Opportunities and Incentives for CHP in Massachusetts

1
Opportunities and Incentives for CHP in
Massachusetts Interconnection Procedures June
19, 2013 Tim Roughan
2
Agenda

• MA interconnection process
• Federal Energy Regulatory Commission (FERC)
  interconnection process at ISO-NE
• Appendix Technical considerations
• Appendix Net metering in MA

3
Safety Moment

• This mornings session provides a great safety
  moment.
• All the benefits derived from Distributed
  Generation quickly lose their value if someone is
  injured as a result of an improper
  interconnection.

4
DG Activity Trends National Grid

• Received over 491 applications worth more than 77
  MW of interconnection applications in Q1 2013
  (Last year estimated 1,811 apps, actual was 2086)
• Small (lt100kW) Interconnection application are
  triggering large studies because of the aggregate
  generation on the circuit.
• More projects are in construction phase
• Some circuits have over 20 interconnected
  generators

4
5
Massachusetts Interconnection Standard

• In late 2002, the MA DTE directed the investor
  owned utilities to commence a collaborative
  process to propose unified interconnection
  standards, policies, and procedures for
  distributed generation.
• In 2009, DPU approved tariff that included net
  metering provisions.
• In the summer of 2012, DPU convened a Distributed
  Generation Working Group (DGWG) to recommend
  improvements to the MA DG Tariff. The DGWG,
  comprised of utility, state and DG community
  stakeholders, reached consensus on all but one
  issue and the DPU approved the revised tariff on
  3/20/13 and went into effect May 1, 2013.
• This interconnection standard covers all forms of
  generation operating in parallel with the grid
  (it does not apply to emergency generation).

6
What is the Interconnection Process?

• Process of getting an interconnection agreement
  from your local utility (or distribution company)
  to connect a distributed generation system to
  their distribution system.
• This process is used by the four investor owned
  utilities (IOU) in Massachusetts (NSTAR, National
  Grid, Unitil and Western Mass Electric)
• Municipally-owned utilities are not required to
  follow this process, and may follow a different
  criteria.
• The process is used to make sure interconnecting
  DG systems are integrated into the distribution
  system responsibly with respect to impacts on
  reliability, power quality and safety
• Can not allow DG to affect neighbors on feeder

7
Importance of the Interconnection Process for CHP

• Following the interconnection process is
  important because a DG system changes the one-way
  power flow from the utility to customer, which
  can present dangers to utility workers if proper
  equipment is not installed
• While robust and capable of handling minor
  disturbances, the quality of grid power is
  extremely important. The interconnection process
  ensures the DG meets safety, reliability, power
  quality requirements with regard to
• Islanding
• Transient Voltage Conditions
• Noise and Harmonics
• Frequency
• Voltage Level
• Machine Reactive Capability
• It is essential that each interconnection get an
  interconnection agreement with the utility before
  installing any generation. You are proceeding at
  your own risk if you choose to install a system
  without utility approval.

8
Pre-Application Report
Customer needs to provide
Utility to provide

• Contact Person
• Mailing Address
• City
• Telephone E-Mail Address
• Alternative Contact Information (e.g., system
  installation contractor or coordinating Facility
  Information
• Proposed Facility Location (street address with
  cross streets, including town, and a Google Map
  still picture and GPS coordinates)
• Generation Type
• Size (AC kW)
• Single or Three Phase Generator Configuration
• Stand-alone (no on-site load, not including
  parasitic load)?
• If there is existing service at the Proposed
  Facility site, provide
• Interconnecting Customer Account Number
• site minimum and maximum (if available) current
  or proposed electric loads
• Minimum kW
• Maximum kW
• Is new service or service upgrade needed?

• Circuit voltage at the substation
• Circuit name
• Circuit voltage at proposed Facility
• Whether Single or three phase is available near
  site If single phase distance from three phase
  service
• Aggregate connected Facilities (kW) on circuit
• Submitted complete applications of Facilities
  (kW) on circuit that have not yet been
  interconnected
• Whether the Interconnecting Customer is served by
  an area network, a spot network, or radial
  system
• Identification of feeders within ¼ mile of the
  proposed interconnection site through a snap-shot
  of GIS map or other means and
• Other potential system constraints or critical
  items that may impact the proposed Facility.

