Mechanisms 2.0 Study Base Case Results


Dated: November 17, 2016

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Renewable and Clean Energy Scenarios and Mechanisms 2.0 Study  

Base Case Results

November 17, 2016

[download PDF for accompanying slide presentation]

The New England States Committee on Electricity (NESCOE) retained London Economics International (LEI) to conduct modeling in connection with NESCOE’s Renewable and Clean Energy Scenarios and Mechanisms 2.0 Study (Study).  The Study’s “Base Case” results are attached.  The Base Case is one element of LEI’s modeling that will be included in a larger report currently under development.

The Base Case represents the status quo.  The Study will include similar analysis that looks at a range of hypothetical or “what if?” scenarios, and a directional comparison of those futures against the status quo.  The Base Case and the hypothetical scenarios are informed by assumptions, many or all of which history may prove wrong.  For example, due to its timing, the Base Case does not include clean energy resources recently selected for contract negotiation in the New England Three-State Clean Energy Request for Proposals or the Connecticut section 1(B) procurement.[1]  The Base Case is also based on “snapshot in time” assumptions regarding proposed natural gas pipeline projects without the ability to predict their path to operation.  The Study is not predictive or precise and should not be interpreted as such.

This brief memo summarizes and provides important caveats about the Base Case results.  This includes information on the Base Case: 1) forecasted costs (energy, capacity, wholesale load), 2) resource mix and market dynamics (existing resources and new resources), and 3) state policy requirements (carbon emissions and renewable resources).

Summary:  Under Base Case assumptions, the total costs to wholesale load in the years 2025 and 2030 remain within a recent historical range, but increasingly reflect rising capacity costs.  The resource mix is similar to the current generation fleet: remaining coal retires and new entry is mostly natural gas, wind, and solar photovoltaic (PV).  Under Base Case assumptions, the region exceeds power sector carbon dioxide emissions targets and renewable resource additions are inadequate to achieve current Renewable Portfolio Standard (RPS) targets.

Forecasted Costs:

  • Energy: Forecasted energy market prices are closely related to assumed natural gas prices. This is due to the continued dominance of natural gas-fired generation in the regional fleet in 2025 and 2030.  On a seasonal basis, winter natural gas prices affect energy prices more than the summer peak demand for electricity.  In the Base Case, forecasted annual average energy prices in 2025 and 2030 are in the $48-51/MWh range, compared to 2015 actual annual average energy prices of $45/MWh.[2]  For reference, assumed natural gas prices, on an annual average basis, are $5.60/mmBTU in 2025 and $6.31/mmBTU in 2030, compared to 2015 actual annual average natural gas prices of $6.10/mmBTU.[3]
  • Capacity: In the short term, capacity market prices are likely to be set by existing resources. By 2025, capacity prices are forecasted to converge on the assumed net cost of new entry, and rise to the $11.50-13/kW-month range.  For comparison, the most recent capacity auction for 2019-2020 cleared at $7.03/kw-month.[4]
  • Wholesale Load Costs: The estimated cost to wholesale load, calculated as the sum of modeled energy and capacity market costs, in 2025 is $10.8 billion (energy $6.0b plus capacity $4.8b) and in 2030 is $ 11.9 billion (energy $6.3b plus capacity $5.6b). For reference, actual wholesale market costs in the years 2008 to 2015 have ranged from $6.4 billion to $14.0 billion.[5]  In the Base Case, the ratio of energy to capacity costs in 2025 and 2030 is approximately 55% to 45%.  In 2015, the actual ratio of energy to capacity costs is 84% to 16%.[6]

 Resource Mix and Market Dynamics

  • Existing Resources: Capacity revenues represent the majority of profits for natural gas- and oil-fired generators. In contrast, energy revenues represent the majority of profits for nuclear and renewable resources.  By 2025, all of the existing coal-fired generation is forecasted to economically retire.  Based on LEI’s estimates of net going forward fixed costs and other assumptions, existing nuclear resources remain economically viable through the study period.

