Regulatory Updates by Region

ERCOT Regulatory Highlights: August 2016

This month…

  • The PUC received more comments on the planning reserve margin target.
  • Numerous stakeholders filed comments regarding changing the Emergency Response Service (ERS) program.
  • NRG’s Greens Bayou Unit 5 (GB5) is now under Reliability Must Run contract with ERCOT.  ERCOT issued an RFP for Must Run Alternatives to GB5 in July.  Proposals are due in August.
  • ERCOT EMS Failure results in need for resettlement of July 7.
  • The PUC hired a consultant to report on Alternative Ratemaking Mechanisms, the report has been released.
  • The PUC Approved a Proposal for Publication Related to Distributed Generation Interconnection Agreements.

ERCOT and the PUC

Resource Adequacy at ERCOT

In February, in response to a memo filed in 2015 by Commissioner Anderson, the PUC opened Project No. 45572 to review the parameters of the ORDC.  Comments were filed by interested parties.  The Independent Market Monitor reported at the June Board meeting that the ORDC was working properly and not showing significant scarcity pricing during periods with robust reserves.  It is unclear how and if the PUC will proceed.

Also related to resource adequacy, in past years the PUC discussed reviewing the Reserve Margin Target for ERCOT.  In 2014, Project No. 42302 was opened for comments on the topic.    PUC staff filed a memo in June of this year asking for any additional comments on the Reserve Margin Target or addressing previous open meeting discussions.  Only a few market participants weighed in again in comments file in July.  The PUC plans to discuss the topic again in September or later in the year. 

PUC Opens Rulemaking on Emergency Response Service

In May, Commissioner Anderson filed a memo asking to open a rulemaking on the ERCOT Emergency Response Service (ERS).  In response, PUC staff opened Project No. 45927 – Rulemaking Regarding Emergency Response Service.    Staff requested comments from interested parties and multiple parties, including ERCOT and the Independent Market Monitor weighed in on whether or how the ERS market should be changed.  The preliminary rulemaking schedule indicates that if a workshop is needed, it will be scheduled for October, with a draft rule released in November.

Reliability Must Run (RMR) for Greens Bayou and Must Run Alternative RFP

NRG filed a Notice of Suspension of Operation with ERCOT for Greens Bayou unit 5 (GB5) and ERCOT issued a final determination that the unit was needed for reliability.  The ERCOT Board has approved the RMR agreement for the unit.  ERCOT signed the RMR agreement on June 1, with contract dates of July 2016 – June 2018 and operations limited to July – September 2016, June – September 2017, and June 2018.   

The contract indicates RMR energy and standby prices of approximately $65 million to the market over two years.  These costs will be allocated to all load on a load-ratio share basis over the term of the contract.  ERCOT can negotiate for Must Run Agreement (MRA) resources to provide an acceptable solution to reliability concerns that would be solved by the RMR unit.  ERCOT issued a Request for Proposals on July 8 for MRA resources that in whole, or in aggregate could replace GB5.  Proposals are due August 19.  The first required day for the MRA resources would be June 1, 2017.

As a result of this RMR, several market changes are being discussed by stakeholders.  Potential changes include how capital costs might be recovered by ERCOT if those costs are paid to an RMRed resource when the resource either retires or enters market activity again.  Another area of discussion is the planning studies/load forecast used to determine the need for an RMR a unit. 

ERCOT EMS System Failure and Resettlement

On July 7, ERCOT experienced a system failure of the Energy Management System (EMS) which also affected the Market Management System (MMS), Security Constrained Economic Dispatch (SCED), Settlements, and Load Frequency Control.  This was the largest system failure of ERCOT systems to date.  At 11:41 that morning, an incorrect command corrupted data in the network model.  The system was restored at 1:23 pm that day.  ERCOT made an initial attempt to resettle the affected SCED intervals, but did not have enough valid data to settle it correctly.  They continue to work toward having the data they need for an accurate resettlement of that time period.  In addition, stakeholders asked ERCOT to find ways to improve communication about such events in the future.

Consultant Releases Report to the PUC on Alternative Ratemaking Mechanisms

In June, a report summarizing alternative ratemaking mechanisms used in other states to set regulated electric utility rates was released by Christensen Associates Energy Consulting.  The report was in response to a request of the Texas Legislature that the PUC review ratemaking mechanisms adopted by other states that serve as alternatives to traditional cost-of-service ratemaking.  The report expresses a preference for a move to Straight Fixed-Variable (SFV) rate design for the recovery of transmission and distribution costs.  SFV Rates allow the utility to recoup nearly all fixed costs through fixed monthly charges (per customer-month) or peak demand charges (per peak kW) that are independent of the volume of electricity consumed.  The PUC has opened Project No. 46046 to consider the report findings.  Texas Transmission and Distribution Service Providers may now utilize a distribution cost recovery factor (DCRF) for the timely recovery of infrastructure costs.  This DCRF mechanism is set to expire on September 1, 2019 and the PUC is exploring types of alternative ratemaking mechanisms that might be used to ensure timely cost recovery while preserving incentives to achieve the other goals that might be fostered by appropriate rate design.

PUC Approves Proposal for Publication Related to Distributed Generation Interconnection Agreements

The PUC has approved for publication a proposed rule allowing certain entities other than the end-use customer to execute a distributed generation (DG) Interconnection Agreement (IA) with a Transmission Service Provider (TSP).  The proposal would allow for an end-use customer, a premises owner, a generator, or a person who has been assigned ownership rights to enter into an IA. This amendment reflects the current state of financing, installing, and operating small-scale DG in the Texas market today.  Initial comments were filed in July and reply comments are due August 12.

Upcoming ERCOT and PUC Meetings:

Retail Market Subcommittee – August 2

Wholesale Market Subcommittee – August 3

Reliability and Operations Subcommittee – August 4

ERCOT Board Meeting – August 9

Commercial Operations Subcommittee – August 10

Protocol Revision Subcommittee – August 11

Technical Advisory Committee – August 25

Public Utility Commission Open Meeting – August 18

All data provided in this report is intended for general information use only.  Direct Energy does not guarantee the completeness or accuracy of this data, nor does Direct Energy assume any liability for any loss that may result from the reliance by any person or entity on this information.

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