9
Everything starts with the Application

• A complete complex application package includes
• All appropriate sections of 4-page application
  completely filled out. Customer will likely need
  assistance from vendor/engineer.
• Copy of Pre-Application Report
• Application fee 4.50/KW (300 minimum and 7,500
  maximum). This fee covers the initial review.
  (Proposed change in 2012 raises these costs)
• Stamped electric one-line diagram, preferably
  showing relay controls (one copy) (Stamped by
  Massachusetts Electrical PE)
• Site diagram (one copy)
• One copy of any supplemental information (if
  electronic single copy acceptable)
• Identify electric customer and owner of proposed
  generation
• Schedule Z if planning to Net Meter
• Errors or problems with application will slow
  down the process and stop the clock
• Send Electronic copy of all documents preferred
  if possible Easier to distribute, saves paper,
  and is faster. However, submit first page of
  application with application fee.

10
Expedited Review Path

• Applies to
• Single phase customers with listed single-phase
  inverter based systems gt15 kW on a radial feed
• Three phase customers with listed three-phase
  inverter based systems gt25kW on a radial feed.
• Maximum size is based on review of screens
• Does not Apply to
• Non-listed inverters or other generators
  (induction / synchronous / asynchronous)
• Aggregate generation capacity of listed inverters
  that exceed the above-mentioned limits

11
Table 1 of Section 3 in the Interconnection Tariff
Expedited Review Path
Expedited
Eligible Facilities Listed DG
Acknowledge Receipt of Application (Note 2) (3 days)
Review Application for Completeness 10 days
Complete Review of All Screens 25 days
Complete Supplemental Review (if needed) (Note 3) 20 days or Standard Process
Send Executable Agreement (Note 4) 10 days
Construction Schedule By Mutual Agreement
Total Maximum Days (Note 5) 40/60 days (Note 6)
Notice/ Witness Test lt 1 day with 10 day notice or by mutual agreement

• Typically little or no (utility) system
  modifications required. If meter only usually
  no charges passed to customer
• Application fee plus any Supplemental Review
  charges up to 30 hours of engineering time _at_
  150/hr (if needed)
• Relay control system must be well defined to make
  supplemental review easier.
• Witness test fee of up to 300 plus travel is
  required.

12
Supplemental Review

• If one or more Screens are not passed, the
  Company will provide a Supplemental Review
  Agreement.
• Threshold is whether project is less than 67 of
  minimum load on the feeder
• Then other screens review voltage quality ,
  reliability and safety to reduce the potential
  need for impact studies.
• DPU order allowed for the 67 screen, but
  requires utilities to document how the use of a
  100 screen would change the screening process
• Customer signs agreement and pays fee for
  additional engineering time (max fee is now
  4,500).
• The Supplemental Review may be able to determine
  what impacts the generation system will have and
  what (if any) modifications are required. If so
  - an interconnection agreement will be sent to
  customer detailing
• System modification requirements, reasoning, and
  costs for these modifications
• Specifics on protection requirements as necessary
• If Supplemental Review cannot determine
  requirements, an Impact Study Agreement (or
  equal) will be sent to the customer. (You shift
  to the Standard Process.)

13
Standard Review Path

• Applies to
• Non-listed inverters or other generators
• Induction
• Synchronous
• Asynchronous
• Other large MW and Multi MW Projects
• Renewable DG Customers / Developers

14
Standard Review Path
Table 1 of Section 3 in the Interconnection Tariff

• After initial review and/or supplemental review,
  customer may need to enter Standard Process
• Customer can request Standard Process
• Appropriate study agreement sent for signature
  and payment
• Studies could include
• Impact Study Determine the impact of the new
  generator on potentially affected systems,
  including EPS, other customers and other
  generators
• Detailed Facility Study Determine utility system
  modifications required and cost
• ISO notification and possibly Transmission Study
  if over 1 MW
• After studies interconnection agreement sent
  for signature
• Witness test fee is actual cost.

