Phase 2 Final Report

Phase 2 Final Report
Public Distribution February 5, 2014
Table of Contents
Executive Summary ........................................................................................................ 4
Approach........................................................................................................................ 9
Background ............................................................................................................................... 9
Implementation Plan............................................................................................................... 10
Phase 3 Workgroup Approach ................................................................................................ 11
Policy ........................................................................................................................... 13
3.1. Introduction ............................................................................................................................ 13
3.2. Phase 2 Deliverables ............................................................................................................... 16
Issue 1: Following Reserve Assistance Program ................................................................. 16
Issue 2: Data Sharing ........................................................................................................... 19
Issue 3: Bilateral Capacity Product and Platform................................................................ 20
Issue 4: Resource Sufficiency .............................................................................................. 22
Issue 5: Hydro Resources in EIM ......................................................................................... 26
Issue 6: Transmission Compensation .................................................................................. 27
Technical ...................................................................................................................... 30
4.1. Introduction ............................................................................................................................ 30
4.2. Phase 2 Deliverables ............................................................................................................... 32
Revised Costing ................................................................................................................... 32
Data Requirements ............................................................................................................. 36
Data Sharing Approach ....................................................................................................... 39
System Visibility and Data Sharing Tools ............................................................................ 42
Energy Imbalance Market Architecture .............................................................................. 47
Governance .................................................................................................................. 51
5.1. Introduction ............................................................................................................................ 51
5.2. Phase 2 Deliverables ............................................................................................................... 54
Summary of Draft Bylaws for EIM Admin Corp................................................................... 54
Overview of Supporting Documents ................................................................................... 56
NWPP General Services Agreement Discussion.................................................................. 57
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Table of Figures
Figure 1: Technical Dependencies ................................................................................................................ 7
Figure 2: Draft EIM Participant Cost Ranges ............................................................................................... 35
Figure 3: Draft EIM Participant Cost Range Totals ...................................................................................... 35
Figure 4: Data Requirements Matrix........................................................................................................... 36
Figure 5: Geographical Transmission Overview.......................................................................................... 44
Figure 6: Tabular Transmission Overview ................................................................................................... 45
Figure 7: Balancing Authority Geographical Overview ............................................................................... 46
Figure 8: Balancing Authority Tabular Overview ........................................................................................ 47
Figure 9: Systems Interface Overview ........................................................................................................ 48
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List of Tables
Table 1: Data Sharing Matrix ...................................................................................................................... 39
Table 2: Data Sharing Resolution Approach ............................................................................................... 40
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Executive Summary
The Northwest Power Pool Members’ Market Assessment and Coordination Committee
(“NWPP MC” or “MC”) Executive Committee (“EC”) authorized the funding of a three-month
effort (“Phase 2”) that, “completes the major market design policy questions left open at the
end of MC Phase 1, offering decision quality information on a potential Energy Imbalance
Market (‘EIM’) platform design, and navigating associated bilateral market enhancements
necessary to deliver a NWPP-footprint solution to the MC Objectives with or without an
This objective was comprised of five discrete components:
Address EIM design issues that were identified during Phase 1
Initiate data sharing objectives associated with regulation sharing
Refine “all-in” costs including Market Operator, Market Participant and other
requisite costs for starting and operating an EIM
Develop a Regional Implementation Plan that maximizes benefits and options (with
or without an EIM)
Provide illustrative Bylaws for EIM Administrative Corporation (“EIM Admin Corp”)
that would help shield its members from Federal Energy Regulatory Commission
(“FERC”) jurisdiction
This report communicates how each objective was met and outlines the recommendation
from the workgroups on options for moving forward into future Phases that was provided
to the EC. This report summarizes the Phase 2 work product outcomes.
Key Policy Outcomes
After a broad brainstorming session at the NWPP MC Phase 2 Kick-off Meeting, six market
design issues were identified as the core scope for the NWPP MC Policy Workgroup. The
Policy Workgroup held bi-weekly meetings with outside Subject-Matter Experts (“SMEs”)
over a ten-week period to develop an approach for each of the six core issues. While some
detailed design points remain open, the Policy Workgroup did not identify any
NWPP MC Phase 2 Work Order Objective
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insurmountable hurdles to developing a comprehensive set of regionally tailored EIM
Protocols, should the NWPP MC decide to pursue an EIM.
Key Technical Outcomes
The NWPP MC Technical Workgroup focused on operational and data requirements. The
group collaborated with both Southwest Power Pool (“SPP”) and the Western Electricity
Coordinating Council (“WECC”) to explore technical integration among the Market
Operator, Reliability Coordinator, and Market Participants, as well as to identify regional
technical infrastructure that would bolster reliability. The discussions helped solidify
roles, confirm costing assumptions, and provide an improved vision of how a Market
Operator would perform functions for the region.
The Technical Workgroup recommended partnering with Peak Reliability (“RC”)2 on a
contract basis for delivery of technical services required to enhance the reliability and
efficiency of existing bilateral markets, and to support a future Market Operator platform.
The services would be centered on leveraging Peak Reliability’s software and
infrastructure for proposed solutions centered on reliability and grid operations.
Costing Refinements
The cost assumptions related to EIM platform implementation were reviewed and the
Market Operator and Market Participant costs were refined. Additional cost elements for
requisite legal and reliability services were identified. There was a moderate reduction in
the Market Participant cost estimate from the Phase 1 estimate. The overall impact to the
Phase 1 Business Case was minimal. The Phase 2 cost assumption review reinforces the
findings in Phase 1 and provides greater overall cost certainty associated with EIM
During Phase 2, SPP and its members shared that SPP’s original cost-benefit study was
overly conservative. SPP delivered more benefits in the first year of their EIM operation
than originally estimated. This trend has continued in the seven years that the SPP EIS has
been operational.3
During the NWPP MC Phase 2, the WECC was in the process of transitioning its role as Reliability Coordinator to a
new entity named Peak Reliability. The MC workgroups based their outcomes and interactions on the assumption
that the Peak Reliability entity would go live in early 2014.
The SPP EIS is made up of primarily fossil fuel generation; expected benefits in the northwest region must be
calibrated for hydroelectric resources.
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Key Governance Outcomes
The primary deliverable for the governance drafting team was a set of draft bylaws for a
future EIM Admin Corp. The draft bylaws create a locally controlled entity that should not
be subject to FERC jurisdiction. While EIM Admin Corp may be outside of FERC’s
jurisdiction, the drafting team did not attempt to assess the jurisdictional implications
associated with participation in the EIM, but did assume that the Market Operator would be
FERC-jurisdictional. SMEs have suggested that leveraging an existing market design that
does not have a history of triggering FERC intervention can help minimize jurisdictional
risks associated with market participation.
Implementation Plan Summary
During the course of Phase 2, the workgroups shifted their focus from an assessment of an
off-the-shelf EIM platform, to the scoping of a bottom-up, regionally tailored market
coordination program4. The Workgroups recognized that achieving maximum regional
benefits would require a systematic, coordinated effort to enhance reliability within the
members’ footprint, improve the integrity of system operations within the hour, and
increase efficiency. The Workgroups found this could best be achieved through the use of a
security-constrained economic dispatch (“SCED”) platform across the NWPP members’
geographic footprint in combination with other appropriate regional solutions. To that
end, they recommended a collaborative development of regional infrastructure
improvements to provide better tools to enhance reliability outcomes across the region as
a foundational step towards coordinating on mutually beneficial operational projects. The
Workgroups believe this path allows the NWPP MC to follow the foundational work and
provides options for future improvements to the integrity of within-hour operations via a
resource sufficiency standard and further development of a bilateral capacity market. In
the final piece of the plan, the region would follow these steps with the development of a
SCED platform to increase the efficiency, stability, and reliability of within-hour dispatch of
the region’s resources.
It is important to note that the recommended Implementation Plan was specifically
developed as a phased project to provide the NWPP MC EC with functional flexibility,
sufficient funding lead-time and a path to an EIM that contains departure points for MC
Participants who may decide not to proceed to an EIM. Further, it was designed such that
The Workgroups believe the term SCED is more appropriate for the ultimate market coordination efforts they are
proposing; however, EIM remains the term most recognized by NWPP MC and therefore is used interchangeably
with SCED throughout this document.
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MC Participants would receive incremental value as a result of each phase and therefore
could expect to see a return on their investment of time and money in the intermediary
phases, even if not ultimately pursuing a coordinated market (EIM or SCED).
Three additional phases were defined based on functional breakpoints. The next phase
(“Phase 3”) calls for low-cost improvements to the region’s infrastructure that will serve as
a foundation for a bilateral capacity market, improved regional reliability, more efficient
bilateral markets, resource sufficiency policies, and ultimately a robust SCED platform.
This phase would be followed by the Resource Sufficiency phase (“Phase 4”). The objective
of Phase 4 is to develop the tools to perform forward (next day and next hour) feasibility
tests to ensure that each entity’s load can be reliably served at all times. Phase 4 also calls
for a rigorously applied, metric-based resource sufficiency requirement at the individual
entity level that will support further development of a liquid bilateral capacity market. The
last phase (“Phase 5”) would deliver 5-minute dispatch to the region, providing production
cost savings, automated congestion management, balancing of variable energy resources
and other reliability benefits.
Figure 1: Technical Dependencies
Supporting this overall approach, the RC supports the Implementation Plan and recognizes
reliability benefits associated with centralized congestion management, coordinated dayahead planning, robust modeling, and integration with real-time contingency analysis.
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A majority of the Workgroup members recommended that the MC members fund Phase 3
in 2014, and support, through direct staffing, the continued market design, governance and
technical development that needs to occur in advance of decisions for Phases 4 and 5.
The Workgroups believe that the Phase 3 objective of providing the region tools to allow
enhanced reliability and improved RC integration will enable increased inter-Balancing
Authority efficiency, provide an opportunity to more economically serve customers, and
provide the requisite platform for an EIM.
While diverse views remain on the ultimate question of whether to pursue an EIM for the
MC members’ footprint, those concerns were largely focused in three areas; 1) whether an
EIM will produce enough benefits for the Market Participants to outweigh the costs of
participating, 2) can the statutory imperatives of the Bonneville Power Administration
(“BPA”) be adapted to requisite EIM Protocols, and 3) whether FERC jurisdiction over an
EIM poses an unreasonable risk of expansion of FERC jurisdiction in the Northwest. It may
be that not all members in the Phase 2 effort will continue to support future phases, and
that some members choose to end their participation at the conclusion of Phase 3 or Phase
4. Allowing for this optionality is consistent with the idea that EIM Admin Corp does not
need to be created now, and that the NWPP Work Order process would be used to fund
Phase 3.
Lastly, it is important to note that the MC Workgroups were aware, while developing these
recommendations, that the CAISO EIM offering is being evaluated by some of the NWPP
members in parallel to this initiative. As a result, the MC Workgroups operated under the
assumption that if the region is going to have the option of moving forward with a NWPP
MC EIM, it would have to develop that option in a cost and time efficient manner that would
allow members to assess and act on the options in front of them.
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The Workgroups conducted a qualitative analysis of the major market-design and policy
issues that were left open at the end of Phase 1 of the MC Initiative. This report provides
information on the critical issues identified by the policy representatives who participated
in the Phase 2 effort from August 1, 2013 to October 15, 2013.
