NECA Board of Directors 

C. John Meeske, President 

President 

Energy Market Decisions, Inc. 

Mary Beth Gentleman, V P., Policy 

Partner 

Foley Hoag LLP 

Frederick M. Sellars, V.P Administration 

Vice President 

TRC 

Mark C. Kalpin, Secretary 

Senior Partner 

Hale and Dorr LLP 

Keith H. Kennedy, Treasurer 

Vice President 

Tech Environmental, Inc. 

Lawrence W. Plitch, President Emeritus 

Principal 

McCauley & Plitch, LLC 

Scott 1 Mueller, President Emeritus 

Partner 

LeBoeuf, Lamb, Greene & MacRae, L.L.P. 

William C. "Jack" Sheehan, President Emeritus 

President, Managing Director 

Financial Managent Group, LLC 

Peter W. Brown, President Emeritus 

President and Member 

Brown, Olson & Wilson, P.C. 

Pentti J Aalto 

President 

PJA Energy Systems Design 

Scott M. Albert 

Principal & Northeast Region Manager 

GDS Associates, Inc. 

Thomas Atkins 

President 

Pinpoint Power LLC 

Theodore A. Barten, PE 

Managing Principal 

Epstlon Associates, Inc. 

John R. Bitter 

Principal 

Levitan & Associates, Inc. 

Chris Bursaw 

Manager, Regional regulatory Affairs 

USGen New England, Inc. 

Stephen H. Bryant 

President 

Bay Stale Gas Company 

Northern Utilities, Inc. 

Joseph Cavicchi 

Vice President 

Lexicon Inc. 

David Corrsin 

Executive Vice President 

Ameresco, Inc. 

Don C. DiCristofaro 

Manager, Energy and Air Engineering 

Earth Tech 

Michael D. Ernst 

Vice President 

TransEnergie U.S. Ltd. 

Roger D. Feldman 

Partner 

Bingham McCutchen LLP 

Robert G. Eraser 

Senior Program Manager 

ENSR International 

Ted Gehrig 

President & Chief Operating Officer 

Weaver's Cove Energy 

Andy Greene 

Principal 

Navigant Consulting Inc 

John Hanisch 

National Air & Energy Director 

Arcadis GAM 

John E. Higgins, Jr. 

Executive Advisor 

Concentric Energy Advisors, Inc. 

Shawn Konary 

Director, Environmental Affairs 

Mirant New England, L.L.C. 

Dennis Loria 

Principal 

R. W. Beck Inc. 

Mark Magyar 

Managing Director 

Energy Management Group 

James P. Sweeney 

President 

Cost Containment Inc. , 

Peter Zschokke 

VP Slate Regulatory Policy, US Transmission Co. 

National Grid USA 

NECA Administrative Director 

Lois W. Lawson 

Northeast Energy and 

Commerce Association 

1040 Great Plain Avenue • Needham, Massachusetts 02492-2517 

PHONE: (781) 449-5959 • FAX: (781) 449-8319 

E-MAiL:lois@necanews.org. WEB: www.necanews.org 

June 30, 2004 

Mr. Robert T. Donaldson, Associate Director 

Business Compliance Division 

Bureau of Waste Prevention 

Department of Environmental Protection 

One Winter Street, Eighth Floor 

Boston, MA 02108 

RE: Proposed Amendments to 310 CMR 7.00 and 310 CMR 70.00 

Dear Mr. Donaldson: 

The Northeast Energy and Commerce Association ("NECA") appreciates this 

opportunity to provide input into the Massaschusetts Department of Environmental 

Protection's ("DEP") proposed regulation changes for engines and turbines (310 

CMR 7.00 and 310 CMR 70.00). 

