Analysis of Pennsylvania Nuclear
Plants
and Available Policy Alternatives

PREPARED BY:
Andrew G. Place
Commissioner, Pennsylvania Public Utility Commission
Hayley Book
Advisor to Pennsylvania Public Utility Commission Commissioner
Andrew G. Place
Eric Matheson
Advisor to Pennsylvania Public Utility Commission Commissioner
Andrew G. Place

March 6, 2019

 The analysis herein is solely that of those preparing this report and does not reflect the
position of any other Commissioner or of the Pennsylvania Public Utility Commission as a
whole.

Table of Contents
Executive Summary.................................................................................................... 1
Pennsylvania’s Nuclear Fleet...................................................................................... 2
Three Mile Island..................................................................................................... 2
Beaver Valley........................................................................................................... 3
Impact on Nuclear Generation Resulting from PJM Capacity and Energy Markets
Reforms................................................................................................................... 4
Nuclear Options for Pennsylvania............................................................................... 6
Option 1 - No State Intervention..............................................................................6
Option 2- Replace Nuclear Retirements with Renewables and Energy Efficiency....8
Option 3a – Expand AEPS Act to Include a Nuclear Generation Tier......................10
Option 3b – New Tier, wherein other resources qualify..........................................11
Option 4 – Zero Emission Credit Program..............................................................11
Option 5 – Establish a Carbon Market....................................................................12
Option 5a - Establish a Carbon Market for Pennsylvania....................................12
Option 5b – Link with the Regional Greenhouse Gas Initiative (RGGI)................13
Option 5c – Establish a PJM-wide Carbon Market................................................14
Option 5d – Participate in a National Carbon Market..........................................14
APPENDICES............................................................................................................. 15
Appendix A............................................................................................................ 15
PJM Capacity and Energy Market Reforms.............................................................15
Appendix B............................................................................................................ 17
Cost Impact of Nuclear Plant Retirements on Regional Power Markets..................17
Appendix C............................................................................................................ 18
Impact of Nuclear Retirements on the Reliability of Power Markets......................18
Appendix D............................................................................................................ 20
RGGI Summary...................................................................................................... 20
Appendix E............................................................................................................ 23
Summary of Illinois Nuclear Legislation.................................................................23
Appendix F............................................................................................................ 25
1

 Summary of New Jersey Nuclear Legislation.........................................................25

Executive Summary
Pennsylvania has the second largest nuclear capacity of any state in
the nation, with nine nuclear units, at five locations throughout the state.
Exelon Generation, and FirstEnergy Corp, the respective owners of three
of these units, Three Mile Island Unit-1 and Beaver Valley Units 1 and 2
have announced the premature retirement of these plants. Though PJM,
the regional grid operator, indicates that the retirement of Beaver Valley
and Three Mile Island will not impact the reliability of the electric grid,
there may be additional infrastructure investments needed if Beaver
Valley closes. Also, these nuclear plants represent a significant portion of
Pennsylvania’s carbon free generation, the loss of which would result in a
backsliding of air quality in Pennsylvania. The question remains how to,
or if at all to, intervene to prevent the premature closure of these two
plants.
Experts agree that single unit reactors such as TMI are uneconomic,
and industry and plant specific data validate this conclusion. However,
the conclusions around the economics of Beaver Valley are less
straightforward. Some studies indicate that Beaver Valley is economic,
and that the closure of TMI may not necessarily be followed by additional
nuclear power plant closures.
Nevertheless, though the extent of closures is debated, there is a
substantive risk of the loss of some carbon free generation in
Pennsylvania. This paper outlines the reasons for the energy
transformation in Pennsylvania and offers market analysis and impacts of
potential solutions.


Pennsylvania nuclear generation plants provide 39% of PA’s electricity
generation. TMI and Beaver Valley account for 26% of this nuclear
generation.



Single-unit reactors, such as TMI, are at an economic disadvantage and will
continue to be in the future.



If TMI were to retire prematurely no new network transmission upgrades
would be required. However, Beaver Valley, should it retire in 2021, will
require an acceleration in an estimated $182 million in incremental
transmission investments.



PJM’s recent analysis indicated that even with the announced retirements the
PJM system is reliable today and will remain reliable into the future.

2

 

If energy efficiency goals were increased by 1% of statewide usage per year,
the lost emissions reductions for each plant could be replaced in 5 and 11
years, respectively.



At the current annual rate of increase in Alternative Energy Portfolio Standard
(AEPS) Act Tier 1 resources, it would take Pennsylvania 12.6 years to replace
the lost carbon free electricity from TMI, and an additional 28.4 years to
replace Beaver Valley.1

1 The AEPS Act provides for an annual increase in clean Tier 1 resources of 0.5% of
total Pennsylvania electricity consumption through 2021. Legislative amendments
to the Act would be required to extend this annual increase post 2021.
2

 Pennsylvania’s Nuclear Fleet
Pennsylvania is the second largest nuclear capacity state in the nation, with 9
operating nuclear units, at 5 locations throughout the state, with a cumulative
installed capacity (ICAP) of approximately 10.1 GW.2 From a portfolio perspective,
this represents 23% of Pennsylvania’s generation capacity, and 39% of its electric
generation.3 Pennsylvania’s nuclear unit information is as follows:
Unit Name Operator
# Units
Location
County
ICAP, MW
Beaver Valley
FirstEnergy 2
Shippingport Beaver
1,845
Limerick
Exelon
2
Limerick
Montgomery 2,326
Peach Bottom
Exelon
2
Peach Bottom
York
2,526
Susquehanna
Talen Energy 2
Salem
Luzerne
2,568
Three Mile Island Exelon
1
Middletown Dauphin
818

Of Pennsylvania’s five nuclear plants, only 2 plants (3 units) in Pennsylvania
have informed PJM of their intent to deactivate: Exelon’s Three Mile Island (TMI) and
FirstEnergy’s Beaver Valley, which collectively account for 2.7 GWs, or 26% of
Pennsylvania’s nuclear capacity.
Some caveats are in order here with regard to the discussion below on
individual plant economics. These cost and revenue estimates reflect system
average operating and capital costs. Individual plants may be above or below
industry average costs. However, the analysis by Monitoring Analytics (MA), PJM’s
Independent Market Monitor (IMM), does not reflect declining operating costs
consistent with historical industry trends. Instead, the IMM assumes constant costs.
Also, any individual plant could have a pending and significant capital expenditure
that may alter its own situation relative to its peers in the short term.

Three Mile Island
Three Mile Island (TMI) entered commercial service in 1974 and Unit-1 is
currently 100% owned by Exelon Nuclear. The adjacent Unit 2 — shut down in 1979
after the partial meltdown that put the brakes on the nation's nuclear program — is
owned by FirstEnergy Corp. Final cleanup of the damaged Unit 2 reactor awaits the
retirement of the surviving unit. In August of 2015 Exelon announced that TMI was
among its plants that failed to clear the 2018-2019 Base Residual Auction (BRA), not
qualifying for capacity payments from PJM (the regional transmission organization
that operates the transmission grid) typically a relied upon revenue source for
2 EIA Form 860, weighted average of summer and winter capacity ratings.
3 2017 Pennsylvania State Infrastructure Report, May 2018.
3

 baseload generation. On May 30, 2017, PJM was notified by Exelon that it was going
to deactivate the TMI nuclear power plant by September 30, 2019. 4 Subsequently,
Exelon has indicated that it will deactivate this plant on schedule absent “needed
policy reforms”, with a final decision date of May 2019, due to critical refueling
investments that are required to avoid full shutdown in September 2019.
In several forums, Exelon has indicated that the TMI plant is uneconomic
based on current PJM market prices. Further, TMI has not cleared in the last four
BRAs in PJM’s capacity market, thus losing a substantial and important revenue
source to support its operations.5
TMI is a single-unit plant which is costlier to operate compared to the multiunit sites. While statistics from the Nuclear Energy Institute indicate costs are 22
percent higher at single-unit plants, 6 an independent economic analysis performed
by the IMM 7 indicated that it may be 38% more costly. Many of the reactors slated
for early retirement nationwide are, likewise, single-unit plants. On May 24, 2017,
Exelon disclosed that TMI has lost $300 million over the last five years 8.
The IMM’s analysis of TMI in its October 2018 State of the Market Report, confirms
that TMI is currently economically challenged. Single unit nuclear plants, without
any pricing of their carbon free attribute, are not currently economic in PJM markets,
and are projected to remain uneconomic for the next three years, even if they did
procure a capacity commitment. Per the IMM’s analysis, TMI lost approximately
$100 million between 2012 and 2016, but that assumes TMI cleared the capacity
auction every year. To the extent TMI did not clear the capacity auction, the losses
would have been higher. IMM’s analysis projected that losses will continue through
2021 at TMI, even if the plant did clear in the capacity auction, which it hasn’t.