In making the following recommendations, the Workgroups have carefully considered the
broad range of views held by the MC members. The Workgroups recommend that after
consideration and discussion of this report, if the NWPP MC EC wishes to continue to fund
the NWPP MC effort, that the work plan, and its component phases discussed in this report
are an effective means of achieving the goals established by the NWPP MC and of
addressing the Problem Statement based upon available information and the time
In developing this recommended path forward, the Workgroups consulted with a number
of SMEs and, through them, a wide range of industry experts from across the country.5
These recommendations are tailored, to the extent possible, to the real-world operational
requirements of the MC members, respecting local control priorities of individual Balancing
Authority Areas (“BAs”) and self-scheduling utilities, recognizing the unique needs of BAs
that serve multiple Load Serving Entities (“LSEs”) within their Balancing Areas, and
protecting and enhancing the continuing evolution of existing bilateral markets. The MC
members’ original set of objectives, or Problem Statement, is as follows:
NWPP Balancing Authorities and scheduling utilities need additional tools to
respond to rapid changes in load resource balance (ramps) and the increasing
demand for balancing capacity driven by the growth of variable energy resources;
Utilities within the NWPP footprint are managing load and resource balance without
systematically sharing the diversity between their systems; this may be resulting in
increased costs and wear and tear on generating resources;
For example, discussions were held with current market monitors from other regions of the country on the
deployment of hydroelectric generation in their regions and how various operational constraints are viewed
by their Market Monitors.
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The region’s increasingly constrained transmission system would benefit from new
tools for congestion management and more efficient use of existing infrastructure;
The costs and compliance risks associated with operating a BA are increasing; this
has reinvigorated conversations on potential BA consolidation among interested
Evolving operation measures must clearly address cost causation and cost
NWPP members wish to recognize and, if possible, leverage existing platforms (such
as automated sharing of contingency reserve) and innovative and valuable work
from more recent initiatives within the NWPP footprint that deal with reliability,
renewables integration, and transmission congestion management, including efforts
by ColumbiaGrid, Northern Tier Transmission Group (and their joint initiative), and
the Wind Integration Forum. At the same time, these efforts would benefit from
greater focus, coordination, and commitment to implementation among a critical
mass of utilities;
It is very important to the NWPP members to preserve the existing value that they
already receive from the existing NWPP Reserve Sharing Program.
Implementation Plan
The Workgroups recommended that if the MC members decide to continue this regional
collaboration, they consider an additional three phases for the NWPP MC effort that will
provide an incremental set of steps to develop the regional tools and capabilities that are
the necessary precursors for a NWPP EIM to be efficiently, reliably, and sustainably
implemented. These steps include development of the following: a series of data sharing,
aggregation, and “dashboarding” of the members’ real-time systems, a set of bilateral
capacity market enhancements, a set of resource sufficiency metrics to establish a common
basis for EIM market participation, and the deployment of a security-constrained economic
dispatch (“SCED”) tool to create a NWPP EIM.
The Workgroups believe that the approach outlined below addresses these challenges and
opportunities in a balanced, incremental manner that will provide both MC members and
potential market participants with multiple opportunities to assess the value of the efforts
being undertaken and determine whether continued participation is of additional value to
the customers they serve. These ‘on-ramps’ and ‘off-ramps’ have been designed into not
only the contemplated governance structure that has been developed, but also into the
proposed project work plan. A majority of the Policy Workgroup believes that if the NWPP
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MC Executive Committee decides to continue to pursue the benefits of new market tools,
increased cooperation, and information sharing, the proposed path is the best vehicle to
meet these goals.
The Workgroups recognized that it would require a coordinated effort to enhance reliability
within the members’ footprint, to improve integrity of system operations within the hour,
and to increase efficiency through an EIM. They recommend a collaborative development of
system visibility enhancements to provide better tools to maintain reliability.6 This can be
followed by improvements to the integrity of within-hour operations via a resource
sufficiency standard and further development of a bilateral capacity market. Finally, the
Workgroups believe the Northwest could increase the efficiency of the within-hour
dispatch of resources at the operational and commercial level through the use of a SCED
The NWPP MC EC decided on January 2014 to fund Phase 3. There are additional decision
points that precede forming EIM Admin Corp and retaining a Market Operator as part of
Phase 5. The final decision point for the MC members would be to authorize the Market
Operator to deploy an EIM for the Northwest. These NWPP MC decisions will exist within a
broad context of other regional initiatives and opportunities that are expected to develop
over the next three years. The MC Workgroups have highlighted that it will therefore be
critical going forward that MC members consider parallel paths, dependencies, and funding
links between the items above and others that are not represented.
The proposed Implementation Plan supports the Problem Statement while giving each
member an off-ramp prior to each phase. Each phase was designed to deliver incremental
Phase 3 Workgroup Approach
The Workgroups recognized that Phase 3 requires several administrative and procedural
changes. First, there would need to be greater clarity on roles, responsibility and authority
of the respective committees, and workgroups, which will be tasked with the specific
bodies of work identified in the work plan. MC member executives will be strongly
encouraged to obtain additional SME/consulting/facilitation support for Phase 3 to
improve the probability that it will remain on schedule. Further, the MC members would
need to make significant internal staffing allocation and budget decisions in advance of
Phase 3 for it to be successful.
Examples include regional flow forecast, Generation visibility tools and Flow-based operational integration.
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The Workgroups recommended development of a NWPP MC Phase 3 Charter to provide
clarity to all MC members concerning lines of authority, decision-making structure, and
specific roles and responsibilities.7 The Workgroups also recommended that a Leadership
Committee of five representatives be established with leads that represent the diversity of
the NWPP MC Members and have the subject matter expertise necessary to guide the
members through this critical phase. The members of the Leadership Committee will
anticipate more than a “monitoring” role as they will be expected to plan to devote no less
than 20% of their time to this effort, with the Chair possibly devoting 100% of his or her
time. Under the Leadership Committee would be a set of Workgroup co-leads for each of
the major bodies of work. Members should expect that Workgroup co-leads would devote
100% of their time to this effort. Each Workgroup would be supported by one or more
internal or external SMEs. Finally, the Workgroups recommend that a Members and
Stakeholders Roundtable (“MSR”) replace the Organizing Committee group that was
utilized in Phase1, and to a lesser extent in Phase 2. The MSR would be a non-voting body
comprised of Phase 3 Member representatives at the Manager or Director level, regional
representative bodies such as the Public Generating Pool, Public Power Council, and
Northwest Requirements Utilities, and key stakeholders, such as the NWPP Reserve
Sharing Group and Operating Committee, and the RC. The MSR will be a clearinghouse for
updates on the project as it progresses, allowing members to voice their concerns at either
the Workgroup or Executive level to help guide the overall Phase 3 process.
A repeated point of friction during Phase 2 was concern by a few participants that they were not adequately
consulted before decisions were made, documents drafted, etc.
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The remainder of this Report outlines the MC Workgroups’ efforts over Phase 2 to address
the most significant market design and policy questions left open at the end of the NWPP
MC Phase 1. The findings of this Report provide a roadmap for a future EIM for the region,
as well as an assessment of the stand-alone bilateral market enhancements necessary to
deliver a comprehensive solution to the NWPP MC Members’ Initiative Objectives and
Problem Statement.
While considering the Policy Workgroup findings in this report, it is important to note the
following fundamental Market Design assumptions were made:
1. Market Participation in the NWPP EIM will be voluntary for BAs8;
2. The implementation of a NWPP EIM will hold non-participants harmless and will
not negatively impact existing regional efforts like the NWPP Contingency Reserve
Sharing Program;
3. If the NWPP EIM cannot deliver lower-cost generation to serve a market
participant’s load, that market participant will be no worse off and will serve their
own load with their own resources; and
4. A NWPP EIM will not adversely impact existing long-term bilateral contracts and
prescheduled transactions.9
These principles were broadly supported during the course of Phase 1 and the discussions
within the Policy Workgroup in Phase 2 and are critical to our understanding of the specific
issues discussed below.
Recognizing that Phase 1’s cost/benefit analysis could not be solely determinative of
whether the MC members would support the creation of an EIM, and realizing that there
was a vast array of issues associated with the possible creation of an EIM for the NWPP
If a BA chooses to join the NWPP EIM, that choice has implications for Load Serving Entities and generators within
the BA.
In SPP’s market design, energy that is delivered as scheduled will not be exposed to imbalance charges. The
transmission service reservation serves as a congestion hedge to mitigate congestion charges.
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members’ footprint, the Policy Workgroup quickly identified six critical policy issues that
needed to be addressed to inform the Executive Committee’s discussions. It was also
evident that there was a much larger set of issues that there would simply not be time to
discuss fully, given the limited time available. The Policy Workgroup adopted an “iceberg”
metaphor of “above or below” the waterline for determining criticality. Those issues that
were deemed “above the waterline” are discussed herein in some detail. Those issues that
are “below the waterline” are recognized as important, and in some cases critical for
success, but were not identified as necessary for informing the Executive Committee’s
decisions this year.10 Two significant issues that were deferred to Phase 3 are: 1) a full
legal review of BPA’s statutory ability to participate in an EIM and 2) the specific technical
regional integration issues associated with a standalone Market Operator model.
The Following Reserve Assistance Program (“FRAP”) conceived in Phase 1 was initially
seen as complementary to the existing NWPP Contingency Reserves Sharing Program and
was developed as a potential tool for future study. Given changes in FERC regulations
during the summer of 2013, there was a consensus to recommend that the FRAP, as
originally conceived in Phase 1, not be pursued, and instead, bilateral capacity market
options be developed that reflected market-based rate price formation preferences for
following capacity, while leaving open the option for future development of reliability tools,
such as regulation sharing, in other forums.
Data Sharing
During the course of Phase 2 it became clear that an EIM would require data sharing across
the NWPP MC members’ footprint and that doing so would improve reliability. Whether it
is sharing generation and load data, conducting regional flow forecast, or a common
methodology for determining potential transmission curtailments, there are benefits to the
NWPP MC members from better aggregating and sharing the real-time state of the
interconnected system. Additional data sharing is essential to enhance reliability and
establish a foundation for future market evolution. Sections 3.2.2, 4.2.3, and 4.2.4 describe
improvements that the Policy Workgroup supports and has recommended be pursued in
Phase 3, along with the bilateral capacity market developments.
Capacity Market Tools
For example, the Policy Workgroup recognized that Market Design entails a host of critical issues that could not
be fully explored and should be deferred to Phases 3 and 4.
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The Policy Workgroup recommends development of a standardized, 15-minute call/put
capacity product enabling agreement for use by NWPP MC members (and others). NWPP
MC members would be free to begin trading the product immediately, but would be under
no obligation to offer or purchase. Finally, the possibility of using either an existing market
transactional platform (Inter Continental Exchange (“ICE”) or WebExchange) or creating an
explicit pooling mechanism, perhaps with a centralized market clearing price, would also
support evolving bilateral market structures.
Resource Sufficiency
Resource Sufficiency is the concept that BAs must come to the operating interval with
balanced load and generation, including following and contingency reserves, so that there
is no opportunity for “leaning” on the capacity of other BAs. Resource Sufficiency for the
region needs to be checked on a day-ahead and hour-ahead basis with a consistently
applied metric to be effective. Resource Sufficiency is a prerequisite to an EIM because a
set of feasible resources must be made available for the SCED.
It is important to note that Resource Sufficiency is distinct from Resource Adequacy.
Resource Adequacy looks across a longer time horizon and addresses whether the mix of
'steel in the ground,' conservation, and demand-side management is expected to be
adequate to meet long-term peak load including reserve capacity. Resource Sufficiency
considers next day and next hour load forecast, known outages, locational constraints,
ramp times, and dispatchability of resources.
During Phases 1 and 2, MC members agreed that in order for an EIM to function properly
Resource Sufficiency would be required in the day-ahead and hour-ahead periods. Phase 3
will include defining and coming to consensus on detailed Resource Sufficiency metrics and
enforcement for all market participants. Resource Sufficiency metrics will ensure the
deployment of sufficient resources to meet all load service obligations, firm sales, all
ancillary service requirements and ramping and balancing needs with or without an EIM.