NECA is New England's oldest and most broadly based, non-profit trade 

association serving the competitive electric power industry. NECA promotes 

environmentally sound, reliable, and cost-effective wholesale and retail markets 

for the production and delivery of energy. NECA's diverse membership includes 

developers and owner/operators of competitive power projects, regulated and 

merchant transmission and distribution companies, power marketers and traders, 

fuel and equipment suppliers, power consumers, environmental consultants, 

attorneys, consulting engineers, and other service providers to the energy industry. 

NECA commends the DEP for the positive aspects of the proposed regulation. 

These include: (1) the streamlining of the permitting process for distributed 

generators through the proposed certification process; (2) accounting for and 

crediting unit efficiencies through the proposal of output-based standards; and (3) 

the exemption from the emissions limits provided for emergency generators and 

the proposal to revise the definition of emergency (the importance of which we 

detail at the end of this letter on pages 5 through 7). 

However, NECA has serious concerns with the heart of the proposed 

regulation, namely the extremely stringent "fuel and technology-neutral" 

emissions limitations proposed as the criteria for certification eligibility. 

While NECA understands mat the proposed regulation is based on the "Model 

Regulations for the Output of Specified Air Emissions from Smaller-Scale Electric 

Generation Resources" issued by the Regulatory Assistance Project ("RAP") in 
Mr. Robert T. Donaldson 

June 30,2004 

Page 2. 

late 2002, NECA believes that these model regulations are flawed and that their development did not 

include an open and valid stakeholder process. The Northeast States for a Coordinated Air Use 

Management ("NESCAUM"), the New York State Department of Environmental Conservation 

("NYSDEC"), and many others have not endorsed the RAP Model Rule. No states other than 

Connecticut have adopted regulations following the model rule and some (e.g., New York, New 

Hampshire) have developed or are developing quite different rules. In light of this, a detailed technical 

support document must be prepared by the Massachusetts DEP before proceeding further with this 

rule. This document should include an analysis of whether the proposed emission limitation can be 

achieved using best available control technology, the potential economic impact on industries operating in 

the Commonwealth, and the potential effect on the reliable operation of the regional electric power grid. 

Under the proposed -regulations an applicant for certain types of projects has the option to obtain an 

individual permit in lieu of the certification based on meeting the stringent limits. However, the mere 

promulgation of a regulation listing these stringent standards may pre-determine the Best Available 

Control Technology ("BACT") process required for such an individual permit. Thus, while NECA is in 

favor of fuel-neutral, output-based performance standards, we recognize that having such standards is not 

possible due to the inherent limitations of technology (which are reflected in the BACT-analysis process). 

In reality, the need for electric reliability and fuel diversification "trumps" the need for setting the 

extremely low emission limits currently proposed by the DEP, which only can be met based on the use of 

natural gas. No particular technology should be ruled out due to its limitations. Instead, less efficient 

and/or higher polluting technologies should bear an emissions fee burden, as discussed below, as an 

incentive to spur the development of more efficient and cleaner technologies. 

NECA has detailed comments in five areas related to the proposed regulations: (1) the availability of the 

Plan Approval option; (2) the proposed emissions standards for distributed generators; (3) efficiency 

considerations, (4) peaking versus base load considerations and an alternative "market-based" approach 

that would consider this; and (5) the definition of "emergency." 

Plan Approval Option 

It is vital that the Plan Approval option be available for all sources rather than limiting this option to a 

handful of source types. The proposed regulations allow engines or turbines to be operated as peaking 

power production units, load shaving units, units in an energy assistance program, units that produce 

mechanical power to run pumps, units to compress natural gas at a pipeline compressor station, and units 

burning landfill, digestor or other biogas to file for a traditional application for approval (e.g., a permit). 

These operations can have specific technical or economic considerations that should be considered on a 

case-by-case review. 

While NECA is encouraged that the Department apparently agrees with our earlier comments that this 

option is vital to the listed types of projects, NECA sees no reason not to allow this option for all 

applicants since each would be required to meet BACT criteria to the Department's satisfaction if the Plan 

Approval option is selected. Connecticut DEP has taken this approach in its recent distributed generation 

regulations. This would prevent the Department from being in the position of having to try to list in 

advance all categories that might in the future have very legitimate reasons why the certification criteria 

are impossible to meet for their particular cases. 
Mr. Robert T. Donaldson 

June 30, 2004 

Page 3. 