4 Unit-1 is licensed by the U. S. Nuclear Energy Regulatory Commission to operate
until 2034.
5 Exelon Press Release, May 24, 2018
6 For the purposes of this analysis, operating costs were estimated at $30.89/MWh
for a double unit plant, and $42.66/MWh for a single unit plant,
7
http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018q3som-pjm-sec7.pdf, pages 327-332.
8 https://www.philly.com/philly/business/energy/nuke17-headline-here20170914.html.
4

 Projected annual losses for TMI average $54 million per year with capacity
revenues, and $86 million per year without capacity revenues.
Projected losses, however, are highly sensitive to energy prices in PJM. For
example, in 2018, the actual average energy price for the year at the TMI pricing
node (wholesale pricing location) was $31.76/MWh 9, relative to the projected TMI
price of $31.36 used in the IMM analysis – very close to that projected by the IMM,
but 17%, or $4.64/MWh, higher than in 2017, and $8.08/MWh higher than in 2016.
Therefore, losses in 2016 and 2017 were much higher. Even so, if TMI had cleared
the capacity market in 2018, it would still have lost $32 million. Having not cleared
in the capacity market, however, estimated TMI losses were $73 million in 2018.
Generally, every $1/MWh increase in wholesale energy prices increases generation
revenues by $7 million.
Exelon will have additional refueling costs this year. A decision to shut down
operations must be made by the end of May or beginning of June 2019, in order to
avoid shut down in September 2019 as announced by the Company due to required
advanced contracting and ordering of parts and labor.

Beaver Valley
Unit 1 and Unit 2 at Beaver Valley were commissioned for service on July 2,
1976 and November 17, 1987, respectively. On March 28, 2018, FirstEnergy
Solutions Corporation (FES) announced that it plans to retire its Perry and DavisBesse plants in northern Ohio and the Beaver Valley plant located in Western
Pennsylvania by 2021. On May 24, 2018 FirstEnergy confirmed that these three
nuclear generation plants did not clear in the 2018 BRA in PJM’s capacity market for
the 2021-2022 delivery year.10 On August 15, 2018, FES took its next step towards
the closure of these nuclear power plants, filing plans related to their
decommissioning with the U.S. Nuclear Regulatory Commission (NRC). Beaver
Valley Power Station Unit 1 is licensed to operate until 2036 and Unit 2 is licensed
through 2047. According to the NRC letter dated April 25, 2018, FES plans to close
Unit 1 on May 31, 2021, and Unit 2 on October 31, 2021. 11
Beaver Valley is a dual-unit plant. The IMM analysis does not demonstrate
that the plant is uneconomic nor does it confirm a strong and sustained need for
economic assistance. Market revenues dipped in 2012 and 2016, causing the plant
to have a slight estimated operating loss in those two years. However, in all other
9 https://www.pjm.com/-/media/committees-groups/committees/mc/20190122webinar/20190122-item-06a-markets-report.ashx, slide 3.
10 S&P Global Market Intelligence, May 24, 2018.
11 https://www.nrc.gov/docs/ML1811/ML18115A007.pdf.
5

 years, and all projected years, Beaver Valley is projected to be profitable by the
IMM. Projected average profits were $96 million per year, if the two units clear in
the capacity market, and $23 million per year if they don’t clear, for the 2018-2021
period. Using the actual Day Ahead average Locational Marginal Price (LMP)
applicable to the nuclear plant, Beaver Valley’s 2018 profits would be estimated at
$173 million, as actual energy prices were significantly higher than forecasted.
Beaver Valley profits are highly sensitive to energy prices. Every $1/MWh increase
in annual average energy prices for Beaver Valley results in an increase in gross
profits of $15 million.

Impact on Nuclear Generation Resulting from PJM Capacity and Energy
Markets Reforms
Recent and pending reforms in PJM capacity, energy and reserve markets
have, and will continue to have, a substantial impact on the profitability of nuclear
power plants. As an example, it was noted earlier that some of these nuclear units
did not clear in the PJM capacity market. This is a relatively recent market
phenomenon, that coincides with both lower projected natural gas prices and
changes in PJM’s capacity market power mitigation rules. Lower natural gas prices
can explain why single unit plants may have challenging economics under current
PJM market constructs. Lower natural gas prices also lower LMP (energy prices) to
such an extent that single unit reactors are economically challenged.
However, an additional contributor to nuclear units not clearing in the PJM
capacity markets may be PJM’s reforms to capacity market power mitigation
mechanisms. When PJM implemented its Capacity Performance product that
imposed higher penalties for non-performance during peak system usage
conditions, such as during cold winter or hot summer days, it also weakened the
capacity market power mitigation rules to allow a unit to bid above its actual costs
in the capacity market. Therefore, a nuclear unit may not clear in the BRA, and not
receive capacity payments, if a generator believed that overall revenues would still
be higher for its fleet of generation by pushing capacity prices higher. Thus, if a unit
does not clear in the capacity market this does not mean it is uneconomic.
Another pending capacity market reform is the Minimum Offer Price Rule
(MOPR). Recently filed MOPR reforms could have the effect, on one hand, of
increasing capacity prices to offset the potential price suppressive impacts of
subsidized generation in PJM markets. This would have a positive impact on nonsubsidized nuclear units. On the other hand, MOPR reforms may force a subsidized
resource, such as some nuclear generation units in Illinois and New Jersey, to obtain
capacity market payments outside of PJM markets, and could impose further penalty
payments on subsidized units. This would negatively impact nuclear units that
receive out-of-market revenues, such as Zero Emission Credits (ZECs).

6

 Other energy and reserve market reforms pending before the Federal Energy
Regulatory Commission (FERC), or to be filed in March 2019 should have a positive
effect on nuclear generation by increasing energy prices. This will shift market
revenues from capacity markets to energy markets – which will benefit nuclear
units.
As baseload generation units, nuclear plants derive most of their revenues
from energy markets. Appendix A will provide further insight into each of these
reforms.
In summary, PJM has, and continues to actively pursue, reforms in capacity
and energy markets which should enhance earnings of nuclear power plants.
However, some reforms, such as the MOPR reforms, may impose penalties on
nuclear units that receive out-of-market subsidies, such as ZECs.

7

 Nuclear Options for Pennsylvania
Option 1 - No State Intervention
At present, only one single-unit nuclear power plant, TMI, is clearly
uneconomic in current and projected future PJM markets. Beaver Valley was
profitable in 2018 and is projected to be profitable in the 2019-2021 period, based
on average industry costs, and current market price projections. If FirstEnergy does
not render capacity offer bids sufficient to clear in PJM capacity markets, its profits
are significantly reduced – close to breakeven based on the IMM analysis. Absent
further cost support for further out-of-market payments for Beaver Valley, it appears
that the loss of zero-emissions generation may be limited to TMI under this
scenario.
If there is no state intervention, Pennsylvania’s competitive market policies,
which have helped attract considerable investment in new natural gas generation,
in particular, would remain undisturbed.
Annually, Pennsylvania’s nine nuclear plant units produce roughly 82,000
GWh of carbon free electricity, which equates to about 34 million tons of avoided
CO2 annually at the 2017 PA average generator plant emissions rate of 816
lbs./MWh,12 and approximately 39 million tons of avoided CO 2 at the PJM average
generator plant emissions rate of 950 lbs./MWh. 13 Collectively, this represents 41%
of the PA electric generator emissions of 81.9 million tons in 2017 at the
Pennsylvania emissions rate. TMI alone accounts for 3.2 million tons of avoided CO 2
at the PJM average emissions rate, which is 3.4% of total 2017 generator emissions
in Pennsylvania. TMI and Beaver Valley combined account for 10.3 million tons of
CO2 at the PJM average emissions rate, which is 11.1% of total 2017 generator
emissions in Pennsylvania of 81.9 million tons.
It may not be proper to use average Pennsylvania or PJM emissions in
estimating avoided emissions rates. A more accurate method of estimating
average avoided emissions rate would be to model emissions through scenario
analysis. This is beyond the scope of this paper. However, a rough estimate could
be attained by substituting new combined cycle natural gas (CCNG) generation as a
rough proxy for nuclear plant retirement scenarios, as this reflects all of the recent
baseload generation construction in PJM. One study by the European Joint Research
Center determined an emissions rate of post 2010 CCNG units of 344 g CO2/kWh, 14
12 https://www.eia.gov/electricity/state/pennsylvania/.
13 PJM, 2017 Pennsylvania State Infrastructure Report, May 2018.
8