Standard
Eligible Facilities Any DG
Acknowledge Receipt of Application (Note 2) (3 days)
Review Application for Completeness 10 days
Complete Standard Process Initial Review 20 days
Send Follow-on Studies Cost/Agreement 5 days
Complete Impact Study (if needed) 55 days
Complete Detailed Study (if needed) 30 days
Send Executable Agreement (Note 3) 15 days
Construction Schedule By Mutual Agreement
Total Maximum Days (Note 4) 125/150 days (Note 5)
Notice/ Witness Test 10 days or by mutual agreement
15
MA Revised Interconnection Tariff

• 1st payment of 25 of estimate is only required
  within 120 business days of signing an ISA
• Estimates are only good for 60 business days and
  we have the right to re-estimate if customer
  payment is not received before then
• Company is not obligated to order equipment
  without receiving adequate payment as defined
  in customers ISA
• Company not required to begin construction prior
  to receipt of full payment
• If payment is not made within the applicable
  timeframe, the Company shall require the Customer
  to reapply for interconnection.
• Increased study times for large projects
• Those that require modification at substation
• Instead of 55 business days for an Impact Study,
  now have 75 (2013 and 2014), then to 70 (2015),
  and then 60 (2016)
• Projects gt 200,000 estimated costs (not
  including on-site work, metering, recloser, riser
  pole, etc.)
• Instead of 30 business day for a Detailed Study,
  now have 75 (2013 and 2014), then to 70 (2015),
  and then 60 (2016)
• Projects gt 1 million, all study timelines are by
  mutual agreement
• Require more detailed reporting on project status
• For both studies and construction timelines
• ISA must include a mutually agreed upon timeline
  for construction
• DPU has asked DG WG to investigate an
  incentive/penalty mechanism to ensure timeline
  compliance

16
Timeline Compliance

• Regulatory obligation for both the distribution
  company and the customer
• Study times are suspended until such time as
  company receives the requested info from customer
• if an applicant requests additional time at or
  near a milestone, the Company will get additional
  time to achieve that milestone
• if an applicant requests a significant project
  change -- as determined by the distribution
  company -- the applicant will be required to
  submit a new interconnection application
• at any time, an applicant may request a review
  of time-frame compliance by the distribution
  company, and the distribution company must
  respond within ten business days
• There is a process to remove customers from the
  queue if they dont abide by the timelines or
  extensions
• Customer can request refund of application fee if
  the Company does not comply with timeline(s)

17
Responsibility of Costs

• Interconnecting customer responsible for
• Application Fee
• Expedited and Standard 4.50/kW (300 min and
  7,500 max
• Costs of impact and detailed studies if required
• Grid modification requirements can include
  ongoing charges
• Witness Test Fee
• Costs associated with design, construction and
  installation of the facility and all associated
  interconnection equipment on the customers side
  of the meter
• Not all projects will require impact or detailed
  studies or EPS upgrades

18
Third Party Ownership

• Application must include information for both
  generation owner (interconnecting Customer) and
  electric or retail customer (Customer)
• Utility will correspond with owner, customer and
  installer
• Listing email addresses for all parties on
  application makes communication easier and faster
  
• Utility will enter into agreement with our
  electric customer (Attachment G of tariff)
• Note Any Ownership change would require
  updated documentation submitted to the Utility
  Company

19
Common Application Mistakes

• Number of inverters being used not indicated
• Utility account or meter number not included or
  incorrect
• Address of facility not correct
• Name on application differs from name on utility
  account
• Application not signed
• Ownership of property not identified
• Not identifying third party ownership of
  generator

20
Common process delays

• New construction or service upgrade
• Host/Owner misidentification
• Changing inverter or other equipment
• Not supplying electrical permit
• Certificate of Completion (CoC) signed and dated
  before date given approval to install

