DISTRIBUTED ENERGY RESOURCES
Stakeholder Comments submitted prior to DER TF Organizational Meeting (7/15/15)
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Texas Solar Energy Society Board Member (page 1)
Austin Energy (page 3)
Southeast Renewable Energy (page 4)
Longhorn Power (page 4)
Joint TDSPs (page 5)
1. Texas Solar Energy Society Board Member (Received 6/26/15)
Thanks for the opportunity to provide comments on your recent DER Workshop. I believe that
distributed energy resources, and in particular, rooftop solar PV will continue to grow and
become a significant and relevant part of the electricity generation portfolio across Texas.
Please consider these recommendations, comments and questions as your DER projects continue
to evolve (and expand).
1. It is recommended that the 1MW threshold for DG registration not be lowered and that
ERCOT staff take the necessary process steps and changes to the existing protocol to
prevent the unintentional and unintended consequences that the 10MW total of registered
DG per load zone threshold might trigger.
2. Improved and expanded tracking and public reporting of on-site solar generation for
numbers of installations, capacity of installations, and behind the meter generation
tracking (possibly using excess generation to the grid as a proxy for total on-site energy
production) is recommended. It is recommended that these numbers by aggregated by
ERCOT weather zones and TDSPs.
3. My understanding is that the current ERCOT governance model has residential
consumers represented by one voting stakeholder, the Office of the Public Utility
Commission. As more rooftop solar PV owners become integral to the operation of the
grid, does this single vote governance model need to be updated or expanded in some
way?
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4. Can ERCOT do some model testing of the proposed DER minimal, light, and heavy by
projecting how various types of DER installations might map into the three proposed
options outlined during the first workshop? For example, what are the potential ways
that residential solar rooftops, building/commercial solar rooftops, shared-solar
community solar, CHP systems, and other DERs map into the three proposed DER
options? Also, maybe for a few points in time (e.g. 2 years, 5 years, 10 years, 15 years),
can you project an estimate of what might be a range of the number of installations of
each of the types mentioned above? Then from these projections, can a better
determination be made of where the most effort should be placed in further development
of the DER projects.
5. To date, the current electricity market structure that has worked well in Texas since
deregulation is designed around transmission level wholesale pricing. Doesn’t the
growth of rooftop solar & net zero energy homes/businesses necessitate rethinking that
market design to better understand the value of the electricity delivered at the residential
meter? (One rooftop solar PV’s excess is delivered to close neighbors, not transmitted
over all element types of the grid over long distances.) This home to home electricity
delivery model, which is more peer-to-peer, doesn’t seem to fit easily into the existing
hierarchical model (generation –to- transmission –to- sub-station –to- distribution –totransformer) on which the current wholesale & retail pricing electricity market is based.
a) Does ERCOT staff think that the proposed DER minimal/light/heavy approach will
facilitate better valuing the electricity delivered to the end residential customer’s
meter from another home’s rooftop solar generation?
b) Should the DER projects consider what market design changes may be required to
properly value electricity delivered from one residential customer to another
residential customer’s meter?
Thanks again for your consideration of these recommendations, comments, and questions. Let
me know if you have in questions.
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2. Austin Energy (Received 7/10/15)
DER WORKSHOP ISSUES LIST (6/18/15)
1. What is the ERCOT definition of DER?
a. How is storage (including EVs) treated in the definition?
b. How does Wholesale Storage Load treatment factor into the DER issue?
2. Does/should DER in ERCOT include Demand Response?
a. What are implications for PUC Rule?
b. Could we create a second category of DER Heavy that includes DR, settled at LZ
SPP?
3. Does PUC metering rule prohibit Dual Metering (as proposed) in competitive choice areas of
ERCOT?
a. What are the comparisons to how metering is handled at PUNs?
4. What are the costs/benefits of DER Light & DER Heavy? IE, what are the impacts on LSE
obligations (AS obligations, T&D charges, other Load Ratio Share uplifts, etc.)?
5. Should DER Light or DER Heavy status be optional, or mandatory?
a. How would it work if mandatory?
b. If optional, would the DER’s selection be permanent? If not permanent, how
frequently could a DER change its status?
6. Revisit and improve the ERCOT definitions of Resources including DG.
7. Should DERs be subdivided by size (similar to Germany, CA)?
8. Should ERCOT systems be modified to allow AMI metering (instead of IDR/EPS) for
registered DG (for settlement purposes)?