Hydro in an EIM
Early Policy Workgroup discussions disclosed significant concern over the ability of
hydroelectric generation to participate effectively in an EIM, and most critically, that
common, existing operational practices not be viewed after-the-fact as improper market
behavior by any potential Market Monitor. The Policy Workgroup consulted with several
market monitors that operate in other regions of the country where hydroelectric
generation is offered by Market Participants (though not to the extent it is in the NWPP
members’ footprint). While concerns remain, it appears that there are no insurmountable
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barriers to hydroelectric generation, as a resource type, participating in a NWPP MC EIM.
Substantial work will be needed to ensure that specific market rules (and Market
Monitoring function) and design elements accommodate long-standing regional practices
(i.e. coordinated project dispatch, modeling of transmission hubs, etc.) and the nature of
the inter-connected northwest hydroelectric generation system.
Transmission Compensation
The Policy Workgroup saw compensation for transmission system usage as an important
consideration in the overall EIM design.
Each transmission provider can ensure that EIM participants in the transmission provider’s
own footprint have purchased adequate transmission to cover their resource or load’s
access to the market. However, without a specific EIM transmission charge, individual
transmission providers would not have a mechanism to recover costs, if any, for EIM flows
that cross over their system (i.e. the source and sink are not in their transmission provider
footprint but the energy flows across their facilities).
Compensation for the use of transmission for EIM purposes (whether netting against
existing Point-to-Point (“PTP”) or Network (“NT”) transmission agreements or direct
payment by Market Participants who are not currently transmission customers) may be
necessary to prevent market distortions or “free rider” problems. The Policy Workgroup
recognized that added transmission compensation might reduce the SCED’s efficiency.
Finally, it is important to note that the potential inclusion of such compensation does not
define the Market Operator as a Transmission Service Provider (“TSP”). The Market
Operator will not administer a common transmission tariff.
Phase 2 Deliverables
3.2.1. Issue 1: Following Reserve Assistance Program
During the NWPP MC Phase 1 the participating BAs agreed to explore the possibility of
enhancing reliability through the sharing of Following Reserves via the Following Reserves
Assistance Program (“FRAP”). As a result of the Phase 1 analysis, the NWPP MC Executive
Committee authorized a shadow trial of the FRAP for the purpose of gathering certain data
on a consistent basis from all NWPP entities and assessing the feasibility of moving to a
Field Trial at some point in the near future. In the NWPP MC Phase 2, the Policy
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Workgroup discussed how this shadow trial will be executed, what data needs to be
collected, how each participant would determine its reserve requirement consistent with a
common standard or metric, and how the Following Reserves could potentially be priced in
a future Field Trial.
On July 18, 2013 the FERC issued a revision to its policies on Third-Party Provision of
Ancillary Services and clarified what had been known as the “Avista Rule” that had
prohibited the provision of ancillary services at market-based rates absent a very onerous
market screening. Specifically, the FERC will now permit the sale of imbalance energy
service (as well as the capacity to back such service) and Operating Reserves (with certain
showings11) at market-based rates to a transmission provider if they have implemented
intra-hour scheduling of transmission service. 12 During Phase 2, the Policy Workgroup
concluded that a FRAP Field Trial had barriers to implementation and less value to the
region than an enhanced capacity market would. The FRAP concept has potential
reliability benefits to assist BAs with large generation and load variations but will require
significant effort to implement. Therefore, the Policy Workgroup recommends that the
FRAP, as originally envisioned, be removed from the set of solutions being considered as
part of the NWPP MC efforts going forward for the reasons stated below.
Most parties with excess generation wish to monetize their capacity according to
opportunity costs and not just be paid for energy deployment. Assigning value
to the capacity would require either bilateral transactions or a marketing
platform. Achieving this would likely require a program similar to an EIM with
duplicative levels of cost and complexity.
There was concern with the potential settlement process and how to price the
product being delivered. It was determined that the effort required would be
better dedicated to future market design/development efforts for an EIM.
Many BAs that are dominated by relatively predictable load variability carry only
the amount of capacity needed to follow load within each hour, monetizing any
additional quantities, leaving little to share in a FRAP-type context.
For Spinning and Supplemental reserves, the party still has to show that it can be delivered in their service
territory with the same market-opportunity as hourly and 15-minute products (i.e. though readily available
dynamic schedules or other dispatch means, such as transmission provider business practices that allow for autoapproval of “emergency” tags).
144 FERC 61, 056, para. 13. The only remaining limitations apply to reactive supply, voltage control service
and regulation, and frequency response; which are not relevant to the NWPP MC effort.
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The initial assessment of potential FRAP benefits was likely overstated in two
areas. The first area is related to the assumption of how much capacity each BA
is carrying today. Most BAs do not carry the extra capacity used to run the
formula and benefits study in the initial FRAP study. The second area is related
to the event driven nature of FRAP. Entities are unlikely to call on FRAP as
frequently as assumed (it was envisioned as a point-in-time, or event-driven
program, not a continuous or automatic sharing as modeled), thus the benefits
are less frequently realized.
The region does not yet have a common standard for determining the adequacy
of following reserves, so parties were concerned with the possibility of
inequitable sharing if capacity sharing was not in some way standardized or
With the existing Reliability Based Control Program (“RBC”), there is recognition
that some amount of “pooling” already occurs that may reduce the potential
benefit of a FRAP.
With FERC’s change to the Avista Rule, Policy Workgroup participants saw a less
complicated opportunity to more directly buy and sell reserve capacity
bilaterally at an easily identified market-based rate.
Instead, the Policy Workgroup believes the focus should shift to a Capacity Backed
Imbalance Trading program for meeting one of the MC Objectives, of increasing the ability
to transact flexible capacity products to help BAs meet their reliability and efficiency needs
at least cost.
At the same time, the Policy and Technology Workgroups continue to see value in a broad
data collection effort with a goal of gathering a significant amount of data from NWPP MC
Members to inform all aspects of the NWPP MC efforts going forward. This data could be
used to run an analysis similar or identical to the analysis initially designed for the FRAP
Shadow Trial, but would not be limited to that purpose, and would not be intended to lead
to a FRAP Field Trial. Instead, this data would be used to meet reliability analysis
objectives and to inform future decisions of the NWPP MC Executive Committee, including
Resource Sufficiency standards and other required analyses with the ultimate goal to
enhance regional data sharing. As authorized and funded, the “shadow trial” will proceed,
but primarily as an exercise in gathering data to serve the purposes identified below, and
not in anticipation of a FRAP Field Trial.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
3.2.2. Issue 2: Data Sharing
The Policy Workgroup in Phase 2 identified the broader need for data collection and
sharing. In response to that need the Technology Workgroup was formed and then
identified a set of tasks to accomplish, determined the data requirements necessary to
achieve those purposes, and defined how that data will be used to achieve the purposes
identified. During the course of the Policy Workgroup meetings, several members
repeatedly raised the issue of the commercial sensitivity of certain resource planning data.
Some entities are very hesitant to share their data, especially near-term generation plans,
with other entities for fear of losing competitive advantage in the marketplace.13 A
majority of the Policy Workgroup and SMEs agreed that data sharing is a normal practice
throughout the industry and could improve reliability and efficiency outcomes in the
region. The specific technical and legal concerns around data sharing and avenues for
keeping data secure are discussed in Section 4.
During the course of the Technology Workgroup discussions, it became clear not only that
any future NWPP MC EIM would have to be coordinated with both the existing NWPP
infrastructure, but also that of the Reliability Coordinator, Peak Reliability. During the
course of exploring with Peak Reliability staff the technical specifications and requirements
of a NWPP MC EIM, it became clear that they perceived significant reliability value that
could accrue to the NWPP MC members from this effort.14 Further, that increasing the
validity of day-ahead schedules due to more informed Available Transmission Capacity
(“ATC”) postings and better assessments of schedule firmness day-ahead (“DA”), or a BA's
ability to keep a schedule firm within the hour would all enhance the reliability of the BAs
and Transmission Operators (“TOPs”) among the NWPP MC members.15 Most critical from
the RC’s perspective is creating the ability to manage real-time congestion, which they
currently have no means of doing. For example, the enhanced data would enable them to
address System Operating Limit (“SOL”) and Interconnection Reliability Operating Limit
Furthermore, some entities are reluctant to share their data with the reliability or transmission side of
certain organizations for fear that the wall between transmission function employees and merchant function
employees in the receiving organization is unduly permeable, again resulting in the disclosure of data deemed
to be commercially sensitive.
Details of this assertion are included in a separate memorandum document from Peak Reliability.
This initiative also has clear and immediate benefit to load serving entities as current practices have called into
increasing question the ability for a load serving entity to assess the true feasibility of the schedules it submits dayahead or hour-ahead, at times resulting in the inefficient practice of carrying duplicative reserves on one’s system
to be able to maintain load service in the event of schedule curtailments or other market delivery issues.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
(“IROL”) violations in an automated fashion that would materially decrease the risk of
another Sept. 8th/Southwest outage type of event. Non-automated tools (i.e. humans)
cannot coordinate system status and configuration among multiple BAs and TOPs as
quickly and accurately as automated systems.
Additional benefits that were identified include better management of unscheduled flows
and better predictability so that after corrective actions are taken during a reliability event,
the subsequent generation changes result in a reliable operating state. The availability of a
NWPP MC EIM, in combination with the RC’s Enhanced Curtailment Calculator (“ECC”)
would permit management of post-contingency flows to ensure operations within system
limits and move the region into a more reliable operating state. Aligning the NWPP
Reserve Sharing Group, the Peak Reliability RC and the NWPP MC EIM to permit creation of
a common platform could enable event-based dispatch and significantly improve
situational awareness.
Indirect benefits include improvements to the accuracy of the RC models and forecast data
through higher quality day-ahead planning. Collectively, reliability benefits would accrue
to the NWPP MC members who are BAs and TOPs, materially assist them in meeting
existing and contemplated reliability standards, and enhance their ability to avoid system
states that lead to unreliability of service to their customers.
3.2.3. Issue 3: Bilateral Capacity Product and Platform
The NWPP MC Phase 2 Policy Workgroup recommends moving forward with developing a
bilateral capacity product definition and transactional platform. This approach has been
made possible by the recent revision of the Avista Rule in FERC Order 784. As referenced
above, under this revision, FERC jurisdictional entities are now able to transact within-hour
energy (imbalance energy) at market-based rates under their existing market-based rate
authority for wholesale energy sales. These transactions can be pre-arranged via a
capacity transaction prior to the operating hour, which provides a firm commitment by the
seller to dispatch energy within the hour and deliver that energy to the purchaser through
conventional eTag protocols. These transactions will allow entities who are periodically or
seasonally “short” (as well as those who wish to find more efficient solutions to meeting
their supply) of the on-system capacity to meet their imbalance energy needs within the
operating hour to purchase that capacity from their regional counterparties. This approach
is designed to be a merchant-to-merchant transaction, but provides a vehicle for BAs to
procure the capacity they need to operate reliably during periods of increased load or
resource volatility. Further, this approach creates a vehicle for entities to transact capacity
prior to the operating day/hour to meet their Resource Sufficiency requirements in a
future SCED/EIM construct.
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February 5, 2014
For the initial phase of this market development, there are no incremental costs, regulatory
hurdles, or technology requirements beyond existing systems used for wholesale sales in
the bilateral markets.
Future capacity-backed imbalance energy trading could include:
Creating a bilateral platform similar to a bulletin-board service to make it easier
for counterparties to find each other in the market (e.g. ICE)
Developing a way for the capacity to be dispatched at any point within the
operating hour
Creating an option for the capacity to be delivered on “as-available”
transmission, consistent with principles of open access to transmission
Pooling capacity with a centrally cleared market price.