 which converts to an emissions rate of 758 lbs./MWh. This is not significantly
different from the 2017 Average PA Emissions rate.
Pennsylvania’s AEPS Act Tier 1 resources will provide an estimated 10,729 GWh of
carbon free electricity per year by 2021, or roughly 13% of the carbon free
electricity of nuclear plants. Thus, the loss of the entire fleet of nuclear plants in
Pennsylvania would be a substantial step back in reducing carbon emissions in the
Commonwealth. However, as noted above, only one plant is clearly uneconomic
(TMI), and one plant is currently “on the bubble” (Beaver Valley). TMI provides an
estimated 6,665 GWh per year of carbon free electricity, or about 2.7 million tons of
avoided CO2. Beaver Valley provides about 15,034 GWhs of carbon free electricity,
or about 6.1 tons of avoided CO2, using Pennsylvania’s average generator plant
emission rate. If AEPS Tier 1 growth requirements were extended at the current
annual rate of increase in AEPS Act Tier 1 resources of 0.5%, it would take
Pennsylvania 12.6 years to replace the lost carbon free electricity from TMI, and an
additional 28.4 years to replace Beaver Valley.15
In conclusion, if the policy choice is to prevent backsliding on carbon
emissions this is not a very viable option.
Another consideration with regard to nuclear plant retention is the cost of
regional transmission investment required to sustain reliable network transmission
service. PJM has evaluated these deactivation notices and found that TMI
retirement will require no new incremental network transmission upgrades.
However, Beaver Valley, should it retire, will require an estimated $182 million in
incremental transmission investments if the two units retire in 2021. 16 The effect of
this would be to accelerate these transmission projects relative to the retirement of
Beaver Valley #1, coincident with its current license expiration in 2036. Accounting
for the alternative of a later investment, escalation of transmission costs 17 and the
net present cost of this later transmission investment, 18 the alternative current cost

14 Green House Gas Emissions from Fossil Fuel Fierd Power Generation Systems, M.
Steen, DG-JRC/IAM, European Joint Research Center,EUR 19754, p. 19/61,
https://pdfs.semanticscholar.org/d666/1a01ee6a54f86fad283e4650e1074c795b7b.p
df.
15 The AEPS Act provides for an annual increase in clean Tier 1 resources of 0.5% of
total Pennsylvania electricity consumption through 2021. Legislative amendments
to the Act would be required to extend this annual increase post 2021.
16 Assumes all costs are allocated to Pennsylvania customers. Some costs
associated with PJM projects b3006, b3017.1, b3017.2 and b3017.3 will, however,
be allocated to other states in PJM.
9

 is approximately $114 million. Thus, the true net cost of transmission investment
today, versus tomorrow, is an estimated one-time net present cost of $68 million. 19
As more fully described in Appendix B, cost impacts related to regional power
markets largely hinge on whether nuclear generation will be replaced by new
combined cycle natural gas units. Historical trends support this as a very likely
scenario. As such, cost impacts of the retirement of TMI and Beaver Valley are likely
to be insubstantial.
Lastly, concerns have been raised about the potential for impacts to the
reliability of regional power markets. A thorough study of the impacts of announced
nuclear retirements in Pennsylvania concluded that the PJM system can withstand
an extended period of stress while remaining reliable. Even in an extreme scenario,
such as an extended period of severe weather combined with high customer
demand and a fuel supply disruption, the PJM system would remain reliable. Details
of this study are described in Appendix C.

Option 2- Replace Nuclear Retirements with Renewables and Energy
Efficiency
Clearly nuclear plants play a substantial role in carbon emission abatement.
Replacement of this lost abatement could be achieved, but only after a number of
years, as roughly quantified above. However, strategies, or a combination of
strategies, could significantly reduce the time required to replace the emission free
generation of nuclear plants at lower projected annual costs than retaining TMI. For
example, expanded Act 129 energy efficiency; AEPS Tier 1 program extension; or
Tier 1 expansion coupled with utility scale renewable energy procurement, through
enablement of community solar programs.
Tier 1 incremental projects are largely dominated by regional wind
development (45.9% of Tier 1 retired AECs in 2017). Other significant Tier 1
resources include wood/wood waste solids, Landfill gas, and Low Impact Hydro. The
17 See PPI industry data for Electric bulk power transmission and control, not
seasonally adjusted, Series Id: PCU221121221121, Years:2009 to 2019, data run
February 26, 2019. Average escalation rate for transmission was 4.5% per year.
18 Net Present Value calculations assume an internal cost of capital of 7.78%, based
on a debt cost of 5.25%, ROE of 10.3% based on the MAIT Settlement, and a 50%
equity ratio.
19 $182-$114 million.
10

 current market price is $6/MWh.20 Tier 1 resources can be in-state or out-of-state.
Based on the 2017 AEPS report, approximately 19% of certified Tier 1 wind
resources were in-state. Using current owner/operator in-state solar AECs as a
reference cost of replacing TMI generation, the cost would be $233 million per year
at $35/MWh.21 Using a lower cost resource, such as Tier 1 resources, including wind,
would cost $40 million per year at $6/MWh. Using the work of the IMM, the cost of
recovering going forward costs at TMI would lead to a subsidy estimated at $60
million per year, assuming the unit cleared in the capacity auction, and slightly over
$90 million per year, assuming the plant receives no capacity revenues. Again, TMI
has not cleared in the last four capacity auctions. In short, while Tier 1 renewable
resources could replace TMI zero-emission generation at a lower cost, it would take
a substantial amount of time at current Tier 1 growth targets, as noted prior, to
effectuate this replacement, absent an expansion of AEPS requirements.
Using similar parameters for Beaver Valley, using the reference cost of small-scale
current owner/operator in-state solar AECs of $35/MWh, the cost would be $526
million per year.22 A lower cost resource, such as Tier 1 resources, including wind,
would cost $90 million per year at $6/MWh. Per the IMM analysis, Beaver Valley is
earning sufficient revenues to cover its costs going forward. However, actual plant
operation and capital costs for FirstEnergy may be above industry average costs, or
there may be additional one-time capital spending required that is not reflected in
these nuclear industry statistics used by the IMM.
The analysis above is limited to the AEPS structure as it exists today. However,
other potential legislative options could include Community Solar and procurement
of new utility scale solar and wind generation. Community Solar solutions help
drive down the cost of distributed energy systems by expanding virtual net
metering to non-owner/operator systems. This enables the build out of larger solar
facilities and captures greater economies of scale. Lower costs of these systems
are supported by underlying industry cost data. 23 Average installed solar capital
costs for 2018 were $3.7/watt DC for residential systems, $3.1/watt DC for small
20 Spectrometer US Environmental Report, February 22, 2019, for year 2019.
21 Spectrometer US Environmental Report, February 22, 2019, for year 2019.
22 Some large solar projects are in the development process that could lower these
prices should they bid into AEC markets, including the 70MW Community Energy
Solar facility under development to be operated by Adams Solar LLC in Adams
County, Pennsylvania.
23 LBNL, Tracking the Sun, Installed Price Trends for Distributed Photovoltaic
Systems in the United States - 2018 Edition, September 2018.
11

