Regional Greenhouse Gas Initiative Stakeholder Meetings – April 5 & April 10, 2007
Stakeholder Comments Received
TABLE OF CONTENTS
20 Associated Industries of Massachusetts
23 Conservation Law Foundation
27 Dominion Energy New England
31 Environment Northeast
35 First Light Power Resources
39 International Paper Products
41 Machaver/RJ Associates
46 The Nature Conservancy
48 New England Power Generators Association
54 Peabody Municipal Light Plant
56 Union of Concerned Scientists
130 E. Seneca Street
Ithaca, New York 14850
April 11, 2007
To: Nicholas Bianco (Nicholas.M.Bianco@state.ma.us)
William Lamkin (William.Lamkin@state.ma.us)
Subject: AES Comments to Massachusetts on State Implementation of RGGI
We appreciate the opportunity to provide comments to Massachusetts as it develops its rule to implement RGGI. We are very concerned with the RGGI pre-proposal that was released by New York, and encourage Massachusetts to reject its proposed 100% auction for the reasons outlined herein. New York‘s pre-proposal represents a complete
departure from the claimed desire to achieve balance among environmental, energy and economic development needs and does not represent a workable template for a national program.
We therefore encourage Massachusetts to develop program details that provide for a fair allocation of allowances to generators and address other shortcomings of New York‘s pre-proposal.
If you have any questions please contact me at 607/272-5970, ext. 1116.
Chris Wentlent, Director
AES Comments to Massachusetts on State Implementation of RGGI 4/11/ 2007
AES is one of the world's largest global power companies, with operations in 26 countries on five continents. We have 14 regulated utilities and 122 generation facilities worldwide, including plants in four of the RGGI states.
We were one of the first generating companies in the world to voluntarily offset carbon dioxide emissions through forest sequestration projects, have significant holdings in wind farms across the globe, have significant businesses in the creation of greenhouse gas offsets, and over the next 5 -10 years plan to invest $10 billion in CO2 offset, renewable energy, ethanol, solar power, coal-to-liquid technology, and carbon capture projects.
More recently, in New York, we have announced plans to research and demonstrate improved carbon dioxide capture technologies with Praxair for both new and existing electric generation facilities. Once technically and economically feasible, such technologies would be capable of being retrofitted on both new and existing boilers across the country. To date, however, carbon capture and sequestration remain in the development phase. No viable CO2 capture and sequestration technology alternative currently exists.
In a recent January 6, 2007 NY Times interview, our CEO Paul Hanrahan, provided an overview of our climate change activities and specifically identified that in the interim, CO2 emissions could be reduced cheaply through the global utilization of offsets.
Since CO2 is a global challenge, AES believes that the best approach is a national CO2 legislative solution. However, in the interim, we will support a well-structured regional greenhouse gas initiative that properly balances environmental, economic development and energy needs as was promised in the RGGI Action Plan.
Maryland RGGI Study
The Maryland Department of the Environment contracted with the University of Maryland through its Center for Integrative Environmental Research, in collaboration with Resources for the Future, The Johns Hopkins University and Towson University, to conduct an independent study of the economic and energy impacts related to Maryland‘s
potential participation in the Regional Greenhouse Gas Initiative (RGGI). The results are contained in Economic and Energy Impacts from Maryland‘s Potential Participation in the Regional Greenhouse Gas Initiative, which was released on February 1, 2007 (the
"Maryland Report" or the "Report"). The Report contains up do date, valuable information which should help inform Massachusetts on issues associated with RGGI implementation. Included in the Report are the following findings:
1. Generators with long-term contracts for their respective output without a
mechanism for CO2 cost recovery will suffer inordinate harm under RGGI;
2. The cost of base load power will increase and merchant generators will
experience significant declines in profitability;
3. Substantial leakage will occur as electric generation shifts to higher-
emitting non-participating states as a result of RGGI.
Overview of Key Issues
We have the following concerns with respect to the concept of auctioning 100% of allowances:
1. The shift to a 100% auction mechanism without fully understanding the market,
economic, reliability, and investment implications including the immediate
financial distress for contracted facilities without a CO2 pass-through in their
existing long term contracts.
2. A 100% auction will not promote investment in new and existing infrastructure
and will reduce the term of energy transactions.
3. Program design places the highest level of risk on both consumers and suppliers.
4. Program design is not ―expandable and flexible‖ and, thus, will not serve as the
template for a national program.
