Ava Community Energy Board of Directors
May 17, 2023

Staff Report Item 18
Staff Report Item 18
TO: East Bay Community Energy Board of Directors
FROM: Michael Quiroz, Regulatory Analyst
SUBJECT: Request for Approval of an Interim Compliance Plan for the California Energy Commission’s Load Management Standards
DATE: May 17, 2023
__________________________________________________________________ Recommendation
Approve a Resolution to serve as the interim Load Management Standards compliance plan. The proposed compliance plan defers submitting data into the California Energy Commission’s (CEC’s) Market Informed Demand Automation Server (MIDAS) database until issues pending in the CEC’s LMS proceeding are satisfactorily resolved.

Background and Discussion
I. Overview of the Load Management Standards
The Load Management Standards (LMS) are defined in the California Code of Regulations. In October of 2022, the California Energy Commission (CEC) adopted revisions to the LMS.1
The revised LMS require large CCAs, Investor Owned Utilities, (IOUs) and Publicly Owned Utilities (POUs) to develop: (1) hourly location-based electric rates and (2) systems for reporting current and future time-dependent rates.2
1 Proposed Revisions to the Load Management Standards, as adopted by the CEC on October 12, 2022. 2OAL Approval of Revisions to the Load Management Standards, as approved by the CEC on January 20, 2023, and ordered effective as of April 1, 2023
Staff Report Item 18
Our focus in this report is on item (2), the reporting obligation. Unless the Board acts, EBCE must upload to MIDAS all time-dependent rates (such as time-of-use) by no later than July 1st, 2023.3
The Board can vote to extend this deadline. §1623.1(a)(2) of the LMS authorizes POU and CCA Boards to delay or modify compliance with LMS requirements, including MIDAS upload requirements, if “despite a Large POU’s or Large CCA’s good faith efforts to comply, requiring timely compliance with the requirements of this article would result in extreme hardship to the Large POU or CCA,” or would not be “technologically feasible or cost effective.”
Since November of 2022, EBCE staff members have been coordinating with other CCAs, CalCCA, the IOUs, the POUs, and the CEC to provide feedback on the development of MIDAS and proactively address any potential barriers to compliance. Members of EBCE’s Regulatory, Analytics, and Account Services teams have collaborated to participate in several working groups, respond to CEC requests for information, preemptively test MIDAS upload and download capabilities, and inform discussions with CEC staff and Commissioner McAllister via CalCCA. Through this process, EBCE staff has identified critical issues that preclude technologically feasible and cost-effective compliance with the July 1st deadline for LSEs to upload existing rates.

We detail the compliance challenges below.

II. The CEC has not decided how to combine CCA and IOU rates CCAs are responsible just for the generation portion of a customer’s bill. IOUs, in contrast, are responsible for all the other components of a customer’s bill. Things like transmission charges, distribution charges, public purposes surcharges, etc., are solely the IOU’s responsibility.

The question that has arisen is who will merge the CCA portion of a bill – i.e., a CCA rate – with the IOU portions of a bill when uploading to MIDAS? CEC staff has interpreted the LMS as requiring CCAs to upload all rate components associated with each rate, including IOU rate components, to the MIDAS database.

CCAs disagree with this interpretation. CCAs have proposed that third parties merge CCA and IOU rates, or that MIDAS itself merge CCA and IOU rates. 3 §1623.1(c), OAL Approval of Revisions to the Load Management Standards Staff Report Item 18
It is neither technologically feasible, nor cost effective for EBCE to manage the combination of its and PG&E’s rates for MIDAS purposes. Doing so would result in significant hardship to EBCE for two primary reasons: 1) EBCE does not have PG&E’s rate information in a machine-readable format, and 2) the combination of all potentially overlapping IOU and CCA rate components would be labor-intensive and a complex computational process.

EBCE’s billing process can be summarized in three distinct steps:

1. As EBCE’s metering agent, PG&E owns, operates, and reads all customer meters in EBCE’s territory. After reviewing and validating the consumption data from these meters, PG&E provides SMUD with the resulting energy usage data.

2. As EBCE’s billing agent, SMUD retains all information about EBCE’s rates. By multiplying EBCE’s rates by the corresponding usage data, SMUD calculates the generation charges for each EBCE customer.

3. SMUD sends finalized generation charges to PG&E, who is responsible for formatting and distributing the final customer-facing bill.

Neither PG&E nor EBCE exchange any information about their rates in this process.

Moreover, although PG&E posts individual PDFs describing each of its rates online, these PDFs are not machine-readable, and no advance warning is given when rate components are updated. As such, EBCE does not have sufficient access to the specific transmission and distribution rate components that PG&E uses to calculate customer bill amounts.

Without this information, EBCE cannot be responsible for uploading anything beyond its own generation rate components to MIDAS.

Even if EBCE was provided with timely access to all transmission and distribution rate components, the CEC’s interpretation of §1623.1(c) would require EBCE to combine all EBCE’s generation rate components with every eligible set of PG&E rate components in order to upload combined rates to MIDAS. EBCE staff have estimated that there are 11,664 distinct combinations of rate components needed to fully represent EBCE’s current time dependent rates. Combining all of these components with every possible permutation of PG&E components would be extremely difficult and would require significant planning and review to ensure accuracy and reliability. Additionally, while CCAs only change their rates once annually, utility rate changes may be much more common. While EBCE does not agree that CCAs can be responsible for the maintenance of IOU rates, if they are, it would require CCAs to recalculate and upload the above number of scenarios and entries each time. Adopting location-based prices that vary by hour will make this process multiple times more challenging.

Staff Report Item 18
III. MIDAS guidelines and systems are still in development As of the date of this report, the CEC has not released the final specifications or guidelines for how rates must be categorized and formatted before upload to MIDAS.