 commercial systems less than 500 kw, and $2.2 /watt DC for larger systems
between 500 kw and 5,000 kw.
Long term utility scale solar and wind procurements might also offer
opportunities. Recent procurements by the Illinois Power Authority (IPA) provide
insight into the lower cost of utility scale solar and wind procurements. Prices for
four recent utility scale long-term procurement for solar Renewable Energy
Certificate (REC) auctions between September 2017 and December 2018 ranged
from $4.26/MWh to $6.07/MWh. A long-term procurement auction held on August
31, 2017 for Wind RECs resulted in an average price of $4.26/MWh. During these
15 months, 4,000 GWhs per year of solar and wind electricity were procured by the
IPA, or roughly 60% of TMI’s emissions-free generation.
An additional source of carbon abatement is energy efficiency. Under Act
129, the Commonwealth will be reducing electricity use by 5,710 GWhs over a 5year period, or just slightly below the emissions reduction impacts of TMI. These
reductions were based on annual reductions in usage in the range of 0.5% per year
to 1% per year, depending on the Electric Distribution Company (EDC). Each 1%
usage reduction is the equivalent of 1,348 GWh per year. Thus, emissions
reductions of TMI and Beaver Valley could, in theory, be replaced by incremental
energy efficiency investments. For example, if energy efficiency goals were
increased by 1% of statewide usage per year, the loss of the zero-carbon generation
from these plants could be replaced in 5 and 11 years, respectively. Energy
efficiency has no net cost to consumers. Net positive benefits have been observed
for every year during implementation of the Act 129 Energy Efficiency and
Conservation Act.24
In summary, Existing Tier 1 resources currently offer a lower cost solution to
replacing emissions-free generation from TMI. Small scale distributed solar projects
authorized under the AEPS Act are currently not a lower cost solution to TMI.
However, at current rates of annual resource growth under the AEPS Act, it will take
a number of years to replace both TMI and Beaver Valley emissions-free electricity.
Energy efficiency also presents a “net benefits” solution to replacing emissions free
generation, but also will take a number of years to replace both nuclear units.
Other solutions, however – expansion of our existing AEPS and Act 129 energy
efficiency programs, additional procurement of utility scale renewable resources
such as wind and solar, and enablement of Community Solar programs - can be
both cost effective and accelerate the replacement of emissions-free generation
from nuclear plants.
24
http://www.puc.state.pa.us/filing_resources/issues_laws_regulations/act_129_informa
tion/act_129_statewide_evaluator_swe_.aspx; see annual reports and end of phase
reports.
12

 Option 3a – Expand the AEPS Act to Include a Nuclear Generation Tier
A new AEPS tier could be created to acknowledge the carbon free attribute of
in-state nuclear generation – for example a “Tier Z”, with an annual quantity equal
to approximately 82,000 GWhs (the current approximate quantity of Pennsylvania
annual nuclear generation).
Establishment of a Tier Z could certainly ensure that no nuclear plants in
Pennsylvania retire. However, without constraints, the market for Tier Z Alternative
Energy Credits (AECs) would be highly concentrated and, unavoidably, without
attributes of a competitive market.
If the policy goal is to retain all Pennsylvania nuclear plants, based on the
IMM analysis, the Tier Z AEC price would need to be about $9/MWh if the unit
cleared in the capacity market, and $13.62 per MWh without the help of capacity
market revenues. Total market costs would range from $700 million to over $1.1
billion per year.
If, however, a Tier Z approach were designed to retain all nuclear plants other
than TMI, the estimated cost could be significantly reduced. Should the legislature
desire to provide further funds to all remaining Pennsylvania nuclear plants,
establishing a price based on the AEC costs of Tier 1 resources is one approach.
Using a current AEC cost for Tier 1 resources of $6/MWh, this would provide
additional funds of $453 Million to Pennsylvania nuclear plants other than TMI.
However, as stated before, it has not been established that these plants require
additional funding to recover going forward costs outside of PJM markets.
These out-of-market payments would also subject Pennsylvania customers to
potential MOPR Minimum Offer Price Rule (MOPR) capacity market premiums and
costs, depending on the outcome of the current PJM FERC filing. There is also
residual legal risk in the execution of such an approach. Pennsylvania’s competitive
market policies, which have historically helped attract considerable infrastructure
investment in generation, may result in less investment going forward due to
market intervention by the state.
Options to mitigate the cost impacts to rate payers of a Tier Z approach,
include:
1. Limit the quantity of Tier Z requirements to units that can substantiate
economic need (New Jersey – Option 4), and
2. Impose a Market Price Index adjustment to Tier Z credit rates to ensure
that rate payers do not over-subsidize plants when wholesale electricity
market prices rise (Illinois), and

13

 3. Credit any excess profits back to rate payers, during periods of very high
market prices.

Option 3b – New Tier, Wherein Other Resources Qualify.
Another approach would be to create a new zero-emissions “Tier Y” category
open to all zero-emissions resources, including existing Tier 1 resources under the
current AEPS. This sets the value of carbon at the market cost of the marginal
emissions-free resource based on the quantity of Tier Y resources established under
the legislation.
Advantages of a such a program, in theory, is that competition by other
resources would exert some level of discipline on Tier Y prices. The challenges of
such a construct is that nuclear plants are very large sources of power. Market
prices for Tier Y resources would be very volatile, as the supply/demand balance
could shift substantially if even one nuclear power plant retires. It could take a
number of years for market prices to stabilize – absent some type of additional
market intervention (i.e. administrative price caps or Tier Y quantity adjustments).
It is also not clear that a Tier Y approach would retain TMI. This approach would
also provide additional funds to nuclear units which are already profitable. Lastly,
other, more cost-effective resources, such as energy efficiency or low (but not zero)
carbon resources would not be receiving an appropriate price signal.

Option 4 – Zero Emission Credit Program
A targeted nuclear support program could be legislated which strictly
funneled financial support to those plants that can demonstrate a long-term
financial need for out-of-market payments to compensate the nuclear unit for its
environmental and health benefits, similar to the New Jersey legislative approach.
Applicants for a subsidy would need to demonstrate and disclose financial need,
operational fitness, meet certain performance metrics, and be responsible for PJM
market non-performance penalties.
Under the New Jersey ZEC legislation, it is asserted that the zero emission
certificate program set forth in its act is structured such that its costs are
guaranteed to be significantly less than the social cost of carbon emissions avoided
by the continued operation of selected nuclear power plants, ensuring that the
program does not place an undue financial burden on retail distribution customers. 25
New Jersey may impose a retail cost of $0.004 per kilowatt-hour on the bill of retail
customers which reflects the emissions avoidance benefits associated with the
25P.L. 2018, CHAPTER 16, approved May 23, 2018, Senate, No. 2313, Section 1. b.
(8) of the Act.
14

 continued operation of selected nuclear power plants 26, which is roughly equivalent
to $4 per MWh.
The advantages of this approach are that financial support could be
individually targeted to minimize out-of-market payments required to support only
at-risk nuclear plants. ZEC payments, based on the IMM analysis of TMI, are
estimated to be $60-$90 million per year, depending on whether or not the unit
cleared in the PJM capacity markets. Payments to Beaver Valley would be based on
any additional financial information provided in support of the proposed need.
This would reasonably ensure, if that were the desired policy goal, that no nuclear
plants in Pennsylvania would retire and that the benefits of these zero-carbon
resources would be uninterrupted. However, a ZEC program would shield the
nuclear plants from competition, thus there may be reduced incentives for efficient,
lowest cost operations. This could also disadvantage other carbon free resources,
such as energy efficiency, large-scale solar and wind, or low carbon resources which
may be more cost effective in the long run, relative to certain nuclear plants.
Again, with this option, a ZEC qualifies as an out-of-market payment which
would subject Pennsylvania customers to potential MOPR capacity market premiums
and costs, depending on the outcome of the current PJM FERC filing. There is also
residual legal risk of execution of such an approach. 27 Pennsylvania’s competitive
market participants, which have helped attract considerable infrastructure
investment in new generation historically, may invest less going forward due to
market intervention by the state.

