Details for: SCE Comments to Draft Resolution E-5028 (3722e).pdf

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Gary A. Stern, Ph.D.
Managing Director, State Regulatory Operations

September 10, 2019
Energy Division
Attention: Tariff Unit
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102

Comments of Southern California Edison Company
on Draft Resolution E-5028, Which Approves
Extension of, and Modifications of the Green Tariff
Shared Renewables Program.

Dear Energy Division Tariff Unit:
In accordance with Draft Resolution E-5028 (Draft Resolution) and Rule 14.5 of the Rules
of Practice and Procedure of the California Public Utilities Commission (Commission),
Southern California Edison Company (SCE) submits its comments on the Draft
Resolution regarding the extension and modifications to the Green Tariff Shared
Renewables (GTSR) Program.
On December 22, 2017, pursuant to the process established by Decision (D.)15-01-051,
SCE submitted Advice 3722-E, seeking the Commission’s approval to sunset the GTSR
program as of January 1, 2019. On August 20, 2019, the Commission’s Energy Division
issued Draft Resolution E-5028, which, among other things, denies SCE’s proposal to
terminate the GTSR program. Additionally, the Draft Resolution approves the proposals
of Pacific Gas and Electric Company (PG&E) and San Diego Gas & Electric Company
(SDG&E) to extend the Green Tariff Shared Renewables Program (GTSR) beyond
January 1, 2019 and requires SCE to do the same. The Draft Resolution also approves
some proposals by PG&E, SDG&E, and other parties to modify the GTSR programs of all
three investor-owned utilities (IOUs).
SCE appreciates the opportunity to provide comments on this Draft Resolution and looks
forward to continued discussions on improving the GTSR Program.