9. How does NERC’s dispersed generation resource initiative fit into all of this?
10. Establish a reliability need for reporting non-registered DG.
11. What reporting is necessary from non-registered DG to address the reliability concern?
12. Determine the responsible reporting entity for non-registered DG.
13. Address settlement issues including shadow settlement of load behind NOIE Ties.
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3. Southeast Renewable Energy (Received 7/10/15)
I am of the opinion that there needs to be a Light and Heavy option. I think you will find
locations where prices signal the desire for generation and the ability of entities to deliver such
power; however, such entities may very well not be in the “Power Industry” and will only
participate if their generation is part of a seamless process. For example, a facility using their
backup generator to produce incremental revenue.
One the flip side and just as important the DER Heavy will appeal to the developer looking to
strategically locate and build where price signals make sense. This entity can stomach more
complexity and will value being able to participate in greater markets (Day Ahead, Reserve, etc).
I think it would make sense to limit the switching back and forth between light and
heavy. Perhaps allowing a switch only after one year has passed from the initial election (so a
participate can’t manipulate based on seasonal prices).
4. Longhorn Power (Received 7/10/15)
DER Light and Heavy will both include sub-Load Zone pricing, but Demand Response is and
has been envisioned to be settled at a Load Zone price. Considering the complexity required in
the ERCOT systems to integrate these two independent concepts, what is the business case to
justify combining them within the DER definition?
5. Joint TDSPs (Received 7/13/15)
AEP, CenterPoint Energy, Oncor Electric Delivery LLC, Sharyland Utilities, L.P., and
TNMP (“ Joint TDSPs”) appreciate the opportunity to offer comments on the Distributed Energy
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Resources (DER) Presentation presented at the June 18, 2015 DER Workshop hosted by
ERCOT. Joint TDSPs recognize the importance of their role in the facilitation of future DER
market options as proposed by ERCOT. These comments focus on overarching issues and
questions that the market as a whole will need to consider in order to ensure the proposed market
options are effective and can be deployed for the long term. Representatives from the Joint
TDSPs plan to participate in the DER Task Force to assist in the development of the DER
strategy and to evaluate the many technical details that will ultimately flow from these
discussions.
Impacts of Magnitude of Participation
Since the Joint TDSPs are involved with each distributed generation (DG) interconnection on
our respective systems, we understand the impacts a large number of DG facilities can have on
the grid. Currently, there are approximately 550 generation resources connected to the ERCOT
transmission system. While this may appear to be a large number of interconnections, market
participants should consider that currently more than 10,000 DG facilities are interconnected to
the distribution system with a significant number of additional facilities connecting each month.
Requirements developed for participation in each of the proposed market options will need to be
communicated, managed, and enforced for a large and growing number of DG facilities that are
interested and capable of participating. Because of this, Market Participants must strongly
consider the numerous regulatory and operational impacts of these proposed market options.
Another consideration for Market Participants related to the magnitude of participating
facilities is the operational impact of DERs on the transmission grid. DER Operational Issues
were briefly discussed during the June DER Workshop. It is imperative that the Market
Participants determine and resolve all operational issues related to the proposed options prior to
finalizing them. Per PURA 35.151 (a) (2), one of the four essential functions of ERCOT is to
ensure the reliability and adequacy of the regional electric network. ERCOT will need to ensure
that any participation and growth due to the proposed market options will not negatively impact
the reliability of the grid. For instance, one of the initial considerations is to determine what
threshold of DER participation (if any) will cause an impact to the transmission grid, including at
the substation level if DER facilities are sufficiently concentrated. If a threshold is established,
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ERCOT will need to consider what impacts will occur if the threshold is met and surpassed and
what, if any, mitigation plans should be developed.
In addition, actions performed by ERCOT to manage any impacts to the transmission system
could potentially cause disruptions and performance issues on the distribution system. Each
TDSP is responsible for ensuring the safety and reliability of its distribution system, and PURA
39.554(b) provides that the interconnection of DG facilities is subject to TDSP safety and
reliability requirements. PUC Rules 25.211 and 25.212 explicitly authorize a TDSP to study the
reliability impacts of a proposed DG interconnection and require the installation and use of
appropriate protective devices and operating schemes. Market Participants will need to clarify
whether it is appropriate for ERCOT to direct and/or affect operations on the distribution system
based on actions taken to implement the proposed market options.
Finally, ERCOT has cited concerns with firm load shedding of feeders to which DERs are
interconnected. It should be noted that there already exist a number of limitations regarding
which feeders may be included in a TDSP’s load shed program, and exempting feeders to which
DERs are interconnected may not be realistic, particularly as the number of DER
interconnections increases.
Determination of the Communication and Enforcement Entity(ies)
Another item to consider regarding requirements for participation in the proposed DER
market is to determine what entity will communicate and enforce market requirements. While
the Joint TDSPs are currently heavily involved with the interconnections of DG facilities, it
should not be assumed that all facets of DG interconnection will be the responsibility of the
TDSP. Per statute and Public Utility Commission rules, TDSPs are responsible for various
requirements related to the interconnection and metering of DG facilities on the distribution
system. These responsibilities are primarily technical and procedural requirements allowing
open access of the distribution system to DG facilities. Requirements developed based on the
work of Market Participants will primarily be for participation in market activities. While
TDSPs should not unreasonably restrict participation, they do not seem to be the appropriate
parties to communicate and enforce market requirements.