Option 5 – Establish a Carbon Market
There is currently no recognition of the cost of carbon emissions in the PJM
markets, or, for that matter, in Pennsylvania. PJM markets do not recognize the cost
of carbon emissions explicitly, other than through the RGGI states of Maryland and
Delaware, and going forward, New Jersey and Virginia. 28 Energy efficiency
investments in Pennsylvania under Act 129 do not incorporate the cost of carbon
into the cost/benefit calculations. Illinois’ Public Act 99-0906, otherwise known as
the Future Energy Jobs Act, lists an explicit social cost of carbon emissions as an
26Section 3. j. (1) of the Act.
27 Elec. Power Supply Ass’n v. Star, 2018 WL 4356683 (7th Cir. 2018); Coalition for
Competitive Elec, et al. v. Zibelman, 2018 WL 4622696 (2nd Cir. 2018).
28 The clean energy attribute value of RGGI state resources will be reflected in the
bid offers of generators into energy markets in those RGGI states.
15

 appropriate valuation of the environmental benefits provided by zero emission
facilities (ZECs). The Social Cost of Carbon was determined by Illinois to be $16.50
per MWh, which is based on the U.S. Interagency Working Group on Social Cost of
Carbon's price in the August 2016 Technical Update using a 3% discount rate,
adjusted for inflation for each year of the program. 29
A number of carbon market models exist, including a regional market-based
greenhouse gas reduction program like RGGI, or engaging Congress to adopt a
national carbon market, develop a state compact for a PJM wide carbon market, or
supporting a Pennsylvania only carbon market, as in California.

Option 5a - Establish a Carbon Market for Pennsylvania
One variation of a carbon market approach is to establish a Pennsylvania
carbon market, as California is implementing. Pennsylvania has existing authority
to regulate carbon as a pollutant. Either this or a legislative approach could be used
to establish a carbon price or market in Pennsylvania. Such a market would have
most of the same advantages and disadvantages of RGGI. It would provide more
state control of all design elements of the carbon market.
The challenges of this approach are the potential for competitive industry
inequities across more state borders and greater carbon price volatility. Any such
proposals would need to address these additional issues. PJM has not yet developed
a method of state border price adjustments to ensure fair competition between instate and out-of-state carbon emission generators. This issue will be taken up again
in 2019, per PJM management. A PJM border adjustment mechanism, however,
would not address competitive commercial and industrial customer inequities.
California’s carbon allowance market price is currently valued at $17.15 per
metric ton of CO2.30 This translates into an electricity market price of $6.3 to $7.4
per MWh based on the 2017 average generator emissions rate in Pennsylvania and
PJM, respectively.

Option 5b – Link with the Regional Greenhouse Gas Initiative (RGGI)
Linking with RGGI would provide several benefits including providing an
additional boost to Pennsylvania’s four dual-unit nuclear power plants – likely
sufficient enough to keep these units profitable. However, it would be insufficient to
keep TMI from being retired at current carbon market prices. Current RGGI market
prices for carbon are approximately $5.30/short ton, which, when applying the 2017
29 Illinois’ Public Act 99-0906, Section 1-75, Subsection (d-5) (B) (i).
30 A metric ton is 2,204.62 lbs.
16

 system average PJM emissions rate of 950 lbs./MWh, is equivalent to $2.50/MWh.
As an example, each $1/MWh increase in LMP adds about $15 million to the bottom
line of Beaver Valley. With that said, the impact on LMPs from the inclusion of a
carbon price into energy market offers (specifically, the particular carbon price
adder to the energy bid by the marginal plant) requires detailed modeling to
reasonably project localized pricing impacts to Pennsylvania electricity consumers.
RGGI provides member states with flexibility in how carbon revenues are
remunerated, including returning revenues to customers, reinvestment in energy
efficiency or renewable energy programs, or low-income assistance programs.
Participation in RGGI would place Pennsylvania’s residential, commercial, and
industrial customers on par with other member states; create a larger more stable
regional market for carbon; internalize the cost of carbon across both producers and
consumers of electricity; incent more efficient investment of capital than other
support mechanisms; while maintaining Pennsylvania’s commitment to competitive
markets by providing a price signal.
The net cost to consumers is likely to be minimized under such a carbon price
mechanism, while carbon credit revenues may be returned to customers and
businesses to further mitigate cost or competitive industry impacts.
A “Border Adjustment” wholesale market pricing mechanism has not been
developed by PJM to ensure fair competition from non-RGGI states within the PJM
RTO, as noted above. Absent such a “Border Adjustment” mechanism, further
modeling would be required to measure the negative impact to Pennsylvania
natural gas generation, and most notably, coal related businesses. A PJM state
compact, wherein other states, such as Ohio, Indiana and Illinois agreed to link to
RGGI could also address this inequity in wholesale electricity competition, as well as
impacts to competitive commercial and industrial businesses.

Option 5c – Establish a PJM-wide Carbon Market
An extensive state compact that established a carbon price for all PJM states
would provide a more cost-efficient solution to carbon emissions abatement. Such a
mechanism could address a meaningful level of competitive inequities across
electricity markets, and commercial and industrial businesses relative to other
options, such as a state-level carbon price, or RGGI membership. Carbon markets
allocate resources efficiently across all market sectors, including all generation, load
reduction (energy efficiency, and demand response), and carbon capture
investments.

17

 Option 5d – Participate in a National Carbon Market
Of course, a national carbon market would be the most efficient solution for
achieving carbon emission goals. It would also resolve most competitive industry
inequities, other than imported goods, which would otherwise need to be addressed
by tariffs or similar adjustment mechanisms. However, while most competitive
market inequities are resolved by a national carbon market, such legislation is
unlikely to render TMI economic.

18

 APPENDICES
Appendix A
PJM Capacity and Energy Market Reforms
Capacity Performance Market Reforms: When implementing its Capacity
Performance reforms, PJM permitted units to bid into capacity markets at the higher
of actual going forward net costs, or the Net Cost of New Entry (NetCONE) of the
reference Combustion Turbine (CT) unit.31 This NetCONE value is substantially
above historical capacity prices in PJM. Since capacity markets have been found to
be uncompetitive, this reform essentially enabled units to exert market power in
capacity markets by bidding some units as high as NetCONE, thus altering the
supply/demand balance in the Regional Transmission Organization (RTO) region, or
subzone, and raising prices for capacity through economic withholding strategies.
In this context, a nuclear plant owner could bid into the capacity markets with its
nuclear unit(s) at above cost, thus not clearing the nuclear unit(s) in the forward
capacity auction, but otherwise raising the capacity cost for the remainder of its
generation fleet. Though capacity market payments can be an important part of
baseload generation, a unit not clearing in the capacity market does not by itself
mean a unit is uneconomic.
Minimum Offer Price Rule (MOPR): PJM has recently filed a revision of its
Minimum Offer Price Rule (MOPR) proposal.32 On the one hand, PJM filed a plan to
isolate subsidized resources, like some nuclear plants in Illinois and New Jersey,
from the capacity market, by creating a Resource Carve-Out (RCO) mechanism.
This mechanism essentially ensures that subsidized resources clear in the capacity
market by being bid in at a capacity price of zero in Step 1, of the auction, therefore
allowing non-subsidized units to set the capacity clearing price. However, in
tandem with this RCO filing, PJM also filed an Extended Resource Carve-Out
(Extended RCO) mechanism, which included a second step in the capacity auction
process that removes the RCO units from the bid stack and reprices the capacity
market without removing any demand from the market. Thus, higher cost non-RCO
units, that didn’t clear in the original auction, would set the capacity market
clearing price. In addition, the RCO units would need to pay these non-clearing
31 PJM asserted that higher non-performance penalties would raise opportunity
costs of committed units to the level of NetCONE. However, the persistent level of
excess capacity has resulted in no Capacity Performance penalties since
implementation. Thus, the theoretical foundation for reforming the market power
mitigation rules has not transpired in actual practice. PJM has no plans to
reexamine these assumptions
32 FERC Docket No. EL18-178-000.
19