21
Behind the scenes at utility

• Review and replacement of metering, modifications
  to billing
• Modifications to protection systems as required
  (e.g. replace or install fusing, install switch,
  modify breaker/recloser set-points, transfer
  trip, etc.)
• Larger generators require review by NEPOOL
  reliability committee and registration with
  ISO-NE
• Adding generation asset to geographic information
  systems, maps, system one-lines, dispatch
  systems, etc.
• Publish internal special operating guidelines for
  utility field personnel on larger generators.
• Set up future testing for relay protection, meter
  calibration, insurance tracking, etc.

22
Many Stakeholders Involved
Utility
Interconnecting Customer

• Application analyst processes application and
  contracts
• Lead Engineer for reviews/studies
• Relay Engineering
• Distribution Planning
• Distribution Dispatch
• Distribution Design Engineering
• Meter Operations
• Meter Engineering
• Meter Data Services
• Relay Telecom Operations
• Inspection team
• Customer Service / Billing
• Legal

• Customer
• Equipment vendor
• Lead contractor
• Electrician
• Electrical Engineer (PE)
• Relay Engineer
• Relay testing firm
• Legal

ISO-NE (If necessary)
23
Interconnection Summary and Recommendations

• Submit your interconnection application with
  National Grid early, during conception phase
  before committing to buy no matter how simple or
  small the DG might be.
• You can always request general utility
  information about a specific location from your
  utility
• Large interconnection application take longer to
  study
• Stand alone (no load behind the meter)
  interconnection application take longer to study
• Interconnection timeframes do not apply to
  Electric Power System construction if required.

24
Summary and Recommendationscontinued

• The Interconnection Standard is a wealth of
  information get to know it
• Time frames are standard working days and do not
  include delays due to missing information or
  force majeure events
• Interconnection expenses such as application
  fees, required studies, potential system
  modifications and witness tests should be
  budgeted into each project
• Consider hiring an engineer to help with
  interconnection process
• ISO-NE notification not included in time frame
• Interconnection applications have increased
  significantly in the past few years APPLY
  EARLY!!!

25
Compensation for excess CHP generation

• If the customer will never export power no
  concern
• If under 60 kWs, customer can net usage over
  billing period
• Paid average clearing price for load zone for
  excess
• If customer will export power they can sell
  their exported power to the market through a
  registered market participant.
• Customer will need a Qualifying Facility (QF)
  certificate from FERC for the generator, to
  sell to local utility (Power Purchase Schedule)
• Receive hourly clearing price for load zone for
  excess
• Customer can work with any registered market
  participants to sell power
• Customer must pay for all power they use.
• Energy is netted for each hour, not over the
  billing period
• FERC QF page http//www.ferc.gov/industries/elec
  tric/gen-info/qual-fac.asp

26
State vs. ISO-NE Process

• If project is large enough (gt6 -10 MWs), will
  need to interconnect to transmission system
  through Small Generator Interconnection
  Procedures (SGIP)
• Need to apply to the New England Independent
  System Operator (ISO-NE)
• If you will be selling your power to a third
  party, or bidding in capacity to the Forward
  Capacity Market (FCM) you may have to apply
  through ISO-NE
• If circuit is already FERC Jurisdictional and
  project is selling to a third party, it will need
  to apply to ISO-NE.
• If another generator is selling to the wholesale
  market, then the circuit is FERC jurisdictional
• http//www.iso-ne.com/genrtion_resrcs/nwgen_inter/
  index.html