Additionally, MIDAS itself requires updated documentation and appears to remain under active development by the CEC. EBCE will not be able to develop automated systems to upload complex pricing to MIDAS while the system is in active development and without current documentation. While limited manual upload of rates may be possible, it would, at best, be a time and labor-intensive process.

IV. Conclusion
As it stands, there is not currently a technologically feasible process in place for EBCE to compile unbundled customer rates for upload to MIDAS. EBCE cannot take responsibility for the accuracy of PG&E’s rates. The CCAs have proposed that third party automation providers build into their technology the capability to compile CCA generation and IOU transmission/delivery rates (to make up the combined rate). The CCAs have also proposed that MIDAS itself have the capability to compile the rate itself, which could be more efficient given the rate compilation would all be done in one place. However, CEC staff have not responded to the CCA proposals, and the IOUs and CCAs currently have no guidance on the rate compilation issue.

EBCE staff recommend that the Board approve an interim compliance plan that extends the July 1st deadline for uploading EBCE rates to MIDAS to no less than nine months after compliance barriers have: (a) been resolved, (b) in a manner that allows for cost effective and technologically feasible CCA compliance.

Fiscal Impact
The proposed interim compliance plan minimizes LMS compliance costs and requires no additional funding beyond current authorizations.

Attachments
A. Resolution to Approve an Interim Compliance Plan for the California Energy Commission’s Load Management Standards
B. Relevant Sections of the Load Management Standards
C. IOU & CCA Request for Extension of July 1, 2023 Deadline Set By Revised Load Management
Staff Report Item 18
D. EBCE Response to CEC Request for Information
Attachment Staff Report Item 18A
RESOLUTION NO.

A RESOLUTION OF THE BOARD OF DIRECTORS

OF THE EAST BAY COMMUNITY ENERGY AUTHORITY TO APPROVE AN INTERIM COMPLIANCE PLAN FOR THE CALIFORNIA ENERGY COMMISSION’S LOAD

MANAGEMENT STANDARDS
WHEREAS The East Bay Community Energy Authority (“EBCE”) was formed as a community choice aggregation agency (“CCA”) on December 1, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Alameda, and the Cities of Albany, Berkeley, Dublin, Emeryville, Fremont, Hayward, Livermore, Piedmont, Oakland, San Leandro, and Union City to study, promote, develop, conduct, operate, and manage energy-related climate change programs in all of the member jurisdictions. The cities of Newark and Pleasanton, located in Alameda County, along with the City of Tracy, located in San Joaquin County, were added as members of EBCE and parties to the JPA in March of 2020. The city of Stockton located in San Joaquin County, was added as a member of EBCE in December of 2022.

WHEREAS The CEC approved revisions to the Load Management Standards on January 20, 2023, that require large CCAs, Investor Owned Utilities (IOUs), and Publicly Owned Utilities (POUs) to develop hourly location-based electric rates and systems for reporting current and future time-dependent rates; and WHEREAS Members of EBCE’s Regulatory, Analytics, and Account Services teams have collaborated to proactively identify and address any potential barriers to compliance by participating in several working groups, responding to CEC requests for information, preemptively testing MIDAS upload and download capabilities, and informing discussions with CEC staff and Commissioner McAllister via CalCCA; and WHEREAS There is not currently a technologically feasible or cost-effective process in place for the CCAs or IOUs to combine their rates and upload to MIDAS by July 1, 2023, as is required by §1623.1(c) of the LMS. There are differences in CCA and CEC interpretations around who is responsible for doing so; and WHEREAS the CEC has not formally released the final specifications or guidelines for how rates must be categorized and formatted before upload to MIDAS, and MIDAS itself requires updated documentation and appears to remain under development; and
WHEREAS Addressing these foundational issues is crucial for EBCE staff to develop further plans for compliance with future requirements described in the Load Management Standards.

WHEREAS Requiring EBCE to upload combined rates by July 1, 2023 would result in extreme hardship to EBCE; and
Attachment Staff Report Item 18A
WHEREAS §1623.1(a)(2) of the Load Management Standards authorize a CCA’s Board of Director’s to delay or modify compliance with LMS requirements, including MIDAS upload requirements, if “despite a Large POU’s or Large CCA’s good faith efforts to comply, requiring timely compliance with the requirements of this article would result in extreme hardship to the Large POU or CCA,” or would not be “technologically feasible or cost effective.”

NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE EAST BAY COMMUNITY ENERGY AUTHORITY DOES HEREBY RESOLVE AS FOLLOWS:

Section 1. The Board hereby authorizes this Resolution to serve as EBCE’s interim compliance plan for implementation of the Load Management Standards.

Section 2. The Board hereby authorizes an extension of the July 1, 2023 deadline for uploading EBCE rates to MIDAS to no less than nine months after compliance barriers have: (a) been resolved, (b) in a manner that allows for cost effective and technologically feasible CCA compliance.

Section 3. If such barriers are not resolved, the Board authorizes EBCE staff to make additional modifications to the interim LMS compliance plan, as necessary.

ADOPTED AND APPROVED this 17th day of May.