P.O. Box 800

8631 Rush Street

Rosemead, California 91770

(626) 302-9645

Fax (626) 302-6396


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Energy Division California Public Utilities Commission September 10, 2019 Page 2 DISCUSSION I. SCE Urges the Commission to Not Adopt a Year-Round Procurement Concept Until the Commission and all Relevant Stakeholders Have Been Able to Review a Developed and Comprehensive Proposal from the IOUs The Draft Resolution conceptually proposes to approve a year-round procurement proposal from PG&E claiming that this, “process will encourage more developers to participate and be particularly helpful in promoting projects in (Environmental Justice) EJ communities.”1 Additionally, the Draft Resolution states that the Annual Program Forum would provide the ideal opportunity for PG&E to lead, “a discussion with key stakeholders to develop the details of a year-round procurement process,” and directing the IOUs to submit a joint Tier 2 Advice Letter seeking approval of the new year-round procurement process following the Annual Program Forum.2 The Draft Resolution supports a year-round procurement process because it “could allow developers to match the timing of their bids with their own project’s unique development cycles and constraints. The developer would not have to wait until an open solicitation period, but rather could offer a bid at any time while MWs remain under the program cap.”3 To evaluate proposals, the Draft Resolution includes a proposal for the IOUs to batch-review bids during specified windows. While this proposal allows Developers to submit bids on an ongoing basis, the evaluation window will not significantly change the milestones needed to achieve contract execution between a developer and an IOU, specifically as it relates to IOUs awarding contracts to all ECR projects whose bid price meets the pricing threshold established in D.16-05-006.4 While SCE supports the goal of encouraging developer participation, SCE is concerned that a year-round procurement process will lead to increased administrative burdens and costs on the IOUs, including, but not limited to: requiring additional personnel (for procurement, planning/valuation, and support for site maintenance, correspondence, upkeep of submitted documents), a website for the duration of the year-round procurement process, and a dedicated Independent Evaluator (IE) who SCE will need to retain for the year-round process, as opposed to the fixed procurement timeframe in the current program. 1 2 3 4 See Draft Resolution E-5028 at p. 26. Id. See Draft Resolution E-5028 at p. 25. D.16-05-006 required IOUs to award contracts to projects whose bid price is at or below 120 percent of the maximum executed contract price up to the capacity offered at that solicitation. For Enhanced Community Renewables-Environmental Justice projects, the utilities must award contracts to all projects whose bid price is at or below 200 percent of the maximum executed contract price up to the Environmental Justice capacity offered at that solicitation.
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Energy Division California Public Utilities Commission September 10, 2019 Page 3 In addition to administrative cost and burden, as the Draft Resolution acknowledges, the proposed year-round procurement process “lacks specific details for [the Commission] to adopt.”5 Given the concerns and unknowns, SCE proposes that the Commission defer adopting or implementing the proposal until the IOUs have had the opportunity to collaborate at the Annual Program Forum, create a proposal, and then, if appropriate, adopt a year-round procurement process, once a proposal has gone through the appropriate regulatory review. II. SCE has Concerns with the Inclusion of NEM Customers in the Community Renewables Program SCE’s GTSR tariffs currently permit NEM customers to participate in the Green Rate (GR) but not Community Renewables (CR). That is the case for legal and policy reasons. The Commission should thus maintain the current framework and allow the other IOUs to adopt SCE’s framework. With regard to the legal issues, NEM customers cannot lawfully participate on GTSRCommunity Renewables (CR) but can lawfully participate in the Green Rate (GR). That is the case because the Commission cannot expand VNEM to facilities that do not serve the customers’ onsite load. The reason why California’s NEM statute and the Commission’s NEM and Virtual Net Energy Metering (VNEM) tariffs are lawful and not preempted by federal law is because they are predicated upon the requirement that participating customers have installed onsite eligible renewable generating facilities that are designed to primarily serve onsite load and are thus sized to their annual historical onsite load.6 The California NEM statute and the NEM and existing VNEM tariffs thus require customer-sited eligible renewable generators to be sized to historical 5 6 Draft resolution E-5208, p. 26. See PUC 2827(b)(4) (defining an “‘[e]ligible customer-generator’ [as] a . . . customer of an electric utility, who uses a renewable electrical generation facility, or a combination of those facilities, with a total capacity of not more than one megawatt, that is located on the customer’s . . . premises, and is interconnected and operates in parallel with the electrical grid, and is intended primarily to offset part or all of the customer's own electrical requirements.” Note, this sizing restriction is different from the program cap and individual facility MW cap, which were lifted by AB 327.); D.11-06-016 at pp. 52-53, AB 920 (adding statute to allow NEM customers to receive compensation for excess NSC and including analysis, “Because net-metering is based on sizing the generation to meet a customergenerator's own load, the customers has no incentive to build larger solar energy systems.”); see also D.02-03-057 at p. 2; D.06-07-028 at pp. 2-6; D.14-11-001; Tariffs VNEM & VNEMST (The VNEM tariffs properly require the generator to serve adjoining parcels and to satisfy the sized to historical onsite load requirement. Specifically, the VNEM 1.0 tariffs requires all benefiting customers must be located behind the same service delivery point. NEM 2.0 expanded VNEM to allow benefiting customers to be on the same property. Both require sizing to historical onsite load.