Proposed Emission Standards for Distributed Generators 

As detailed below, NECA recommends the following changes to the proposed emissions standards. 

• Increase the lower size threshold to 300 kW; 

• Include more achievable emissions standards for fuels for the first category of limits (installation 

after January 1, 2005) by providing for a fuel Best Available Control Technology ("BACT") 

analysis; 

• Eliminate the second and third categories of limits (installation on or after May 1,2008); 

• Raise the ammonia limit from 2 ppm to 10 ppm; 

• Work towards the development of a market-based approach by allowing an emissions fee system, 

such as a fee-based system similar to what New Hampshire has enacted or an allowance system, 

as an alternative to the emissions standards. Such a system would, by its nature, consider unit 

efficiencies and differentiate between heavy and light use (see next sections). 

Under the proposed changes to 310 CMR 7.00, the DEP is proposing very strict emissions standards for 

new distributed generators for non-emergency use. It is unlikely that any new diesel (liquid fuel) 

generators will be able to meet these proposed standards even with BACT. If owners and operators of 

small-scale diesel generators wish to use their units for non-emergency generation, the resulting 

applications for individual permits under 310 CMR 7.26 will cause an increased workload for the 

Department and negate the underlying purpose of the proposed regulatory revisions. The June 2003 

NESCAUM report "Stationary Diesel Engines in the Northeast: An Initial Assessment of the Regional 

Population Control Technology Operations and Air Quality Policy Issues" states: "stationary diesel 

engines are, by a large margin, the most commonly used engines for distributed generation." As the 

proposed distributed generator regulations are currently written, very few diesel (liquid fuel) distributed 

generator engines will be able to be in compliance without obtaining an individual permit, even if postcombustion controls were added.1 

The NESCAUM report indicates that selective catalytic reduction ("SCR") technology has been 

successfully applied to large diesel engines where it can achieve NOx reductions of 80-90% or more. 

However, these systems are more cost effective for large engines that operate frequently. Less costly NOx 

control strategies include injection-timing adjustments; generally provide more modest reductions on the 

order of 10-20%. Thus, there are no cost-effective controls available yet that will lower NOx emissions 

from smaller scale diesel engines or those that operate infrequently to the proposed levels. The use of 

SCR does not even guarantee that the proposed emission limits will be met.2 

1

 For example, using AP-42 emission factors, a 1-MW, 4-stroke lean-burn diesel (liquid fuel) engine has oxides of 

nitrogen ("NOx") emissions of more than 19 lbs/MWh which is more than thirty-one times the proposed standard of 

0.6 lbs/MWh for new DGs installed before May 1, 2008. The estimated PM emissions of 1 lb/MWh are higher than 

the proposed standard of 0.7 lbs/MWh. 

2

 A new 2-MW Caterpillar XQ2000SCR, 4-stroke diesel reciprocating engine with SCR that reduces NOx emissions 

by 90% will not meet the standards for new DGs - even though that engine currently represents BACT. The 

estimated NOx emissions from the engine with SCR which represents BACT are 1.9 lbs/MWh, which is three times 

the proposed standard of 0.6 lbs/MWh for new DGs installed before May 1, 2008. 
Mr. Robert T. Donaldson 

June 30, 2004 

Page 4. 

NECA can only support the proposed stringent standards during the first phase (units installed after 

January 1, 2005) if they become applicable only to natural gas firing and achievable limits are established 

for other fuels (e.g., by allowing a fuel BACT analysis) so long as the DEP establishes a market-based 

system in the near future.3 NECA also urges that the second and third phases of limits (effective in 2008 

and 2012) be eliminated since the ability of any new reciprocating engines or turbines to achieve these 

stringent limits in a cost-effective manner is highly speculative at this time. These limits become 

unnecessary if a market-based approach to regulating these sources is adopted within the next few years 

as recommended below. 

