MA DG Working Group Update Restructuring Roundtable October 26, 2012

1. MA DG Working Group UpdateRestructuring RoundtableOctober 26, 2012 Fran Cummings – Peregrine Energy Group Tim Roughan – National Grid

2. Source: DOER chart of data from Massachusetts utilities

3. Source: Monthly data from Massachusetts utilities

4. DPU 11-75 DG Working Group • DPU orders 4-month WG process to improve interconnection process • Utilities and other stakeholders – over 20 entities • Facilitated/mediated process • Reached consensus on package of report recommendations filed 9/14 • Only one issue about minimum load screen for Expedited process was not agreed to • Had DPU technical conference 10/24 and will submit redlined tariff by 10/31 • WG to meet monthly during implementation/transition year, and form new Tech Standards WG

5. Findings: “necessary characteristics” of an efficient and effective interconnection process that will foster continued DG growth Requirements DG customers must know: how long the steps in the process over which utility has control will take, & what technical standards will be. And those expectations must be reliably adhered to by utility. Utilities, to reliably adhere to those expectations, must be given sufficient time & resources to process all applications. Customers need to respond quickly to utility information needs to keep the process moving Strategies Enforce timelines on both utility & customer sides, which cannot be done without tracking performance against timelines; Include more transparent technical standards with non-utility parties process for input Have specific ways to deal with projects that are not moving forward, but holding a space in the interconnection queue

6. 7 Main Improvements to Interconnection Process Implementation of strategies • Assurance – utilities: a multi-faceted utility timeline assurance and enforcement strategy • Assurance – customers: a more clear-cut and definitive process for utilities to withdraw project applications when applicants miss deadlines • freeing up feeders for other applicants • Additional time for “Complex” applicationsthat will require more analysis – large projects requiring dedicated feeders or substations • Utility-run tracking system to monitor both utility and customer timelines, with transparency for each customer, and enhanced monthly reporting • Standards Manual & Standards Review Group*: a uniform … Technical Standards Manual that is periodically updated with non-utility … input Additional process changes • Revisions to the technical screens • to allow more projects to qualify for the shorter tracks; • Pre-Application Report: required for applicants over 500 kW • to help applicants prioritize among locations and configurations & • to reduce the number of speculative applications.

7. Other Recommendations • DGWG recommends that DPU name a staff DG Ombudsperson with technical interconnection expertise & authority to: • conduct independent interviews • propose non-binding solutions • offer decisions that can be appealed through normal DPU process • identify recurring issues in quarterly reports • participate ex officio in Review Group • Change existing monthly utility briefings into training with online modules • may or may not include applicant certification • could be mandatory • could address any future online application process • details to be worked out in transition process • Fees for Expedited & Standard • increase application fees from $3.00 to $4.50/kW & increase maximum from $2,500 to $7,500 • Continue no fee for Simplified • Develop Group Studies process for multiple DG on single feeder • Consider allowing applicants to use outside engineers during application & construction • Consider geographic mapping to show feeders & DG activity Other • Changes Affecting the Simplified Track* • Spot and Area Networks* • Increase Engineering Resources

8. Technical Standards Manual & Review Group • Membership of Review Group: 1 representative each from the 4 utilities & 3 non-utility representatives who are engineers with electric supply systems & DG interconnection expertise • Differences of opinion on standards will be recorded in minutes • Meets semi-annually, plus meetings if requested • Group will begin to meet in January 2013 & begin discussion of at least: 1) DTT and anti-islanding, 2) Limit of 3 MW/MVA on 13-15 kV feeders and related capacity limits, 3) RTUs, 4) External disconnect switches for small generators, 5) Interconnection practices in other states, 6) Witness testing protocols

9. Changes Affecting the Simplified Track(generally for smaller projects) Size Thresholds • Increase single phase maximum size from 10 kW to 15 kW • Leave three phase maximum size at 25 kW Peak Load Threshold (Screen #2) • Increase threshold from 7.5% to 15% so screen will read: • “Is the aggregate generating Facility capacity less than 15% of feeder/circuit annual peak load and, if available, line segment? • Objective: allow more DG to stay in Simplified or Expedited Track Timeline • Keep total utility review time at 15 days, but • Allow utilities 5 extra days for applications that fail Screen #5 (~must be all single-phase or all 3-phase) in order to keep those applications in the Simplified Track rather than moving them to the Expedited Track

10. Spot and Area Networks (mostly downtown areas) For “spot” networks, remove size screen (< 15 kW) for simplified process, if: • the existing < 1/15 of Customer’s minimum load screen requirement is met Extend the simplified network screen also to “area” networks, if: • DG capacity < 15 kW, as well as < 1/15 of Customer’s minimum load • applicant has interval meter data for appropriate period (i.e., for on-site load) • minimum load data is available (i.e., for utility’s network) • other necessary screens are passed Continue to monitor & track IEEE 1547 & national best practices, and incorporate IEEE guidance on networks into the new TSM Manual • (While not stated in Report, similar discussions were held about IEEE guidance on microgrids.) Continue to study & experiment on Massachusetts area networks (e.g., NSTAR’s current Boston pilot project)

11. Evolving DG-related Policy Landscape • If policy makers want to address rate impacts of increased DG, must also weigh societal benefits, esp. mkt price suppression & GHG • As concerns rise about intermittency, need to test & demonstrate potential of storage (VTG at 8pm) & local demand response to mitigate cost • Benefits of DG to grid & power market & local customers (incl. reliability) are greater for DG on-site or near loads, but may require ride-thru & backup (gen &/or DR), • Need hard look at utility ownership or other win-win business models to align DG benefits with costs • need positive DG incentive for utility shareholders on top of decoupling • core functionality of a green ‘smartgrid’ should be DG plug & play, reducing cost to DG to interconnect

12. Evolving DG-related Policy Landscape • Impacts & issues: • Quantity of DG • Reliable operation of electric distribution system • Clarity needed from DPU on recovery of on-going costs to operate the system • Analysis of costs and rates for DG users and non-participants • Need to maintain a transparent and fair allocation of these costs • Expansion of net-metering • 3% private, 3% public caps • When cap is reached - increase in costs to National Grid distribution customers could reach $40-$60M/year • 11-11C order of August 24th • Limits net-metering to 2 MWs per site and a single meter

13. Evolving DG-related Policy Landscape • Policies in MA & other states: • Can we leverage energy efficiency with net metering & solar incentives? • CHP policies • Grid Modernization • Non-Transmission Alternatives & distribution planning • Location, location, location • The MA utilities fully recognize the push for expanded renewables with the clear policy decisions by the state legislature and executive branch • Need to balance this against workload demands in providing service to all customers • DG installations can not affect the reliability and safety of the electric distribution system for their neighbors