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Energy Division California Public Utilities Commission September 10, 2019 Page 4 onsite load for the primary purpose of offsetting and serving that onsite load or the load of adjacent properties. When California and other states first enacted their NEM statutes, the Federal Energy Regulatory Commission (FERC) issued a decision disclaiming jurisdiction over the portion of the NEM program that constitutes a pure “billing arrangement” between a customer and the utility.7 FERC’s finding that no wholesale transaction occurs under the Federal Power Act (FPA) or Public Utility Regulatory Policies Act of 1978 (PURPA) for the monthly net billing arrangement that occurs when a customer generator receives a retail rate bill credit for excess energy the customer exports to the utility that is not consumed on site at the time of generation, is predicated upon the theory that over the course of the billing period, NEM customers generally use more energy from the utility to serve the onsite load than they export.8 Thus, solely for the monthly net billing period, FERC treats the transaction as a billing arrangement between the utility and its customer. That is not the case, however, with Net Surplus Compensation (NSC). FERC concluded PURPA and its wholesale avoided cost pricing parameters apply to NSC. A net sale of energy occurs when a customer-generator generates more electricity (measured in kWh) during a twelve-month period than that which is supplied by the utility. As a result, FERC finds the customer-generator receives direct compensation for the excess energy.9 In essence, that excess at the end of the twelve-month period is treated as a wholesale power purchase transaction. The CPUC adopted this precise legal framework in D.11-06-016.10 In sum, FERC’s decision disclaiming jurisdiction and allowing NEM applies exclusively to onsite generation sized to serve the onsite load. If the energy exported is serving load that is not onsite or at least on adjacent parcels, FERC controls compensation to the generator under the FPA and requires the energy to be sold through the CAISO at wholesale. Likewise, the CAISO does not permit netting to eliminate the wholesale sale. For instance, the CAISO requires renewable generators over 1 MW to participate in the CAISO market if they use the transmission system. The CAISO has informally interpreted this requirement as not applying to NEM Successor Tariff customers over 1 MW, so long as the generating facility is onsite and sized to onsite load. CR cannot satisfy these legal requirements for NEM under state and federal law. In addition to the legal bar, it is against public policy to allow NEM customers to participate in the CR tariff because doing so may unreasonable increase the NEM subsidy cost shift 7 8 9 10 FERC Order 2003-A, 106 FERC ¶ 61,220 at 747 (2004) (citing MidAmerican Energy Co., 94 FERC ¶ 61,340 at 62,263 (2001)). Id. Id. (“Only if the Generating Facility produces more energy than it needs and makes a net sale of energy to the utility over the applicable billing period would [FERC] assert jurisdiction.”) (citing MidAmerican, supra, at 62,263). D.11-06-016 addressed the terms and conditions of utility payment for surplus kilowatt hours produced by NEM projects, otherwise known as NSC, as required by Assembly Bill (AB) 920.
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Energy Division California Public Utilities Commission September 10, 2019 Page 5 to non-participating customers. In the CR program, customers receive a credit from the IOU, which is based on what the developer tells the IOU a customer’s share of a project was for that month. In instances where a customer’s credits are higher than their net usage, cost shifts to non-participating customers will occur. A NEM customer served on Schedule GTSR – CR could potentially receive more credits for sending generation in excess of usage back to the grid than he or she would by being served on Schedule NEM alone. For instance, a customer whose usage (kWh) is less than the amount generated by the sized-to-load system could receive credits for exports under Schedule NEM. By equating the amount of exports (kWh) to the assigned share of facility or output, the customer can also receive a credit under Schedule GTSR – CR. An NEM customer with net usage on Schedule GTSR - CR could receive a credit for his or her assigned share of facility output, decreasing the amount of charges that the customer should have paid to have on-site load supplied by SCE. For this reason, SCE’s tariffs currently provide that NEM customers can participate in GR but not CR. A discussion of the relevant tariff provisions is set forth below. The Commission should maintain the status quo in this regard. a) NEM Participation on GTSR – Green Rate (GR) Per Special Condition 5.c of SCE’s current Schedule GTSR – GR, NEM customers are permitted to be served under the Schedule. Relevant GR charges, credits, and any indifference payments would be assessed at the end of participating customer’s 12-month Relevant Period. If usage (kWh) is less than the amount of kWh generated and exported by the participating customer’s Renewable Electrical Generating Facility (kWh) (i.e., net export), then the GR charges, credits, and any indifference payments would not be applied. If the difference (i.e., net usage) is greater than zero, then the charges and credits would be assessed on the customer’s bill at the end of the Relevant Period. This practice should continue to ensure that NEM customers served under Schedule GTSR – GR would not receive credits for net generation under both NEM and GTSR – GR programs. b) NEM Participation on GTSR – Community Renewables (CR) Per Special Condition 3.c of SCE’s current Schedule GTSR – CR, participating customers cannot participate in any NEM tariff. Per Section of D.15-01-051, SCE enters into a power purchase agreement (PPA) with a developer to purchase energy generated from a Community Renewables project (“facility”). The developer then assigns his or her right to receive payments under the PPA to the subscribing customer who then receives a credit from the IOU in the form of a non-time-differentiated class average credit, which is assessed on a volumetric basis upon the customer’s assigned share of facility output. For these reasons, NEM customers should continue to be excluded from participation on Schedule GTSR – CR but permitted to participate in GTSR-GR.
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Energy Division California Public Utilities Commission September 10, 2019 Page 6 CONCLUSION SCE is preparing to host the 2019 GTSR Annual Program Forum and will continue to engage in discussions with all relevant stakeholders on solutions to improve the GTSR Program for our customers. Southern California Edison Company /s/ Gary A. Stern /s/ Gary A. Stern Gary A. Stern, Ph.D. GAS:ez:cm cc: Edward Randolph, Director, CPUC Energy Division Franz Cheng, CPUC Energy Division Cherie Chan, CPUC Energy Division Paul Phillips, CPUC Energy Division Matthew Freedman, TURN Dennis Herrera, City Attorney Michael Campbell, Office of Ratepayer Advocates Kenneth White, Clean Coalition Marc Joseph, CUE John Clark, Forefront Power John Leslie, Joint Direct Access Parties Jeanne Armstrong, Joint Solar Interests Service List for A.12-01-008 et al.
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