NECA also recommends that the lower size threshold for this regulation be set to 300 kW. Regulating the 

extremely small sources is unnecessary because their total emissions burden is minor relative to the 

significant administrative burden to both source owners/operators and the DEP. DEP's existing 

regulatory cutoff for these sources is approximately 300 kW and lowering this by almost an order of 

magnitude may lead to a number of potentially difficult procedural issues such as addressing these 

changes in the Title V operating permit program for the major sources. 

Combined Heat and Power Credit 

It is recommended that the regulations provide for an emissions credit in Combined Heat and Power 

(CHP) applications, provided that the proposed efficiency standard does not penalize some efficient 

systems while allowing other inefficient systems. CHP systems that save energy over conventional 

systems will meet the following formula: 

Echp"^"(Hchp*(Econv/Hconv)) ^ Econ v 

where EChp and HchP are electrical and heating efficiencies of CHP and Econ v and Hc0nv are efficiencies of 

conventional systems displaced. Econ v should instead be the marginal delivered efficiency for electricity, 

with a likely value of between 0.30 and 0.40. 

Alternative "Market-Based" Approach 

The regulations need to recognize the environmental differences between systems that operate frequently 

and those that only run occassionally. Expensive after treatments provide little environmental benefit in 

peaker systems when the peakers do not run. Cleaner systems should be encouraged to operate more 

frequently than dirtier systems. NECA believes that a market-based system could best address both the 

frequency of operation and the combined heat and power credit. 

Realizing that the development of a market-based approach may require a long lead time, NECA 

encourages the DEP to immediately work towards the development of a market-based system to replace 

these standards as soon as possible. As stated previously, as an interim measure while a market-based 

system is being developed over the next several years, NECA recommends that more reasonable fuelspecific standards be developed and added to the existing initial standards which would then be applicable 

3

 Included in these changes should be an alternative limit for all fuels of 10 ppm for ammonia instead of the 

proposed 2 ppm limit since this extremely stringent lower limit is simply neither practical nor necessary for these 

smaller sources of air pollution. 
Mr. Robert T. Donaldson 

June 30,2004 

Page 5. 

for natural gas only.4 These additional standards would be for sources installed on or after January 1, 

2005 firing fuels other than natural gas. 

One example of a "market-based" system that NECA recommends be considered is the emissions fee 

system that is being used by New Hampshire. As the NESCAUM report states: 

"innovative regulatory approaches can provide attractive alternatives to mandating costly 

retrofit controls. New Hampshire has introduced a program of emissions fees for small 

diesel generators. Fees are imposed per ton of NOx generated and are scheduled to 

increase over time. Similar incentive programs could be used to promote less polluting 

engines elsewhere, with resulting revenues applied to research, development and 

demonstration and to support available cleaner technologies. Another option would be to 

require distributed generators to obtain pollution allowances, especially where emissions 

budget and trading programs already exist." 

Charges under the New Hampshire emissions fee system range from $400 to $800 per ton of NOx 

emissions, depending on whether emissions occur during the summer ozone season, and are scheduled to 

increase to $500 to $1,000 per ton, respectively, in 2005. Small engines (i.e., those with NOx emissions 

below 5 tpy) and emergency generators are exempted. 

NECA recommends that Massachusetts consider a similar emissions fee system that would apply to 

generators used to meet economic demand response. Under such a plan, units with annual emissions in 

demand response mode exceeding a certain threshold would be subject to emissions fees. The fee would 

not be required for units that run during periods of emergency (including periods of OP-4, Action 12 or 

higher operations). 