Elisa Marquez, Chair
ATTEST:

Adrian Bankhead, Clerk of the Board
§ 1623.1. Large POU and Large CCA Requirements for Load Management Standards.
(a) Large POU Plans to Comply with Load Management Standards (1) Within six months of April 1. 2023, each Large POU, and within one year of April 1, 2023, each Large CCA, shall submit a compliance plan that is consistent with this Section 1623.1 to its rate approving body for adoption in a duly noticed public meeting to be held within 60 days after the plan is Attachment Staff Report Item 18B
submitted. The plan shall describe how the Large POU or the Large CCA will meet the goals of encouraging the use of electrical energy at off-peak hours, encouraging the control of daily and seasonal peak loads to improve electric system efficiency and reliability, lessening or delaying the need for new electrical capacity, and reducing fossil fuel consumption and greenhouse gas emissions. The plan shall include consideration of programs and rate structures as specified in section 1623.1 (b)-(d).
(A) The plan must evaluate cost effectiveness, equity, technological feasibility, benefits to the grid, and benefits to customers of marginal cost-based rates for each customer class. (B) If after consideration of the factors in Subsection 1623.1 (a)(1 )(A) the plan does not propose development of marginal cost-based rates, the plan shall propose programs that enable automated response to marginal cost signal(s) for each customer class and evaluate them based on their cost-effectlveness. equity, technological feasibility, benefits to the grid, and benefits to customers.
(C) The Large POU or the Large CCA shall review the plan at least once every three years after the plan is adopted. The Large POU or Large CCA shall submit a plan update to its rate approving body where there is a material change to the factors considered pursuant to Subsections 1623.1 (a)(1)(A) and (B).
(2) The rate approving body of a Large POU or a Large CCA may approve a plan, or material revisions to a previously approved plan, that delays compliance or modifies compliance with the requirements of Subsections 1623.1 (b)-(c), if the rate approving body determines that the plan demonstrates any of the following:
(A) that despite a Large POU's or Large CCA's good faith efforts to comply, requiring timely compliance with the requirements of this article would result in extreme hardship to the Large POU or the Large CCA, (B} requiring timely compliance with the requirements of this article would result in reduced system reliability (e.g., equity or safety) or efficiency, (C} requiring timely compliance with the requirements of this article would not be technologically feasible or cost-effective for the Large POU to implement, or
(D} that despite the Large POU's or the Large CCA's good faith efforts to implement its load management standard plan, the plan must be modified to provide a more technologically feasible, equitable, safe or cost-effective way to achieve the requirements of this article or the plan's goals. (3) Commission Approval of Large POU and Large CCA Plans to Comply with Load Management Standards and Material Plan Revisions
Attachment Staff Report Item 18B
,~A) Within thirty (30) days after adoption of a plan or material plan revision pursuant to this subdivision each large POU and Large CCA shah submit its plan to comply with the requirements of this Section 1623.1 or material ~(~n rn..:';8lC}fl ~rJ' t~C ~YA~.:.lt!`.8 QlrA~tnr
~B1 The Executive Director shall review plans or material plan revisions and either return them to the Larcle POU or the Large CCA for changes or submit them to the Commission for review and potential approval. The Executive Director shall make an initial determination whether the plan or material plan revision is consistent with the requirements of Section 1623.1(a)(1) and (2). in reviewinq plans and material plan revisions, the Executive Director may request additional information or recommend changes to make it consistent with the requirements of Section 1623.1 tal ~1) and (2). The Large POU or Large CCA shall respond to requests or recommendations within ninety (90) days of receipt from the Executive Director. The Executive Director shall then submit the plan or material plan revision to the Commission with a recommendation on whether to approve it. The Commission may also request additional information and shall approve plans and material plan revisions which are consistent with Section 1623.1(a)(1) and (2), and which show a good faith effort to meet the goals listed in Section 1623.1(a)(1) and (2). The Commission mad place conditions on its approval of plans or material plan revisions that are necessary to guarantee that the plan or material plan revision will comply with Section 1623.1 (a)(1 }and (2} by a date certain.
(C) Each Large POU and Large CCA shall submit to the Executive Director annual reports demonstrating their implementation of plans approved pursuant to this subsection as such plans may be revised pursuant to this subsection. The reports shall be submitted one year after plans are approved pursuant to subsection (2) and annually thereafter. fib) Large POU and Large CCA Marginal Cost-Based Rates and Programs. Each Large POU and each Large CCA shall develop marginal cost-based rates or public programs structured according to the requirements of this article. {1) Total marginal cost shall be calculated as the sum of the marginal energy cost the marginal capacity cost (generation, transmission, and distribution), and any other appropriate time and location dependent marginal costs, including the locational marginal cost of associated greenhouse pas emissions, on a time interval of no more than one hour. Energv cost computations shall reflect locational marginal cost pricing as determined by the associated balancing authority, such as the Los Angeles Department of Water and Power the Balancing Authority of Northern California, or other balancing authority. Marginal capacity cost computations shall reflect the variations in the probability and value of system reliability of each component (generation, transmission, and distribution).

Attachment Staff Report Item 18B
21 Within two (21 years of Agril 1.2023. each Larae POU. and within twenty-seven (27) months of Aprii 1, 2023, each ~arge CCA, sha11 apply to its rate-approvinq body for approval of at least'one marginal cost-based rateLthat meets the requirements of Subsection 1`623.1(b)(1). Large CCAs may apply for approval of marginal cost-based rates that are'offered by the Large fOUs in whose service areas the Large CCAs exist in.
(A) Lame P4Us and Large CCAs shall apply for approval of margina( cost-based rates only for those customer classes for which the rate-approving body deterrriines such a rate`will materially reduce peak load. (B1 Large POUs and Large CCRs shall provide the Commission with informational copies of tariff applications when they are submitted to their rate-at~~rovina bodies.