AES is concerned with so drastic a deviation from the RGGI Final Model Rule recommendation which provided for at least a 25% auction, with the remaining allowances to be allocated to generation sources, to an immediate 100% auction mechanism with no allocation to generation sources.
The broad-brush rationale used to support this change, “that all generators will receive “windfall” profits if allocated allowances” is flawed. Even highly efficient natural gas
fired facilities that are able to recover most of the RGGI allowance costs within their bids will face cash and collateral issues that will limit their ability to enter into longer term transactions. Moreover, oil and coal fired generating capacity will outright face substantial economic harm, not profit windfalls, if a 100% auction is utilized. At a time
when economic development and infrastructure improvements are critical priorities, a program design that could negatively impact current existing infrastructure needlessly presents significant risks.
100% Auction Impact – Impact on Different Commercial Arrangements &
Various policy statements prepared by state agencies and boards have identified fuel diversity as an issue of concern that should be addressed through effective regulations that encourage diversity. As stated in the “Regional System Plan 2005” approved by
ISO New England, the diversity of fuels used to generate electricity in New England is a major issue of concern. The short-term issues relate to a large portion of the gas-fired generating units‘ lacking either firm gas contracts or dual-fuel capability. The
longer-term issues relate to the high and increasing reliance on natural gas for producing electric power in New England and neighboring regions, suggesting the need for greater electric supply-side fuel diversity in the region.‖
The Maryland modeling clearly demonstrated that even allocating 75 percent of Maryland‘s RGGI CO2 allowance budget to existing generators still resulted in
substantial increased compliance costs, reduced gross margins, eroding facility profitability (not windfall profits), and increases in the marginal cost of in-region
electric supplies. The Report‘s conclusions cannot be assumed to apply to the much more
severe proposal that sources receive no direct allocation, but have to attempt to obtain all of their allowances in an auction. The impact on Maryland‘s merchant plants is projected to be significant (a decrease in annual profit of 3% in 2015, worsening to nearly an 8% decrease in 2025 – the impact on coal-fired merchant plants is projected to be much more severe than this range, as discussed below). The magnitude of the financial impact
with a 100% auction was not modeled. Based on the reported results of a 25% auction,
it is apparent that adverse financial impacts will be magnified by a 100% auction.
As noted in the Maryland Report, this finding regarding generator impact is at variance with earlier work by Palmer et al (2006) which suggested that roughly 30 percent of the allowances would need to be given away to compensate the industry as a whole in the Classic RGGI region for all facilities‘ losses. This is a critical finding of the detailed
Maryland Report, and clearly refutes the contention that allocating allowances to sources will provide them with windfall profits The fact that this assumption is not valid
for Maryland (and, by extrapolation, to dual fuel and coal-fired generators in other states) should clearly point to the conclusion that a 100% auction concept being contemplated in Massachusetts and other states is based on inaccurate assumptions and, at a minimum, should be reconsidered. The original Model Rule struck a proper balance of 25% auction, and 75% allocation to source. This specific issue was debated throughout the three year RGGI regional process. A dramatic shift to 100% auction can not be done in a
vacuum but rather would require other components of the RGGI program to be modified to avoid substantial economic risks to consumers and suppliers.
Long-Term Contracted Facilities
The RGGI region has a number of plants with long term power contracts that do not contain a CO2 cost pass-through. Failure to provide a mechanism for these facilities to
costs is likely to cause reduced unit reliability, force default under the recoup their CO2
terms of the contract and an associated change of owner or possibly unit shutdown. Even though showing significant impact on coal-fired plants, the conclusions in the Maryland modeling report (as well as the RGGI IPM modeling) cannot be applied to contracted plants and do not address impacts to generators that cannot seek to recover allowance costs in the wholesale market. Before any decisions can be made as to the program‘s
impact on plants across the state, or on Massachusetts‘ allowance allocation methodology, the state must assess this key distinction between merchant and contract plants. The Maryland Report recognizes that this distinction exists, through the statement on page 59 that, ―… utilities that have long-term energy contracts for power, from sources with high
CO2 emissions, may have to pay more for the emissions and suffer from reduced competitiveness in energy markets,‖ but does not further evaluate or model its
Without properly assessing this critical difference between contracted and merchant plants, implementation of RGGI would have the unintended and paradoxical consequence of causing significant financial harm to some of the most modern, environmentally efficient clean facilities in the RGGI region. Many of these facilities operate with natural gas as its primary fuel, state-of-the-art control technologies and provide cogeneration capability to a neighboring business.