Definition of Emergency 

The Independent System Operator for New England ("ISO New England" or "ISO"), the entity 

responsible for operating New England's bulk power system, has determined that electric load in parts of 

Massachusetts could exceed the capability of existing electric generating and transmission resources in 

the region. Under certain conditions, these existing resources may not be able to supply the load without 

overloading the lines or reducing voltage. In 2002, the ISO reported that two to four times per year the 

ISO was only one step away from shedding 50 to 100 megawatts ("MW") of load for as many as ten 

hours at a time. The Commonwealth needs to act immediately to ensure the continued reliability of 

power supply in Massachusetts. Without this reliability, Massachusett's economy and business climate 

will severely suffer. 

The DEP's intent to amend the definition of "emergency" to include situations when ISO New England 

declares Action 12 under NEPOOL Operating Procedure 4 ("OP 4") "Action During A Capacity 

Deficiency" or higher for a specified area is strongly supported. This will allow back-up generators to 

participate in ISO New England's 30-minute real-time demand response program (the "emergency" 

demand response program). OP 4, Action 12, as it is referred to, is the start of brownouts with the next 

4

 While the initial limits are extremely stringent even for natural gas-fired distributed generators, NECA can support 

them for natural gas fired applications above 300 kW in size with the important exception of ammonia. It is apparent 

that many applications would require SCR to achieve the NOx limit and 2 ppm ammonia slip is inappropriate for the 

size of generators being regulated here and does not represent BACT. NECA recommends 10 ppm for the ammonia 

standard. 
Mr. Robert T. Donaldson 

June 30,2004 

Page 6. 

step being involuntary interruptions of load. This declaration is taken very seriously by the ISO. In fact, 

even under the extreme weather conditions which occurred during the summer of 2002, the ISO did not 

declare OP 4, Action 12. Other than on August 15, 2003, in response to the major power failure that 

occurred throughout the Northeast, this level has rarely been declared - it is truly reserved for emergency 

situations. This declaration should not be confused with other ISO programs that are enacted for 

economic reasons (such as the ISO's price response program). 

OP 4, Action 12, as approved by the NEPOOL Participants Committee on June 26,2003, is: 

"Implement a voltage reduction of five percent (5%) of normal operating voltage 

requiring more than 10 minutes to implement. Interrupt Real-Time Demand Response -

30 Minutes or Less Notification (that requires a voltage reduction to be implemented)." 

NECA recommends that the DEP use language similar to the language that the Connecticut DEP has 

proposed in its proposed amendment to the definition of "emergency." This proposal has been through 

the public hearing process and is expected to be enacted on January 1, 2005. The proposed language that 

the Connecticut DEP has proposed in §22a-174-22(a)(4) that revises the definition of emergency is: 

"requires the operation of the emergency engine during the period of time in which the 

New England Region System Operator begins voltage reductions or involuntary load 

interruptions within the Connecticut load zone." 

This amendment does not explicitly use the term OP 4, Action 12 because the Connecticut State 

Implementation Plan Revision Advisory Committee ("SIPRAC") subcommittee of the DEP that drafted 

these proposed regulations was concerned that ISO may change the terminology in the future. Thus, 

language was used that describes OP 4, Action 12. It is not until OP 4, Action 12 that the ISO can 

implement voltage reductions. Further, the definition does not even identify the ISO-New England - but 

rather uses the New England Region System Operator terminology instead - to account for any future 

reorganization or renaming of that entity. 

We do not believe the language that the DEP proposes in its revisions to 310 CMR 7.00 is adequate. 

Specifically, the proposed language: 

"Emergency shall also mean when the imminent threat of a power outage is likely due to 

failure of the electrical supply or when capacity deficiencies result in a deviation of 

voltage from the electrical supplier to the premises of three percent (3%) above or five 

percent (5%) below standard voltage." 

should be replaced with the following language that combines the Massachusetts proposed language 

along with what the Connecticut DEP is using: 

"Emergency shall also mean when the imminent threat of a power outage is likely due to 

failure of the electrical supply, such as when the operation of the emergency engine is 

required during the period of time in which the New England Region System Operator 

begins voltage reductions or involuntary load interruptions within the Massachusetts load 

zone(s)." 