It is commonly assumed that TDSPs have an ongoing relationship with DG facility owners
beyond the typical relationship developed as a result of providing electric service to customers in
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the respective service territories. However, this is not necessarily true. TDSPs often only
interact with DG owners during the initial interconnection and when potentially significant
changes to the interconnection are required. Typically, the TDSP’s contact information for DG
owners is only as accurate as what is provided to them by the REP serving the premises.
Additionally, any requirements developed and approved by the ERCOT Board of Directors will
be ERCOT Protocol or Guide requirements. Therefore, TDSPs will not have the inherent
authority to enforce those requirements without a ruling from the PUCT.
DER Modeling, Data Provision and Maintenance
In order to effectively analyze and manage impacts to the ERCOT system along with
allowing DER participation as outlined in ERCOT’s options, the TDSPs recognize the necessity
for modeling DERs. However, the TDSPs emphasize that they should not necessarily be
considered the default source for providing DER facility data needed for modeling. As stated in
the above section, apart from the interconnection process, the TDSPs are often not aware of all
changes that may affect the operations of DERs. Therefore, they may not have all of the
necessary data to appropriately create the DER models as will be required by the development of
the proposed options. To ensure accurate and effective modeling, responsibilities should be
assigned to appropriate parties. One method could be to consider data provisioning and
modeling of generation resources on the transmission system. ERCOT Protocols and Guides
outline responsibilities of multiple parties including ERCOT, QSEs, Resource entities, and TSPs.
A similar approach could be considered for DER modeling to include all affected and interested
parties.
In addition, requirements for DER modeling must recognize the fundamental difference
between the relatively static nature of the transmission grid and the highly dynamic nature of
radial distribution systems. For example, DERs can be moved from one load bus to another due
to daily switching necessary to support the operation of the distribution system. And the
dynamic nature of the distribution system will likely increase as the smart grid continues to
mature and automated fault restoration switching is implemented. Given the frequency and
number of changes to TDSP distribution systems, the NOMCR process may not be well suited
for reflecting changes to the load busses to which DERs are interconnected.
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Metering
Metering and the configuration of meters is a key component of the DER market options
proposed by ERCOT. The TDSPs recommend all Market Participants evaluate the necessity of
measuring gross generation and gross load separately to have a fully functioning DER market as
proposed. Currently, the ERCOT Protocols don’t require this of resource entities interconnected
to the transmission system. Although there may be benefits for planning and operations, Market
Participants should investigate and fully understand why a different approach should be taken for
DERs. The investigation should include an evaluation of metering options and the various
existing statutes and PUC rules related to the metering of DG facilities and Distributed
Renewable Generation facilities. Finally, it should be noted that additional metering costs may
be borne by the DG owner under current rules.
Other Considerations for Moving Forward
Since the DER workshop, the TAC directed a DER task force be created to consider
various issues relating to the proposed DER market options. As previously announced by
ERCOT, the DER concept paper is planned to be released by the end of the 3rd quarter of 2015.
If this deadline remains, the task force will not have sufficient time to fully address and resolve
the issues. It would be premature to release a concept paper without more comprehensive
direction on fundamental issues that will be addressed by the DER Task Force. The TDSPs
recommend postponing the release of the DER concept paper until those fundamental issues can
be identified and addressed. Based on the comments raised at the DER Workshop, the
development of DER market options is a major enhancement to the market. Since the change is
so great, it seems appropriate to take time to ensure the right policies are put in place rather than
trying to meet an artificial deadline to release the concept paper. Also, the recommendations
made by the task force should be used by ERCOT in the development of the concept paper. This
approach seems more efficient than having two parallel efforts driving for the same outcome
occurring separately.
The changes proposed could have large impacts on multiple Market Participants.
Considering this, the cost-benefit analysis to be performed prior to approval of the options
should account for impacts on all Market Participants; not just ERCOT. The total value of this
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potential change should be available for Market Participants prior to voting to enact any of the
options.
Conclusions
Again, the Joint TDSPs appreciate the opportunity to offer comments. As the electric
industry moves forward, market options such as those offered by ERCOT will need to be
discussed and evaluated in order for the market to remain effective at offering consumers low
prices for electricity while enabling various types of entities to participate. The DER market
options proposed should be thoughtfully considered to develop the optimal market for all parties
involved. The TDSPs request that ERCOT and the DER Task Force consider the issues and
recommendations stated in these comments.
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