6 NYCRR Part 242 CO2 Budget Trading Program Revised Job Impact Statement
Nature of Impact
On December 20, 2005, New York State entered into a historic regional agreement to reduce greenhouse gas (GHG) emissions from power plants, an important step to protect our environment and meet the significant challenge of climate change. Under the agreement, the governors of 10 Northeastern and Mid-Atlantic states have committed to propose the Regional Greenhouse Gas Initiative (RGGI), a program to cap and reduce carbon dioxide (CO2) emissions from power plants in the region by 10 percent by 2019, for adoption in their state.1 In order to carry out the State's commitment, the Department of Environmental Conservation (the Department) is proposing to establish the CO2 Budget Trading Program (the Program) by promulgating 6 NYCRR Part 242, and to revise 6 NYCRR Part 200, General Provisions.
The burning of fossil fuels to generate electricity is a major contributor to a warming climate because fossil-fuel generators emit large amounts of CO2, the principal GHG. Overwhelming scientific evidence suggests that a warming climate poses a serious threat to the environmental resources and public health of New York State-the very same resources and public health the Legislature has charged the Department to preserve and protect. The warming climate threatens the State's air quality, water quality, marine and freshwater fisheries, salt and freshwater wetlands, surface and subsurface drinking water supplies, river and stream impoundment infrastructure, and forest species and wildlife habitats. Not only will the Program help counter the threat of a warming climate, it will also produce significant environmental co-benefits in the form of improved local air quality, forest preservation, improved agricultural manure handling practices leading to better water and air quality in rural areas of the State, and a more robust, diverse and clean energy supply in the State.
Based on analyses conducted for the RGGI states by the Economic Development Research Group, the Program is expected to have a very modest net positive impact on economic growth in New York and in the region.2 As such, the Program will have minimal positive impacts on overall job and employment opportunities. Electricity generators will incur costs related to the requirements of the Program and based on the modeling this will translate into modest increases in electricity costs.
Categories and Numbers Affected
The Department sought input from the New York State Energy Research and Development Authority (NYSERDA) and the New York State Department of Public Service (DPS) with respect to the costs and other impacts associated with compliance with the Program. The analysis provided by NYSERDA includes modeling of the electricity sector showing the impacts of RGGI. ICF International (ICF) was contracted by NYSERDA to perform the modeling analysis. ICF utilized the Integrated Planning Model (IPM®), a nationally recognized modeling tool that is used by the EPA, state energy and environmental agencies, and private sector firms such as utilities and generation companies. The Department also analyzed the costs associated with state and local governments' compliance with the Program and considered analysis of the impacts the Program may have on the state economy.3 In addition, a jobs impact analysis has been provided based on NYSERDA's experience with the Energy $mart Program and their administration of energy efficiency programs that are very similar to those that will be funded with auction proceeds.
Costs to the Regulated Sources and the Public
The modeling analysis and review process was coordinated by NYSERDA staff, working closely with the Department and DPS staff, as well as staff from each regional Independent System Operator (ISO, a federally regulated regional organization which coordinates, controls and monitors the operation of the electrical power system of a particular state) staff and the RGGI Staff Working Group, consisting of energy and environmental representatives from all of the states participating in the Program.
To estimate the potential impacts of the Program, IPM®was used to compare a future with the Program (Program Case) to a business-as-usual (BAU) Case that projects what the electricity system would look like if the Program were not implemented. The modeling assumptions and input data were developed through an extensive stakeholder process with representatives from the electricity generation sector, business and industry, environmental advocates and consumer interest groups. Modeling results were presented to stakeholders for review and comment throughout the process of developing the RGGI proposal.
