hydro resources,
enabling them to more efficiently generate energy at times most
valuable to their systems.
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Units that provide regulating reserves must respond faster than the EIM's 5-
minute dispatch interval, so EIM participants are assumed here to receive no
regulating reserve diversity savings as a result of participation in the EIM.
While there is currently no uniformly defined requirement for BAs to carry
flexibility reserves, all BAs must maintain Area Control Error (ACE) within
acceptable NERC-defined limits, which necessitates that BAs hold reserves on
generators to respond to within-hour changes in load and variable resource
output. These reserve needs will grow under higher renewable penetration
scenarios.
Additionally, in December 2014, the CAISO implemented a flexible ramping
constraint in the five-minute market optimization to maintain sufficient upward
flexibility in the system within the hour.8 Generators that are chosen to resolve
a constraint are compensated at the generation shadow price, which reflects
the marginal unit's opportunity cost. Furthermore, the CAISO is in the process of
introducing a flexible ramping product, which would allow economic bids to be
submitted to procure upward and downward ramping capability.
The CAISO's calculation of flexible ramping constraints for EIM participants is
adjusted to reflect diversity of net loads for all participants, subject to
transmission constraints. The CAISO determines flexible ramp constraint
8 See CAISO, 2014, Flexible Ramping Constraint Penalty Price In the Fifteen Minute Market. Available at:
http://www.caiso.com/Documents/TechnicalBulletin-FlexibleRampingConstraintPenaltyPrice­
FifteenMinuteMarket.pdf. See also CAISO , 2015, Flexible Ramping Products Revised Draft Final Proposal.
Available at:
https://www.caiso.com/Documents/RevisedDraftFinalProposal-FlexibleRampingProduct-2015.pdf.
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requirements for the CAISO and each EIM participant based on the aggregate
load, wind, and solar resource forecasts and expected variability. By establishing
the requirements based on the aggregate load and resource profiles, the
benefits of diversity can be reflected in the EIM flexibility reserve requirements.
The flexible ramping constraint in the EIM also compensates resources for their
contribution to meeting the flexibility constraint.
In the simulations run for this study, flexibility reserves were not adjusted to
reflect net load diversity in any scenario (BAU and EIM case). This means that
the benefits found in this study do not include benefits arising from reductions
in flexibility reserves upon joining the EIM. In a previous study, E3 estimated
that PGE would receive $0.8 million in additional savings due to reduced
flexibility reserves from joining the Western EIM.
2.4 Detailed Scenario Assumptions
2.4.1 INPUT DATA
The initial dataset used for this study is the database used in E3's PGE EIM
Comparative Study: Economic Analysis Report:9, which updated the database
from E3's 2014 EIM study for Puget Sound Energy with input from PGE along
with representatives from several northwestern BAs. The 2014 PSE database
applied PSE-and CAISO-specific updates to the database originally developed
for the NWPP Phase 1 EIM analysis.
9 See E3, 2015, PGE EIM Comparative Study: Economic Analysis Report. Available at:
http://edocs.puc.state.or.us/efdocs/HAD/lc56had152028.pdf.
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This study for IPC further refined the study database used in the PGE EIM
analysis. These refinements are described below in more detail. Utilizing this
database allowed this study to reflect the best available information compiled
to represent BAAs in the Northwest.
This study made the following key updates to the case:
+ Topology updates. The 2015 PGE EIM study was used as a starting point
for topology data. Major changes include removing a transmission link
from SCL to IPC zones because it is a link to SCL-owned hydro generator
at Lucky Peak, not the SCL balancing authority area. Additionally, E3
updated the line rating for the link between Northwestern and IPC to
reflect the latest WECC path ratings.
+ Gas prices. Monthly 2020 hub prices came from OTC Global Holding
Natural Gas Forwards & Futures (provided by SNL) for selected hubs in
the West region.10 As in the PGE EIM study, these data were translated
from hub prices to BA-or plant-specific burner tip prices using the
mapping of pipelines, variable transport fees, and other adjustments
outlined in the NWPP Phase 1 assessment.
+ Hydro optimization window. In practice, IPC plans its dispatch of
flexible hydro units up to a week in advance to optimize the value of its
reservoirs. This flexibility of hydro generation is prominent in the
Northwest. Yet modeling hydro as such in PLEXOS runs the risk of
unrealistically optimizing hydro dispatch with perfect foresight over a
very long time horizon, without reflection of forecast error in identifying
when the hydro will most be needed. Therefore, to balance
dispatchable hydro units and maintain flexibility, while preventing
10 Obtained from SNL Financial LC on October 15, 2015
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perfect foresight, dispatchable hydro units for this study are optimized
with a 24-hour optimization window. In this study, hydro modeling is
handled through a series of interactions between simulation stages:
monthly hydro energy budgets, which are database inputs, are allocated
to each day using PLEXOS's monthly MT simulation based on anticipated
load, wind, and solar across the month. Then, the DA and HA simulation
stage first optimizes the hydro for each hour based on a DA and HA
forecast of hourly load, wind and solar, constrained by the daily
generation budget. The RT simulation is permitted to update the hourly
hydro schedule across the day to respond to real-time needs within
each of the six 10-minute sub-hourly intervals each hour but must
maintain the same daily hydro energy total.