27
Interconnection Contacts Tariff Links

• National Grid
• Email Distributed.Generation_at_us.ngrid.com
• Phone Alex Kuriakose [phone], Bob
  Moran [phone]
• W. Adam Smith [phone],
  Vishal Ahirrao [phone]
• Sean Diamond [phone], Chandra
  Bilsky [phone]
• Kevin G. Kelly [phone]
• http//www.nationalgridus.com/non_html/shared_int
  erconnectStds.pdf
• NSTAR
• Joseph Feraci  [phone]
  (joseph.feraci_at_nstar.com)
• Paul Kelley [phone] (paul.kelley_at_nstar.c
  om)
• http//www.nstar.com/business/rates_tariffs/inter
  connections
• Unitil
• Tim Noonis 603-773-6533 (noonis_at_unitil.com)
• http//www.unitil.com/energy-for-residents/electr
  ic-information/distributed-energy-resources/renewa
  ble-energy-generation
• WMECo
•  Phone [phone]

28
Other Information Resources

• MA DG and Interconnection Website
  http//sites.google.com/site/massdgic/
• Net Metering Basicshttp//sites.google.com/site/
  massdgic/Home/net-metering-in-ma
• Interconnection Guide for Distributed Generation
  (Mass-CEC)http//www.masscec.com/masscec/file/I
  nterconnectionGuidetoMA_Final28129.pdf

28
29
Appendix Technical Aspects of Integrating
DGwith the Utility Distribution EPS
30
Interconnection StandardsLocal Rules National
Grid

• What are the local rules that apply to DG
  interconnections?
• National Grid ESB 756 Parallel Generation
  Requirements
• Originates from the ESB 750 Series and applicable
  Company tariffs in each state jurisdiction
• ESB 756 main document
• Appendices to ESB 756 for Jurisdictional
  Requirements
• Some key factors that influence the
  revision/update of Electric Service Requirements
  are
• Government
• DPU (Massachusetts), PSC (NY), and PUC (one each
  for NH RI)
• FERC
• Federal, State, and Local Laws
• MA Court Rules Solar PV Installations are
  Electrical. PHYSICAL INSTALLATION of PV Systems
  Must Be Done by LICENSED ELECTRICIANS. July 2012
  ruling by Suffolk Superior Court
• Company tariffs
• Company policies practices
• National codes

Each utility has their requirements pursuant to
the regulations that govern them as varying from
state-to-state based on the NESC.
www.nationalgridus.com/electricalspecifications
31
Interconnection Standards (contd) National Grid
ESB 750 Series

• Key Points for Electric Service Requirements
• Require some means of disconnect and main
  overcurrent protection, i.e., service equipment.
• Billing meters secure.
• Interface points clear to avoid potential
  operating and safety problems.

• Key Points for Parallel Generation Requirements
• Company determines the interconnect voltage and
  method of interconnection.
• Prior notification to and approval by the Company
  is required for any generation to be installed or
  operated in parallel with the Company EPS.

32
Technical Issues

• Technical Process End-to-End (Study to
  Energization/Synchronization) with National Grid
• Technical Submittals for Utility Review
• Potential Impacts of Parallel Generation on
  Distribution Electrical Power Systems (EPS)
• Limits on National Grid Distribution EPS
• Radial Systems
• Network Systems
• Service Connections of Small Net Metered DGs lt
  600V
• Typical Distribution EPS Upgrade Costs for
  Complex DG Installations

33
Technical IssuesTechnical Submittals for
Utility Review
Recommended Guidelines for Residential and
Commercial Single-line Diagram Submittals (for
example, see Exhibit 5 Figures 1 2 in ESB 756
Appendix C)

• 1. Identify the project, Companys electric
  service order (ESO) number, location and
  submitters name and address.
• 2. Indicate standard and any non-standard system
  voltages, number of phases, and frequency of the
  incoming circuit. Indicate wye and delta systems
  show whether grounded or ungrounded.
• 3. Identify cable, conductors and conduit, the
  type and number including Point of Common
  Coupling. (The Company is interested in how the
  power is getting from the service point to the
  protective equipment.)