For illustration purposes, two examples of comparable capacity transactions are provided,
the first bilateral, the second via an automated process.
Example of manually processed CAP transaction (initial phase):
At 00:05 Entity 1 (E1) contacts E2 to purchase 50-MW of flexible capacity for the
upcoming operating hour, with a strike option for each 15-min period, to be
elected 20-min prior to flow.
E1 agrees to pay E2 $17/MW for the capacity and $48/MWh for any dispatched
E1 purchases transmission service from source to sink and submits an eTag with
0-MWh Energy profile and 50-Mwh Transmission profile for the upcoming hour.
At 01:07 E1 notices its wind facilities are trending below their projected forecast
for the hour and calls E2 to strike the dispatch option for 01:30 to 02:00 flow.
E2 bills E1 for capacity ($17 x 50 = $850) and energy (($48 x 50)/2 = $1,200)
Note: this arrangement could provide both increment and decrement capabilities by
setting the Energy profile to a point between 1 and 50MW at the start of the hour.
Example of an automatically processed CAP transaction (final phase)
At 00:05 Entity 1 (E1) checks the CAP dashboard and notices 50-MW total of
flexible capacity is posted as available at the Mid-C trading hub for the upcoming
operating hour, with a strike option for each 15-min period, to be elected 20-min
prior to flow.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
25-MW are posted by E2 at $27/MW capacity and $50/MWh for energy.
25-MW are posted by E3 at $13/MW capacity and $125/MWh for energy.
E1 agrees to purchase both products for the next hour.
E1 purchases transmission service from source to sink and submits an eTag with
0-MWh Energy profile and 25-MWh Transmission profile for each product for
the upcoming hour.
At 01:07 E1 notices its wind facilities are trending below their projected forecast
for the hour and strikes its dispatch option from E2 through the automated CAP
for 01:30 to 02:00 flow for 25MWh.
At 01:23 E1 notices its wind facilities are continuing to trend below their
projected forecast for the hour and is expecting a steep load pickup at the end of
the hour. E1 does not have sufficient on-system capacity to manage its
variability. E1 strikes its dispatch option from E3 through the automated CAP
for 01:45 to 02:00 flow for 25MWh.
The Index settles at $50 for the hour.
E2 bills E1 for capacity ($27 x 25 = $675) and energy (($50 x 25)/2 = $625)
E3 bills E1 for capacity ($13 x 25 = $325) and energy (($125 x 25)/4 = $781.25)
These examples illustrate how market participants who require additional capacity to
reliably serve their load within the hour would have market opportunities to do so in a
manner that prior FERC regulations had not permitted. Additionally, they illustrate how
market participants who have excess capacity may have an opportunity to monetize that
capability in a manner that the current day- and hour-ahead markets do not.
3.2.4. Issue 4: Resource Sufficiency
It is a well-established principle in organized markets across the country that generation
capacity sufficiency must be achieved in both day-ahead and again in real-time to protect
reliability of the interconnected system. Day-ahead resource sufficiency is necessary due
to the lead-time required to start-up and deliver energy from many generation units on the
grid. Relying on the commitment and start-up of generating units solely in real-time to
meet expected load may lead to reliability risks. Within-hour resource sufficiency is also
required due to changes in load forecasts, changes in variable resource output, as well as
generation and transmission contingencies on the grid that may all occur after the dayahead market and day-ahead resource sufficiency processes have been completed.
The Policy Workgroup has made a fundamental assumption that BAs retain their obligation
to load balancing and reliability compliance under the operation of a NWPP MC EIM.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
Another significant assumption is that all BAs would enter the within-hour EIM dispatch
“Resource Sufficient” and that this would be ensured prior to each delivery hour. As used
here, “Resource Sufficiency” means that each BA in the EIM members’ footprint must be
able to demonstrate to the Market Operator that the BA has firm access to sufficient,
dispatchable resources with transmission service to meet its forecasted balancing
requirement for the delivery hour. The purpose of this requirement is to ensure that
market participants are not “leaning” on the EIM for balancing capacity deficits.
An EIM performs a SCED of available resources across a market footprint to meet all
imbalances and create a more efficient dispatch solution for load-resource balance for each
five-minute dispatch period within any given hour. An EIM does not compensate market
participants for the capacity that backs the energy dispatched by the EIM and does not
procure or provide additional capacity to the EIM. Capacity needs for meeting imbalance
(aka. maintaining load-resource balance) at the BA level can vary widely depending on any
one entity’s expected predictability and volatility of resources and loads for any given hour.
These capacity needs can be expressed in terms of both quantity (gross ramping capability
within a given period) and quality (accuracy and speed of ramping within a given period).
The Market Operator would have contracts only with participating BAs and participating
load-serving entities (“LSEs”) and generators. A participating BA may have LSEs or
generators in its area that do not participate in the EIM market as a buyer or seller.
Consequently, those non-participating entities would not have contracts with the Market
Operator and would not owe a contractual obligation to the Market Operator to be resource
sufficient or demonstrate that status to the Market Operator. This is distinct from the
obligations they may have to their BA. BAs may or may not have contracts with their
interconnected LSEs and generators for the provision of data that the BA would need to
forecast balancing requirements for each delivery hour and to demonstrate resource
sufficiency. This is an open question, which will need to be resolved before moving
forward. Although LSEs are currently required to coordinate their daily and hourly
operating plans with their BA, not all BAs currently use those plans to forecast balancing
reserve requirements.16
In the NWPP MC members’ footprint, BAs are not operated in strict isolation. One BA’s
failure to meet its imbalance requirements (i.e. not procuring sufficient capacity to
It is not now known whether the TSP or BA may legally use the data for any purpose other than compliance
with a particular mandatory reliability standard or whether the data are sufficient for the demonstration of
resource sufficiency.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
maintain its load-resource balance) will physically affect adjacent BAs’ ability to reliably
run their systems. Therefore, in order for the EIM to operate reliably and produce
equitable results, each BA within an EIM footprint must take responsibility for ensuring the
integrity of the inter-connected system through their Resource Sufficiency – that is, their
ability to maintain load-resource balance across each and every hour, and each and every
five minute dispatch period, when they choose to participate in the EIM.
Assessment of each BA’s ability to maintain its load-resource balance may be part of an
overall EIM assessment of the reliability of each BA’s hourly schedule of the resources
available to meet its required energy and capacity to meet forecast load, operating reserves
and regulation.
Resource Sufficiency Principles
Each BA shall be responsible for ensuring its Resource Sufficiency for each fiveminute dispatch period through whatever means they choose (e.g. through market
purchases of firm capacity contracts, through on-system resources dedicated to
providing the service, or through other schedule-based parameters such as reducing
firm commitments).
Each BA shall be responsible for allocating capacity requirements among its
customers/loads, including collecting payment for the capacity resources that are
needed to maintain the BA’s load-resource balance17,18.
The EIM Market Operator will need to perform a Resource Sufficiency check on a
day-ahead basis and again prior to each market flow period, including a check for
deliverability (from both a capacity and transmission perspective), to ensure each
BA and, by extension, the BA’s embedded LSEs, have met their Resource Sufficiency
LSEs embedded in a BA’s boundaries shall retain the responsibility to acquire the resources to fulfill their load
service obligations. BAs may establish resource sufficiency requirements within their boundaries that require
embedded LSEs to identify the capacity resources used to meet their load and may seek to enforce scheduling
accuracy to limit the BAs exposure to imbalance both within, and across, scheduling periods.
Per the pro-forma Open Access Transmission Tariff (“OATT”), transmission service providers are required to offer
imbalance service to their transmission customers when feasible. The costs for providing this service are generally
recovered through the transmission service providers OATT ancillary service schedules. In the NWPP footprint,
transmission service providers generally provide this service through their BA function, using on-system resources
available to the BA.
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February 5, 2014
The EIM Market Operator will require that Resource Sufficiency, as a set of metrics,
is consistently applied and takes into account the specific load-resource balancing
needs of each individual BA and the LSEs within the BA boundaries (e.g. a BA or LSE
with a large amount of wind relative to its Firm commitments would likely have a
significantly greater Resource Sufficiency requirement in terms of both quality and
quantity than a BA or LSE with no wind and a very stable, predictable load for the
flow period).
The EIM Market Operator, or their delegate, will need to monitor Resource
Sufficiency in real-time such that if any BA’s or embedded LSE’s activity directly
results in the undermining of equitable, reliable operations of the EIM, the EIM
Market Operator, or their delegate19, will be able to take corrective action against
that BA to protect market outcomes across the members’ footprint.
EIM entities must be able to understand and apply the resource sufficiency standard
prior to participating in the EIM.
Resource Sufficiency Requirements
Put simply, Resource Sufficiency is the idea that a BA will have balanced load and
generation within each of the twelve, five minute dispatch periods within the hour that an
EIM would operate. Another way to consider this is –
Demand must always be equal to, or less than, Supply.
In determining a BA’s demand, both the native loads, reserves, and all firm export
obligations are considered within that hour. Similarly, the supply available to a BA must
include the minimum available output of generation it has within its BA area as well as the
firm imports available within that hour, including any purchased capacity. In determining
demand and supply, BAs rely upon forecasts. As such, both the methodology used and the
certainty required for these forecasts are important components of a potential Resource
Sufficiency standard for an EIM. For example, a day-ahead confidence level of 95% could
be required, whereas the hour-ahead confidence level could be set at 99.5% to assure all
market participants that all have a similar commitment to the integrity of the within-hour
operations of the system. While the development of a specific Resource Sufficiency
proposal is beyond the scope of this NWPP MC Phase 2 Report, due to the time available,
for informational purposes, this section provides general observations and some
Depending on the final market design and functional relationships established, it is expected the Market
Operator would work closely with the Reliability Coordinator to identify potential reliability concerns and
recommend corrective actions be taken by the appropriate, responsible entity.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
information on how resource sufficiency principles are applied in other regions, as
discussed by the Policy Workgroup.
3.2.5. Issue 5: Hydro Resources in EIM
Due to the large penetration of hydroelectric generation in the Northwest, issues
associated with the modeling, management and dispatch of hydro resources must be taken
into account when considering the implementation of an EIM. The issues can be broken
down into three main categories, though all three are interrelated and therefore cannot be
treated in isolation from one another. These are significant issues that will require a
tremendous amount of work during the drafting of market rules and market monitor
Market Design Considerations
It is critical that any market design specification considers the unique nature of hydro
resource management, and that this design permits the hydroelectric generation modeling,
resource management, and dispatch practices presently used in the Northwest. Specific
considerations include the existence of multiple cascaded hydroelectric generation projects
on river systems with interdependent storage and operational parameters and limitations,
as well as constrained interconnecting transmission. During Phase 3, market bidding and
dispatch timelines will be developed that are consistent with existing hydro management
practices. The eventual market design may need to consider whether to allow joint bidding
of interconnected projects/system basis, whether to have “must run” rules for hydro
resources and whether, or to what extent, run of river plants are considered dispatchable
vs. variable energy resources.
Hydro Resource Bidding Considerations
Developing bid curves for hydro resources can present unique challenges. Factors such as
physical generation constraints, physical flow constraints, environmental impacts and
constraints, and various statutory, regulatory, or contractual obligations all need to be
considered. Hydro managers will need to develop ways to do the following:
Submit bids and configure market dispatch responses consistent with
hydro/river system optimization.
Assign system level generation to load aggregation points in their base
Maintain flexibility to adjust their base schedules or include a dynamic
component to cover load variation within hour without exposure to congestion
prices, at least for network loads that may not be market participants.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
Maintain flexibility to deal with more uncertain flows due to the uncertainty of
whether economic bids will be dispatched or not.
