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September 6, 2019
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 | NEM Retail Energy and Advanced Technology Forum and Executive Committee Meeting | |
| NEM will convene a Retail Energy and Advanced Technology Forum and Executive Committee Meeting on October 16-18, 2019, at The Hotel Hershey in Hershey, Pennsylvania.
Confirmed Speakers thus far include:
• Neil Chatterjee, Chairman, FERC
• Andy Ott, Chairman, PJM
• Gladys Brown Dutrieuille, Chairman, Pennsylvania Public Utility Commission
• Norman Kennard, Commissioner, Pennsylvania Public Utility Commission
• Andrew Place, Commissioner, Pennsylvania Public Utility Commission
• John Coleman, Commissioner, Pennsylvania Public Utility Commission
• Bob Burns, Chairman, Arizona Corporation Commission
• Obi Linton, Commissioner, Maryland Public Service Commission
• K.R. Sridhar, Founder and CEO, Bloom Energy
• Don Dodge, Developer Advocate, Google
• John Chambers, Chairman Emeritus, CISCO, CEO, JC2 Ventures
• Christian Belady, P.E. General Manager, Microsoft
The room block is now set up to accept reservations at The Hotel Hershey. The room block cut-off date is Friday, September 20, 2019. Reservations can be made by calling 855-729-3108 and asking for the room block for the NEM Fall Policy Leadership Roundtable 2019 at The Hotel Hershey. Alternatively, reservations can be made at this link.
A draft agenda is available at this link.
You may register at this link. | |
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| FERC Data Request on RTO/ISO Policies That Affect Interconnection of DERs | |
| FERC staff issued a data request in its rulemaking on Distributed Energy Resource (DER) Aggregation to CAISO, ISONE, NYISO, PJM, SPP and MISO. The Commission began exploring DER aggregation policy in 2016 with its NOPR on electric storage and then opened a separate rulemaking on the issue in 2018, including a technical conference. The data requests are intended to follow up on comments received in the rulemaking. In particular, the data requests are to "further explor[e] the interconnection of distribution-connected DERs, in particular those that participate or will participate in DER aggregations for the purpose of providing wholesale service in markets operated by Regional Transmission Organizations (RTO) and Independent System Operators (ISO)."
The data request is as follows:
"1. Under your RTO's/ISO's existing rules for small generator interconnection, if a DER seeks to participate in wholesale markets and plans to interconnect at the distribution level, please describe the step-by-step process by which that resource would interconnect to the system.
a. What are the respective roles of the RTO/ISO and the distribution utility in that process?
b. How would the DER ascertain whether it must interconnect pursuant to a state-jurisdictional interconnection process or a Commission-jurisdictional process?
c. How does your RTO/ISO define the physical boundaries of a distribution facility when determining whether a distribution facility to which a new DER seeks interconnection is already subject to an Open Access Transmission Tariff (OATT) for purposes of making wholesale sales?'
2. Does the interconnection process described in response to Question # 1 differ based on whether or not the DER is a Qualifying Facility, and if so, how?
3. Does the interconnection process described in response to Question # 1 differ if the DER seeking to participate in wholesale markets is interconnecting behind a retail customer meter (whether on the distribution or transmission system), and if so, how?
4. Does the interconnection process described in response to Question # 1 allow studies for bi-directional service (i.e., both from a DER to the transmission system and from the transmission system to a distribution-connected wholesale customer)?
5. Under the interconnection process described in response to Question # 1, and assuming all of the individual DERs in the aggregation are new resources, which of the following would apply: (1) an aggregation of DERs located at multiple points of interconnection would be studied as one aggregated resource by your RTO/ISO and require only a single Generator Interconnection Agreement (GIA); (2) each individual DER would be studied individually and require its own GIA; (3) each DER would be studied individually with the aggregation still only requiring a single GIA; or (4) a different approach (please describe if a different approach would be used).
6. In contrast with the scenario in Question # 5, please assume that at least some of the individual DERs in a proposed aggregation are existing resources already interconnected and in service. If multiple existing and new DERs were able to aggregate at separate points of interconnection across your RTO/ISO to participate in wholesale markets as an aggregation rather than as individual resources, under what circumstances would your RTO's/ISO's existing interconnection procedures and study processes apply to the individual DERs in the aggregation? If multiple existing and new DERs were able to aggregate at separate points of interconnection across your RTO/ISO to participate in wholesale markets as an aggregation rather than as individual resources, under what circumstances would your RTO's/ISO's existing interconnection procedures and study processes apply to the aggregation? Would any revisions be needed to accommodate aggregations of DERs (existing and new) at multiple points of interconnection?
a. Under existing tariff rules, which entity (i.e., the RTO/ISO or the distribution utility) would be responsible for processing the interconnection of the individual DERs seeking to join an aggregation?