 generation units on the margin in Step 2 the difference between the final clearing
price in Step 2, and the bid offers from the higher cost non-RCO units, thus imposing
an additional cost barrier to nuclear units seeking RCO status. In summary, the
Extended RCO proposal would result in higher capacity prices paid to all generation
resources that cleared in Step 1 of the auction and impose a penalty on RCO units
paid to marginal units didn’t clear in Step 1 but set the price in Step 2 of the
auction. Ultimately, it will be electricity customers that will pay the costs resulting
from PJM proposals. A FERC decision on the PJM filing is anticipated sometime in
March 2019.
Operating Reserve Demand Curve Reform: PJM has recently announced its
intent to file with the Federal Energy Regulatory Commission (FERC) its Operating
Reserve Demand Curve reforms in March 2019, which, when co-optimized with LMP,
were last projected to increase energy prices by 7.3%. 33 For TMI and Beaver Valley,
this 7.3% increase, this translates into an estimated $15 million and $34 million per
year in additional energy revenues, respectively. The actual impact related to these
reforms may vary, depending on FERC’s actions on these future filings, regional
price variations, and changes in market behavior of existing or new market
participants.
Recategorization Inspection and Maintenance Costs: PJM has already filed to
eliminate a current restriction that prevents sellers of energy from Combined Cycle
Natural Gas and Combustion Turbine plants from including inspection and overhaul
(I&O) costs in their energy market offers, as opposed to including these costs in
capacity market offers today. Such a change is likely to increase energy market
costs, and, over time, decrease capacity market costs. PJM has not quantified the
impact of this change. I&O costs embody a substantial percentage over overall
inspection and maintenance costs of these units. This could be a meaningful
increase in energy prices.
Fast Start Resources Proceeding: Lastly, FERC issued an order requiring RTOs,
like PJM, to file modifications to allow generation units that have a minimum run
time of one hour or less to include commitment costs of these fast-start resources
(start-up and no-load costs) to be reflected in (energy) prices. 34 PJM is arguing for a
different measure of what constitutes fast-start resources (defining those as having
a start-up time of two hours or less and a minimum run time of two hours or less,
instead of 1 hour). PJM has not quantified the impact of this change on energy
market revenues, but the impact should increase energy market revenues, and,
33 https://www.pjm.com/-/media/committees-groups/taskforces/epfstf/20181214/20181214-item-05-simulation-results-summary-priceformation-proposal.ashx. Slides 6 and 10.
34 Docket No. EL18-34-000, Issued December 21, 2017.
20

 over time, decrease otherwise applicable capacity prices, which will benefit nuclear
profitability.

21

 Appendix B
Cost Impact of Nuclear Plant Retirements on Regional Power Markets
A number of dueling cost impact studies on the loss of nuclear power in
Pennsylvania have been undertaken. A 2016 study by The Brattle Group 35
concluded that Pennsylvania consumers would pay $788 million more annually
(2016$) and $6.6 billion more over the next ten years (on a present value basis)
without these plants. This study appears to assume that all nuclear plants in
Pennsylvania close, and assumes that only a small amount of this generation is
replaced by new natural gas plants in Pennsylvania, thus, transforming our state
from a strong exporter of power (24%), to a moderate importer of power (12%).
Such assumptions are not well supported. Pennsylvania is the second largest
producer of natural gas in the nation, and, as such, has a strong foundation for
being a dominant source for replacement power for any shuttered nuclear plants.
A recent analysis by Seth Blumsack,36 found that capacity and energy prices would
increase only in the case where Beaver Valley and Three Mile Island were to shut
down without replacement. The net impact on electricity costs in Pennsylvania thus
depends on the pace at which gas-fired capacity enters the market as nuclear
capacity is exiting the market. While future market outcomes are uncertain, this
paper illustrates the impacts of different gas generation build scenarios on
ameliorating the impacts of nuclear retirements. The analysis concludes that the
impact on Pennsylvania ratepayers over a three-year period, assuming that both
Beaver Valley and Three Mile Island retire at the same time, would range from an
electricity cost increase of $400 million in the scenario where nuclear deactivations
are not replaced by any new capacity, to an electricity cost decline of nearly $500
million in the scenario where a large gas generation build-out more than
compensates for lost nuclear capacity. 37
At a very high level, nuclear units are not on the margin in PJM energy
markets. They currently contribute nothing to LMP at the margin of PJM energy
markets. Rather, coal and natural gas prices are the underlying drivers for PJM
35 The Brattle Group, Pennsylvania Nuclear Power Plants’ Contribution to the State
Economy, December 2016.
36 The Electricity Journal 31 (2018) 57-64, Impacts of the retirement of the Beaver
Valley and Three Mile Island nuclear power plants on capacity and energy prices in
Pennsylvania, Seth Blumsack, Energy Policy and Economics, John and Willie Leone
Family Department of Energy and Mineral Engineering, Pennsylvania State
University, State College, PA, United States.
37 Blumsack at 64.
22

 energy markets.38 As noted by Blumsack, the rate of generation unit replacement of
nuclear units is the key factor in future energy markets.
Underlying announcements of new generation plants in PA support scenarios
wherein any nuclear power plants decommissioned would very likely be replaced
mostly by new, efficient combined cycle natural gas power plants, many of which
would be developed in-state, and, to a lesser degree, renewable resources related
to state Renewable Portfolio Standards (RPSs). In short, it is not clear that the
retirement of these two nuclear power plants in Pennsylvania will have a significant
impact on PJM power prices under today’s resource environment.

Appendix C
Impact of Nuclear Retirements on the Reliability of Power Markets
Overall, Pennsylvania is a strong net exporter of electricity generation, with
41.5 GW of generation, and a peak day usage of 29.6 GW, the largest in the United
States. As of December 31, 2017, 9.6 GW of additional generation capacity was
under construction in Pennsylvania.39 Summer peak load growth for the PJM RTO is
projected to increase very modestly, with an average 0.3% per year increase over
the next 10 years, and 0.4% increase over the next 15 years. 40 Given these supply
and demand fundamentals, Pennsylvania is anticipated to continue to have
adequate generation, and continue in its role as an exporter of power to the PJM
RTO. However, reliability is ensured by PJM on a regional level. On this level, the
transmission system and the level of generation are currently in a very reliable state
relative to historical infrastructure build.
PJM recently performed an analysis to test the resiliency of its system to
severe system stresses and concluded that the PJM system is reliable today and will
remain reliable into the future. In the analysis, PJM stress-tested the fuel delivery
systems serving generation in the PJM region under more than 300 extreme
scenarios to identify when the system begins to be impacted and to identify key
drivers of reliability risk. These scenarios included:

38
http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018q3som-pjm-sec3.pdf, p. 188, tables 3-84 and 3-85.
39 2017 Pennsylvania State Infrastructure Report, May 2018.
40 https://www.pjm.com/-/media/library/reports-notices/load-forecast/2019-loadforecast-report.ashx?la=en, p 2. PJM is a summer peaking RTO. As such, summer
demand increases drive reliability requirements for the RTO.
23

 1. Generation retirements – base case assumption of 4.8GW of nuclear and
7.5GW of coal units, with 2 other scenarios of 15.6GW and 32.1GW of coal
and nuclear plant retirements.
2. High customer demand - a 14-day period of cold weather with typical winter
load and generation retirements announced as of Oct. 1, 2018.
3. Fuel delivery failures, and
4. Fuel disruptions
Key elements, such as on-site fuel inventory, oil deliverability, location of a
fuel supply disruption, availability of non-firm natural gas service, 41 pipeline
configuration and demand response become increasingly important as the system
comes under more stress.
The study removed the capacity of all announced generation retirements as
of October 1, 2018, including nuclear retirements such as TMI and Beaver Valley,
with a resultant generation installed capacity reserve of 25.8%, which remains far
above the required generation reserve requirement of the last generation capacity
auction of 15.8%.42 PJM concluded that its system can withstand an extended
period of stress while remaining reliable. Even in an extreme scenario, such as an
extended period of severe weather combined with high customer demand and a
fuel supply disruption, the PJM system would remain reliable.
It was only under very extreme modeling scenarios - under escalated
retirement scenarios looking out 5 years when combined with extreme winter load,
the system may be at risk for emergency procedures and load loss. These
escalated retirement scenarios essentially assumed the level of reserves were
brought down to the minimum reliability requirement of 15.8%. 43
Absent substantial reforms in the Variable Resource Reliability demand curve
used to procure capacity resources, this low level of reserves is highly unlikely, and,
in fact, has never occurred in the entire history of PJM capacity procurement.

41 Non-firm gas supply means the power plant has non-firm transportation contracts (also
called interruptible) for the delivery of natural gas supply, which are lower priority, depend
on the availability of pipeline capacity, and maybe interrupted should conditions warrant.