+ Renewable generation updates in California. Consistent with the PGE
EIM study, this analysis has also updated the CAISO renewable resource
mix to reflect a higher expected share of solar PV in the 2020 renewable
resource portfolio and lower share of wind resources, based on current
and planned additions for meeting the state's 33% RPS target by 2020.
The resource mix was also adjusted to include additional rooftop PV
solar in the CAISO, which was not reflected in the original TEPPC model.
+ Generation updates in the Northwest. In order to collect and verify
generator data for the PGE EIM study, PGE arranged discussions with
experts from several northwestern BAs, including IPC. The data
collected from these sessions were integrated in the PGE study
database. For this study, IPC reviewed and largely maintained this data,
making minor changes to its generator fleet. In the early coal retirement
scenario the following units were retired as well: Valmyl, Valmy2,
RdGrdnr4, Navajol, SanJuan2, SanJuan3.
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2.4.2 DISPATCH SAVINGS SCENARIOS
The dispatch savings were evaluated under 4 scenarios with different
assumptions regarding the current participants in the EIM, the retirement dates
of coal plants throughout the west, and the buildout of renewable resources by
2020. The scenarios were developed based on input from IPC staff to highlight
changes that IPC believed both plausible to occur and also valuable to explore to
test the robustness of EIM savings. Table 4 summarizes the assumptions used
for each scenario modeled for calculating sub-hourly benefits.
Because IPC is interested in the benefits of joining the Western EIM11, this study
defines a base scenario that represents a plausible trajectory for the West's
operating environment in which IPC joins the Western EIM. This base scenario is
subjected to three sensitivities: (1) APS and PGE are assumed to not have joined
the EIM by 2020 as planned; (2) Certain coal plants in the West are modeled to
retire earlier than planned in the base case; and (3) significant renewable
generation is added in California and throughout the West.
11 In all scenarios but one, CAISO, PAC, NVE, PSE, APS, and PGE are assumed to be already participating in the
Western EIM in order to provide the most accurate baseline scenario, given the information available over the
course of this study. A single sensitivity scenario models APS and PGE as not having joined the EIM by 2020.
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1. Base
2. No APS or
PGE in EIM
3. Early Coal
Retirements
4. High RPS
Idaho Power Energy Imbalance Market Analysis
Table 4. Overview of EIM Scenario Assumptions
15% 33% 15% 35.0 CAISO, PACW, PACE, NVE, PSE, APS,
PGE, IPC
15% 33% 15% 35.0 CAISO, PACW, PACE, NVE, PSE, IPC
15% 33% 15% 31.3 CAISO, PACW, PACE, NVE, PSE, APS,
PGE, IPC
20% 40% 20% 35.0 CAISO, PACW, PACE, NVE, PSE, APS,
PGE, IPC
*PGE BAA includes non-PGE customers, resulting in a smaller renewable energy share of
BAA load than RPS target; CAISO RPS includes renewable energy from out of state imports,
does not reflect behind the meter PV generation.
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Table 5. Renewable Capacity Added in High RPS Scenario {MW)
Region Zone Wind Solar PV Geothermal
FAR EAST IPC 128
MAGIC IPC 132
TREAS IPC 112
PG&E VLY CAISO 2,489 1,973
SCE CAISO 514 1,724 491
SDGE CAISO 102
AVA NW 774
BPA NW 1,737 135
PGE NW 484
SMUD NW 498 616
TIDC NW 84
2.5 Methodology for Attributing Benefits to IPC and
Other Participants
To evaluate the benefits yielded by an EIM, we calculated the difference
between procurement costs in a business-as-usual case and in an EIM case.
There are three components of total procurement costs in our model: hour­
ahead net import costs, real-time imbalance costs, and real-time generation
costs. First, we define a few terms.
+ Hour-ahead net imports: the hourly difference between imports
and exports.
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+ Locational marginal price (LMP): a given BA's generation shadow
price in a certain time period (the cost of generating an additional
MWh of electricity).12
+ Real-time imbalance: the within-hour energy imbalance found in
the EIM cases, where trading occurs at 10-minute intervals.
+ Average LMP: the imbalance-weighted average of all EIM BAs'
LMPs.
Hour-ahead net import costs are calculated as the product of hour-ahead net
imports and the locational marginal price, and then summed over all hours in
the year. Real-time imbalance cost to a given BA is a 10-minute interval's
imbalance multiplied by that interval's average LMP, summed over all 10-
minute intervals in the year. Real-time generation costs include the variable
costs of energy production modeled in PLEXOS -fuel prices (updated by E3
based on OTC Global Holding Natural Gas Forwards & Futures data provided by
SNL), and variable operation and maintenance and unit startup costs (based on
the costs characteristics for units in the TEPPC database, but not directly
modified for this study).