b. For existing DERs that are currently not participating in wholesale markets and that interconnected under a state-jurisdictional process, under your current interconnection procedures would the DER's decision to participate in an aggregation trigger the RTO/ISO interconnection process? Would additional studies be necessary to ensure that participation in your RTO's/ISO's wholesale markets through an aggregation does not cause reliability problems on the transmission system? If so, what studies? If not, why not? For example, would the original state-jurisdictional interconnection process have already studied the DER in a variety of operational scenarios that eliminate the need for further studies prior to wholesale market participation in your region?
c. If existing distribution-level DERs that are currently not participating in wholesale markets join aggregations and start making wholesale sales for the first time, how would that new wholesale use of existing DERs and their associated distribution facilities impact your assessment of whether those distribution facilities are subject to your OATT? Would Commission-jurisdictional interconnection procedures apply to subsequent requests to interconnect to those distribution facilities? Why or why not?
d. For large and small generator interconnections subject to Order Nos. 2003 and 2006, the transmission provider is required to coordinate between the interconnection customer and "affected systems" (i.e., third-party transmission systems) to ensure that any needed affected system issues are resolved.' With respect to new DERs seeking to interconnect to distribution facilities that are subject to a Commission-jurisdictional OATT, do the relevant small generator interconnection procedures in your region treat the transmission system to which the relevant distribution facilities are connected as an "affected system" in order to address any needed transmission upgrades at the initial interconnection stage?
7. If the individual DERs in an aggregation are seeking to interconnect to a combination of distribution facilities, some of which are subject to a Commission-jurisdictional OATT and some that are not subject to an OATT, would any, all, or only a subset of the DERs in the aggregation be required to go through the interconnection process you described in response to Question #1 and to execute GIA(s) under your tariff? Please explain.
8. If available, please provide data on or estimates of the number of individual DERs in your region that are directly participating today in your RTO/ISO markets as compared to DERs in your region that are not participating in wholesale markets. If possible, please provide estimates by resource type and participation model (i.e., generator, demand response, etc.).
9. Do you or the distribution utilities in your region have data on or estimates of how many distribution facilities, as defined in your answer to Question #1.c. above, are currently subject to an OATT compared to the total number of distribution facilities in the RTO/ISO footprint?
a. If yes, please provide this data or estimates.
b. How is this information managed and updated?
10. Is your RTO/ISO engaged in any ongoing discussion or coordination with state or local authorities regarding the interconnection process for DERs? If so, please describe this discussion or coordination.
11. If a DER needs to transmit its output over distribution facilities to make sales into the RTO/ISO markets, are there any existing tariff provisions that govern such service? If so, please list and describe such provisions and describe whether that service is bi-directional."
Data responses by the RTOs/ISOs are due by October 7th. Comments on the data responses are due thirty days from filing of the response. The full text of the Data Request is available on the NEM Website. | |
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 Connecticut
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| Executive Order on Climate Change | |
| Governor Lamont issued Executive Order No. 3 this week, intended to further combat climate change. Of particular note, the Executive Order directs study and analysis of the achievement of a zero carbon target by 2040 for the electric sector. Specifically, "[i]n order to accelerate achievement of the goals in the 2008 Global Warming Solutions Act and the 2018 Act Concerning Climate Change Planning and Resiliency, spur innovation in carbon-reduction strategies and economic development throughout the state and region, and ensure that strategic electrification strategies for decarbonizing the transportation and building sectors will result in real emission reductions, DEEP [Department of Energy and Environmental Protection] shall, in consultation with the Public Utilities Regulatory Authority as appropriate, in the Integrated Resource Plan (IRP) pursuant to sections 16a-3a and 16a-3b of the Connecticut General Statutes, analyze pathways and recommend strategies for achieving a 100% zero carbon target for the electric sector by 2040." The full text of the Executive Order is available on the NEM Website. | |
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 DC
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| Comment Sought on Proposed Pepco Tariffs Related to Customer Switching | |
| The Commission is seeking comment on two proposed Pepco tariff filings related to customer switching. The Commission previously ordered that Pepco should implement three business day switching in the Consumer Bill of Rights rulemaking. The Commission also ordered Pepco to remove the twelve month minimum stay provision applicable to commercial customers that return to Standard Offer Service after receiving competitive supply. Pepco filed proposed tariffs to implement these changes. Comments are due September 30th. The full texts of the Notice of Proposed Tariffs and Pepco's Tariff Filings are available on the NEM Website. | |
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 Nevada
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| Staff Straw Proposal on Impact Fees in SB547 Rulemaking | |
| SB547 enacted earlier this year changed the Commission's standard for reviewing and approving customer applications to depart electric utility commodity service; revised the application procedure for a customer to seek Commission approval to shop with a competitive electric supplier; required "providers of new electric resources" to obtain a license by the Commission; and required the Commission to establish a process for a shopping customer to apply to return to bundled electric utility service. SB547 also revised the requirements for utility filings of integrated resource plans. Such plans must now include:
"a proposal for annual limits on the total amount of energy and capacity that eligible customers may be authorized to purchase from providers of new electric resources through transactions approved by the Commission pursuant to an application submitted pursuant to NRS 704B.310 on or after May 16, 2019. In developing the proposal and the forecasts in the plan, the utility or utilities must use a sensitivity analysis that, at a minimum, addresses load growth, import capacity, system constraints and the effect of eligible customers purchasing less energy and capacity than authorized by the proposed annual limit.