X31 No later than eighteen X181 months after April 1y2023, each Large POU and each Large CCA shall submit to the Executive Director a list of load flexibility programs deemed cost-effective.. by the Large POU ar the ~arge CCA. (A~ The portfolio of identified programs shall provide of least one option for automating response to MIDAS signals fior each customer class that the rate-approving body determines such a program will materially reduce peak load.
(B) The programs shall allow customers to respond to f~IDAS signals indicating marginal cost-based rates, marginal prices, hourly or sub-hourly marginal greenhouse gas emissions, or other Commission-approved marginal signal(s).
~4) Within three (3) years of April 1, 2023, each Large POU, and within fifty-one (51) months of April 1.2023, each Large CCA, shall offer to each of its electricity customers voluntary participation in ~ith~r a margina{ cost-based rate developed according to Subsection 1623.1(b)t2), if such rate is approved by the l~arge POU's or ~arQe CCA's rate-approving body, or acost=effective program identified according to Subsection `i 623.1(b)(3). ~5) Each Large POU and ~arge CCA shall conduct a public information program to inform and educate the affected customers why marginal cost-based rates or load flexibility programs, and automation are needed, flow they will be used,-and how these ra#es or programs can save the customer money. (c) Publication of Machine-Readable Electricity Rates.'No later fihan three (3) months after April 1, 2023, each ~arge POU and each Large CCA shall upload its existing time-dependent rates applicable #o its customers to the Commission's Market Informed Demand Automation Server tMIDAS_~ database. Each ~arge POU and Large CCA shall upload all time-dependent rates, including those approved after April 1, 2023, to MIDAS prior to the effective dots of the time-dependentrates each time atime-dependent rate is approved by the rate-approvinclbody and each time atime-dependent rate changes.

Attachment Staff Report Item 18B
The time-dependent rates uploaded to the MIDAS database shall include all applicable time-dependent cost components. including, but not limited to, generation, distribution, and transmission. The Commission maintains public access to the MIDAS database thmugh an Application Programming Interface (API) that. provided a Rate Identification Number (RIN), returns information sufficient to enable automated response to marginal grid signals, such as price, emergency events, and greenhouse gas emissions.
(d) Enforcement. The Executive Director may, after reviewing the matter with the Large POU or the Large CCA, file a complaint with the Commission following the process set forth in Sections 1233.1 to 1233.4 or seek injunctive relief if a Large POU or Large CCA:
(1) Fails to adhere to its approved load management standard plan. (2) Materially modifies its approved load management standard plan without approval,
(3) Does not provide information by a deadline established by the Executive Director or the Commission, or
( 4) Violates the provisions of this article.
(e) There shall be no reimbursement to local government entities for the costs of carrying out the programs mandated by these standards, because the Commission has found these standards to be cost-effective. The savings which these entities will realize as a result of carrying out these programs will outweigh the costs associated with implementing these programs.

Note: Authority cited: Sections 25213, and 25218(e), and 25403.5, Public Resources Code. Reference: Sections 25132 and 25403.5, Public Resources Code.

Attachment Staff Report Item 18B
Jennifer Privett 1415 L Street, Suite 280
State Agency Relations
[email protected]
Sacramento, CA 95814
(916) 698-8033
April 28, 2023
Drew Bohan
Executive Director
California Energy Commission
Re: Docket No. 21-OIR-03
715 P Street
Sacramento, CA 95814-5512
Re: 21-OIR-03, 2022 Load Management Rulemaking:

Request for Extension of July 1, 2023 Deadline Set By Revised Load Management Standards
Dear Executive Director Bohan:

Pacific Gas and Electric Company (PG&E), on behalf of itself and other load serving entities (LSEs) that are subject to the recently revised load management standards (LMS) (collectively, the Joint Parties),1 writes to request your approval of an extension of the July 1, 2023 deadline set by the revised LMS for the Joint Parties to upload their existing time-dependent rates to the California Energy Commission’s (CEC) Market-Informed Demand Automation Server (MIDAS) Database.

This letter follows up on a constructive conference call the Joint Parties held with Commissioner Andrew McAllister, CEC staff members, and CEC counsel on April 10, 2023, during which the Joint Parties explained their concerns about the feasibility of the July 1, 2023, deadline. This letter summarizes those concerns and proposes a path forward that combines flexibility as to the deadline with a phased approach that will allow for forward movement in the near term toward meeting the important goals set by the revised LMS. 1 The other parties, all of which have agreed to PG&E sending this letter on their behalf, are: Southern California Electric Company (SCE), San Diego Gas & Electric Company (SDG&E), Clean Power Alliance of Southern California (CPA), East Bay Community Energy (EBCE), Marin Clean Energy (MCE), Central Coast Community Energy (CCCE), Silicon Valley Clean Energy Authority (SVCE), San Jose Clean Energy (SJCE), Peninsula Clean Energy Authority (PCE), CleanPowerSF (CPSF), Sonoma Clean Power Authority (SCP), San Diego Community Power (SDCP), Pioneer Community Energy (Pioneer), Valley Clean Energy (VCE), and Orange County Power Authority (OCPA).

Attachment Staff Report Item 18C
2 1. Background Regarding Revised LMS
On January 20, 2023, the Office of Administrative Law approved, and ordered effective as of April 1, 2023, the CEC’s proposed amendments to California Code of Regulations (CCR) §§ 1621-1625, which set forth the LMS.2 The revised LMS are intended to facilitate a statewide real-time signaling system that can be used by mass-market end-use automation to provide load flexibility on the electric grid.

Among other changes, the revised LMS set a deadline of July 1, 2023 for the Large Investor-Owned Utilities (the Large IOUs, namely PG&E, SCE, and SDG&E), the Large Publicly-Owned Utilities (the Large POUs, namely LADWP and SMUD), and the Large Community Choice Aggregators (the Large CCAs, namely any CCA that provides in excess of 700 GWh of electricity to customers in any calendar year) to upload their existing time-dependent rates to the MIDAS database.3

2. The Joint Parties’ Concerns with the July 1, 2023 Deadline As stated during the April 10, 2023 conference call, the Joint Parties are concerned about the feasibility of the July 1, 2023 deadline for upload of existing time-dependent rates to the MIDAS database.

This concern stems from the fact that the MIDAS Database is still in development (as discussed further below), and until it is finalized, the Joint Parties will not be able to automate the process of uploading rates to MIDAS. While manual uploads of rates are possible to some extent, large scale manual uploads are not feasible or cost-effective given the number of different rates and the personnel time required to perform such uploads.