Total savings associated with an EIM are the difference between the sum of
hour-ahead net import costs, real-time imbalance costs, and real-time
generation costs in the business-as-usual case and the EIM case. In all scenarios,
the hour-ahead simulation is identical for the business-as-usual and the EIM
cases, meaning the hour-ahead net import costs can be ignored in the
12 The minimum LMP used for calculating benefits was set to -$100/MWh, which is the model's penalty price for
overgeneration. In overgeneration conditions, renewable resources may be curtailed but also could require
replacement costs for renewable energy to fulfill RPS goals in some jurisdictions.
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calculation. Table 6 provides an example of benefits parsing that highlights the
methodology discussed in this section.
Table 6. Benefits Parsing in the Base Scenario, IPC in Western EIM
Costs (2015S m1ll1on)* Business-as-Usual Western EIM Savings vs.
EIM BAU
Real-Time Generation and $108.8 $110.1 ($1.3)
Import Costs
Real-Time Imbalance Costs ($0.1) ($5.9) $5.8
(Market Revenues)
Total Real-Time Procurement $108.7 $104.2 $4.5 Costs
Note: Individual estimates may not sum to total due to rounding. Positive values in the final
column represent cost reductions, or savings in the EIM case relative to the BAU.
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3 Results
3.1 Benefits to IPC
Table 7 below presents the simulated annual benefits of IPC participation in the
EIM in 2020 under each sensitivity scenario. Each cell in the table represents the
incremental benefit to IPC as a result of its participation in the EIM. These
savings are each calculated as the reduction in cost compared to the IPC BAU
case. Overall, the dispatch cost savings range from $4.1 million in the early coal
retirement scenario to $5.1 million in the high RPS scenario. Reduced reserves
would provide additional savings in addition to these figures, though reserve
reductions were not modeled for this study.
Table 7. Annual Benefits to IPC by Scenario, EIM (2015$ million)
Sensitivity Scenarios
No APS/PGE in EIM $4.2
Early Coal Retirement $4.1
High RPS $5.1
*Dispatch cost savings for Sensitivity Scenarios are shown as alternatives to the Base case,
not cumulative additions. Reserves savings were not modeled.
EIM base scenario savings to IPC were $4.5 million with a decrease in annual
real-time procurement costs (real-time generator production cost plus real time
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imbalance cost of purchases and revenue from sales) from $108.7 million in the
BAU case to $104.2 million in the EIM case (a reduction of more than 4%).
Section 3.3 goes into more detail for each sensitivity scenario.
3.2 Incremental Benefits to Current EIM Participants
Table 8 below presents the simulated incremental benefits resulting from IPC's
EIM participation to the current participants in the EIM. IPC's EIM participation
is expected to create $2.2 to $3.1 million in yearly savings to the current EIM
participants across all scenarios.
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Table 8. Annual Benefits to Current EIM Participants by Scenario
(2015$ million)
Incremental
Scenario savings to
Ex1st1ng EIM
Part1c1pants
Sensitivity Scenarios
No APS/PGE in EIM $2.2
Early Coal Retirement $3.0
High RPS $3.1
*Dispatch cost savings for Sensitivity Scenarios are shown as alternatives to the Base case,
not cumulative additions. Reserves savings were not modeled.
3.3 EIM Results Discussion
3.3.1 BASE SCENARIO
The base scenario brings $4.5 million of savings to IPC, as well as $2.9 million to
the existing EIM participants. Various factors underlie EIM participation benefits
in the scenarios modeled. In all scenarios, EIM participation enables IPC to export
and import with other EIM participants in real time to respond to intra-hour
imbalances. As illustrated in Table 6, IPC's real-time generation costs increase in
the EIM, while its imbalance costs decrease by a larger amount. This is because, in
the EIM, IPC can export its hydro generation extremely flexibly at 5-minute
intervals, ramping the units up when LMPs are high and down when prices are
low. A second benefit of EIM participation is smoother operation of thermal units;
the real-time flexibility of the EIM prevents thermal generators from having to
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respond to within-hour imbalances (for the most part), decreasing ramping. This
flexibility also allows IPC to avoid starting and running its CT generators at times.
The following chart illustrates all the benefits described above, displaying IPC's
dispatchable generation in real time over a three-day period in the spring. In the
EIM dispatch chart, hydro output is highly variable at the 10-minute level, in
striking contrast to the smooth hydro output seen in the BAU case. Thermal
generation is perfectly constant in the EIM case, whereas ramping is required in
the BAU case. Furthermore, CT units are not used at all in the EIM case, whereas
CT units are started and turned off at least four times in the BAU case.
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Figure 3. IPC Real-Time Dispatchable Generation, Western EIM, April 28 -May 1
BAU
f4000 Net Load
2 eneration Types i 3000 ., hydro .. i: other
CT ... CCGT It:
coal
0 20 40 60 Hour
IPC in Western EIM
-Net Load a eneratlon Types i3000 ., hydro
f 2000 other
J,ooo CT ... CCGT It:
0 coal
3.3.2 ALTERNATIVE SCENARIOS
Modeling APS and PGE as not in the EIM slightly reduces the size of the total EIM
market and has a small downward impact on IPC savings relative to the base case,
to $4.2 million.
