EEA Database on Distributed Generation

WHAT'S NEW:

No recent state activity has been identified.

Emergency or standby engines with a rated power output equal to or greater than 37kW that begin operation on or after March 23, 2006 must meet applicable emission limits set by the EPA for non-road engines. Emergency turbines with a power output less than 1 MW must meet a NOx limit of 0.60 lbs/MW-hr. Also, there is a de minimis exemption for construction, substantial reconstruction or alteration that results in potential emissions of less than one ton of any air contaminant, calculated over a 12-month period. A more comprehensive list of exemptions can be found in 310 CMR 7.02 (2)(b). On and after March 23, 2006, an individual internal combustion engine including a combustion turbine or reciprocating engine installed and operated in compliance with 310 CMR 7.26(40) through (44), or an internal combustion engine regulated by EPA as a nonroad engine pursuant to 40 CFR 89, 90, 91, and 92.

MINOR SOURCE PERMITTING

BACT is required of units with an emissions increase of 5 tpy or more (except for certain engines and turbines). These units must submit either a Limited Plan Application (LPAs) or Comprehensive Plan Applications CPAs. Units that cannot qualify for the above exemption must complete a BACT analysis for PM, NOx and VOCs. Application costs, permitting process timelines, and other permitting information can be accessed here.

MAJOR NSR/PSD PERMITTING

A potential to emit 250 tons per year of a criteria pollutant triggers PSD. 50 tons of NOx or VOCs per year triggers NSR. RACT requirements apply to sources with a potential to emit 50 tons per year of NOx, before the application of air pollution control equipment, certain exemptions apply, see 310 CMR 7.19.

TREATMENT OF EMERGENCY ENGINES

Emergency units may operate no more than 300 hours during a 12-month period. This operating restriction includes normal maintenance and testing procedures recommended by the manufacturer. A non-turnback hour counter must be installed, operated and maintained in good working order.

There are also specific emission limits based on the size of emergency engines and turbines. For emergency or standby engines with a rated power output equal to or greater than 37 kW and emergency turbines with a rated power output of less than 1 MW that are constructed, substantially reconstructed or altered after March 23, 2006. Engines with a rated power output of equal to or greater than 37 kW must comply with the applicable emission limits set by the EPA for non-road engines (40 CFR 89 as in effect October 23, 1998). All emergency engines with a rated power output of less than 1 MW must comply with NOx limits of 0.60 lbs/MWh. Emergency engines or turbines can only use diesel fuel that meets the EPA’s sulfur limits outline in 40 CFR 80.29, 80.500, and 80.520 (a) and (b) as in effect January 18, 2001. There are also specific stack height and opacity limits of less than 20%, applicable to these engines, which are outlined in 310 CMR 7.26 (42).

All engines with a rated power output equal to or greater than 50 kW and combustion turbines with a rated power output equal to or less than 1 MW installed after March 23, 2006 must meet emission standards outlined in the Engine and Combustion Turbine ERP regulation [310 CMR 7.26(43)]. The owner or operator of these engines and turbines must obtain from the supplier a completed Emission Limit Certification form, certifying that the system as designed and installed will comply with the applicable emissions limits for the lesser of the first three years or 15,000 hours of operation. The applicable emission limits are described in the tables below –

Engine Emission Limits (lbs/MWh)

Installation Date	NOx	PM (liquid fuel only)	CO
On and after March 23, 2006	0/6	</= 1 MW 0.7; > 1 MW 0.09 lbs/MWh	10
On and after 1/1/08	0.3	0.07	2
On and after 1/1/12	0.15	0.03	1

Emission Limits – Turbines

Rater Power Output	NOx	Ammonia	Carbon Monoxide
Less than 1 MW	0.47 lbs/MWh natural gas	N/A	0.47 lbs/MWh natural gas
1 to 10 MW	0.14 lbs/MWh natural gas, 0.34 lbs/MWh oil	2.0 ppm at 15% O2 dry basis	0.09 lbs/MWh natural gas, 0.18 lbs/MWh Oil

Emission Limits – Engines and Turbines

Installation Date	Carbon Dioxide
On and after March 23, 2006	1900 lbs/MWh
On and after January 1, 2008	1900 lbs/MWh
On and after January 1, 2012	1650 lbs/MWh

Visible emissions cannot exceed 20% opacity at any time during emergency engine and emergency turbine operation. There are also specific stack height requirements, which are outlined with other details in the Engine and Turbine Environmental Certification Workbook.