As discussed during the April 10, 2023 conference call, the MIDAS database remains in development in important respects, preventing the Joint Parties from initiating the significant work necessary to allow for automatic uploading of rates. Current impediments to automation of uploads include the following.
(a) Until the Requirements for Rate Identification Numbers are Finalized, the Joint Parties are Unable to Develop Processes for Automated Uploads of Rates to MIDAS

2 See CEC, Docket 21-OIR-03, TN# 248526, Office of Administrative Law Approval of Revisions to the Load Management Standards, docketed 1/25/23, available at
https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=21-OIR-03. 3 See 20 CCR § 1623(b) (“No later than three (3) months after April 1, 2023, each Large IOU shall upload its existing time-dependent rates applicable to its customers to the [MIDAS] database.”); 20 CCR § 1623.1(c) (“No later than three (3) months after April 1, 2023, each Large POU and each Large CCA shall upload its existing time-dependent rates applicable to its customers to the [MIDAS] database.”).

Attachment Staff Report Item 18C
3 Starting in November 2022, the CEC convened Working Groups to develop functional requirements for MIDAS and the format for Rate Identification Numbers (RINs). However, except for one meeting on March 30, 2023, all Working Group meetings in March 2023 were cancelled. As of the date of this letter, the CEC has not formally released the final specification for RIN construction, and MIDAS is not yet able to support all required rate components.

Among some of the unresolved questions are the following:
 How should unbundled vs. bundled rates and RIN be addressed? o While the LSEs do not interpret LMS to require rate compilation for unbundled customer rates (made up of a Large CCA’s generation rates plus the IOU’s transmission and distribution rates) prior to LSE upload, if such rate compilation is required, who will build, pay for, and be responsible for maintaining a rate compilation tool?
 There is not currently a technologically feasible process in place for the IOUs or CCAs to compile the unbundled customer rates to upload to MIDAS, either in MIDAS or otherwise.
 The CCAs and IOUs cannot take responsibility for the accuracy of each other’s rates (i.e., the CCA generation rate and the IOU transmission/delivery rate).
 There is no system or process available to update and keep unbundled customer rates current and accurate in MIDAS when rates change, as required by the LMS regulations. The IOUs and CCAs need time to fund, create, and maintain these systems and processes.
 The CCAs have proposed that third party automation providers build into their technology the capability to compile CCA generation and IOU transmission/delivery rates (to make up the unbundled rate). The CCAs have also proposed that MIDAS itself have the capability to compile the rate itself, which is the most efficient option given the rate compilation will all be done in one place. However, CEC staff have not responded to the CCA proposals, and the Joint Parties have no guidance on the rate compilation issue.
 Because rate modifiers can result in different generation and distribution prices for different customers, should all rate modifiers be included, or should the list be filtered based on the number of customers eligible?
 What are the examples of rate modifiers that may need different RINs because they affect volumetric charges? These include, without limitation:
o CARE
o FERA
o Medical baseline (only if it affects the volumetric price) o Disadvantaged community discount
o Green tariff (50% or 100%)
Attachment Staff Report Item 18C
4 o Critical Peak Pricing (e.g., SmartRate)
o Line voltage (service voltage) levels
o Connection type: Transmission, primary, secondary, phase service o Vintage year (results in different Power Charge Indifference Adjustments for different CCAs customers)
o Location (when it affects volumetric pricing)
 How should MIDAS’s current inability to accept rates with different import and export prices (e.g., DAHTRP-CEV) be addressed?
 What rate data granularity should be used?
o For hourly rates, 8760 hours vs. 24 hours
o For TOU rates, should this follow the same level of granularity as hourly rates? o Should the upload involve only the time-dependent charges of a customer rate or the entire rate, including static charges?
Even as these questions require more clarification through further effort by the Working Group, it is already clear that the numerous factors involved will likely result in an extremely high level of complexity for RIN. As an example, PG&E has approximately 36 time-dependent rates, including residential, non-residential, and agricultural. Based on the rate modifiers above, each rate could have 45 to 450 RINs, amounting to from 1620 to 16200 RINs in total, and this figure does not include the locational permutation.4 If each RIN were required to be uploaded on a daily basis on a 24-hour interval, PG&E estimates it would need to upload 38,880 to 380,000 price intervals into MIDAS. This number could double if each unbundled customer has two RINs, one for its UDC and one for its LSE.

Only after these questions are resolved and the standards and requirements for RIN are firmly established will each of the Joint Parties be able to begin to develop the systems and processes necessary for automated uploads to MIDAS.
(b) Until Application Programming Interface Requirements are Finalized with Current Documentation, the Joint Parties are Unable to Develop Processes for Automated Uploads of Rates to MIDAS
In addition to needing to finalize guidelines for RINs and price formatting as described in the previous section, the MIDAS system needs to be stabilized and documentation updated. Initially, SCE was testing the MIDAS application programming interface (API) by uploading test data but has now paused that effort due primarily to the system being under active development with no availability of updated documentation. 4 SDG&E has 30 commodity and UDC time dependent tariffs, spanning residential, adaptive lighting, commercial and agricultural. These equates to over 95 rate categories that SDG&E uses for billing in its systems. Factoring in the modifiers and renewable programs with these rate categories, SDG&E estimates it would need to upload anywhere from 30k to 300k price intervals into MIDAS.

Attachment Staff Report Item 18C
5 For example, during the LMS Working Group Meeting 5 held on February 21, 2023, CEC staff informed stakeholders that all test data should be uploaded with “TEST” as the location code. After this meeting, SCE attempted to upload data with “TEST” in the location field as requested, but the upload failed. CEC staff made a change to the system, and subsequently “TEST” was accepted as a location code but did not appear in the LOCATION table when SCE downloaded it. Around this same time, SCE requested updated documentation, and CEC staff notified SCE that they were working on updated documentation or changelogs.