The scenario with additional retirement of regional coal generators produces
savings $0.4 million lower than the savings to IPC in the base scenario ($4.1
million in the early coal retirement case -$4.5 million in the base case). This
difference is less than 10% of total savings, and is thus also fairly insignificant,
indicating that model results for identified IPC savings are robust to participation
and coal resource retirement.
The high RPS scenario brings $5.1 million of savings for IPC, which is $0.6 million
higher than the savings in the base scenario. As expected, a higher renewable
Page 1341 Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 39 of 40
Results
generation buildout increased savings to IPC, as the EIM allows resources from a
wider area to address real-time variability in net load, and creates increased
revenue opportunities for IPC's flexible hydro generation in the real-time
market.
© 2016 Energy and Environmental Economics, Inc. Pagel35I Exhibit No. 4
Case No. IPC-E-16-19
K. Anderson, IPC
Page 40 of 40
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-16-19
IDAHO POWER COMPANY
ANDERSON, DI
I
TESTIMONY
EXHIBIT NO. 5
02/01/2016 1.0
04/30/2016 2.0
EIM Quarterly Benefit Report Methodology
Effective with Ql, 2016 EIM benefits report
Revision History
Lin Xu
Allow the ISO's units to be committed in Lin Xu
the counter factual dispatch
This document illustrates how the EIM benefit is calculated with an example. In the past, the ISO had
discussed the method in Technical Bulletins and in the benefit reports. This document consolidates
these prior materials into a concise paper for easier understanding.
The total EIM benefit is the cost saving of the EIM dispatch compared with a counterfactual (CF) without
EIM dispatch. The counter factual dispatch meets the same amount of real-time load imbalance in each
BAA without EIM transfers with neighboring EIM BAAs. For an EIM BAA, the benefit can take the form of
cost savings or profit or their combination. A BAA will be likely to have energy cost savings when the
BAA is importing energy economically, or its base schedules are being optimized by the EIM. A BAA will
be likely to have an energy profit when the BAA is exporting energy economically to other BAAs, and
being paid a price higher than the bid cost. A BAA, other than the ISO, may also have a GHG profit when
the resource is allocated GHG MWs, and is receiving GHG revenue based on marginal GHG cost that is
likely higher than its own GHG bid cost.
For each 5-minute interva I, EIM benefit for a BAA = counterfactual dispatch cost -(EIM dispatch cost +
transfer cost) + GHG revenue -GHG cost. Then the 5-minute level EIM benefit are aggregated every
month with a multiplier 1/12 to convert ($/5 min) to a dollar amount.
EIM benefit calculation components
EIM dispatch cost
The total dispatch cost for a BAA for an interval is the sum of all the unit level EIM dispatch cost for that
BAA and for that interval.
For all other BAA's other than CAISO, the dispatch cost only includes variable dispatch cost, i.e. the bids
submitted by the corresponding Scheduling Coordinator.
Exhibit No. 5
Case No. IPC-E-16-19
K. Anderson, IPC
Page 1 of 7
For the ISO's long start units, we only consider variable dispatch cost. For the ISO's short start units, we
use a generic cost formula, which includes variable dispatch cost, startup cost, and no load cost.
Specifically, the three-part cost include
• the variable dispatch cost of RTD, which is equal to the bid cost associated with the delta
instruction above or below the base schedule for each interval,
• the no load cost associated with the incremental dispatch, which is equal to the no load cost
divided by Pmax and then multiply it with the delta instruction from base schedule,
• the startup cost associated with the incremental dispatch, which is equal to the startup cost
divided by the minimum online hours, and then multiply it with the delta instruction from base
schedule divided by the Pmax.
The purpose for this generic cost formula is to evaluate cost differences between EIM dispatches and
counter factual dispatches without performing sophisticated unit commitment simulations. Prior to Ql
2016, only variable dispatch cost was considered in the EIM benefit calculation. With NV Energy joining
EIM and improving the transfer capabilities from and to the ISO, we observed significantly increased
transfer volume in EIM. The higher transfer volume cannot be sufficiently replaced by resources online
in EIM without committing or decomitting resources. That is why we adopted the three-part cost
formula starting from Ql 2016 to allow for unit commitment decisions to better evaluate the production
difference between EIM and the counter factual dispatch of the ISO. The unit commitments decisions
were made only for short start units that are not combined cycle units. The combined cycle units had
complicated models in EIM, so their counter factual commitment status are fixed at the EIM
commitment status to avoid oversimplification.
We approximate the ISO's commitment costs by converting the startup cost and no load cost into
variable dispatch cost, assuming a committed short start resource will be fully loaded for minimum
online hours. For each supply segment, the corresponding three-part variable cost is equal to
bid_price + no_load_cost/Pmax + startup_cost/min_up_hour/Pmax
Note the formula above converts startup cost (in unit$) and no load cost (in unit $/h) into variable
dispatch cost (in unit $/MWh). By doing this, the commitment for the ISO's units can be determined
based on the economic metric order of the three-part variable cost.