The same emission limits found in the tables above also apply to engines or turbines that are to be operated as peaking power production units, load shaving units, units in an energy assistance program, units that produce power to run pumps, and units to compress natural gas at a compressor station.

SITING REQUIREMENTS FOR NON-UTILITY GENERATORS:

Approval is needed from the state siting board for any application greater than 100 MW.

The Massachusetts' Energy Facilities Siting Board is an independent state review board located administratively within the Massachusetts Department of Telecommunications and Energy ("DTE"). The Siting Board is charged, by state statute, with ensuring a "reliable energy supply for the Commonwealth with a minimum impact on the environment at the lowest possible cost." (G.L. c. 164, § 69H). The nine-member Siting Board is made up of three commissioners of the DTE, the Secretary of Environmental Affairs, the Director of Economic Development, the Commissioner of the Division of Energy Resources, and three public members who are appointed to three-year terms by the Governor. The Siting Board decides whether prospective developers may construct major energy facilities -- electric generating plants, electric transmission lines, intrastate natural gas pipelines, facilities for the manufacture or storage of natural gas, and various oil facilities -- in Massachusetts. The scope of the Siting Board's review of a proposed facility varies, depending on the type of facility being reviewed. The Siting Board's review of electric generating plants focuses on environmental impacts and mitigation, while its review of other types of facilities considers the need for the proposed facility, the cost of the facility, and its impacts on the environment. Alternatives to a proposed facility, including one or more designated alternate routes for transmission line and gas pipeline projects, may also be considered.

Massachusett's Energy Facilities Siting Board Rules

BUILDING, ZONING AND FIRE CODES:

Building Codes: Massachusetts enforces the Massachusetts Basic Building Code, 7th Edition (2007), which is rule 780 CMR. [1] The code is mandatory statewide and can only be amended by local jurisdictions with state approval. It does not appear to be based in any large part on a model code.

Board of Building Regulations and Standards

Energy Codes: Massachusetts will enforce, as part of their 7 th edition building code, a new state energy code. This energy code will require use of the 2006 IECC with 2007 supplement OR ASHRAE 90.1-2007, with Massachusetts amendments. [2]

Department of Energy Resources

Fire Codes: Massachusetts enforces the Board of Fire Prevention Regulations, 527 CMR, which do not appear to be based on a model code.

State Fire Marshal

Zoning: Zoning and planning happens at the local level. Check with each jurisdiction regarding their zoning codes.

Resources (information may not be as current as provided above)

A general overview of each state’s enacted codes can be found HERE.

The International Code Council Adoption page gives state-by-state adoption status of specific ICC codes, as well as information about code adoption by some municipal governments within that state.

Information about energy codes can be found at the Department of Energy’s Building Codes for Energy Efficiency page or at the Building Codes Assistance Project

INTERCONNECTION REQUIREMENTS:

Massachusetts Overview

Massachusetts 's Interim Uniform Interconnection Standards (first issued in 2003 and amended in 2004 and 2005) apply to all distributed generation operating in the state, including renewables, with simplified rules for certified, inverter-based, single phase systems less than 10 kW. For the simplified interconnection process there are also no fees fro the approval process, and applications must be processed within 15 days. Other systems can qualify for an “expedited interconnection” or can go through the “standard” interconnection process. Under the expedited procedure, the application timeframe and fees are limited. Fees are set at $3/kW with a minimum charge of $300 and a maximum of $2500. The Massachusetts Technology Collaborative has the following Interconnection Guide for Distributed Generation, http://masstech.org/cleanenergy/howto/interconnection/index.htm.