The Joint Parties are unaware of the MIDAS documentation having been updated since October 2022.5 Based on the interactions described above, it appears that MIDAS remains under active development by the CEC.
(c) Large Scale Uploading of Rates is Not Feasible Until MIDAS Is Finalized Such that the Joint Parties Can Automate the Uploading Process The Joint Parties will not be able to develop automated systems to upload complex pricing to MIDAS while the system is in active development and without current documentation. While manual uploads of rates may be possible to a limited extent, this is not a feasible or cost-effective broad-based solution given the time- and labor-intensive nature of such work. The discussion regarding PG&E’s rates above is indicative of the magnitude of the uploading work that would be required to be performed manually, potentially on an ongoing basis to keep rate information current in MIDAS. The Joint Parties submit that it would be incongruent and counterproductive for load serving entities to be required to perform (using ratepayer funds) extensive manual uploading for a system that is intended to promote efficiency and end-use automation to provide load flexibility on the electric grid.

3. An Extension of the July 1, 2023 Deadline Is Warranted The Joint Parties acknowledge that the revised regulations may differ with respect to the process for IOUs and Large CCAs to seek an extension, even though the Joint Parties’ reasons for seeking the extensions are aligned. Section 1621(e) allows the IOUs to apply directly to the Executive Director for an exemption or extension of a compliance deadline, based on a showing that requiring timely compliance would cause extreme hardship, result in reduced system reliability or efficiency, or would not be technologically feasible or cost-effective.6 While Section 1623.1(a)(2) provides Large CCAs the ability to seek approval from their rate approving body of a compliance plan that delays compliance under the regulations (based on the same criteria as the IOU request for extension),7 the compliance plans of the Large CCAs are 5 See https://www.energy.ca.gov/publications/2021/market-informed-demand-automation-server-midas-documentation-version-12. 6 See § 1621(e).
7 See § 1623.1(a)(2) (“The rate approving body of a . . . Large CCA may approve a plan, or material revisions to a previously approved plan, that delays compliance or modifies compliance with the requirements of Subsections 1623.1(b)-(c) . . . .”).

Attachment Staff Report Item 18C
6 not due until April 2024.8 Therefore, the regulations do not explicitly provide for a process for CCAs to request an extension of the July 1, 2023 MIDAS upload requirement.9 Nevertheless, grounds exist to extend the July 1, 2023 deadline for all of the Joint Parties to upload all existing time-dependent rates to MIDAS to nine months after the final MIDAS protocols are issued by the CEC. Requiring the Joint Parties to upload all of their existing time-dependent rates to the MIDAS database by July 1, 2023 would cause extreme hardship to, and is technologically infeasible for, the Joint Parties because (1) the requirements for RINs are still in development by the CEC, have become very complex, and automating the uploads will require significant time and resources; and (2) MIDAS API functional requirements continue to change and need to be in a stable state with current documentation before the Joint Parties can build the systems and processes needed for automated uploads. The LSEs note that the ability of the LSEs to upload all existing time-dependent rates within the proposed nine-month period is predicated on the LSEs’ interpretation of the regulations that each LSE is required to upload its own time-dependent rate (i.e., that rate combination between the CCAs generation and IOUs’ transmission and distribution rates is not required).

The Joint Parties therefore submit that in response to this letter, the Executive Director may (i) approve the Joint IOUs’ extension request, and (ii) approve the Large CCAs' extension request without requiring individual CCA requests for extension or governing body approval, acknowledging that the Large CCAs face the same impediments to meeting the July 1, 2023 deadline as do the Joint IOUs.

4. Proposal for Alternative Timeline Involving Staged Implementation As discussed during the April 10, 2023 conference call, given the many challenges and complexities described above, the Joint Parties ideally would prefer an extension of the deadlines set forth in 20 CCR § 1623.1(b) and 20 CCR § 1623.1(c) for uploading existing time dependent rates to MIDAS to 12 months after adoption of standards for RINs.

However, based on the feedback of Commissioner McAllister during the conference call, the Joint Parties have worked together to develop proposals for a phased implementation of the LMS over a nine-month period after the MIDAS completion that would avoid a flat extension of 12 months. For each milestone listed below during the nine-month period, each LSE will endeavor to provide the most information possible, based on technological feasibility and cost-effectiveness. The compliance parameters set forth below provide a range of the implementation capabilities of the 16 LSEs making up the Joint Parties. For all LSEs, the 8 See § 1623.1(a)(1) (“Within . . . one year of April 1, 2023, each Large CCA, shall submit a compliance plan that is consistent with Section 1623.1 to its rate approving body . . . .”). 9 Despite this ambiguity, each of the Large CCAs signing on to this letter can seek approval from its respective rate approving body for an extension of the July 1, 2023 upload requirement, and can provide any such approval to the Executive Director at a later date. However, the Large CCAs submit that a blanket extension is warranted given the regulation ambiguity and the overall circumstances.

Attachment Staff Report Item 18C
7 milestones established are predicated on the LSEs’ interpretation of the regulations that each of the LSEs upload its own time-dependent rate (i.e., that rate combination between the CCAs’ generation and IOUs’ transmission and distribution rates is not required).

Specifically, the Joint Parties propose as follows:

By July 1, 2023:
 Manual Rate Uploads - Because rate uploads at this compliance milestone will be done manually, and not driven from an automated system, only the base rate(s), without modifiers, will be uploaded. For the same reasons, rate upload format will be in the most efficient manner, and likely not hourly as discussed in the MIDAS workshops.

These prices will be maintained until automated solutions are developed.