42 Fuel Security Analysis: A PJM Resilience Initiative, table 1, p. 12. The base case
used in this study reduced the installed capacity of nuclear units to 28.8GW in PJM,
which reflects the announced retirements of 4.8GW of nuclear generation and
7.5GW of coal-fired generation, table 4, p. 17.
https://www.pjm.com/-/media/library/reports-notices/fuel-security/2018-fuelsecurity-analysis.ashx?la=en.
24

 43https://www.pjm.com/-/media/committees-groups/committees/mrc/20181101fuel-security/20181101-fuel-security-phase-1-analysis-results.ashx?la=en,
Escalated Scenario 1 assumed an additional 13.6GW of nuclear and 18.5GW of
additional coal plants retired [residual nuclear flee if 15.2GW]. Escalated Scenario 2
assumed an additional 9.4GW of nuclear and 6.2GW of additional coal plants retired
[residual nuclear capacity of 19.7GW]. Under both scenarios, generation
replacement was limited to only meeting the minimum allowed reserve requirement
of 15.8%.
25

 Appendix D
RGGI Summary
The Regional Greenhouse Gas Initiative (RGGI) is the country’s first market-based
program to reduce emissions of carbon dioxide (“CO 2”) from existing and new power
plants and has now been operating since 2009 - for over nine years. The scope of
RGGI is significant: the current set of RGGI states account for more than one-eighth
of the population in the U.S. and more than one-seventh of the nation’s gross
domestic product.44 The ten original RGGI states were Connecticut, Delaware,
Massachusetts, Maryland, Maine, New Hampshire, New Jersey, New York, Rhode
Island, and Vermont. New Jersey participated in the first three years of the RGGI
program and withdrew its participation at the end of 2011. New Jersey recently
issuing an executive order to reinstate its prior participation in RGGI, Virginia
moving forward with legislative priorities to participate with RGGI states. Some
important design elements are as follows:
1. Who must buy CO2 Allowances? RGGI requires owners of emitting power plants
to purchase CO2 allowances. Power Plant owners recover these costs in their
energy offer bids in the wholesale markets. Shortly after the end of each threeyear compliance, every affected source must retire a number of allowances
equal to the total tons of CO2 emissions from the source over the three-year
compliance period (one allowance equals one ton of emissions). Affected units
may obtain allowances at various points in time prior to the end of the
compliance period. Sources can purchase, bank, and use allowances bought at
any auction for a given compliance period within the three-year compliance
period. Allowances can be purchased and banked for use beyond the
compliance period in which they were purchased. Sources can meet up to 3.3
percent of their CO2 compliance obligation through the purchase of offsets – that
is, GHG-reduction projects outside the power sector.
2. How are targets set? The original cap was set at 188 million tons annually. This
cap is reduced each year. By 2017, 84.3 million allowances were available, a
55% reduction. The regional cap is apportioned to states in a manner based
generally on emissions from the affected sources (i.e., fossil fuel power plants
that are 25 megawatts or more in size), according to an agreed-upon ratio that
roughly reflects each state’s relative share of regional CO 2 emissions from the
power sector as of a historical time period. The RGGI cap is set in a public
process that includes input with and by the state departments of environmental
protection and state public utility commissions from the RGGI states.

44 The Analysis Group, “THE ECONOMIC IMPACTS OF THE REGIONAL GREENHOUSE
GAS INITIATIVE ON NINE NORTHEAST AND MID-ATLANTIC STATES”, Review of RGGI’s
Third Three-Year Compliance Period (2015-2017), April 17, 2018, p. 1.
26

 3. Use of carbon fee proceeds: RGGI states have received virtually all of the nearly
$2.8 billion in proceeds from CO2-allowance auctions and disbursed them back
into the economy in various ways, including through expenditures on: energy
efficiency (“EE”) measures and programs; renewable energy (“RE”) projects;
GHG-emission reduction measures; direct electricity consumer bill assistance,
including for low-income households; and education and job training programs. 45
Participating states retain jurisdiction over how funds are dispersed. 46 Pursuant
to an MOU, 25 percent of the state’s allowances should be allocated “for a
consumer benefit or strategic energy purpose”. 47 The use of the RGGI funds are
set by each state either in their enabling RGGI statutes or regulations.
4. Determination of carbon reductions. RGGI states collectively decide aggregate
annual carbon cap reductions. Current annual carbon emission reductions are
set at 2.5% through 2020, consistent with the RGGI model rules that each state
must adopt.
5. Centralized carbon allowance trading. States can elect to sell their carbon
allowances in centralized auctions conducted quarterly by RGGI, Inc. on behalf of
the RGGI states, or allocate allowances in a manner consistent with their own
policy objectives. The vast majority of states elected to participate in this
centralized auction. Funds collected in auctions are transferred to each state for
inclusion in the state’s budget process consistent with that state’s enabling
statute and/or regulations.
6. High price mitigation mechanisms: RGGI has a Cost Containment Reserve
(“CCR”) trigger price, which, when hit, causes additional allowances to be sold
into the market to lower carbon prices. The trigger price was $10 in 2017, rising
2.5 percent each year thereafter through 2020 (to account for inflation). After
2020, the trigger price will rise by 7 percent in each subsequent year.
Subsequently, the trigger price was increased to $13 in 2021, increasing 7%
annually thereafter.
7. Market Power Monitoring: An independent market monitor assesses the
performance of the auctions to ensure that they are administered according to
45 Id. P. 2.
46 Id. P. 5. Overall, the distribution of spending across the RGGI states was as
follows: 52% on EE; 18% on RE projects; 13% on bill-payment assistance to
consumers; 7% on program administration; 4% on GHG-emission reduction
programs; 3% on clean technology research and development; 2% on education,
outreach, and job training; and 1% for payments into a general fund. Individual
state expenditures varied significantly across these categories.
47 Id.p. 16. MOU Section 2.G.
27

 auction rules, and that there is no anti-competitive behavior in the market.
There is also a 25 percent cap placed on purchases by a single buyer or group of
affiliated buyers in each auction.
8. Low price mitigation mechanism: A price floor is established in 2014 at $2.00
and increases annually by 2.5 percent. RGGI subsequently created a CO2
emissions containment reserve allowance (CO 2 ECR allowance) that is withheld
from sale at an auction for the purpose of additional emission reduction in the
event of lower than anticipated emission reduction costs. The ECR trigger price
in calendar year 2021 will be $6.00 and increases 7 percent annually thereafter.

Economic studies conducted on RGGI demonstrate net positive benefits from
membership. Over the last three years (2015-2017), the RGGI program led to $1.4
billion (net present value (“NPV”)) of net positive economic activity in the nine-state
region.48 Since RGGI’s commencement in 2009, energy and dollar savings resulting
from all states’ investments in EE and RE has more than offset the wholesale market
price increases associated with inclusion of allowance costs in market bids. 49
Taking into account the gains and losses to consumers and producers, RGGI
Compliance Period 3 [2015-2017] led to overall job increases amounting to
thousands of new jobs over time. According to the Analysis Group, the net effect is
that RGGI activity during the 2015-2017 period leads to over 14,500 new job-years,
cumulative over the study period, with each of the nine states experiencing net jobyear additions.50