Current Policy Status

In February 2007, the Massachusetts Department of Telecommunications and Energy (DTE) approved (docket 02-38-D) revisions to the state's Model Interconnection Tariff that were included in the Distributed Generation Collaborative’s 2006 annual report. The 18 approved proposed changes include expanding the size limit for systems eligible for the simplified interconnection process from 10 kW to 25 kW for three-phase facilities, and replacing the cap with a requirement that the aggregate generating facility capacity be less than 1/15th of the customer's minimum load. The DTE opened Docket DTE 07-6 in March 2007 to investigate standby rates and alternative rate structures that will promote the deployment of DG, issues not covered in docket 02-38-D discussed above. The DTE has since been dissolved (in April 2007), DTE issues are now taken up by the Department of Public Utilities.

More information on Massachusetts’ interconnection procedures can be obtained by contacting:

Barry Perlmutter
Massachusetts Department of Public Utilities
100 Cambridge Street, Room 1210
Boston, MA 02202
Phone: (617) 305-3659
Fax: (617) 723-8812
E-Mail:barry.perlmutter@state.ma.us
Web site:http://www.state.ma.us/dpu

EXIT FEES:

There are exit fees in Massachusetts for DG applications that are greater than 60 kW. Renewable energy technologies and fuel cells are exempt regardless of their power rating. The Department of Telecommunications and Energy (DTE) used to be the authority concerning exit fees, but has been recently split into the Department of Telecommunications and Cable (DTC) and the Department of Public Utilities (DPU), which will handle electric, gas, siting pipeline, water and transportation issues. The DPU must now determine on a case-by-case basis the date upon which a utility can no longer collect transition charges. (See below)

In some cases, on behalf of its other customers, a distribution company is allowed to charge exit fees to customers that develop on-site generation because of the impact that their leaving has on the distribution company's overall revenues, and in turn the regulated rates of its other customers. However, Massachusetts' restructuring law specifically provides that distribution companies cannot charge exit fees to renewable or distributed generation facilities if certain conditions are met. If a customer provides the distribution company and DPU with at least six months notice of its plans to install on-site cogeneration equipment, renewable energy technologies, or fuel cells, it will not be subject to an exit charge. For facilities that are eligible for net metering-for example, facilities with a design capacity of 60 kW or less-no such six-month notice is required.

In addition, if a customer provides the distribution company and DPU with at least six months notice of its plans to buy electricity from onsite renewable energy technologies, fuel cells, or cogeneration equipment with a combined heat and power system efficiency of at least 50 percent, or if the customer operates or buys from an on-site generation or cogeneration facility of 60 kW or less that is eligible for net metering, it will not be subject to an exit charge even though its actions will result in less electricity being purchased from the service provider. In both cases, certain additional conditions also need to be met regarding the total amount of generation leaving the system. The Qualifying facility (QF) or On-site generation facility (OSGF) cannot have been responsible for more than 10% of the service provider's annual gross revenues during the past year; and the combined previous electricity purchases of the QF or OSGF and all other customers who, during a three-year period leave the service provider's system, cannot total 10% or more of the service provider's annual gross revenues. If they total more than 10%, each such customer will pay an exit fee charge that reflects its pro rata share of the portion of the annual gross revenues that is over the 10% limit. The DPU publishes a report by July 1st indicating the amount of generation produced from QFs and OSGFs so that each utility can keep track of the growth in percent revenue each year. According to the Rate and Regulation Department of the MA DTE, there has been only one instance of an exit fee assessment. This occurred when MIT installed an onsite power system that significantly reduced the load of the local utility. The Massachusetts Department of Telecommunications and Energy has recognized the importance of distributed generation as a resource option in the restructured electric industry.

Rules Governing the Restructuring of the Electric Industry 220 CMR 11.00

(d) The Department shall determine whether an exit fee may be charged to a Retail Customer that reduces purchases of electricity through the operation of, or purchases from, on-site generation or cogeneration equipment in accordance with the provisions of M.G.L. c. 164, § 1G(g).