Importantly, the modeling is based on assumptions identified, not on facts or resource owners’ business judgment.  In this study, nuclear resources’ forecasted economic viability is likely influenced by several factors: (1) assumed natural gas prices, (2) LEI’s approach for estimating so-called “missing money” (i.e., forecasted revenues from the wholesale markets minus estimated going forward fixed cost estimates) and (3) limitations of the approach taken to model the energy market.  Assumed natural gas prices are relatively moderate on an annual average basis, $5.60-$6.31/mmBTU, despite seasonal price volatility ranging from $3.48 to $12.16/mmBTU in 2025, for example.  LEI applies principles of economic theory in developing its resource type-specific net going forward fixed cost estimates, which do not include so-called “avoidable costs.”  LEI’s modeling output showing continued nuclear economic viability does not include several financial considerations: return on equity; FCM performance risk; or potential significant capital expenditures.  LEI’s energy market model is not configured to simulate negative energy prices in New England.

  • New Resources: New resources are a mix of modeled natural gas (62%) and assumed renewables (38%).[7] The assumed resources are 168 MW solar photovoltaic (PV) resources and 925 MW of on-shore nameplate wind resources.  These assumed resources are added by 2025.  Transmission system limitations inhibit further on-shore wind development in 2025 and 2030.  Over the study period, the capacity market model adds 2,000 MW of natural gas-fired resources to maintain resource adequacy.

 State Policy Objectives

  • Carbon Emissions: Power sector carbon dioxide emissions are forecasted to be 26.8 million tons in 2025 and 25.2 million tons in 2030.[8] For reference, 2015 actual power sector carbon dioxide emissions were 30.8 million tons.  Compared to the 2020 Regional Greenhouse Gas Initiative (RGGI) aggregate carbon dioxide cap for the six New England states at 26.4 million tons, the Base Case indicates that some in-region resources may need to procure additional RGGI allowances or carbon offsets for compliance.[9]
  • Renewable Resources: Due to transmission system limitations,[10] comparative resource economics,[11] and without an increase in renewable energy imports,[12] the region is forecast to be under-supplied with Renewable Energy Certificates (REC) relative to Renewable Portfolio Standard (RPS) targets in:
  • 2025 by 2.1 TWh, or 10.5% of Class 1 targets
  • 2030 by 3.9 TWh, or 17.0% of Class 1 targets[13]

Result Caveats and Interpretation Notes

Forecasted Costs:

  • The modeling results are based on a host of assumptions. These assumptions influence which resources are dispatched, when and for how long, and, importantly, the prices at which resources produce energy and supply capacity. With time and hindsight, almost all of the assumptions may be proven wrong and may affect the models’ forecasts in either direction to varying degrees.
  • The energy and capacity market models are a simplified representation of the wholesale electricity markets and regional transmission system. The forward looking modeling was completed on the basis of certain assumptions which may not capture all possible operational conditions in the real world. In the model, generator availability is consistent with annual averages, the weather is always normal, and the load forecast is invariably accurate.  Such a simplified representation of these markets may understate prices and emissions.[14]

Resource Mix and Market Dynamics:

  • Resource retirements and new entry are based on simulated capacity market outcomes, which are primarily driven by: (1) estimated net going forward fixed costs and (2) forecasted energy market revenues.[15] Net going forward fixed costs for existing resources include fixed operations and maintenance costs; debt repayment expenses; and selling, general, and administrative expenses.  All other costs (return on equity, as one example) are not included in existing resources’ capacity market offers. Such other costs and financial considerations will be relevant to market participants. Exclusion of certain going forward costs from the analysis may overstate an existing resource’s willingness to remain in operation.  This would delay new entry and its associated impacts on energy and capacity prices and power sector emissions. Under- or over-estimated energy market revenues may delay or accelerate, respectively, some resource retirements.
  • The model assumes that all market participants have a similar financial risk tolerance. This may not accurately reflect the diversity of risk tolerance among various market participants.  Therefore, modeling results may under- or over-state a market participant’s willingness to continue operations with an under-performing resource.