• Assign economic bid value to decrement capacity as well as to increment
As the region moves through the market design process envisioned in Phases 3 and 4,
efforts should be made to ensure that members can incorporate lessons learned and best
practices from other regions that have faced similar challenges associated with hydro
resources participating in a within-hour market.20
Regulatory/Market Oversight Framework Considerations
The establishment of an EIM will change the regulatory framework of the region and will
make participants in a within-hour EIM subject to oversight of those transactions. Because
of the complexity of establishing a methodology to assign capacity value, as well as energy
value, to a hydro resource and its associated storage, it is critical that the market rules that
are established do not put members at undue risk of regulatory or market rule violations.
Rules around issues such as market power and economic/physical withholding can be
challenging when applied to the bidding behavior associated with hydro resources. Factors
such as opportunity cost, and non-market considerations (e.g. environmental trade-offs,
FERC Hydro-licensing requirements, and other operational constraints) must be
incorporated when developing market rules and compliance policy. While participation in
the NWPP MC EIM is voluntary, if an entity chooses to participate in the EIM, they will be
subject to oversight of their EIM transactions by the Market Operator, Market Monitor, and
potentially regulatory bodies.
3.2.6. Issue 6: Transmission Compensation
The NWPP MC EC must understand that no region of the United States has created an EIM
without previously having a single, common transmission tariff. The Policy Workgroup
does not want to minimize the policy and operational challenges the NWPP MC effort will
face in Phase 3 of having multiple TOPs, TSPs, and BAs reach a consensus and, consistent
with principles of open access to transmission, establish a common set of rates, business
practices, and revenue allocation methodologies without first establishing the formal
structure used in other regions of the United States for doing so. This critical step is
perceived as both difficult and fundamentally necessary. It will be challenging given the
region’s history of highly contentious transmission service provider ratemaking and
For example, NYISO and Hydro-Quebec market participants with sizable hydroelectric generation resource.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
business practice negotiations. Success will heavily depend upon NWPP MC Executivelevel commitment and engagement, as well as a willingness among multiple entities and
interests to abandon the status quo in favor of a new-era of grid-management and serviceprovider practices likely to benefit the NWPP MC members’ constituents.
The Policy Workgroup believes that sub-hourly EIM use of transmission should be
compensated, whether as a net against existing transmission service agreements or by
applying an incremental, non-firm rate for its use. It is also critical to understand that for
Load Serving Entities, having firm transmission is a form of “insurance” for assuring that
the load is served, and that by doing so the LSE has capped the potential cost of serving its
load in relation to the EIM.
The five-minute EIM dispatch utilizes “as-available” transmission. That is, only the
transmission flow capability available in real-time for immediate utilization by the SCED
would be used. Sub-hourly EIM flows are not intended to displace, or replace, existing
transmission service required to serve firm obligations, including serving load and
honoring export obligations. These pre-EIM-market-run transactions are currently
scheduled and tagged using a combination of Firm, Non-Firm, Network, and Re-directed
transmission service. With an EIM, purchasing transmission service could potentially be
avoided in areas with minimal, or predictable, congestion.21 On the other hand, on
congested paths, entities will likely schedule and tag transactions physically as a hedge
against price risk between nodes, with a potential increase in transmission service sales to
support those hedges. Each transmission provider can ensure that EIM participants in the
transmission provider’s own footprint have purchased adequate transmission to cover
their resource or load’s access to the market. However, without a specific EIM
transmission charge, individual transmission providers would not have a mechanism to
recover costs, if any, for EIM flows that cross over their system (i.e. the source and sink are
not in their transmission provider footprint but the energy flows across their facilities).
Additional Considerations on Transmission Pricing
There are competing theories with respect to charging for the non-firm, as-available
transmission currently anticipated to be used for energy deliveries. Because the energy is
not sold point-to-point, it will not be practical to follow the contract path paradigm in the
It should be noted that post-EIM operation the opportunity may exist for financial transactions (e.g. Contracts
for Differences) based on EIM SCED outcomes to displace tagged and physically flowed bilateral activity
associated with economic resource displacement (i.e. the replacement of generation from a more expensive
resource by that of a less expensive resource).
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
region. Furthermore, transmission charges on a per MWh basis may interfere with the
benefit of minimizing fuel costs that could be achieved by an effective real-time imbalance
market like the proposed EIM. On the other hand, transmission owners have a right to be
compensated for the use of their facilities. A lack of transmission charges for the EIM could
lead to reduced transmission revenues and possibly create an unwarranted cost shift
among transmission owners and customers.
The majority of the Policy Workgroup agreed that it would be preferable for the EIM
market design to include rules that would ensure compensation to transmission owners.
Such compensation should reflect the non-firm nature of the product. The details of the
compensation will need to be worked through the design process in Phase 3. It is
anticipated that the EIM market rules and governance structure would allow changes to the
transmission compensation, as warranted, to maintain equity among the transmission
users and promote an efficient imbalance market.
There is little reason to suggest that EIM transmission pricing should be lower than the
equivalent transmission pricing for 15-minute scheduling or dynamic scheduling deliveries
in the contract path model. Moreover, it is generally unwise from a market efficiency
perspective to offer discounted transmission pricing in any one temporal market and not
the others as this can lead to significant unintended consequences.22 The primary EIM
transmission pricing issue going forward should be the challenge of how to implement
existing Open Access Transmission Tariff (“OATT”) transmission charges (including credits
for transmission rights already owned) into a centrally dispatched, nodal market model
that spans multiple transmission providers’ systems.23
The FERC has generally recognized that selective discounting of transmission services violates the Federal
Power Act’s prohibition on undue discrimination and preference. Consequently, Commission policy generally
prohibits transmission service discounts except when necessary to increase throughput on a transmission
provider’s system and requires that any such discount be offered to all eligible customers for the same time
period on all unconstrained paths that go the same point of delivery.
Any discussion of region-wide lower transmission pricing and/or transmission rate consolidation across
multiple transmission providers’ footprints is best addressed as a regional topic outside the NWPP MC EIM.
Specifically, it should be recognized that reduced transmission rates and/or reduced or eliminated
transmission rate pancaking can improve dispatch efficiency in all of the forward, day-ahead, real-time and
EIM markets – there is no specific nexus uniquely to an EIM. At the same time, it must be recognized that
reduced transmission pricing and/or “rate pancaking” also generally comes at the expense of significant
transmission cost shifting amongst participants.
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February 5, 2014
The dual objectives of the Technology Workgroup in Phase 2 were to identify what, if any,
significant hurdles are apparent in the potential implementation of an EIM in the
Northwest and to chart a path forward to address the NWPP MC problem statement.
Significant hurdles were identified on the implementation path toward an EIM. The
hurdles primarily related to the lack of market formation experience and limited data
sharing among Northwest parties. These hurdles must be addressed in order to pursue
reliability advancements, existing bilateral market enhancements or any prospective
market formation; they represent significant opportunities to improve outcomes in the
region once addressed. The Technology Workgroup set about charting a path forward that
minimizes the region’s cost to remedy these significant hurdles by building on local,
regional and interconnection-wide capabilities. Proposed solutions look to expand the
NWPP MC members’ access to information already compiled, consistent with other regions
and Standards of Conduct. The group proceeded in a manner that was responsive to the
results and priorities emerging from Phase 1.
Summary of Phase 1
Phase 1 of the NWPP MC effort “set out to explore a range of alternatives that could help
the Balancing Authorities and scheduling utilities in the Northwest Power Pool area
address growing operational and commercial challenges affecting the regional power
system”.24 The Phase 1 report proposed three items that were addressed by the
Technology Workgroup in Phase 2:
“Evaluating, and if appropriate, proceeding with implementation of
Transmission Visibility Enhancements;
Proceeding with a shadow trial of the Following Reserve Assistance Program
(considering also whether the data gathering process for the Following reserve
Assistance Program may be leveraged to capture data for other potential uses,
such as evaluation of operational aspects of an EIM); and
Completing an EIM business case through in-depth technical, policy, and cost
scoping work sufficient to enable interested MC members [to] determine
NWPP MC Final Phase 1 Report, page 1.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
whether there is a workable framework for moving ahead with
In its assessment of significant hurdles and charting a path forward, the Technology
Workgroup set about addressing these priorities.
Phase 2 Approach
The Technology Workgroup supports further evaluation and implementation of data
collection in support of system visibility enhancements, which address the first two
priorities emerging from Phase 1.26 The data collected by the NWPP MC will be applied to
concise data visualizations. The Technology Workgroup recommends implementation of
several high priority visualizations for use by MC members. The Technology Workgroup
also advanced the scope of the cost assessment in Phase 2 and concluded that some
refinements were necessary, though through the cost assessment, no significant hurdles
were identified.
In its approach to identifying significant hurdles and charting a path forward, the
Technology Workgroup employed the following tactical deliverables.
Revised Costing: Further refine the scope of costs provided in Phase 1 consistent
with the limited set of alternatives available for implementation.
Data Requirements: A comprehensive assessment of data requirements to improve
regional infrastructure and support future phases.
Data Sharing Approach: A resolution to enable regional members to more efficiently
share data to meet the NWPP MC objectives.
System Visibility Approach: Data visualizations to foster collaboration and trust
amongst MC members while simultaneously providing better and more accurate
operational data to enhance reliability and increase efficiency.
EIM Architecture: An overview of how primary technical components will be
connected to deliver a regional EIM.
NWPP MC Final Phase 1 Report, page 5.
Based on direction from the Policy Workgroup, the FRAP Field Trial was not pursued and based on Executive
Committee direction Transmission Visibility was not included as a discrete scope item in Phase 2 but was refined
into what is more broadly referred to as system visibility (to include generation visibility as well) or Regional Data
Sharing Tools.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
Each of these tactical deliverables will be an instrumental part of Phase 3, Phase 4 and
ultimately Phase 5. Examining all Phases comprehensively was intended to reduce the
potential of redundant effort and/or sunk costs of efforts between the Phases. At a highlevel, Phase 3 is focused on implementing BA-level data collection and visualization to
support reliability and better chart-out forward going integration with the reliability
function in the region. Phase 4 is focused on implementing nodal-level data collection and
visualization to support resource sufficiency, further reliability and solidify a regional
framework for possible security-constrained economic dispatch. Phase 5 would consist of
implementation of the SCED and market trials, targeting market operations go live on April
1, 2017.
Status of Phase 2 Objectives
The Phase 2 deliverables have satisfied the objectives of Phase 2. They discuss possible
remedies to the significant hurdles and chart a step-wise path forward for the region. The
remedy also seeks to contain and make more certain the costs to the region and its
members by building on extra-regional, regional and WECC-wide capabilities and
expanding the MC parties’ access to information already compiled, consistent with other
regions and Standards of Conduct.
Phase 2 Deliverables
4.2.1. Revised Costing
The EIM implementation costs are broken into three components: regional infrastructure,
Market Operator, and Market Participants’ integration costs. Regional infrastructure is
centered on the centralized Energy Management System (“EMS”), with its attendant
network model, forecasts, and communication links. Regional infrastructure is necessary to
support both reliability and future market initiatives. The Market Operator costs are
comprised of the Resource Sufficiency and SCED software along with the supporting “backoffice” functions such as financial settlement and administrative services. Finally, the
Participants need to be constantly interfacing with both sets of systems. The Participants
will incur costs to deploy software and staff to support both interfaces. The intensity, and
in some cases the frequency, of the Participants’ interfacing will be increased relative to
existing interfacing with the RC.