48 Id. P. 4.
49 Id. P. 5.
50 Id. at 9.
28

 Appendix E
Summary of Illinois Nuclear Legislation
Legislation was referred to as the Public Act 99-0906 (“Act”), House Resolution 1146,
also known as the Future Energy Jobs Act, which was signed into law in December
2016 and became effective June 1, 2017. The Illinois Commerce Commission’s (ICC)
approved the Zero Emission Credit (ZEC) procurement plan of the Illinois Power
Authority (IPA) in Docket No. 17-0333. The IPA’s evaluation criteria are fully
described in the IPA’s Final Approved Zero Emission Standard Procurement Plan
subject to the modifications on September 11, 2017, and the final approval of the
procurement of ZECs was granted on October 31, 2017, less than 1 year after
signing of the Act.
A ZEC is a tradable credit representing the environmental attributes of one
megawatt hour of energy produced by a zero-emission facility. A zero-emission
facility is defined as a nuclear facility, located in PJM or MISO, that further provides
carbon free energy, and minimizing sulfur dioxide, nitrogen oxide, and particulate
matter emissions that adversely affect the citizens of the State of Illinois. The
procurement process is designed to favor Illinois resources based on the localized
emission reduction benefits. Unit winners of ZECs were Quad Cities, Units 1 and 2,
and Clinton Unit 1, both located in Illinois.
The overall annual target quantity of ZECs of 20,118,672 ZECs was
determined in the ZES Plan on the basis of the amount equal to approximately 16%
of the actual amount of electricity delivered by Ameren and ComEd during the
calendar year 2014 and an amount equal to approximately 16% of the portion of
power and energy procured by the IPA for MidAmerican Energy Company (MEC) for
the delivery year commencing June 1, 2016. Coincidentally, this was also equal to
average of the state’s Renewable Portfolio Standard (RPS) targets for the 2017-2023
period.
For the first delivery year June 1, 2017 through May 31, 2018, the ZEC price
paid to each facility will equal $16.50/MWh, the Social Cost of Carbon, as specified
in Public Act 99-0906. As a result of cost caps included in Public Act 99-0906, some
contractual volumes may not be paid for during the delivery year and may be paid
for in a subsequent delivery year in which unpaid contractual volumes can be paid
without exceeding the cost caps. Beginning with the delivery year commencing
June 1, 2023, the [Social Cost of Carbon] price per MWh shall increase by $1/MWh
and continue to increase by an additional $1/MWh each delivery year thereafter.
However, the Social Cost of Carbon is then required to be adjusted based on a
Market Price Index (MPI), which is initially set at $31.40, and which represents a
proxy rate for compensation in energy and capacity markets in PJM and MISO. To
the extent the MPI increases above $31.40, the ZEC credit price would decrease. In
short, the Illinois legislation has a mechanism to adjust the price paid for carbon29

 free attributes of nuclear plants in the event wholesale market prices increase. The
ZEC mechanism terminates on January 1, 2028.
All customers pay the ZEC costs, based on a cents/kWh fee. However,
important consumer protection provisions cap the amount payable at 1.65% of the
per kilowatt hour rate paid by eligible retail customers during the year ending May
31, 2009 multiplied against retail customer load. For 2017-2018, the total maximum
amount that can be spent to procure ZECs for all the utilities under this applicable
cap was $234,827,816, which is lower than the $331,958,084 amount based on the
ZEC Contractual Volume and the applicable ZEC Price for delivery year 2017-2018.
The estimated 5,886,683 unpaid ZECs will therefore be eligible for payment in a
future delivery year when the rate cap does not limit the total amount paid for ZECs
in that year.
Permissible ZEC Contract Termination Provisions include:


Standard force majeure conditions that are outside of the control of the zeroemission facility as described in Section 1-75(d-5)(1)(D)(ii).



The zero emission facility can terminate its ZEC contract in the event
legislation is enacted by the General Assembly that “…imposes or authorizes
a new tax, special assessment, or fee on the generation of electricity, the
ownership or leasehold of a generating unit, or the privilege or occupation of
such generation, ownership, or leasehold of generation units by a zero
emission facility.”



The zero-emission facility can terminate its contract if the facility requires
capital expenditures of more than $40 million that were unknown or
unforeseeable at the time it executed the ZEC contract and which a prudent
owner or operator would not undertake.



The zero-emission facility can terminate its ZEC contract if the Nuclear
Regulatory Commission terminates the facility’s operating license.

30

 Appendix F
Summary of New Jersey Nuclear Legislation
Overall Description:


Bill creates a ZEC: "Zero emission certificate" or "ZEC" means a certificate,
issued by the board or its designee, representing the fuel diversity, air
quality, and other environmental attributes of one megawatt-hour of
electricity generated by an eligible nuclear power plant selected by the board
to participate in the program.



Eligibility Criteria: An “eligible” nuke plant must provide to the NJ BPU
certified cost projections over the next 3 energy years that include O&M
expenses, fuel expenses, non-fuel capital expenses, the cost of operational
and market risks that would be avoided by ceasing operations and any other
info to demonstrate that the nuke plant’s fuel diversity and air quality
attributes are at risk of loss because the nuke plant is cash negative on an
annual basis or, alternatively, is not covering its costs, including cost of
capital, on an annual basis.



Who pays the Nuclear Plant: Each utility will have to buy ZECs on a monthly
basis from each selected nuke plant with payment due within 90 days of the
end of the energy year. Each utility gets full cost recovery for the ZECs and
the costs of the NJ BPU’s implementation of the program through a nonbypassable surcharge to all customers.

ZEC Price:


Price is fixed at $0.004/kWh for the first 2 years. However, If the Board
determines, in its discretion, that no nuclear power plant that applied
satisfies the objectives of the Act, the Board shall be under no obligation to
certify any nuclear power plant as an eligible nuclear power plant.



BPU has the right to modify the $0.004/kWh charge as early as during the full
third year of the first ZEC payment term if the BPU decides not to continue
the program, provided the BPU determines that the reduced rate “will
nonetheless be sufficient to achieve the State’s air quality and other
environmental objectives by preventing the retirement of the nuclear power
plants that meet the eligibility criteria established pursuant to subsections d.
and e. of this section



BPU also has the authority to modify the $0.004/kWh charge at the beginning
of the second three-year ZEC payment term and in subsequent periods under
certain defined conditions.

ZEC Quantity:

31

 

Per the Act, the highest ranked units, in order, will be selected to receive
ZECs until their combined total capacity equals no more than 40% of the total
number of MWh distributed in the State in the 2017 energy year.



Units that are awarded ZECs will receive them for the period between April
19, 2019 through May 31, 2019 and the following three energy years (2019–
2020, 2020–2021, 2021–2022) per the Act.

Labor:


A selected nuclear power plant shall not lay off any personnel unless the layoff is due to employee misconduct or underperformance issues, or due to the
suspension or cessation of the selected nuclear power plant’s operations as
provided in subsection k. of this section.

Excuse from performance of selected units receiving ZEC revenues:


Force majeure – due to an event beyond its control, including but not limited
to acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic,
war, riot, labor dispute, labor or material shortage, sabotage, or explosion.



State Law Regulatory Out – significant new tax, special assessment, or fee on
the generation of electricity, the ownership or leasehold of a generating unit,
or the privilege or occupation of the generation, ownership, or leasehold of
generation units by a selected nuclear power plant;



Regulatory Out – impacting ZEC value - State or federal law is enacted that
materially reduces the value of a ZEC, or the board exercises its discretion to
reduce the amount of the per kilowatt-hour charge pursuant to paragraph (3)
of subsection j. of this section;



Unanticipated large CapEx – nuclear power plant requires capital
expenditures in excess of $40,000,000 that were neither known nor
reasonably foreseeable at the time it was selected to receive ZECs, and the
capital expenditures are expenditures that a prudent owner or operator of a
selected nuclear power plant would not undertake.



Loss of Nuclear Regulatory Commission license.



Non-performance penalty – If a selected nuclear power plant ceases
operations during an eligibility period for any reason other than those
specified in the bill, the plant is to pay a charge to the utilities that purchased
ZECs from the selected nuclear power plant in an amount equal to the
compensation received for the sale of ZECs since the board’s last
determination of the selected nuclear power plant’s eligibility to receive
ZECs.

ZEC Program evaluation – after 10 years
32

 ZEC Application Requirements:


Must be licensed to operate by the United States Nuclear Regulatory
Commission beyond 2030.



Must make a significant and material contribution to air quality in New Jersey.



Must provide fuel diversity, air quality, and other environmental attributes
that are at risk of loss without a material financial change.



Must receive no payments or credits for fuel diversity, resilience, air quality,
or other environmental attributes that would eliminate the need for ZECs.



Must include the requisite application fee of $250,000.

ZEC Status:




All 3 nuclear units in New Jersey have applied for ZECs
o

Salem 1 Generating Station [57.41% PSEG, 42.59% Exelon] –
Nameplate 1,170MW

o

Salem 2 Generating Station [57.41% PSEG, 42.59% Exelon] Nameplate
capacity 1,170MW

o

Hope Creek Generating Station [100% PSEG] – Nameplate - 1,291MW

Commission Decision on awards is pending before the NJBPU. A Decision is
required by April 18, 2019.

33