Depending on the LSE, the uploads will consist of the following range amongst the Joint Parties:
o SCE, PG&E and SDG&E will provide a selection of base rate prices to MIDAS that will cover the majority of customers on time dependent rates and attempt to cover a variety of scenarios.

Rates will include a selection of Residential TOU, Commercial TOU with peak demand charge and Agricultural/Pumping rates.  SDG&E will provide its pricing files in an excel spreadsheet to CEC staff.
 PG&E will provide its pricing files in csv format to CEC staff.  SCE will manually upload its pricing files via API directly to MIDAS.
o The Large CCAs’ submissions of rate schedules will vary among each Large CCA and will range from uploading to MIDAS a selection of between one and four base rates, to creating spreadsheets or .csv files with between one and all of their time dependent rates and sending those spreadsheets or .csv files to CEC staff for upload into MIDAS. The Large CCAs will endeavor to submit rates covering a large number of customers. The rate(s) submitted will include at a minimum one vintage and one renewable energy option.

By October 1, 2023, assuming MIDAS is stable by July 1:
 SDG&E and PG&E plan to begin to upload rate/price information described above directly into MIDAS using manual processes. SDG&E and PG&E will require three months after MIDAS is stable to begin to upload rate/price information, otherwise the processes described above will continue.

Attachment Staff Report Item 18C
8 CEC Issuance of MIDAS Final Protocols (Date to be provided to LSEs by the CEC):
 Party concerns described above in item 2 have been resolved, including stabilization of MIDAS development, resolution of the IOU/CEC rate compilation issue, and adoption of working group best practices for uploading rate adders and price granularity.

CEC Issuance of MIDAS Final Protocols (Date to be provided to LSEs by the CEC) plus nine months:
 All parties have completed necessary development of final automated systems to upload all prices for all time-dependent rates into MIDAS and have achieved full compliance with the LMS.

5. Conclusion
The Joint Parties appreciate the Executive Director’s attention to this request and look forward to moving forward collaboratively to implement the revised LMS. We are available for further discussion and to answer any questions at your convenience, and we look forward to your response.

Sincerely,
Darren P. Roach
Chief Counsel
Pacific Gas & Electric Company
Cc: Energy Commissioner Andrew McAllister, [email protected] Michael Sokol, CEC Director of Efficiency Division, [email protected] Jennifer Nelson, CEC Manager of Existing Buildings Branch- Efficiency Division, [email protected]
Stefanie Wayland, Load Management Standards Lead, [email protected] Rebecca Hansson, San Diego Gas & Electric Company, [email protected] Sarah Taheri, San Diego Gas & Electric Company, [email protected] Jeff DeTuri, San Diego Gas & Electric Company, [email protected] James Whooley, Southern California Edison, [email protected] Brandon Sanders, Southern California Edison, [email protected] Eva Molnar, Southern California Edison, [email protected] Robert Thomas, Southern California Edison, [email protected] Mark Krausse, Pacific Gas & Electric Company, [email protected] Emily Bartman, Pacific Gas & Electric Company, [email protected] Andrew Au, Pacific Gas & Electric Company, [email protected] Shirley Woo, Pacific Gas & Electric Company, [email protected] Sharon Pierson, Pacific Gas & Electric Company, [email protected] Attachment Staff Report Item 18C
9 Leanne Bober, California Community Choice Association (on behalf of the Large CCAs), [email protected]
Evelyn Kahl, California Community Choice Association (on behalf of the Large CCAs), [email protected]
Eric Little, California Community Choice Association (on behalf of the Large CCAs), [email protected]
Attachment Staff Report Item 18C
1) For each CCA subject to the regulation, what are the CCA time-dependent cost components? How are these CCA cost components handled in the current billing process in conjunction with IOUs?
a) EBCE’s only time dependent cost component is generation. As an energy-only provider, EBCE replaces PG&E generation service on a customer’s bill. EBCE does not have any transmission or distribution rates, time-dependent or otherwise. EBCE’s current and previous rates can be found at https://ebce.org/rates/.

Nearly all EBCE’s rates are time-variant. EBCE employs time-varying demand and energy charges that feature peak, partial peak, off-peak, and super off-peak periods. Rates are also often seasonal (differing in the summer and winter). Combinations of the above result in 81 discrete generation rates per rate sheet. With six distinct rate sheets, one for each of the PCIA vintages that EBCE customers can fall into, EBCE offers a total of 486 rates. Again, most of these rates are time-variant. b) EBCE’s billing process relies on coordination among EBCE, PG&E, and SMUD. PG&E is EBCE’s metering agent. PG&E owns, manages, and reads customer meters, and then provides EBCE with aggregated usage for each customer according to PG&E predefined Time of Use (“TOU”) periods. For example: “the customer used X units during the peak period and Y units during the off-peak period as defined by their rate schedule.” SMUD is EBCE’s back-office services provider. SMUD uses usage data from PG&E together with EBCE’s rate schedules to perform a price times quantity calculation.

SMUD then provides PG&E with a generation charge to place on a customer’s bill.