Transfer cost
As a convention, select the importing direction as the default direction for a transfer, so importing
transfer is positive and exporting transfer is negative. The transfer cost is equal to the transfer MW
times the transfer price. For an importing BAA, the transfer price is the LMP of the BAA minus half of the
absolute value of the transfer shadow price. For an exporting BAA, the transfer price is the LMP of the
BAA plus half of the absolute value of the transfer shadow price. Transfer could occur in both the 15-
minute market and the 5-minute market. In this case, the transfer cost is 15-minute transfer* 15-
minute transfer price+ (5-minute transfer-15-minute transfer) * 5-minute transfer price for each 5-
minute interval.
Exhibit No. 5
Case No. IPC-E-16-19
K. Anderson, IPC
Page 2 of 7
Counterfactual dispatch cost
The counterfactual dispatch for an EIM BAA mimics the market operations without importing or
exporting through the EIM transfers. The counterfactual dispatch moves units inside the BAA to meet
the same real-time load imbalance as the EIM dispatch without considering transmission constraints.
However, for PacifiCorp, the transfer limit between PACE and PACW is enforced in the counter factual
dispatch. Relaxing transmission constraints tends to under estimate the counterfactual dispatch cost
and the EIM benefit. However, because few transmission constraints were observed binding in EIM, it is
unlikely the EIM benefit will be significantly under estimated.
The counterfactual dispatch makes unit commitment decisions only for the ISO's short start units. The
unit commitment decisions are based on the generic three-part variable cost formula, which has
converted startup cost and no load cost into variable dispatch cost. So unit commitment can be
determined by the economic metric order of the three-part cost.
In cases where a counterfactual dispatch could not be produced for a BAA using available bids, the
highest bid dispatched will be extended as the marginal cost for procuring more supply. An EIM BAA
may restrict the pool of dispatchable units in the counterfactual dispatch if that the BAA's practice prior
to joining EIM was to balance real-time load from a limited pool.
ISO counterfactual dispatch
The ISO would need to meet load without EIM transfers in the counterfactual dispatch. The
counterfactual dispatch is constructed in the following way.
1. Calculate the ISO's net EIM transfer;
2. Economically dispatch resources from the ISO to replace the transfer
A. If the ISO is importing from the EIM,
a. Find the ISO's undispatched supply with the variable cost (bid and three-part converted)
greater than or equal to the transfer price;
b. Sort and stack the supply by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the transfer megawatts
B. If the ISO is exporting to the EIM,
a. Find the ISO's dispatched supply with the variable cost (bid and three-part converted)
less than or equal to the transfer point price;
b. Sort and stack them by the variable cost from high cost to low cost; and
c. Clear the supply stack from high cost to low cost up to the transfer megawatts
NV Energy counterfactual dispatch
NV Energy's counter factual dispatch is constructed in the following way.
1. Calculate the real-time net load imbalance for NVE;
2. Economically dispatch resources from NVE on top of the base schedules to meet NVE's net load
imbalance
A. If the net load imbalance is positive,
Exhibit No. 5
Case No. IPC-E-16-19
K. Anderson, IPC
Page 3 of 7
a. Find NV Energy's bid-in supply above base schedules;
b. Sort and stack them by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the net load imbalance.
B. If the net load imbalance is negative,
a. Find NV Energy's bid-in supply below base schedules;
b. Sort and stack them by the variable cost from high cost to low cost; and
c. Clear the supply stack from high cost to low cost up to the net load imbalance.
PacifiCorp counterfactual dispatch
PacifiCorp East BAA and PacifiCorp West BAA would need to meet demand without intra-hour transfers
between PacifiCorp and the ISO, but transfers could occur between PACE and PACW in the
counterfactual dispatch. The PacifiCorp counter factual dispatch will be constructed in the following
way:
1. Calculate the real-time net load imbalance for each BAA;
2. Economically dispatch resources from the limited pool on top of the base schedules to meet net
PacifiCorp load imbalance without violating the transfer limitations between PACE and PACW.
A. If the net load imbalance is positive,
a. Find PacifiCorp's bid-in supply above base schedules;
b. Sort and stack them by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the net load imbalance subject to
the transfer limit between PACE and PACW
B. If the net load imbalance is negative,
a. Find PacifiCorp's bid-in supply below base schedules;
b. Sort and stack them by the variable cost from high cost to low cost; and
c. Clear the supply stack from high cost to low cost up to the net load imbalance subject to
the transfer limit between PACE and PACW
GHG revenue
Greenhouse gas (GHG) revenue for a resource is equal to its GHG allocation MW times the GHG price.
GHG cost
GHG cost for a resource is equal to its GHG allocation MW times its GHG bid.
Example
This example illustrates how the EIM benefit is calculated.
The transfers out of the EIM optimization are listed below. Base scheduled transfers have been excluded
in the FMM transfers and RTD transfers.
