MA DG Collaborative – Year 1

1. MA DG Collaborative – Year 1 Tim Roughan Director of Distributed Resources Timothy.Roughan@us.ngrid.com June 17, 2005 Restructuring Roundtable

2. Background • Different interconnection polices among the four MA utilities • Perception that customers not getting assumed benefits of DG • MA DTE issued 02-38 order in 2002 • Authorized DG collaborative to standardize interconnection process • DTE approved statewide interim standard April 2004 • Authorized two year collaborative • Further enhance interconnection policy • Review DG and distribution planning • Additional work regarding network interconnections • Meter ownership

3. Year 1 report 5/31/05 • New interconnection process is working well • 144 (18.5 MWs) applications from 4/1/04 to 3/31/05 • In MECo 13 requests 2003, 32 in 2004 • NStar had 62% of all requests • Extensive tracking of projects • Tracking timelines and costs • Have suggested some process changes to interconnection tariff • If the ISO has to study a project, timelines may be extended • Requirement for wiring inspection • P1547 is now IEEE Standard 1547-2003

4. Year 1 report 5/31/05 • Network system interconnection • Multiple primary sources feeding one or more customers • Issue arose whether you can delay protective functions to allow DG breaker to trip, however MA Utilities will not delay network protectors because it violates basic protection strategies • Need to find another solution • Meter ownership • QFs already can own their meter • QFs under PURPA • Which policy can they use?

5. Year 1 report 5/31/05 • DG and Distribution Planning • Distribution Planning reviews • MECo: 1,115 feeders, 295 substations • NSTAR: 1,300 feeders, 300 substations • WMECo: 271 feeders; 43 substations • FG&E: 44 feeders; 17 substations • Total: 2,730 feeders; 655 substations • Approximate allocation of capital budgets • Asset Replacement: 25-40% • Reliability: 25-35% • Capacity: 30-45% • To make the budget, projects typically have to resolve 2 or more of the above issues

6. Year 1 report 5/31/05 • Beginning to work through some ‘paper’ pilots to determine value and costs of DG installations in certain areas • Value to DG customer is reduced energy costs, which is a cost to the utility • Value from the utility is typically only from deferral for capacity projects in low-growth areas • Unless real sustained capacity is realized non-DG ratepayers likely will not benefit from DG installations • This may involve utility control of the DG • Or, enough DG to use diversity on a feeder by feeder basis • Could result in cross-subsidization by non-DG customers

7. Year 2 work plan • Any additional streamlining of tariff • Look at new FERC small gen process and how the ISO-NE will implement • Additional investigation of interconnecting to network systems • Are there other cost-effective solutions besides violating basic fault protection practices? • Continue working through the costs and benefits to all parties for DG on the distribution system

8. Year 2 work plan • Utility Congestion Relief Pilot (UCRP) • MTC is interested in testing DG value • Looking to work within MECo’s Lowell area targeted load response project • MECo pays 50¢/kWh for load shed, plus $3/kW for summer months as a retainer • Must be customer > 200 kWs • Other possibilities being discussed for smaller customers including residential • MTC interested in projects with other utilities

9. Summary • A lot more time required than was assumed • This is not a simple issue, and it takes time to do it right • Need involvement from real customers • Need perspective of people who are not in the industry • New FERC rules will affect us • LICAP: demand response customers can earn back their LICAP contribution • Small Generator rule: how will this interact? • Comments due 6/23 to MA DTE on report • http://www.mtpc.org/renewableenergy/public_policy/DG/2005_annualreport.htm