DISTRIBUTED ENERGY RESOURCES

Stakeholder Comments submitted prior to DER TF Organizational Meeting (7/15/15)

·  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)

·  Texas Commercial Energy Holdings (page 9)

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?
  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 –to- transformer) 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.

2.  Austin Energy (Received 7/10/15)

DER WORKSHOP ISSUES LIST (6/18/15)

  1. What is the ERCOT definition of DER?
  2. How is storage (including EVs) treated in the definition?
  3. How does Wholesale Storage Load treatment factor into the DER issue?
  4. Does/should DER in ERCOT include Demand Response?
  5. What are implications for PUC Rule?
  6. Could we create a second category of DER Heavy that includes DR, settled at LZ SPP?
  7. Does PUC metering rule prohibit Dual Metering (as proposed) in competitive choice areas of ERCOT?
  8. What are the comparisons to how metering is handled at PUNs?
  9. 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.)?
  10. Should DER Light or DER Heavy status be optional, or mandatory?
  11. How would it work if mandatory?
  12. If optional, would the DER’s selection be permanent? If not permanent, how frequently could a DER change its status?
  13. Revisit and improve the ERCOT definitions of DG Resources including DG.
  14. Should DERs be subdivided by size (similar to Germany, CA)?
  15. 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.

  1. Address settlement issues including shadow settlement of load behind NOIE Ties.

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 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, 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 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.

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.