Exhibit No. 5
Case No. IPC-E-16-19
K. Anderson, IPC
Page 4 of 7
PACE NEVP 140 $26 10 $3,890
NEVP CISO 160 $26 20 $30 $4,760
PACE PACW 190 $26 10 $25 $5,190
PACW CISO 110 $26 -10 $30 $2,560
BAA to BAA transfers and prices
Assume the EIM energy imbalance and prices are as follows. Every BAA is balanced with Gen+ Transfer
-Load = 0. Assume the EIM optimization results in $1 GHG price, which means the ISO's LMP is $1
higher than the neighboring BAA (NEVP and PACW), because there is no congestion going into the ISO in
the example. In the table below, positive transfer MW means the BAA is importing and negative transfer
MW means it is exporting. Also, transfers in the table are sum of the transfers occur in both the FMM
and the RTD with base scheduled transfer being excluded.
CISO 0 280 280
NEVP 50 20 -30 $30 $1
PACE 150 -200 i -350 $20 $1
PACW 100 200 100 $30 $1
EIM energy imbalance and prices by BAA for one 5-minute interval
Transfer cost
The transfers occur in both FMM and RTD, and their volume and prices are listed below. They are
calculated from applying the convention that importing is positive and exporting is negative the BAA to
BAA transfers, and summing them over all the neighboring BAAs.
CISO
NEVP
$7,320 = $4,760+$2,560
($870) = $3,890-$4, 760
Exhibit No. 5
Case No. IPC-E-16-19
K. Anderson, IPC
Page 5 of 7
PACE ($9,080) = -$3,890,$S,:t90
PACW $2,630 = $5,190-$2,560
EIM transfer cost by BAA
EIM dispatch cost
Now calculate the total bid cost associated with the EIM dispatches (delta from base schedules). The
EIM dispatch costs are listed below.
CISO t 0
NEVP 50 $1,450
PACE 150 $2,700
PACW 100 $2,800
EIM dispatch cost by BAA
Counterfactual dispatch cost
Then construct the counter factual dispatches as described in the previous section, and sum up the
counter factual dispatch cost for each BM.
NEVP 20 $640
PACE -200 ($3,800)
PACW 200 $6,200
Counterfactual dispatch cost by BAA
GHG cost and revenue
The GHG costs associated with the 280 MW of importing transfer into CISO, and the revenues received
by the GHG allocated MWs in both FMM and RTD are listed below.
Exhibit No. 5
Case No. IPC-E-16-19
K. Anderson, IPC
Page 6 of 7
NEVP 0 0 $0 $0
PACE 200 200 $20 $200
PACW 70 80 $75 $80
GHG cost and revenue by BAA
EIM benefit
With all the cost and revenue for each BAA available, we can use the formula EIM benefit for a BAA=
counterfactual dispatch cost -(EIM dispatch cost + transfer cost} + GHG revenue -GHG cost to calculate
EIM benefit for each BAA.
NEVP $640 $1,450 ($870) $0 $0 $60
PACE ($3,800) $2,700 ($9,080) $20 $200 $2,760
r
PACW $6,200 $2,800 $2,630 $75 $80 $775
EIM benefit for one 5-minute interval
This calculation is performed for each 5-minute interval with unit $/hr. We convert the $/hr benefit into
the dollar benefit by multiplying 1/12. Then the 5-minute interval benefits in dollar amount can be
aggregated into the monthly benefit by summing all the 5-minute intervals in the month.
Exhibit No. 5
Case No. IPC-E-16-19
K. Anderson, IPC
Page 7 of 7
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-16-19
IDAHO POWER COMPANY
ANDERSON, DI
TESTIMONY
EXHIBIT NO. 6
California ISO 2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
www.ca iso.com
Benefits for Participating in EIM
July 28, 2016
Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 1 of 8
California ISO 2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
Revision History
Date Version
07/29/2016 1.0
MQRI/LXu/Copyright 2016 California ISO
Desert tlon Author
Lin Xu
Revision History
Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 2 of 8
California ISO 2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
Table of Contents
EXECUTIVE SUMMARY .................................................................................................................................... 4
EIM BENEFITS IN Q2 2016 ............................................................................................................................... 5
INTER-REGIONAL TRANSFERS ................................................................................................................................... 6
REDUCED RENEWABLE CURTAILMENT ..................................................................................................................... 7
FLEXIBLE RAMPING PROCUREMENT DIVERSITY SAVINGS ......................................................................................... 7
CONCLUSION ..................................................................................................................................................... 8
MQRI/LXu/Copyright 2016 California ISO Page 3 of 8 Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 3 of 8
California ISO 2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
Executive Summary
Th is is the "Quantifying EIM Benefits" report for the second quarter of 2016. The estimated gross
benefits for April, May and June 2016 are $23.60 million. This brings the EIM total benefits to $88.19
million since it expanded the real-time market to balancing areas outside the California ISO starting in
November 2014.
The total gross benefits for Q2 2016 increased from the last quarter driven by seasonal changes in
supply and demand. A similar trend was also observed in 2015 from Ql to Q2.