Merchant Coal-Fired Facility Impact
Gas plants generally set the marginal price of power, and will for the most part recoup the cost of CO2 allowances in the price they get for their power A combined cycle gas-fired plant emits CO2/MWH on roughly a 1:2 ratio as compared to coal units. Accordingly, a coal fired unit will recoup approximately 40% of its CO2 cost from the market. The remainder will be an immediate financial consequence to the facility.
Assuming a CO2 allowance price of $5, this equates to a market recovery of roughly $2/MWH for gas-fired generation that will be included in their bid price. Therefore, with these plants setting the marginal price of electricity a majority of the time, all merchant generators (including coal-fired) will get a $2/MWH incremental price for their power. The Maryland Report projects that even with a 75% allocation to sources the profits of coal-fired plants decline by 13% in 2015, and by over 20% in 2025.
Merchant Oil-Fired Facility Impact
Oil fired generating facilities generally are less cost effective than an efficient gas fired facility. Oil facilities require allowances on a 1.5 to 1.0 ratio as compared to gas facilities. Accordingly, this type of facility will operate at even lower capacity factors, will lose net revenue margin on the limited peak system condition occasions that they do run and become totally dependent on the capacity market or reliability must-run contracts for revenues to continue operation.
Most stakeholders will agree that CO2 Capture and Sequestration technology is still in its formative stage. In the interim, offsets provide a reasonable, verifiable and lower cost path as a compliance option to control CO2 emissions. There are no environmental or
economic reasons to control the percentage and geographical location of quantifiable offset projects. Broader application of offsets provide low cost compliance
reductions, reduce environmental and economic leakage at options, result in net CO2
RGGI borders, and assist in CO2 price control. Consumers and suppliers are both better protected with expansion of the offset program.
Investment (New & Existing)
The litmus test of good policy is whether the proposed guidelines will support investment in new and existing facilities. Without a commercially available solution, a 100% auction approach will make investment and capital financing of new fossil generation extremely difficult by creating the need to cover up to twenty (20) years of CO2 risk at the front end of a new project. Without an auction protocol available, it makes further analysis of this potential more difficult.
In addition, with respect to existing facilities, the successful structure of the SO2 and NOx programs (both federal and state) resulted in low cost energy, reduced emissions, and the addition of new technology. Under those programs, when considering a control technology solution, both the improved dispatch cost and sale of unused allowances due to the equipment upgrade were considered when making the capital decision. Under a 100% auction approach, since the source receives no allowance allocation, all future CO2 investments will be forced to only depend on long term energy forecasts to make investments that could range in the $150-300 million dollar range depending on size of the facility.
To date, neither the Regional Model Rule nor the New York State Pre-proposal has provided any roadmap to site and develop new fossil generation. At a time when new generation is critical, leaving the mechanism for new investment to chance is not in Massachusetts‘s or the region‘s best interest.
The potential unintended outcome of a 100% auction program design will be that states that adopt this approach will carry a higher regulatory risk premium than other markets or (states) when competing for the next new capital investment.
Units are dispatched in the wholesale markets serving the RGGI states largely on economics. The Maryland Report finds that as a consequence of RGGI, relative electric prices will be higher in the RGGI region than in the surrounding regions. Also, transfer limits into the RGGI region will be maximized and generation levels from within the RGGI region will be supplanted by a larger amount of imports. As noted in the Maryland Report, Pennsylvania has excess capacity and could absorb some of this ―carbon leakage,‖ most likely to the detriment of the primary goal of CO2 reduction. Its CO2 emissions in 2002 alone exceeded the annual cap for the seven RGGI states as defined by the states in their MOU. In addition, new generation in states west or south of the RGGI region, combined with transmission upgrades leading into Maryland, will facilitate the shift of generation away from originating within Maryland, Delaware and New Jersey, and towards generation from within non-participant states. Ironically, the report (at page 67) credits imports resulting from RGGI with "holding down the price effects of the Maryland joins RGGI scenario." However, the Maryland Report neglects to analyze or mention the affects of these imports on the efficacy of the program and ambient air quality. Further, the report fails to capture the additional congestion costs that could arise by becoming even more dependent on imported energy. Currently, within the RGGI region, Maryland, Delaware, New Jersey, New York, Connecticut, Massachusetts, and Rhode Island are in need of additional generation capacity. In addition, Washington, DC, Baltimore, central Maryland, eastern PA, northern New Jersey, New York City, Long Island, southwest Connecticut, and Boston are all subject to congestion risk. These additional congestion costs have not been captured within the modeling except at the RTO control area borders.