The proposal in the plan must include, without limitation:
(a) A forecast of the load growth of the utility or utilities;
(b) The number of eligible customers that are currently being served by or anticipated to be served by the utility or utilities;
(c) Information concerning the infrastructure of the utility or utilities that is available to accommodate market-based new electric resources;
(d) Proposals to ensure the stability of rates and the availability and reliability of electric service; and
(e) For each year of the plan, impact fees applicable to each megawatt or each megawatt hour to account for costs reflected in the base tariff general rate and base tariff energy rate paid by end use customers of the electric utility."
The Commission opened a rulemaking to implement SB547. The rulemaking will be conducted in three phases: 1) integrated resource planning issues; 2) licensing of providers of new electric service; and 3) the revised exit application process.
Staff has now filed a straw proposal on integrated resource planning issues, including regulations on impact fees. Staff considered whether impact fees should be the same for every customer exiting pursuant to a plan on annual limits or whether components of an exit fee should vary based on customer-specific factors. Staff also considered whether impact fees should be set based on customers load profile characteristics. Staff ultimately proposed that impact fees should be the same for every customer exiting pursuant to a plan on annual limits, opining that a customer-specific approach would be burdensome. Staff requests feedback on whether a group characteristic, such as load factor, should be utilized in an impact fee.
Staff's proposed "calculation of impact fee" is as follows:
"1. In determining the impact fee applicable to each megawatt or each megawatt hour of energy and capacity that eligible customers may be authorized to purchase from providers of new electric resources as provided in NAC 704.925(2)(b)(v), the utility shall:
a) Calculate the impact to the base tariff general rate paid by end-use customers of each the electric utility [sic]. To perform such calculation the electric utility shall:
i) Assume all of the accounts or services associated with the eligible capacity and energy will remain distribution and transmission customers after its departure;
ii) Use the utility's current rates as approved by the Commission;
iii) Use the utility's currently-approved FERC transmission rates;
iv) Hold the FERC, BTGR, and Distribution-Only Service (DOS) rates constant for the length of the ten-year analysis period;
v) Exclude the energy efficiency (EE) rates;
vi) Perform a ten-year rate analysis, with takeoff points for each year;
vii) Include the marginal generation demand cost allocation share of the costs associated with the generation projects/facilities that have been given resource planning approval but are not yet in rates; and
viii) Develop an average hourly load profile of all large commercial customer classes of each utility to shape the proposed annual capacity and energy limits and use the developed average hourly load profile as the billing determinants.
b) Calculate the impact to the net-base tariff energy rate paid by end-use customers of the electric utility. To perform such calculation the electric utility shall:
i) Use the utility's modeling software to perform a ten-year production cost simulation for a ten-year analysis period, with takeoff points for each year of the analysis period;
ii) Perform two sets of production cost simulations under the guidelines provides below: A) Base Case Expansion Plan; and B) Exit Impact of "Change Case" Plan.
A) Base Case Expansion Plan
1) Use the utility's load, fuel and purchase power forecasts from the utility's preferred case in the current Integrated Resource Plan filing;
2) Exclude all energy and capacity needs associated with the placeholder resources from the plan and assume all energy and capacity needs are fulfilled with market purchases at the prices contained in the fuel and purchase power forecast;
B) Change Case Plan
1) The load forecast for the Change Case Plan is the Base Case Expansion Plan (above) load forecast with the proposed energy and capacity that eligible customers may be authorized to purchase from providers of new electric resources removed;
2) Use January 1, of the following year, as the Departure Date for the analyses;
3) Perform the production costs simulations with external sales turned off;
4) Assume no physical transmission constraints that would prevent an eligible customer from being granted its full requested transmission import rights.
C) Non-Bypassable Rate Analysis
1) After the BTER impact is calculated (as outlined above), calculate the portion of the BTER associated with the out-of-the-money costs of the long-term renewable energy contracts (R-BTER) that NPC has entered into and subtract those costs from the BTER impact fee to determine the "Net BTER."
2) Perform the R-BTER calculation in the same manner as was directed by the Commission in its Orders issued in Docket Nos. 15-05006 and 15-05017.
3) Subtract the monthly R-BTER cost from the monthly BTER cost to determine the monthly "Net BTER" cost."
Proposed regulations on licensing of providers of new electric service are due September 6, 2019. A workshop will be convened to consider the proposals on November 21, 2019. The full text of Staff's Proposal is available on the NEM Website. | |
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