The benefit calculation method is described in a separate document.1 This analysis demonstrates the
El M's ability to select the most economic resources across the PacifiCorp, NV Energy and the California
ISO balancing authority areas (BAAs) that comprise the EIM footprint. The benefits quantified in this
report fall into three categories and were described in earlier studies.2
• More efficient dispatch, both inter-and intra-regional, in the Fifteen-Minute Market (FMM}
and Real-Time Dispatch (RTD}, by automating dispatch every fifteen minutes and every five
minutes within and across the EIM footprint, including the California ISO, PacifiCorp, and NV
Energy.
• Reduced renewable energy curtailment, by allowing balancing authority areas to export or
reduce imports of renewable generation when they would otherwise need to be economically
curtailed, and
• Reduced flexibility reserves needed in all balancing authority areas, which saves cost by
aggregating the load, wind, and solar variability and forecast errors of the combined EIM
footprint. This report quantifies the diversity benefits of flexibility reserves for the entire EIM
footprint.
Table 1 shows the estimated gross benefits summary for the second quarter of 2016 in millions of
dollars per EIM entity.
NV Energy 1.09 1.34 2.77 5.20
PacifiCorp 4.63 2.44 3.44 10.51
Total 8.27 6.03 9.30 23.60
Table 1: Estimated gross benefits shown are in millions and accrued in the second quarter of 2016
1 EIM Quarterly Benefit Report Methodology, https://www.caiso.com/Documents/EIM BenefitMethodology.pdf
2 PacifiCorp-ISO, Energy Imbalance Markets Benefits, http://www.caiso.com/Documents/PacifiCorp­
lSOEnergylmbalanceMarketBenefits.pdf
MQRI/LXu/Copyright 2016 California ISO Page 4 of 8 Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 4 of 8
California ISO 2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
One of the significant contributions to the EIM benefits are transfers across the balancing areas which
provide lower supply cost, even while factoring in the cost of compliance with greenhouse gas (GHG)
emissions cost when it is transferring into the ISO. As such, the transfer volumes are a good indicator of
a portion of the benefits attributed to the EIM. Transfers can take place in both the Fifteen Minute
Market (FMM) and Real-Time Dispatch (RTD). Generally, the transfer limits are based on transmission
rights and interchange rights that participating balancing authority areas make available to EIM, with the
exception of the PACW-ISO transfer limit in RTD. The RTD transfer capacities between PACW and the
ISO are dynamically determined based on the allocated dynamic transfer capability driven by system
operating conditions. This report does not quantify a BAA's opportunity cost that the utility considered
when using its transfer rights for the EIM.
Balancing authority areas may submit base scheduled transfers. These transactions occurred between
NV Energy and PACE. The EIM inter-regional benefits are calculated based on the transfer difference
between the EIM and the base schedule. This is because the benefits associated with base scheduled
transfers, to the extent that they exist, should be attributed to decisions made prior to the EIM, not to
the economic efficiencies gained through the EIM.
While market conditions will vary, the EIM continues to provide benefits to participating entities and
their customers as demonstrated in this report.
NV Energy's EIM benefits mainly reflect inter-regional transfer benefits resulting from intra-hour
transactions. This is attributed to NV Energy's optimization of its base schedules prior to submission to
the EIM.
Background
The EIM began financially-binding operation on November 1, 2014 by optimizing resources across the
ISO and PacifiCorp BAAs, which includes portions of California, Oregon, Washington, Utah, Idaho and
Wyoming. NV Energy, operating in Nevada, began participating in December 2015. The EIM facilitates
renewable resource integration and increases reliability by sharing information between balancing
authorities on electricity delivery conditions across the EIM region. The ISO started publishing quarterly
EIM benefit reports in January 2015. As other BAAs join the EIM, this report will expand to include the
benefits associated with their participation.
EIM Benefits in Q2 2016
Table 1 breaks out the estimated EIM gross benefits by each BAA per month. The savings presented in
the table show $8.27 million for April, $6.03 million for May, and $9.30 million for June.
MQRI/LXu/Copyright 2016 California ISO Page 5 of 8 Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 5 of 8
California ISO
Inter-regional Transfers
2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
One of the significant contributions to the EIM benefits is transfers across the balancing areas which
provide lower supply cost. Table 2 provides the 15-minute EIM transfer volume and the 5-minute EIM
transfer volume, both with base schedule transfer excluded. NV Energy and PACE had submitted base
schedule transfers. The EIM benefit is only attributable the transfers that occurred with EIM, but not
the base schedules submitted prior to the EIM.
The transfer from BAA_x to BAA_y and the transfer from BAA_y to BM_x are separately reported. For
example, in an interval, if there is 100 MWh transfer on top of base transfer from CISO to NEVP, it will
be reported as 100 MW with from_BAA=CISO and to_BAA=NEVP, and it will be reported as O MW with
from_BAA=NEVP and to_BAA=CISO in the opposite direction. The 15-minute transfer volume results
from EIM optimization in the 15-minute market with all bids and base schedules submitted into EIM.
The 5-minute transfer volume results from EIM optimization in the 5-minute market with all bids and
base schedules submitted into EIM, and unit commitments determined in the 15-minute market
optimization.