Regional Infrastructure Costs
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There are four options to consider for regional infrastructure needs of the NWPP MC
efforts. The first three options are current service providers within the region. The options
available are:
Peak Reliability (RC)
Build from scratch
Regional Infrastructure includes the EMS, model and real-time telemetry required to
enable the SCED. It is a prerequisite to an EIM and a cost component to the Market
Operator. During Phase 2, the Technology Workgroup assessed the relative merits of the
EMS systems in place at both BPA and the RC. The CAISO EMS was not considered for the
Regional Infrastructure component because of the priorities the region has placed on local
control, reliability, cost, and software compatibility between the Regional Infrastructure
functions and the Market Operator functions. 27 Finally, the option to build from scratch
has not been considered in Phase 2 because of the cost associated with a new build-out of a
regional model, an EMS and the supporting communications links necessary.
The RC’s tools are more consistent with the software requirements specified in the SPP
Market Operator Estimate. BPA software versioning lags the RC. However, BPA may be in
a position to initiate small-scale steps more quickly due to its current role as a service
provider of analytics and communications support to the NWPP Reserve Sharing Group. As
a result of these varied capabilities and states of readiness, the Technology Workgroup
supports taking initial interim steps with BPA and then migrating towards the RC if
mutually satisfactory arrangements can be reached.
Market Operator Costs
There are three options that were considered for Market Operator needs of the NWPP MC
efforts in Phase 1:
Contract with SPP to perform third-party Market Operator functions;
Contract with CAISO to perform third-party Market Operator functions; or
Build from scratch.
The CAISO Market Operator solution is still under consideration and will be part of Phase 3 RFP.
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The efforts of Phase 2 have focused on refining the costs associated with the Market
Operator using the SPP Market Operator Estimate as a proxy. The CAISO Market Operator
function was not reviewed in Phase 2 because the market design remained under
development. Once CAISO has successfully integrated PacifiCorp into its EIM footprint, a
second evaluation can be conducted on the overall costs. CAISO remains a viable option
that can be evaluated in Phase 3. Finally, the option to build from scratch has not been
considered in Phase 2 because of the cost and uncertainty associated with a new build-out
of a Market Operator solution.
In Phase 2, the Technology Workgroup worked closely with SPP executives to better
understand the SPP Market Operator Estimate submitted in December 2012 and its
assumed requirements for regional infrastructure specified in the General Assumptions
section of the estimate. The assumptions are outlined below.
The RC will host the EMS, and SPP will receive data from it to be utilized on the EIM
EMS as a shadow system, which will be based on the same version of EMS software.
The RC EMS will:
o Provide the primary EMS service, including Supervisory Control And Data
Acquisition (“SCADA”), State Estimator, Real-Time Contingency Analysis
(“RTCA”) and Real-Time Generation (“RTGEN”);
o Provide EIM with all EMS resident data required to run the market;
o Data submissions for transmission status and flowgate information to SPP;
o Provide short-term load forecast (“STLF”);
o Send dispatch signals to market participant resources;
o Be responsible for any changes to the EMS to support EIM; and
o Provide all computer data information and Inter-control Center
Communication Protocol (“ICCP”) to send out the MP Resource instructions.
The RC provides the network model, which the RC may need to modify with more
density for the purposes of the EIM.
The RC will manage a net schedule interchange interface between their EMS,
scheduling tool, and the SPP supported EIM Market Operator System (“MOS”).
The Technology Workgroup also engaged with staff of Peak Reliability to understand their
ability to perform the functions listed in the SPP Market Operator estimate. As such, Peak
Reliability submitted a preliminary estimate of costs they would expect to incur under
contract to EIM Admin Corp. These costs were then added to the overall estimate of
Market Operator costs. Nonetheless, the value of the overall estimate of Market Operator
costs has changed little from Phase 1.
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Participant Costs
In the Final Phase 1 Report, the market participant costs are divided into two components:
start-up and ongoing costs. The start-up costs ranged from $31 to $60 million and the
ongoing costs ranged from $15 to $33 million. Limited additional detail can be found in the
following figure:
Figure 2: Draft EIM Participant Cost Ranges
To further refine the Participant’s cost estimates during Phase 2, the Technology
Workgroup connected David Luedtke of Utilicast and Patrick Damiano of Columbia Grid
who chaired the Phase 1 NWPP MC EIM workgroup and were responsible for collecting the
Participants’ cost estimates. Outliers were identified and Mr. Luedtke spoke individually
with those entities. As a result, the High On-Going Cost was reduced from $31 million to
$27 million and tweaks were made to the Start-Up Cost ranges that can be observed when
comparing the above and below figures.
Figure 3: Draft EIM Participant Cost Range Totals
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4.2.2. Data Requirements
Within any software system or application, the quality and quantity of the data itself can
offer multiple points of failure if not addressed properly in setting out the requirements.
The Phase 2 goal is to capture the majority of data elements necessary to service the data
content aspect of the EIM.
A comprehensive Data Requirements Matrix was prepared; an excerpt from the matrix is
provided in the figure below. The matrix contains rows of data elements that are mapped
to columns of various requirement groupings. The top portion of the Data Requirements
Matrix is shown below. Rows are categorized by application and data type, where the
columns are grouped and associated with application processes in place “As-Is” and
planned in future phases.
The legend in the top left side of the matrix details those data elements that are already
available to NWPP members (X), Data not available (O), and data that exist but require a
policy decision before data can be shared (P). Much of the data requirements listed serve
one or more of the listed column categories. To date, out of an identified group of 141 data
requirements, the technology group has identified less than 20 new data elements that will
need to be provided by NWPP members.
Figure 4: Data Requirements Matrix
The As-Is grouping contains two categories:
1. Peak Reliability is already receiving data from the Balancing Authorities and/or
Transmission Owners according to 68 specific data requirements published by
WECC on December 31, 2012, and available at:
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The data requested and supplied by the RC membership is specifically listed within
the data requirements matrix. It includes real-time facility data, schedule type data,
facility outage information, and electrical equipment modeling data. These data are
necessary for the RC to carry out its functions, as defined by the NERC Reliability
Standards, including:
Real-Time Situational Awareness
System Alarms and Visualizations
Advanced Applications and other Network Analysis Tools
Future, Next Day and near Real-Time Engineering Study Analysis
Post Analysis, Event Analysis, Trends, Forecasts, etc.
Much of this data are securely transmitted to the RC via ICCP and the other data are
delivered by secure File Transfer Protocol (“FTP”) services and/or other
communication needs according to type and timeliness of data and security
2. Northwest Power Pool contains two sets of data requirements. The first set of data
requirements was established by and according to the NWPP Reserve Sharing
Documentation. This document states that the standards established by NERC and
WECC require all electric balancing authorities to carry reserve for contingencies
and disturbances. Except when communication links are down or the computer
system for reserve sharing is not functioning, the reserve sharing process for the
NWPP is automated. The data required by these standards are currently being
serviced and delivered by BPA under contract with NWPP. The data are currently
stored within a data historian system maintained at the NWPP. While the NWPP
data requirements are not specifically listed within the matrix as such, the data
elements themselves have been evaluated and found to be duplicative with the data
elements required by the WECC specifications noted earlier.
The second set of data requirements are new and come from a draft document
authored on June 19, 2013 by the NWPP, titled “Transmission Visibility Expansion.”
This document states the “Northwest Power Pool (NWPP) currently maintains a
simplified radial connectivity transmission model. With the growth in the NWPP
geographic area and the additional transmission, NWPP members are finding that
the radial model is insufficient for ensuring reliable deployment of resources
without the potential of congestion.” It further states, the “proposed NWPP solution
is to create a new component that provides the necessary transmission visibility
that would enable the analysis of the ability to deploy resources accounting for
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physical congestion.” The data requirements associated with the functional aspects
are consistent with the EIM approach and were captured accordingly.
The additional columns contain several categories, loosely associated by the use of color
and span Phases 3 through 5. It is important to note that each application listed below
adds immediate value once implemented and is not discarded or rendered obsolete with
the subsequent phase implementation work.
The cumulative results of these tools and applications provide the “technology essence” of
the proposal and benefit all members of the NWPP.
1. Visualization Displays with several groupings:
a. Lines and Flowgate Overview
b. NWPP Balancing Authority Overview
c. Variable Energy Resource, Load and Forecast
d. Net Area Interchange Overview
2. Centralized Flow Forecast
3. Resource Sufficiency
4. Regulation Pooling
5. Enhanced Contingency Reserve
6. Enhanced Curtailment Calculator
7. Dynamic Scheduling
8. Activating Constraints
9. Centralized Nodal Assessment
10. Security Constrained Economic Dispatch
During the implementation of the phased components listed above, the data requirements
and design must be revisited. In Phase 3, a detailed analysis is required.
Clearly, technology and stakeholder drivers and data needs will change over the course of
the project’s implementation and well afterward. These drivers will change the
requirements or add requirements, which will need to be vetted, especially given the
importance of preserving the integrity and quality of the data, new and existing, coming in
and out of the applications and their components. Gaining stakeholder appreciation and
buy-in to changes or new requirements can be tenuous if proper research and preparations
are not considered ahead of time followed by effective communication and education.
Failing to pay attention to these types of details will promote errors and failures, which can
render the applications and subcomponents obsolete well before their time, at a cost factor
far higher than the original implementation cost.
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4.2.3. Data Sharing Approach
The question remains as to how much of this data can be shared, with whom, and in what
manner. Overarching considerations are:
1. Not violating cyber security or Critical Infrastructure Protection (“CIP”)
2. Not violating existing agreements about data collection and sharing;
3. Not releasing commercially sensitive data; and
4. Not sharing data that would give an unfair market advantage to certain entities.
For example, in row 1 below, NWPP MC would be sharing its own data, therefore, the
restrictions would most likely be in the CIP requirements. In row 2, the NWPP MC would be
sharing another entity’s data and it would be necessary to determine whether the NWPP
MC has permission to share it, and if so, what limitations surround that permission. Row 3
is more similar to Row 1 because the data set is a compilation, which is akin to NWPP MC
data because the NWPP MC “produced” it using inputs from others (this assumes that
individual data cannot be disaggregated).
Table 1: Data Sharing Matrix
Who is Sharing Data?
What Data are Shared?
With Whom are Data Shared?
BA Y Data X
Aggregated Data X for all BAs
General Public
General Public
General Public
The analysis is simplified if Column A is always NWPP sharing and Column C is always the
General Public, but there may be other combinations to consider.
It is believed that aggregated system data, assuming market-sensitive data are not allowed
to be disaggregated, can be shared with fewer restrictions. However, based on the above
analysis, it is presumed that a data sharing agreement between and amongst the NWPP and
its members may be necessary prior to facilitating the system visibility enhancement
envisioned in Phase 3.
NWPP MC Data Resolution Process
The Technology Workgroup suggests pursuing data sharing for the NWPP MC effort under
the auspices of a data resolution process tied to the NWPP MC work orders associated with
each phase. The NWPP MC work orders include confidentiality provisions. It is proposed
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that these provisions be combined with one or more resolutions voluntarily enjoined by
members of the NWPP MC Executive Committee. A summary comparison between the
NWPP MC Data Resolution approach and WECC’s Universal Data Sharing Agreement
(“UDSA”), detailed in the following subsection, helps illustrate the Technology Workgroup’s
support for the data resolution approach:
Table 2: Data Sharing Resolution Approach
Example Drivers
NWPP MC Data Resolution
NWPP Executive Committee
Voluntary, Northwest
RC, TOP, BA; but excludes
marketing function
All of WECC
A form of data resolution that establishes procedures for the exchange of confidential
information between the NWPP MC members and third parties was discussed during Phase
2. In summary, a form of resolution will include:
Identifies the Parties exchanging data;
Describes the specific data to be collected;
Specifies the manner through which the data will be collected (e.g. ICCP);
Establishes the role of the third-party using / evaluating the data received;
Outlines the purpose(s) for which the data are being collected;
Sets forth the Participants’ access to the data and/or information produced as a
result of the data collection effort; and
Limits the duration of the resolution.