34
Technical Issues (contd)Limits on Distribution
EPS - Radial

• Typical Planning Limits for DG Connection to
  Radial Distribution Feeder

DG installations are classified into two types -
those interconnecting to the National Grid system
on a dedicated radial feeder and those
interconnecting on a non-dedicated radial feeder.
35
Technical Issues Anti-Islanding on Distribution
EPS - Radial

• Anti-Islanding Protection
• The Companys position is that the
  interconnection of all parallel generators
  requires safeguards for synchronization and
  back-feed situations. A parallel generator is
  prohibited to energize a de-energized Company
  circuit.
• The Company uses three main tests any
  determine if anti-islanding protection is
  required for exceeding minimum load issue or a
  protection issue or operating concern
• Feeder Load versus Generation Test
• Fault Sensitivity Test
• Feeder Selectivity Test
• Tips
• DG Customers protective device coordination
  study demonstrates generation voltage and/or
  frequency protection will trip within 2.00
  seconds for the loss of the utility source.
• Type-tested inverter-based parallel generation
  operated in regulated current mode, transient
  overvoltage protection is required upon detection
  of an island.
• When DTT is specified for a parallel generation
  project, the Company will determine the
  requirements and responsibilities for equipment,
  installation, and communications media in the
  interconnection study.

36
Technical IssuesLimits on Distribution EPS -
Network

• Unlike radial distribution systems that deliver
  power to each customer in a single path from
  source to load, underground secondary area
  network systems deliver power to each customer
  through a complex and integrated system of
  multiple transformers and underground cables that
  are connected and operate in parallel.
• Area Networks consist of one or more primary
  circuits from one or more substations or
  transmission supply points arranged such that
  they collectively feed secondary circuits serving
  one (a spot network) or more (an area network)
  electric customers.

37
Technical Issues (contd)Limits on Distribution
EPS - Network
Area Networks consist of one or more primary
circuits from one or more substations or
transmission supply points arranged such that
they collectively feed secondary circuits serving
one (a spot network) or more (an area network)
Interconnecting Customers. Portions of the
following cities are served by area networks
(customers in these areas should ask where the
nearest radial system is located for possible
tie-in)
WMECo Unitil National Grid NSTAR
Greenfield Pittsfield Springfield West Springfield Fitchburg Brockton Lynn Worcester Boston New Bedford Cambridge
(For National Grid, see Exhibit 3 in ESB 756
Appendix B, or C, or D.)
37
38
Technical Issues (contd)Limits on Distribution
EPS - Network

• The connection of customer DG facilities on
  networks is an emerging topic, which
• (i) poses some issues for the Company to maintain
  adequate voltage and worker safety and
• (ii) has the potential to cause the power flow on
  network feeders to shift (i.e., reverse) causing
  network protectors within the network grid to
  trip open.

• To ensure network safety and reliability
  additional information will be required for the
  Companys engineering analysis such as
• Electric demand profile showing minimum load
  during peak generation time,
• Expected generation profile shown for a 24-hour
  period and typical 7-day duration, and
• Customers complete electric service single-line
  diagram up to the service point supplied by the
  Companys secondary network EPS.

39
Technical Issues Upgrades and System
Modifications
Some Upper End Typical Utility Interconnection
Costs Duration Scheduling for Complex DG
Installations
Notes 1) Distribution EPS relates to 15kV class
system. 2) These are representative estimates
only and are not inclusive of all costs i.e.
land rights, removal costs, taxes, etc. which
will vary from job to job and that they are
presented here for budgetary purposes only.
40
Post ISA CoordinationWitness Testing (overview)

• 1.) Relay Witness Testing
• National Grid Witnesses relays trip based on
  settings approved by NG Protection Engineer
• 2.) DTT Witness Testing
• Communication (RFL) to the Local Substation
• Typically Fiber or Lease line
• 3.) RTU Witness Testing (1MW)
• Provide Real time monitoring of Large DG at
  National Grids Regional Control Center.
• Ordering Correct (MPLS) communication circuit
  from Verizon
• Verizon Regional Account Teams consults with
  Verizons Service Delivery Department