The ISO continued to export a significant amount of energy to NV Energy and PacifiCorp in this quarter,
which was first observed in Ql 2016. It is also worth noting that a significant level of energy that was
exported by the ISO consisted of renewable generation.
2016 April PACW
2016 April crso
2016 April NEVP PACE -2016 April PACE
2016 April PACE PACW ----2016 April PACW CISO
2016 May CISO NEVP
2016 May CISO PACW
2016 May I NEVP CISO
2016 May NEVP PACE
2016 May PACE NEVP
2016 May I PACE I PACW
2016 May
'
PACW CISO
2016 June I CISO I NEVP
2016 1 June I CISO PACW
2016 June I NEVP I CISO
2016 June : NEVP PACE
2016 June I PACE I NEVP
~
MQRI/LXu/Copyright 2016 California ISO
10,899
48,422
118,420
38,270
10,354
76,026
178,120
27,561
29,820
134,092
I 24 513 '
13,800
I 54,856
151,491
42,772
55,793
52,150
77,205
11,286
73,963
123,547
41,397
21,736
81,880
158,983
27,804
62,126
133,344
29 969 I ' I 2s,499
52,302
I 134,804
44,661
I s1,3o6
63,785
I 76,448
I
I
I
I
Page 6 of 8 Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 6 of 8
California ISO
2016 June PACE I PACW
~ 2016 June PACW I CISO
2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
36,809 I 52,867 i
!
36,723 I 39,296 I
Table 2: Energy transfers (MWh) in the FMM and RTD for the second quarter of2016
Reduced Renewable Curtailment
The EIM helps avoid renewable curtailments within the ISO, which has both economic and
environmental benefits. The EIM benefit calculation includes the economic benefits that can be
attributed to avoided renewable curtailment within the ISO. If not for energy transfers facilitated by the
EIM, some renewable generation located within the ISO would have been curtailed via either economic
or exceptional dispatch. The total avoided renewable curtailment volume in MWh for Q2 2016 was
calculated to be 67,373 MWh (April)+ 49,296 MWh (May)+ 42,136 MWh (June)= 158,806 MWh total.
The energy being exported by the ISO included a significant level of renewable generation.
The environmental benefits of avoided renewable curtailment are significant. Under the assumption
that avoided renewable curtailments displace production from other resources at a default emission
rate of 0.428 metric tons C02/MWh, avoided curtailments displaced an estimated 67,969 metric tons of
CO2 for Q2 2016. Avoided renewable curtailments may also have reduced the volume of renewable
credits that would have been retracted. However, this report does not quantify the additional value in
dollars associated with this benefit.
Flexible ramping procurement diversity savings
The EIM facilitates procurement of flexible ramping capacity in the FMM to address variability that may
occur in the RTD. Because variability across different BAAs may happen in opposite directions, the
flexible ramping requirement for the entire EIM footprint can be less than the sum of individual BAA's
requirement. This difference is known as the flexible ramping procurement diversity savings. Starting in
June 2015, the ISO implemented an automated tool to analyze historical uncertainties and calculate the
flexible ramping requirement for each BAA in the EIM. In Q2 2016, the flexible ramping requirement for
the ISO varied from 300 MW to 500 MW, the requirement for PACE varied from 91 MW to 150 MW, the
requirement for PACW varied from 60 MW to 100 MW, and the requirement for NVE varied from 80
MW to 100 MW. Due to the reduction in flexible ramping requirement associated with the larger EIM
footprint, the total requirement across the four BAAs varied from 400 MW to 530 MW.
The flexible ramping procurement diversity savings for all the intervals averaged over a month are listed
in Table 3. The percentage saving is the average MW savings divided by the sum of the four individual
BAA requirements .
MQRI/LXu/Copyright 2016 California ISO Page 7 of 8 Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 7 of 8
California ISO 2016 Q2 Report
Quantifying EIM Benefits, 07/28/2016
Sum of BAA requirements 777 770 758
Percentage savings 36% 36% 36%
Table 3: Flexible ramping procurement diversity saving for the second quarter of 2016
Under the current flexible ramping constraint design, the procured flexible ramping capacity can be fully
accessed in RTD. If the flexible ramping procurement in the FMM is beneficial, it will reduce the RTD
dispatch cost. With the EIM benefits being quantified on a 5-minute level, the benefit of flexible
ramping is fully captured in the RTD dispatch. The EIM benefits calculated at a 5-minute level includes
the savings'from procuring and deploying flexible ramping. However, this analysis does not breakout
the dollar savings separately because the savings are tightly integrated with the RTD dispatch.
Conclusion
The EIM continued to show significant benefits during the second quarter of 2016. The total benefits for
the quarter of $23.60 million are consistent with pre-launch studies, and reflect the transfer benefits of
a more robust EIM footprint, that includes both PacifiCorp and NV Energy.
MQRI/LXu/Copyright 2016 California 150 Page 8 of 8 Exhibit No. 6
Case No. IPC-E-16-19
K. Anderson, IPC
Page 8 of 8