WECC Universal Data sharing Agreement (“UDSA”)
The WECC Universal Data Sharing Agreement (UDSA) is the product of a collaboration of
western balancing authorities, transmission owners, transmission operators, and WECC.
This agreement improves WECC’s ability to share synchrophasor data and operating
reliability data with those charged with preserving and enhancing the reliability of the
Western Interconnection. This shared information provides the following benefits.
Improved situational awareness for system operators in the Western
Better models, which form the basis of next day, seasonal, and planning studies
Disturbance evaluation
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The Agreement enables the exchange of information among those who need synchrophasor
and operating reliability data to carry out their reliability responsibilities. At the same
time, it keeps this data from merchants and marketing functions, and helps ensure the
protection of market-sensitive information.
Much of these data are exchanged through the portal. Because of the UDSA,
data can be shared between members and WECC, and between the members themselves.
All signatories of the WECC UDSA may have access (Balancing Authorities, Transmission
Operators, and Reliability Coordinators) to a tremendous amount of operational data. Any
entity within WECC with a reliability role can access this data in several ways:
1. Via the WECCRC.ORG website:
a. Real-Time Displays
b. Real-Time Contingency Analysis
c. Study Libraries
d. Operational data Library
e. Outages
f. West-wide System (“WSM”) Model Library
g. Event Reports
2. Directly to their EMS system via ICCP and the RC EHV Data Pool28
3. Bi-laterally via ICCP (or other) with other BAs or TOPs
However, marketing/commercial functions (IPP’s, Merchants, etc.) do not have access to
this data except:
1. What their affiliated reliability function may share29
2. What a specific TOP/BA may willingly decide to share publicly
3. What they purchase from a vendor
Much of the data already submitted to the WECC RC is a sound foundation from which to
begin improving system visibility, data sharing, a resource sufficiency program, and
ultimately SCED.
The WSCC EHV Data Pool was developed to provide generation, flow, voltage and frequency information on the
whole interconnected system to operating entities.
Inconsistent data sharing policies between BAs and their merchants is a regional issue. Centralizing data sharing
should provide an improved “level playing field.”
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4.2.4. System Visibility and Data Sharing Tools
Absent an EIM, the region currently lacks the tools and visibility into the system to: better
manage ramps and increasing demand for balancing capacity associated with variable
energy resources; systematically share load and resource diversity across their systems;
and adequately manage and use the increasingly constrained regional transmission system.
System visibility is essential in allowing entities in the NWPP footprint to have a common
set of tools that would increase the region’s reliability and situational awareness. The
NWPP MC Technology group has brought forward several system visibility tools that would
provide forecast and real-time information for purposes of operational planning and
system management. By providing entities, such as the Balancing Authority, IPPs,
Transmission Operators, Power Marketers and Merchant Operators, etc. with access to
aggregate level information, it would provide more transparency to operational planning
and efficiencies.
In an effort to foster collaboration and trust amongst members while simultaneously
providing better and more accurate operational data to purchasing/selling entities
(“PSEs”) and the general public, the Workgroups propose to broadly share several
aggregated datasets:
Path and Flowgate loadings (Limit, Actual)
Regional BA Nets (Totals of BA’s in NWPP or sub-regional/zonal)
Regional Supply and Demand, including Load Forecasts and Generation Fuel-type
Individual BA data (Net Scheduled Interchange (“NSI”), Net Actual Interchange
(“NAI”), Area Control Error (“ACE”), Net Load, Net Generation, Reserves, etc.)30
Ideally this type of data would be shared with everyone simultaneously. There are three
general classifications of users that may need to be considered:
1. General Pubic
2. Power Producers
3. Reliability Entities
Individual BA data may be considered sensitive information by some BAs (exposing a long or short position),
even though many BAs and many regions post much of this data in aggregate form.
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The benefits of providing this data more broadly include:
Better situational awareness of operational conditions, allowing more timely and
appropriate dispatch of resources in response to congestion or allowing merchants
and IPPs more time to arrange capacity or energy;
Facilitates regional problem solving; and
Provides a foundation for resource sufficiency.
There are numerous examples across North America of individual utilities, Regional
Transmission Organizations and Independent System Operators making excellent
system/operational data available to the general public and market participants in near
The RC makes available at the WECCRC.ORG site a tremendous amount of data and
displays. Many of the displays are very similar to some of the datasets that the Technology
Workgroup envisioned sharing. A few displays that are targeted for sharing include the RC
Transfer Paths and Path Map displays, as well as certain elements of the Automated
Generation Control Totals and Load Comparisons displays.
Note: As detailed in the Universal Data Sharing Agreement (“UDSA”) section of this document,
there are no known restrictions or barriers to reliability entities (BAs, TOPs, RCs) sharing or
receiving the data described above.
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Transmission Loading Data
Having access to instantaneous information of aggregate flowgate and path loading data
would prepare and prevent entities from entering into system positions that could
accelerate system operational limits and increase reliability concerns.
Geographical Overview Example
The display below would provide a high level overview of key transmission flowgate and
path loadings. The color of the elements on the display would change color as loading
approaches the operating limit and potentially provide audible alarms to alert the user.
Hovering a mouse over an element would provide popups with additional information.
Figure 5: Geographical Transmission Overview
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Tabular Overview Example
This view would provide more detailed loading data in a sortable table. The default sort
would be to show the most highly loaded paths (i.e., those closest to their operating limit)
at the top. Similar to the previous display, the color of the data on the display would
change as the loading approaches the operating limit and potentially provide audible
alarms to alert the user. This display would also be capable of showing loading trends over
the previous several hours or days.
Figure 6: Tabular Transmission Overview
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Balancing Authority Data
Providing access to instantaneous interchange data at the BA, regional, or sub-regional
level would illustrate the exchange of flow in and out of the corresponding areas. In
addition, displaying the scheduling control error of the NAI against the NSI could also
provide additional information on constraints in the region in terms of real power flow.
Geographical Overview Example
The display below would provide a high level overview of NWPP Balancing Authority
Areas. The color of the elements on the display would change color and key BA metrics
approach critical operating limit and potentially provide audible alarms to alert the user.
Hovering a mouse over an element would provide popups with additional information.
Figure 7: Balancing Authority Geographical Overview
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Tabular Overview Example
This view would provide more detailed BA data in a sortable table. Similar to the previous
display, the color of the data on the display would change as values deviate from normal or
reach critical operating limits. This display would also be capable of showing loading
trends over the previous several hours or days.
Figure 8: Balancing Authority Tabular Overview
4.2.5. Energy Imbalance Market Architecture
In concert with defining Data Requirements and future EIM operational roles, the
Technology Workgroup identified the conceptual market architecture. Below is a highNorthwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
level diagram showing the general relationship between the EMS and the SCED Engine.
The architecture is loosely based on Southwest Power Pool. It is envisioned that the RC
would provide the real-time telemetry and a majority of the EMS functionality.
Systems Interface Overview
EIM Entity (Northwest Power Pool )
Regional Infrastructure, Regulation Pooling, Resource
Sufficiency, System Visibility,
Security Constrained Economic Dispatch
Operations Center
Data Acquisition
Generation Control
Reliability Coordinator
(EMS Applications & Functionality)
Network Model
State Estimator
Contingency Analysis
Reserve Calculations
Reserve Monitoring
Topology Model
Data Acquisition
Market Operator
(EIM & SCED Functionality )
Other Applications
Full Graphics
Load Forecasting
(Short/Long Term)
Enhanced Curtailment
Calculator (ECC)
Other Applications
Interchange Distribution
Calc (IDC)
Curtailment Adjustment
Tool (CAT)
Web services
Participant Interfaces
Scheduling Price
Dispatch (SPD)
Simultaneous Feasibility
Test (SFT)
MOS File Server
*Above represents key but not all EMS functions
3rd Party Market Apps
eDNA (archive)
*Above represents key but not all EIM functions
Figure 9: Systems Interface Overview
Both the RC and SPP use the same EMS software vendor, ALSTOM. Both entities are using
same version of the ALSTOM EMS software. SPP also uses ALSTOM market software.
Alstom’s EMS utilizes a proprietary real-time database engine, HABITAT, to support its
applications whereas the market systems utilize Oracle as their relational database engine.
This integration issue is resolved through file and other open interfaces.
Load Forecasts: Short-term (“STLF”) and Mid-term (“MTLF”)
Load forecasts are critical to the overall solution because they estimate demand for both
Resource Sufficiency and SCED. The Short-term Load Forecast (“STLF”) estimates the load
on a five-minute basis for the next three hours whereas the Mid-term Load Forecast
(“MTLF”) estimates the load on an hourly basis for one to seven days in the future.
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In the region, these forecasts must be tightly coordinated with both the RC and BAs. All
regional entities should use the same forecast to ensure operational consistency. While
MTLF is currently being calculated and shared between the BA and RC, the region is
currently not using a STLF.
STLF is essential in the operation of the SCED. STLF calculates short-term demand. Timely
implementations of decisions lead to the improvement of network reliability and reduce
occurrences of equipment failures and blackouts. Load forecasting is also important for
contract analysis and evaluations of various energy pricing products offered by the market.
Most forecasting methods use statistical learning techniques and algorithms such as
regression, neural networks, fuzzy logic, and expert systems. A variety of methods such as
these, and others such as similar day approach, and time series methods have been
developed for STLF.
Variable/Dynamic Transfer Constraints
Dynamic Transfer Capability (“DTC”) is the ability of the operator of a generator to change
the output of that generator within the hour without causing an excessive voltage
excursion, unacceptable changes in Remedial Action Schemes, or other unacceptable
operational results. Historically, variations in generation within hour to supply regulation
and following services to load, to address contingencies, and to integrate remote resources
into a BA have been accommodated without incident because these historic variations
occurred at only a few resources to address predictable and relatively small variations in
The advent of large additions of wind to the Northwest power grid has yielded movements
of generation to compensate for changes in wind output that are larger, less predicable, and
more rapid than historic load variability. This has resulted in operational limits being
placed on the amount of variable transfers that can be allowed.
By definition, an EIM is a mechanism by which resources within the EIM are dispatched
every five minutes to meet load and export obligations at least cost. This mechanism may
result in large, unpredictable, and rapid movements in generation from dispatch interval to
dispatch interval from time to time. Changes in generation from resources that are
scheduled across the Northwest may cause unacceptable system conditions. As a result,
the EIM will likely be required to implement additional rate-of-change mechanisms and
constraints to manage these changing flows on flowgates and paths. At this time, the cost
and difficulty of implementing rate-of-change controls should be minimal in either SPP’s
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market system or the system used by the California ISO. However, it should be noted that
this is a requirement unique to the Northwest that is uncommon in other markets and will
need to be considered in the final implementation of a NWPP footprint EIM.
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During Phase 1 of the MC Initiative, the Executive Subcommittee on Governance
(“Governance Subcommittee”) developed a straw proposal (the “Phase 1 Straw Proposal”)
laying out the basic framework for a proposed governance structure for a voluntary Energy
Imbalance Market in the Northwest Power Pool area. The framework was intended to
further a number of key objectives, including local control, avoiding scope creep of energy
imbalance market functions or geography (unless broadly supported by the region’s
utilities), preserving reliability, and minimizing the risk of any expansion of FERC
jurisdiction over non-jurisdictional entities.