Policy Objectives:

  • The model does not explicitly limit power sector air emissions. The modeling incorporates a price on carbon dioxide emissions based on current RGGI allowance secondary market prices, escalated at an assumed rate of inflation that essentially keeps carbon prices flat in real dollar terms.  The price on carbon dioxide emissions, on its own, does not limit the amount of power sector air emissions.  Given New England’s resource mix, especially the amount of natural gas-fired generation, assumed carbon prices are unlikely to affect merit order in the dispatch.[16]  A higher carbon price assumption (and all other assumptions held constant), while likely to influence prices, is unlikely to affect the region’s power sector air emissions totals.[17]
  • LEI’s renewables development outlook and perspective on transmission system limitations directly influence the supply of RECs. LEI assumes that due to transmission system limitations, and other factors, the region may be under-supplied with RECs over the study period.  The Base Case assumptions about the status quo lead to this result.  To the extent the Base Case assumptions regarding renewable technology costs, energy production capabilities, and penetration are wrong, the supply of RECs may be closer to RPS targets.

Document Source Citations

[1]           For more information, see  and$FILE/2016.10.27_FINAL Small Scale Selection Notice.pdf.

[2]           See 2015 Report of the Consumer Liaison Group (“2015 CLG Report”), at Table 3 on page 34, available at

[3]           See U.S. Energy Information Administration, natural gas city gate prices, available at  Assumed natural gas prices are the result of LEI’s Levelized Cost of Pipeline model.  For reference, the 2016 NEPOOL Economic Study assumed natural gas prices are consistent with the U.S. Energy Information Administration’s 2016 Annual Energy Outlook, which are $5.40/mmBTU in 2025 and $5.57/mmBTU in 2030.

[4]           See ISO New England Key Grid and Market Stats, available at

[5]           2015 CLG Report.

[6]           In 2015, actual energy and capacity costs were $5.9 billion and $1.1 billion, respectively. 2015 CLG Report.

[7]           Capacity addition percentages are based on nameplate MW.

[8]           Emissions results are expressed in short tons. Declining aggregate emissions in the Base Case are a function of: the declining ISO-NE long-term load forecast for energy (net of energy efficiency and solar PV), improving fuel efficiency of the generation fleet (new entry lowers system average heat rate),

[9]           The emissions results presented below include a small contribution from resources that are not subject to RGGI.  For example, resources < 25 MW are not currently subject to RGGI.  Estimating the carbon dioxide emission contributions of these resources is beyond the scope of the Study.  ISO-NE economic analysis for NEPOOL suggests that an additional 2 to 5 million tons per year may be emitted by the class of resources not subject to RGGI.

[10]          In the Base Case, transmission system enhancements are limited to the reliability-related upgrades that are currently in-process.  LEI added on-shore wind resources to the model’s northern Maine zone until the installed capacity equaled the transfer limit out of the zone.

[11]          Based on estimated renewable resource capital costs, LEI assumes that Alternative Compliance Payments are likely more economic than AC transmission system enhancements and other scalable RPS-eligible technologies.

[12]          The Base Case assumes that recent levels of imported renewable energy persist through the study period.  See National Renewable Energy Laboratory’s 2015 analysis, Quantifying the Level of Cross-State Renewable Energy Transactions, available at  An increase in imported renewable energy may help address such a forecasted shortfall of RECs, but should be considered within the context of New York’s Clean Energy Standard proposal to provide incentives for existing renewable resources that currently export to New England.

[13]          Class 1 Targets are defined as the sum of: Connecticut, Maine, and Massachusetts Class I; New Hampshire Class 1 and 2; Rhode Island New (including recently enacted H.B. 7413); and Vermont’s Distributed Generation carve-out.  These totals are estimated to be 20.1 TWh in 2025 and 22.9 TWh in 2030.

[14]          For more information, see Base Case Results slide 22.  LEI analysis indicates that approximately 5% of the highest priced hours may not captured in the modeling.

[15]          LEI retires resources when net going forward fixed costs exceed energy and capacity market revenues for three consecutive years.

[16]          See generally Base Case Results slide 10.

[17]          To the degree that higher energy prices resulting from higher carbon allowance prices increased existing resources’ energy market revenues, some existing resource retirements may be delayed.  The impact of potential delays in resource retirements could affect regional air emissions totals in either direction, depending on the emissions profile of the retiring resource(s) and any corresponding new entry.