(g) Effective as of March 1, 1998, if the utility and the department have received at least a six months notice of the customer's plans to install on-site cogeneration equipment, renewable energy technologies, fuel cells, or to purchase electricity through cogeneration equipment, a customer that reduces purchases of electricity through the operation of, or purchases from, on-site generation or cogeneration equipment, shall not be subject to an exit charge if

(i) such customer provided less than or equal to 10 percent of the annual gross revenues collected by its previous service provider in the year prior to the customer leaving the system after the retail date established in this bill; provided, however, that in the event that two or more customers who, at any time within a 36-month time period, leave such system, after the retail access date established in this bill, and represent together the aggregate of greater than or equal to more than 10 per cent of the annual gross revenues collected by such previous service provider in the year prior to the initial exit from the system, all such customers shall be subject to an exit charge based upon that portion of the annual gross revenues which is over the 10 per cent limit; and provided, further, that such fee shall be prorated amongst such customers who have left or are leaving on the system based upon the proportion of annual gross revenues each customer represented within the total amount of gross revenues being subtracted from the service provider's system; or

(ii) the customer reduces purchases through the operation of, or purchases from, on site renewable energy technologies, fuel cells, or cogeneration equipment with a combined heat and power system efficiency of at least 50 per cent, based upon the higher heating value of the fuel used in the system; or

(iii) the customer reduces purchases through the operation of, or purchases from, an on site generation or cogeneration facility of 60 kilowatts or less which is eligible for net metering. Except as provided in existing contracts or tariffs, the department and the utility shall not require more than six months notice of the customer's plans to install said equipment. Any such exit charge shall be payable to the customer's distribution company for the benefit of other customers. Such exit charge may be equal to but no greater than the expected value of the access charge payments the customer would have paid out but for the operation of such equipment and shall be determined by the department based upon federal and state law, any applicable judicial determinations, and criteria promulgated by the department through rules and regulations. Notwithstanding clauses (i) to (iv), inclusive, if the total kilowatt hour usage in any service territory falls below usage levels following the installation of such on-site generation or cogeneration equipment, and the department determines that the aggregate reduction in future purchases of electricity and transition charge payments resulting from customers' installing such equipment will have a significant adverse impact on electric bill to be paid by other customers in said distribution company's territory during the remaining period of transition cost recovery, then the department may order that an exit charge shall be paid on such terms as determined by the department based upon criteria promulgated herein and through rules and regulations. The department shall issue a report on July 1, 1999 and every year thereafter, for the period of transition cost recovery, relative to degree of impact on the aggregate reduction of the electricity and impact on transition charges due to implementation or use of cogeneration systems, fuel cell and renewable energy technologies.

(Source: Regulations page of the DTE Website)

UTILITY STANDBY RATES:

Information on DG interconnection in Massachusetts can be found here. Each utility in the state must file an interconnection tariff with the Department of Public Utilities. Utility tariff's are based on uniform statewide interconnection standards, and must have charts showing the time frames for different steps in the interconnection process, along with potential fees.

Individual Utility Standby Rates

Massachusetts Electric Co (National Grid) - there is no standard standby rate. Customers seeking standby service would enter into a contract with the utility that specifies one of the regular rates to be billed under. Large facilities would be on primarily demand based rates. Rate available at: http://www.nationalgridus.com/masselectric/non_html/rates_tariff.pdf

Boston Edison Co (NStar) - Rate SB-G3 -

Rate SB-G3: Standby Delivery Service (rate per month, applies to the Boston area)
Customer Charge	A customer charge of $237.07 applies.
Distribution Charge	Winter Contract Demand < 1000 kW: $4.46, Summer CD < 1000 kW: $7.38
Distribution Charge	Winter Contract Demand >= 1000 kW: $6.25 Summer Contract Demand >= 1000 kW: $10.35
Transmission	No charge.
Transition	No charge.

Massachusetts

WHAT'S NEW:

AIR EMISSIONS REGULATIONS:

BUILDING, ZONING AND FIRE CODES:

EXIT FEES: