Study Summary

On November 18, 2015, the Massachusetts Attorney General’s Office released a study, Power System Reliability in New England:  Meeting Electric Resource Needs in an Era of Growing Dependence on Natural Gas (Study).  The Study was undertaken by Analysis Group, Inc., and evaluates options to address regional electricity reliability in New England, including new natural gas capacity, through 2030.

The Study was designed, broadly, to answer two questions:

  • Could the region experience power system "deficiencies"—periods during peak winter demand when the electric system may not be able to meet peak electric demand?
  • If any such deficiencies are identified, what is the full suite of practical options for maintaining power system reliability, particularly during winter months, and including, but not limited to, electric ratepayer funding for natural gas infrastructure?

The Study found that, under existing market conditions (status quo), there is no electric sector reliability deficiency through 2030, and that no additional pipeline gas capacity is needed to meet electric reliability needs.  Existing market conditions constitute a base case projection over the next fifteen years that anticipates continuing increased reliance on dual-fuel units (natural gas- and oil-fired generation) and accounts for the declining long-term forecast of winter peak demand.

The Study also modeled whether deficiencies would occur under certain stressed conditions. The Study assumed a scenario in which New England becomes even more reliant on natural gas power than expected, and experiences a short-term disruption in other fuels—causing the electric system to be more stressed than expected on very cold days. Under these stressed conditions, the region could need about 2,400 MW for a few hours on a few very cold days (around 9 days) by 2029/2030. This is the energy-equivalent of an additional 0.42 billion cubic feet per day (Bcf/d) of new gas capacity, beyond any capacity that could be built to serve gas customers. That amount is equal to about one-third of the Northeast Energy Direct (NED) project, and 40 percent of the Access Northeast Project.

"Solution sets" were modeled to meet that 2400 MW deficiency at peak winter demand arising under the stressed conditions:

  • Reliance on incremental dual fuel-power plants (the status quo);
  • Increased reliance on firm liquefied natural gas (LNG);
  • Additional natural gas pipeline capacity totaling 0.42 Bcf/d (0.3 Bcf/d or more by 2024, with 0.12 Bcf/d added by 2029);
  •  Incremental energy efficiency and demand response (EE/DR), installed above and beyond currently planned programs;
  •  EE and winter-firm imports of low carbon energy on existing transmission; and
  •  EE and winter-firm imports of low carbon energy on new transmission.

Solution sets were evaluated for cost effectiveness and ability to meet regional greenhouse gas emissions (GHG) reduction targets, compared to the status quo "market outlook," represented by greater reliance on dual-fuel units. Results are shown in the figure below.

Solution set results demonstrate that:

  • Investment in EE/DR will result in the greatest customer savings and substantial GHG emissions reductions.
  • Building new gas pipeline capacity sized to meet the deficiency is more expensive than the EE/DR solution, and increases regional GHG.
  • The LNG solution would yield some savings, and would be the lowest cost to implement, but has a negligible effect on GHG emissions reductions.
  • Saving ratepayers less than the EE/DR solution, but more than the pipeline solution, the EE and winter-firm imports on existing transmission solution offers the greatest GHG emissions reductions.
  • The EE and winter-firm imports on new transmission solution offers equivalent large emissions reductions, but does not result in savings, and, in fact, costs about $100 million more than the status quo, due to the cost of constructing new transmission.
  • Both of the EE plus transmission solutions factor in the relatively high cost of contracting for firm hydro during the winter months.

Importantly, none of the solution sets modeled places us on a trajectory to meet regional climate commitments, though the EE/transmission solutions come close. The chart below shows the potential Regional Greenhouse Gas Emissions Initiative cap (dotted line) out to 2030 (the current cap does not extend beyond 2020), compared to solution sets (dual-fuel and LNG track pipeline emissions quite closely and are not shown).

To further understand the effect of building a larger pipeline or a larger new clean import transmission project on electricity prices (not solely reliability) two larger infrastructure scenarios were also modeled. These infrastructure scenarios are distinct from the solution sets due to their size and/or timing of availability. In the case of the pipeline, it would deliver 0.5 Bcf/d, an amount of energy greater than the 2400 MW (0.42 Bcf) deficiency, and come on line for the 2020/21 winter—earlier than any identified deficiency emerges in the model. In the case of the transmission project, while sized the same as the solution sets (2400 MW), it would come on line earlier, in 2020. Results are shown in the table below.

The larger pipeline saves nearly as much as the EE/DR solution set ($133 million and $146 million in annual savings, respectively), but results in greater GHG emissions over the status quo than any other option analyzed—an increase of 0.2 million metric tons (MMT), or 200,000 tons per year. The transmission infrastructure scenario results in the highest cost, but also would produce the largest GHG emissions reductions, 6.65 MMT annually.

AGO Regional Electric Reliability Options Study Report  pdf format of AGO Regional Electric Reliability Options Study Report

Study Overview

On July 6, AG Healey announced that her office would commission a timely regional study to identify and evaluate options to address electricity reliability needs, including natural gas capacity demand, in New England through 2030 (“the Study”).

The Study will include an evaluation of all potentially available energy resource options to meet reliability needs, including natural gas (both natural gas pipelines and LNG), oil, hydro imports, energy efficiency, demand response, and renewables.  The Study will provide an assessment of costs and benefits, including price impacts, of each option, consistent with the region’s energy and climate goals.

The Study will also focus on those options that will allow the region to meet applicable greenhouse gas emission reduction requirements.

Given the recent announcement of the Pilgrim Nuclear Generating Station's retirement no later than mid-2019, and after considering the input of the Study Advisory Group, AGO and Analysis Group concluded that, in the interest of clarity and completeness, the goals of the study would best be served by re-running the modeling with a 2019 Pilgrim retirement date.  This will push back the study release date to mid-November.

Study Advisory Group and Members

The Study Advisory Group is a “modeling sounding board” comprised of various stakeholders to give feedback and input to Analysis Group, Inc. on the study design, solution sets, data sources, and assumptions. Participation in this exercise by Study Advisory Group members does not signify their endorsement of any findings or conclusions contained in the final report, and they may disagree with inputs, analysis, and observations set forth in it.


            Melissa Hoffer, Chief, Energy & Environment Bureau
            Rebecca Tepper, Deputy Chief, Energy & Environment Bureau
            Paul Brennan, III, Special Counsel for Energy Policy

MA Executive Office of Energy & Environmental Affairs
Michael Altieri, Attorney, DOER

Acadia Center
            Peter Shattuck, Director, MA Office

Associated Industries of Massachusetts
            Robert Rio, Senior Vice President & Counsel – Government Affairs

Conservation Law Foundation*
            Greg Cunningham, VP & Director – Clean Energy Climate Change

Environmental Defense Fund*
            N. Jonathan Peress, Air Policy Director – Natural Gas

            James Daly, Vice President – Energy Supply

LNG Importers
            Tony Scaraggi, Vice President of Operations, GDF Suez

National Consumer Law Center, Inc.
            Charlie Harak, Attorney

National Grid Massachusetts
            Marcy Reed, President

Northeast Clean Energy Council
            Janet Besser, Vice President of Policy and Governmental Affairs (alternate)
            Peter Rothstein, President

New England Power Generators Association, Inc.
            Dan Dolan, President

Northeast Energy Efficiency Partnerships, Inc.
            Sue Coakley, Executive Director

Northeast Gas Association
            Thomas Kiley, President & CEO

            Cynthia Arcate, President and CEO

The Regulatory Assistance Project
            Richard Sedano, Principal and US Program Director

Retail Energy Supply Association
            Marc Hanks, State Electric Caucus Vice-Chair

(*) Shared Seat