Summary of Phase 1
The Phase 1 Straw Proposal included the following elements:
The region would form a specific-purpose nonprofit corporation (“EIM Admin
Corp”) to oversee the development, implementation, and operation of a “standalone,” voluntary energy imbalance market. (The term “stand-alone” means that the
scope of the energy imbalance market would be sub-hourly energy dispatch only,
not encompassing transmission operations, transmission provider services, or
controlling unit commitment in the pre-schedule period.)
EIM Admin Corp would have a small, independent Board of Directors exercising
general oversight and policy-setting authority over EIM Admin Corp, except on
issues (described below) for which decision-making authority is reserved to the
EIM Admin Corp members have the right to vote on matters of greatest concern,
separated into two categories—issues for which a 60% majority vote is required,
and issues for which an 80% majority vote is required.
An affirmative vote of 60% of EIM Admin Corp’s members is required to:
o elect or remove members of EIM Admin Corp’s Board,
o approve proposed budgets or budget changes for EIM Admin Corp,
o waive or modify the funding commitment required of late-joining members, or
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o approve actions related to hiring the Market Operator for the energy
imbalance market.
An affirmative vote of 80% of members is required to:
o change the scope of EIM Admin Corp or the energy imbalance market (or
approve funding to study potential change in scope),
o modify EIM Admin Corp’s Articles of Incorporation or Bylaws, or
o expand the list of organizations eligible to be members of EIM Admin Corp.
EIM Admin Corp would have a standing committee of member representatives (the
Member Committee) selected by the member organizations. The Member
Committee would serve in an advisory capacity to the Board, acting through nonbinding votes.
Initial membership in EIM Admin Corp would be open to eligible organizations
willing to commit funding for start-up of the energy imbalance market. Eligibility
would be based on being either a Balancing Authority or a self-scheduling loadserving utility operating in the Northwest Power Pool area. There would be no
requirement that organizations wishing to participate in the energy imbalance
market become members of EIM Admin Corp, or that those organizations wishing to
become members of EIM Admin Corp commit themselves to participate in the
energy imbalance market.
Funding obligations might be “scaled” according to the size of an organization
(which could be defined in many ways – revenues, transmission facilities, load,
anticipated benefits from participation in the energy imbalance market, etc.).
The Board of EIM Admin Corp would set up procedures to make sure that there are
appropriate opportunities for interested stakeholders to provide input concerning
EIM Admin Corp’s activities and the energy imbalance market.
Objectives of Phase 2
The governance objective for Phase 2 was to develop draft bylaws for EIM Admin Corp that
would implement the principles the Governance Subcommittee identified in the Phase 1
Straw Proposal.
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The draft bylaws attempt to address every element of the Governance Subcommittee’s
Phase 1 Straw Proposal, although the governance drafting team did present to the
Governance Subcommittee their recommendations to modify certain elements of the Phase
1 Straw Proposal. Among these were the following:
Decisions concerning eligibility of organizations to join EIM Admin Corp will be
made by the Board of Directors, applying criteria established in the bylaws, rather
than by members voting on whether to modify a pre-established list of eligible
organizations. It will still require an 80% member vote to modify the bylaw’s terms
defining membership eligibility criteria.
The governance drafting team felt it would be appropriate, given the unique
operational responsibilities and compliance risks that apply to Balancing Authority
Areas, for all member votes to require not just a particular overall member
threshold, but also a minimum level of concurrence from members that are
Balancing Authorities. This is sometimes described as a “double-majority”
requirement. This reflects, among other things, the drafting team’s expectation that
obligations to contribute start-up funding for the energy imbalance market would
apply only during the early years of EIM Admin Corp’s existence. Later on, once the
energy imbalance market is self-sustaining and has been able to reimburse
members’ start-up funding contributions, admission to membership would require
only meeting eligibility criteria.
The governance drafting team provided for removal of directors to require a higherlevel member vote (80%) than the election of directors (which requires a 60%
member vote).
The governance drafting team concluded that it was not feasible, with the level of
information currently available, to incorporate into the bylaws details related to
member funding obligations, the manner in which member start-up funding
contributions would be reimbursed, and related terms. The bylaws have therefore
been structured to rely on a companion agreement (the “Membership Agreement”)
to spell out these provisions once sufficient decisions and details have been worked
out by the organizations that intend to provide energy imbalance market start-up
The draft bylaws also incorporate the drafting team’s recommended provisions to
address various second-level details left open or unresolved in the Phase 1 Straw
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February 5, 2014
Phase 2 Deliverables
The primary Phase 2 deliverable for the governance drafting team was a set of draft bylaws
for EIM Admin Corp. To make sure all parties reviewing the draft bylaws have sufficient
context concerning what assumptions the governance drafting team made when drafting
the bylaws, as well as understanding any issues that could not be resolved or fully
addressed through terms in the bylaws, the governance drafting team also developed a set
of companion documents. The companion documents include a high-level discussion of
FERC jurisdiction as it may pertain to EIM Admin Corp, an “assumptions and flagged issues”
list, and a “road map” document describing further work that remains with respect to
governance and associated contractual arrangements. The road map document has several
informational attachments, such as an outline of proposed terms to be included in a
Membership Agreement for EIM Admin Corp.
5.2.1. Summary of Draft Bylaws for EIM Admin Corp
The key provisions of the draft bylaws for EIM Admin Corp are as follows:
Purpose and Limitations Section (Section 1): Section 1 defines EIM Admin Corp’s
purpose, which is to oversee the development, implementation, and operation of a
voluntary energy imbalance market for the Northwest Power Pool area. It also
establishes limitations on EIM Admin Corp’s ability to take certain actions (such as
electing to submit to FERC jurisdiction or changing the geographic or functional
scope of the energy imbalance market) without sufficient member authorization.
The purpose and limitations provisions, together with how the term “Energy
Imbalance Market” is defined in the bylaws, are key components to address one of
the Governance Subcommittee’s primary objectives—preventing scope creep.
Membership Provisions (Section 3): Section 3 includes eligibility criteria for
membership, which, as noted above, are to be administered by the Board. It also
defines the members’ voting rights (including what issues members are entitled to
vote on and the threshold required for approval in each of those areas). Although in
the process of developing the Phase 1 Straw Proposal the Governance
Subcommittee debated whether all members should have equal voting power—that
is, one member, one vote—or voting power should be differentiated according to
members’ relative funding contributions, the Governance Subcommittee
subsequently instructed the governance drafting team to provide for equal voting
power. Although each member organization has just one vote, the member voting
provisions require not only requisite thresholds of member approval (generally
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February 5, 2014
60% or 80%), but also a minimum level of support (51%) from members that are
Balancing Authorities. The potential for members to have “tiered” funding
obligations (that is, funding levels scaled to reflect differences in members’ ability to
contribute) remains, but is not directly addressed in the bylaws because detailed
funding terms cannot be worked out until later stages in the development process.
These would be addressed in the Membership Agreement.
Provisions Governing the Board of Directors (Section 4): Section 4 defines the
composition, responsibilities, and limitations on the authority of EIM Admin Corp’s
Board of Directors. It also establishes procedures for nominating and electing Board
members. As noted above in the summary of the Phase 1 Straw Proposal, approval
of the members (at a 60% level) is required for the Board of EIM Admin Corp to
select and hire the Market Operator. Section 4.13 includes detailed provisions to
make sure that scope restrictions on EIM Admin Corp are carried through to the
terms of any contract for market operation services.
Provisions Establishing a Member Committee (Section 5): Section 5 defines the
composition, powers, and responsibilities of the Member Committee. The Phase 1
Straw Proposal called for the Member Committee to consist of seven
representatives—three elected by public power members, three elected by investorowned utility members, and one elected by federal power marketing agency
members. Recognizing that these three categories did not encompass all of the
types of organizations that could be eligible for membership in EIM Admin Corp, the
governance drafting team provided for one additional representative to be elected
by members that don't fit into any of the other three categories.
Development and Approval of EIM Admin Corp Budgets (Section 6): Section 6
requires the Board of EIM Admin Corp to consult with members in developing (or
substantially revising) the annual budget for EIM Admin Corp, and to submit budget
proposal to the members for approval (which requires a 60% member vote).
Section 6 also provides a fallback mechanism if a proposed budget does not gain
sufficient member approval.
Consultation Obligations Related to Regulatory Filings (Section 8): Because of the
importance of issues related to FERC jurisdiction, Section 8 contains detailed
provisions requiring EIM Admin Corp to consult with members in developing and
submitting filings to FERC and other energy regulatory authorities. Provisions
elsewhere in the bylaws also require the Board of EIM Admin Corp make good-faith
efforts to seek similar consultation commitments from the Market Operator.
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Section 8 also includes provisions that entitle any non-jurisdictional member to
immediately withdraw from EIM Admin Corp if it believes remaining a member will
have adverse jurisdictional consequences.
Stakeholder Consultation Provisions (Section 10): Section 10 requires the Board to
develop policies and procedures to promote ongoing consultation with, and input
from, market participants and the general public.
Provisions to Protect Member Rights (Sections 11 and 12): Section 11 contains
terms that make it difficult to change the bylaws. None of the provisions in the
bylaws can be changed without approval of 80% of the members, except one section
(containing the provisions that require unanimous members approval for EIM
Admin Corp to voluntarily submit itself to FERC jurisdiction), which can be changed
only if the members approve unanimously. Section 12 is designed to echo any
requirements for member approval of amendments to EIM Admin Corp’s Articles of
General: The proposed bylaws for EIM Admin Corp also include typical provisions
to address such things as directors’ and officers fiduciary duties; procedures for
meetings of the Board, members, and Member Committee; limitations of liability
and indemnification of officers and directors; and corporate record-keeping.
5.2.2. Overview of Supporting Documents
As noted above, to provide additional background information and context, the governance
drafting team developed a set of supporting documents to supplement the draft bylaws for
EIM Admin Corp. These documents include the following:
High-Level Discussion of FERC Jurisdiction As It Pertains to EIM Admin Corp: The
Governance Subcommittee indicated in the Phase 1 Straw Proposal that EIM Admin
Corp is intended to be non-jurisdictional. This document summarizes the views of
the governance drafting team on this topic.
Assumptions and Issues List: The governance drafting team’s “assumptions and
issues” list is meant to provide important context about what the drafting team
assumed in developing proposed bylaws for EIM Admin Corp, and to also flag
important issues that are outside the scope of the bylaws or cannot be resolved fully
through bylaws provisions.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014
Road Map Document: The “road map” document is intended to convey that the draft
bylaws for EIM Admin Corp are a work-in-progress and that substantial additional
work remains to carry out the objectives identified by the Governance
Subcommittee and to create all necessary contractual arrangements. The road map
also includes three informational attachments: (1) a diagram depicting the
relationships among EIM Admin Corp, its members, the Market Operator, and
market participants, (2) a draft outline of a Membership Agreement for EIM Admin
Corp, and (3) a preliminary list of organizations potentially eligible for membership
in EIM Admin Corp, based on the criteria in the proposed bylaws.
5.2.3. NWPP General Services Agreement Discussion
To the extent the MC members elect to undertake further stages of the MC Initiative, and
wish to do so with less formality and greater flexibility than would be associated with
formation of EIM Admin Corp, the option to rely on “work orders” managed through the
Northwest Power Pool corporation remains available. The advantage of this approach is
that the Northwest Power Pool members are familiar with it, and because work orders are
contractually tied into an existing “umbrella” agreement (known as the General Services
Agreement) with the Northwest Power Pool corporation, many of the general terms and
conditions that might otherwise have to be negotiated in a multilateral contract are already
in place. This simplifies the work order development process, enabling the parties to focus
on scope of work, funding obligations, and decision-making processes. Work orders can
also be configured for different sets of activities encompassing different combinations of
MC members as needed.
Northwest Power Pool Market Assessment and Coordination Committee
February 5, 2014