That might look like:
(1) Peak @ $.20/kWh x 200 kWh = $40.00
(2) Off-peak @ $.10/kWh x 300 kWh = $30.00
(3) Total CCA charges = $70.00
2) What IOU time-dependent costs components (e.g. transmission, distribution, PCIA, etc.) are needed by CCAs from IOUs to meet the regulation?
a) The LMS amendments do not require CCAs to include any IOU rate components to meet the regulations. Section 1623.1.c of the LMS States:
“No later than three (3) months after April 1, 2023, each Large POU and each Large CCA shall upload its existing time-dependent rates applicable to its customers to the Commission's Market Informed Demand Automation Server (MIDAS) database. Each Large POU and Large CCA shall upload all time-dependent rates, including those approved after April 1, 2023, to MIDAS prior to the effective dots of the time dependent rates each time a time-dependent rate is approved by the rate approving body and each Attachment Staff Report Item 18D
time a time-dependent rate changes. The time-dependent rates uploaded to the MIDAS database shall include all applicable time-dependent cost components, including, but not limited to, generation, distribution, and transmission.” EBCE’s “existing time-dependent rates applicable to its customers” do not include any IOU rate components. As CCAs do not have distribution and transmission rate components, those rate components likewise are outside the scope of CCA obligations under the LMS amendments.
b) EBCE does not maintain information on the IOUs current rates and cannot speak to which PG&E rate components PG&E should upload.
3) Are the lists of IOU cost components publicly available? If so, are they in a workable format?
a) At least some IOU cost components are publicly available as individual PDFs of tariffs on PG&E’s website. EBCE cannot confirm whether these records are comprehensive. b) IOU cost components are not, to EBCE’s knowledge, publicly available in a workable format for the purpose of rate compilation and upload into MIDAS. To be uploaded, rate components from each tariff PDF would need to be manually converted into a machine-usable format. This �me-intensive process would need to be repeated each �me one of the IOU’s rates are changed.
4) What data format is needed by CCAs to calculate composite rates? Notwithstanding EBCE’s objection to the relevance of this question for compliance with the regulations, EBCE notes that a .csv would be ideal for storing both the inputs to and outputs from the combination process. Additionally, a reconciliation or adaptation process could be used to ensure utility and CCA formatting is consistent. 5) Have CCAs requested the needed information in the desired format from IOUs? Please identify IOU contacts for this information or describe the steps have taken so far.

EBCE has not requested any additional rate information from PG&E. 6) The combinatorics issue has been brought up in the workgroup. Please provide complete details about the issue and its scale, e.g., how many IOU cost component combinations are there? How many CCA cost components are there? What is the final number of combinations?
a) It is difficult to estimate the final number of combinations possible without further discussion among the IOUs, CCAs, and the CEC, as well as the finalization of MIDAS protocols with regards to how certain rate modifiers will be treated. EBCE respectfully Attachment Staff Report Item 18D
submits that this would be best addressed in a meeting or working group. However, a summary of EBCE’s generation side components is included below, which can begin to give the issue some scope.
i) Each EBCE rate sheet contains 81 rates with over 400 billing determinants based on either energy usage or demand. Most of these determinants are time variant. ii) Almost all EBCE’s rates use both demand and energy charges, which add two potential combinatory dimensions:
81 rates x 2 dimensions = 162 components
iii) EBCE’s rates also differ by season:
81 rates x 2 dimensions x 2 seasons = 324 components
iv) If we assume all rates consist of three potential periods (on-peak, off-peak, and partial-peak):
81 rates x 2 dimensions x 2 seasons x 3 periods = 972 components v) The number of entries will increase significantly as various rate modifiers are introduced. For example, EBCE serves six different customer vintages, each with their own rate sheet. The number of vintages is only expected to grow based on current EBCE expansion plans.
81 rates x 2 dimensions x 2 seasons x 3 periods x 6 vintages = 5832 components vi) EBCE offers customers a choice of two distinct services. The Renewable 100 product supplies customers with 100% renewable energy at a slightly higher price than PG&E; the Bright Choice product is a basic plan which costs less than PG&E. Each rate sheet contains a different set of billing determinants for each product choice. 81 rates x 2 dimensions x 2 seasons x 3 periods x 6 vintages x 2 products = 11,664 components
b) Each of these 11,664 components from EBCE would need to be combined with every possible T&D rate entry from PG&E and then converted to 8760 format. This process would be computationally expensive and would require significant planning and review to ensure accuracy and reliability. Additionally, While CCAs only change their rates once annually, utility rate changes may be much more frequent. While EBCE does not agree that CCAs can be responsible for the maintenance of IOU rates, if they are it would require CCAs to recalculate and upload the above number of scenarios and entries each time.

Attachment Staff Report Item 18D
EBCE cannot effectively use limited staff time and resources (ratepayer dollars) to build the systems and processes necessary to calculate composite rates; this is only more so the case for smaller CCAs named in the LMS regulations with fewer staff members. EBCE believes that any rate compilation should be done by MIDAS itself, a third party, or the CPUC’s Price Machine, which is currently in development in the Demand Flexibility proceeding.
7) Other relevant comments
a) Despite the looming July 1 deadline, there are many outstanding questions regarding what is required for compliance with the regulations. CEC Staff have canceled March MIDAS working group meetings.

In light of the outstanding questions, and lack of a clear process to resolve them, EBCE respectfully requests that the deadline for compliance be extended to:
i) no sooner than six months after all MIDAS rate upload requirements, including the issue of unbundled combination, are finalized and
ii) either: a) agreed upon by all LSEs or b) approved by the CEC.

EBCE shares the CEC’s goals of increasing load flexibility and facilitating load management. Extension of the timeline for implementing LMS ensures that staff time and ratepayer dollars are used efficiently, and that systems and processes developed for compliance will work for customers from day one, and not require expensive and time consuming rebuilding in the near term.
b) Through emails, the MIDAS working groups, and a meeting between the CCAs, CPUC, and CEC staff members, the CCAs have expressed concerns about engaging in extensive testing activities before the CEC finalizes MIDAS protocols. In response to this concern, CEC staff members have stated that the instructions for utilizing MIDAS should not be changing substantially.

While EBCE appreciates the CEC’s confidence, as a practical matter even small changes between now and finalization of the combinatorics issues will have a significant impact on how and where rates are processed and uploaded. It is inefficient to build out internal processes for upload and download to MIDAS given the current uncertainty around what those processes must ultimately produce. EBCE encourages the CEC to resolve combinatorics issues before requiring LSEs to upload complete data sets.

Attachment Staff Report Item 18D