The Maryland Report notes that, “Depending on how they are grouped, states outside of
RGGI could either see a reduction in carbon dioxide emissions when Maryland joins RGGI, or an increase. In general, this leakage will be small.‖ We suggest that, in fact, the CO2 leakage is quite large. As indicated in the Report‘s Table 9.9: Looking for
Leakage: Effect of Maryland Joining RGGI on Cumulative Emissions of CO2 from Fossil Generators (2010-2025), when considering the entire Eastern Interconnect, fully 35% of the CO2 benefit (emissions reductions plus offsets) derived by Maryland joining RGGI is offset by CO2 emissions increases in surrounding Eastern Interconnect states that are outside of the RGGI region. While the Report notes that an argument could be made that it is more appropriate to look at the response of the nation as a whole to Maryland joining RGGI (which the modeling predicts showing overall CO2 reductions), it would seem that the basis for this look and attendant modeling conclusion is somewhat more tenuous. Regardless, it is apparent that leakage will be significant as a result of RGGI, and needs to be addressed to ensure the desired results of the program.
； SO2, NOx, Hg
, NOx and Hg emissions from RGGI states are Due to the fact that power plant SO2
generally at lower levels than surrounding areas, reduced generation within the RGGI states and resultant increased generation from non-RGGI states as a result of the RGGI program could actually result in overall increased SO, NOx and Hg emissions from 2
power plants in surrounding states and the entire Eastern Interconnect Region. Due to different emission characteristics between different plants and fuels, it is not possible, at least at this time, to extrapolate SO, NOx and Hg emissions leakage from CO2 emission 2
leakage data. However, as has been demonstrated through climate and transport analysis by various Northeast states, increased emissions from surrounding states will cause adverse ambient impacts in the RGGI region
We appreciate the fact that other air pollution control programs are expected to assure that SO, NOx and Hg emissions will be controlled over large geographic regions; 2
however, the nature of cap and trade programs will nonetheless allow for leakage issues to arise in the RGGI region. For example, the Clean Air Interstate Rule (CAIR) caps SO 2
and NOx emissions over most of the Eastern U.S. but does not require that emissions will be controlled in any specific state or region (e.g., the Northeast) – only that, overall,
reductions will occur within the Eastern U.S. Under SO and NOx cap and trade 2
programs, it is probable that some sources in states immediately upwind of the RGGI states will increase their import levels to the RGGI region, and hence, their emissions. Similarly, the Clean Air Mercury Rule implements emission reductions through a cap over the entire nation. While the cap and trade provisions of this rule are being challenged, nothing in the promulgated rule assures that increased imports in to the RGGI region will not bring with them increased mercury emissions into the region. States participating in a RGGI initiative must carefully review whether SO2, NOx and Hg emissions leakage resulting from upwind, non-RGGI regions will negate any emissions reductions and cause adverse ambient impacts within the RGGI region.
Need for Additional Studies
A number of key areas of the RGGI Program remain without adequate support or analyses including the following:
； Economic and thorough Environmental Leakage Analysis
； Auction Design Specifics
； Full reliability review with written summary
； Modeling which incorporates the effect of 100% auction methodology.
； Sensitivity studies of CO2 market and reliability impacts at different CO2
allowance price points.
To date, none of these important analyses have been provided and they are necessary to fully evaluate any proposal and its total impact.
In reviewing the Maryland Report it is important to consider the following limitations
o Contracted Plants - The modeling was based on all plants in the state
being merchant facilities. This is not correct, and conclusions drawn as to
the projected impact on merchant plants CANNOT be applied to
contracted plants. Modeling of how RGGI would impact a contracted
plant needs to be performed before any decisions can be made as to how
these plants should be handled under RGGI.
o Allowance Price - The model used imposes a constraint that the rate of
change in the price of CO2 emissions allowances must be no greater than
the interest rate. This is unrealistic. The following table illustrates the
price volatility that has been observed in the EU trading program.
Clearly, the assumption used in the modeling is not appropriate, and
modeling results and conclusions that are sensitive to allowance price
volatility should be questioned.
o Fuel Price – We agree with the author of the Maryland RGGI modeling
study that, ―…one might want to investigate the impact of higher fuel
prices on the resulting electricity rates. While the Haiku model results
have shown that Maryland joining RGGI has a negligible impact on
electricity rates, the same might not be true if, for example, higher natural
gas prices were considered.‖