41
Appendix Net Metering
42
Net Metering in Massachusetts

• December 2009 Net Metering Tariff
• Three Net Metering Classes
• Class 1 Any generator up to 60 KW is eligible
• Class 2 Agricultural, solar, or wind net
  metering facility over 60 KW but less than or
  equal to 1 MW (for municipal or government its
  per unit)
• Class 3 Agricultural, solar, or wind net
  metering facility over 1 MW but less than or
  equal to 2 MW (for municipal or government its
  per unit)
• Recent changes
• limits projects to 2 MWs per parcel of land and a
  single meter
• Must apply to the System of Assurance (SofA) at
  massaca.org for net metering services

43
Net Metering Tariff

• Eligible customers can apply by submitting a
  Schedule Z.
• Eligibility determined when approved within the
  SoA
• Utility can not allow net metering without SofA
  approval
• Class 2 and Class 3 will need a production meter
  on generation.
• Net Metering is limited to 3 of each utilitys
  peak MW for private and 3 of peak for public
  projects for NG-MA this total limit is 308 MWs.
• Contribution towards total 6 limit is posted on
  each utilitys web site and updated monthly
• As of 4/16, NG-MA is at 94 MWs for the private
  and of 52 MW toward the public cap

44
Net Metering changes

• Three Factor Approach (order 11-11C)
• Single parcel / single interconnection point /
  single meter
• Enacted to limit gaming and limits one meter per
  parcel of land with a limit of 2 MWs on the
  parcel for private entities
• A governmental entity can have a total of 10 MWs
  of net-metered accounts throughout the state or
  on a parcel
• No more 6 1 MW projects on a parcel
• We can not provide more than one interconnection
  point (POI)
• In addition, if theres an existing meter(s) on a
  parcel, then customer cant request a meter just
  for the net metering facility, it must be behind
  an existing meter
• Otherwise separate metered project could earn
  higher credits than if it was behind an existing
  meter

45
Net Metering and Interconnection Order

• Net Metering eligibility
• The DPU ruled in the interconnection tariff order
  (10-75E) that Early ISAs will NOT meet the
  executed ISA requirement for entrance into the
  System of Assurance, and will refer the matter to
  DPU 11-11 for further investigation.
• Until such time as the DPU reaches a resolution
  of the issue, Distribution Companies are directed
  to clearly mark Early ISAs on the title page and
  on the signature page with the words Early ISA
  for identification purposes.

46
Net Metering Credits

• Energy use is netted over the billing month
• If there is net energy use utility will bill
  customer for net use
• If net energy export export kWH the following
• Renewable installations will be credited at near
  retail rate for excess kWH (minus conservation
  and renewable energy charges).
• Non-Renewable credited at average monthly
  clearing price ISO-NE
• Tariff allows credits to be allocated (with
  limitations)
• Customer still responsible for customer charges
  and demand charges, even if net export

        Credit the following charges Credit the following charges Credit the following charges Credit the following charges
Tier min max Type Default Service kWH Dist- ribution kWH Trans- mission kWH Trans- ition kWH
1 0 60 KW Agriculture Wind, PV X X X X
2 gt60 KW 1 MW Agriculture Wind, PV X X X X
3 gt1 MW 2 MW Agriculture Wind, PV X Govt only X X
47

48
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49
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50
Net Metering Production Reporting

• Net Metering Tariff requires reporting of
  generators kWH output.
• Class 1 Facilities to provide in writing by
  January 31 and September 30
• Class 2 and Class 3 Facilities may participate in
  production tracking system (PTS).
• Mass CEC provided PTS data to the utilities,
  still working through implementation issues
• Utility will request data from Class 2 and 3
  Facilities

51
Net Metering Summary

• If planning to Net Meter, submit Schedule Z with
  interconnection application
• Correctly fill out Schedule Z
• Name must match electric account of Host Customer
• Must be signed by Host Customer
• If allocating, verify name/address/account info
  of customer(s) or will need to submit corrected
  form
• Production reporting is required.
• Over 60 kWs require registration as a settlement
  only generator (SOG) associated ISO OP 18
  metering requirements