The modified definition of "emergency" should apply to all new and existing sources, whether they are 

permitted by rule or by an air plan approval. All emergency engines should be treated consistently. Thus, 

the existing air regulations for emergency engines as regulated by permit by rule need to be amended so 

that the definition of "emergency" also applies to existing emergency engines located at facilities with 

existing air plan approvals. Thus, the modified definition of "emergency" will be consistent; otherwise, 

the DEP will have to modify every air plan approval that has been issued for emergency engines. 
Mr. Robert T. Donaldson 

June 30,2004 

Page 7. 

A report prepared by Synapse Energy Economics, Inc. for the Environmental Protection Agency ("EPA") 

entitled "Results of Demand Response Emissions Modeling" by Geoff Keith, Bruce Biewald, David 

White and Mike Drunsic dated August, 2003 and revised September 4, 2003, assesses the impacts of 

demand response ("DR") and energy efficiency programs in New England using an electric system 

dispatch model.5 As the report states, "when the DR resource is used to meet reserve requirements, the 

result is more efficient unit commitment, reduced operation of oil- and gas-fired steam units and increased 

operation of combined-cycle units in New England." Even assuming all DR is from diesels, the report 

showed a net benefit in air quality. Thus, by changing the definition of "emergency", more DR resources 

will provide the necessary reserve capacity and regional air quality should actually improve. 

As noted in the Synapse report, "New England has a small amount of quick-start capacity relative to the 

regional peak load compared to most other control areas. Many analysts have noted that this requires 

large power plants to operate more than they would otherwise have to in order to maintain sufficient 

operating reserves - capacity that can be provided quickly in response to unplanned losses of capacity. A 

key goal of this work for EPA was to verify that large units were indeed being operated more than 

necessary in New England to meet reserve requirements, to gauge the probable emission impacts of this 

dynamic, and to estimate potential emission reductions that additional DR could provide if it were used to 

meet operating reserve requirements." 

Summary 

NECA is supportive of the Department's efforts to foster the development of improved combustion and 

pollution control technologies that would lower emissions of air pollutants and improve air quality in the 

Commonwealth. However, the ensuing requirements cannot be so stringent that the Commonwealth's 

stated goals of promoting new technologies, increasing the availability of renewable energy, ensuring the 

reliability of the electrical supply system, and improving environmental quality are not realized. NECA 

hopes that the Department will recognize the importance of reliability and the role of fuel diversity in 

promoting reliability. NECS hopes the Department will give further consideration to NECA's proposal. 

We are confident that through such a deliberative process the appropriate balance that is needed in this 

instance can be realized to the ultimate benefit of the environment and the regulated community alike. 

5

 A hypothetical near-term year in New England using projected 2006 fuel prices and loads was modeled. The 

modeling included 500 MW of DR capability: 60 percent load response and 40 percent generation. The emissions 

impacts when DR is used for reserves results in significant decreases of criteria pollutant emissions, even when it is 

assumed that the DR used to meet reserves is all diesel (e.g., summer air impacts include: NOx decreases 23 tons, 

sulfur dioxide decreases 216 tons, carbon dioxide decreases 31,400 tons, particulate matter 2.5 microns or less 

decreases 12.5 tons, particulate matter decreases 21.2 tons and mercury decreases 0.29 tons). 
Mr. Robert T. Donaldson 

June 30,2004 

Page 8. 

In advance, thank you for your consideration of our comments. 

Sincerely, 

C. John Meeske 

President 

Northeast Energy and Commerce Association 

cc: Ellen Roy Herzfelder, Secretary, EOEA 

Stephen Pritchard, COO, EOEA 

Robert W. Golledge, Jr., Commissioner, DEP 

Paul G. Afonso, Chairman, DTE 

W. Robert Keating, Commissioner, DTE 

David L. O'Connor, Commissioner, DOER