Fran Cummings – Peregrine Energy GroupTim Roughan – National Grid

MA DG Working Group UpdateRestructuring Roundtable

October 26, 2012

Source: DOER chart of data from Massachusetts utilities

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2009 2010 Jan. 2010 -June 2011

July 2011 -Oct. 2011

Nov. 2011 -March 2012

kW/M

onth

Vol

ume

of A

pplic

ation

sAverage Monthly kW Volume of MA DG Applications

>3MW Projects

1-3 MW

501kW-1MW

<=500kW

Source: Monthly data from Massachusetts utilities

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

Findings: “necessary characteristics” of an efficient and effective interconnection process that will foster continued DG growth

RequirementsDG 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

StrategiesEnforce 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 inputHave specific ways to deal with projects that are not moving forward, but holding a space in the interconnection queue

7 Main Improvements to Interconnection ProcessImplementation of strategies1. Assurance – utilities: a multi-faceted utility timeline assurance and enforcement strategy2. 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

3. Additional time for “Complex” applications that will require more analysis – large projects requiring dedicated feeders or substations4. Utility-run tracking system to monitor both utility and customer timelines, with transparency for each customer, and enhanced monthly reporting

5. Standards Manual & Standards Review Group*: a uniform … Technical Standards Manual that is periodically updated with non-utility … input

Additional process changes6. Revisions to the technical screens

to allow more projects to qualify for the shorter tracks;

7. Pre-Application Report: required for applicants over 500 kW to help applicants prioritize among

locations and configurations & to reduce the number of

speculative applications.

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

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

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 kWPeak 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

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)

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 Impact of MA DG on MA Prices

$-

$10

$20

$30

$40

$50

$60

$70

PV Energy Efficiency CHP

Pric

e Ef

fect

(200

7 $

/ MW

h of

Dem

and

Res

ourc

e)

Price Effect: impact on annual average costs of Massachusetts purchases of wholesale electric energy in 2020 due to MA PV, EE and CHP (2007 dollars). Source: Synapse Energy Economics, Inc., “Impacts of Distributed Generation on Wholesale Electric Prices and Air Emissions in Massachusetts,” for Massachusetts Technology Collaborative, March 2008

• 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

Impacts & issues: Quantity of DG Reliable operation of electric distribution system Clarity needed from DPU on recovery of on-going costs to

operate the systemAnalysis of costs and rates for DG users and non-participantsNeed 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

Evolving DG-related Policy Landscape

Evolving DG-related Policy Landscape

Policies in MA & other states:Can we leverage energy efficiency with net metering & solar

incentives? CHP policiesGrid ModernizationNon-Transmission Alternatives & distribution planning

Location, location, locationThe MA utilities fully recognize the push for expanded

renewables with the clear policy decisions by the state legislature and executive branchNeed to balance this against workload demands in providing

service to all customersDG installations can not affect the reliability and safety of the

electric distribution system for their neighbors