Assumptions and sources of input data are specified in detail in the "Assumption Development Document: Regional Greenhouse Gas Initiative Analysis."4 Key assumptions and data include regional electricity demand, load shapes, transmission system capacities and limits, generation unit level operation and maintenance costs and performance characteristics, fuel prices, new capacity and emission control technology costs and performance characteristics, zonal reliability requirements, reserve margins, Renewable Portfolio Standard requirements, national and state environmental regulations, and financial market assumptions. All estimates are based on 2003 dollars. Regional electricity demand growth projections, transmission capacities and limits, and near-term expected infrastructure additions/retirements were provided by the regional ISOs. Long range Henry Hub natural gas prices, based on forecast data from Energy and Environmental Analysis, Inc. were projected to be approximately $7/MMBtu (constant 2003 dollars).
Building new coal-fired and nuclear plants were precluded as an economic choice to meet projected capacity shortfalls within the RGGI region. However, a 600 MW Integrated Gasification Combined Cycle (IGCC) coal plant with 50 percent carbon capture capability was assumed to be operational in upstate New York by 2018 in response to the State's Advanced Clean Coal Power Plant Initiative. New nuclear units were also precluded outside the RGGI region. A national 3-pollutant policy (SO2, NOx and mercury) that approximates the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR) is assumed as well as the achievement of RPS in individual states.
Under the BAU Case, generation from new gas-fired combined cycle units is projected to supply most of the growing electricity demand. Generation from gas-fired plants is projected to approximately double from 36,307 Gigawatt hours (GWh) in 2006 to 64,934 GWh in 2021. (However, note that as recently as 1999, New York's gas-fired generation reached as high as 46,000 GWh.) Generation from new renewable resources (primarily wind units) is projected to increase significantly in response to RPS requirements. While nuclear generation is projected to increase by about two percent between 2006 and 2021 due to capacity up-rates at existing plants, generation from coal-fired plants is projected to increase by about 17 percent between 2015 and 2018 with the addition of the new proposed IGCC plant. Finally, generation from existing oil/gas steam units is projected to decrease over time, as a result of displacement by lower-cost electricity from new gas-fired units.
Net imports of electricity into New York are projected to decrease from approximately 21,000 GWh in 2006 to approximately 10,000 GWh in 2021. Underlying the projected decrease in net imports to New York is the increasing reliance on generation from new gas-fired units in neighboring Mid-Atlantic States. Generally, electricity flows from one region to another because of price differentials between those regions. As gas-fired generation increasingly sets market-clearing electricity prices in neighboring states, their electricity prices increasingly approach those of New York, where electricity prices are already largely determined by gas-fired generation.
CO2 emissions in the BAU Case are projected to increase from approximately 52.9 million tons in 2006 to about 58.6 million tons in 2021. This increase is due primarily to the addition of new gas-fired power plants to meet projected load growth, but also includes the emissions from the new IGCC coal plant. There are several factors that contribute to the result showing that BAU emissions from the model in 2006 are lower than actual CO2 emissions reported to both the EPA and the Department over the period 2000 through 2004. The first is the use of total on-site emissions from cogeneration. Actual emissions reports to EPA and the Department are inclusive of on-site emissions while the modeling analysis reflects only the emissions associated with the electricity provided to the grid. A second contributing is an upward bias in emissions recorded by continuous emissions monitoring systems as reported to EPA.5 As a result, it is expected that emissions reported to EPA are on the order of two to 10 percent higher than actual emission. In contrast the modeling analysis was based on carbon emissions factors that are not subject to systematic errors in measurement. Lastly, significant changes to the electricity sector also contribute to the difference between BAU emissions and 2000 to 2004 actual emissions. These include the addition of new natural gas-fired combined cycle capacity and new renewable resources as well as the updating of existing nuclear units.
Several assumptions were made to project the impacts of the Program in the Program Case. The Program was applied to electricity generators 25 MW and larger in nine northeastern and mid-Atlantic states including New York, Maine, New Hampshire, Vermont, Connecticut, New Jersey, Massachusetts, Rhode Island, and Delaware. For modeling purposes, the proposed initial CO2 cap is assumed to be "current" emission levels. The initial cap level, stabilizing emissions at current levels, is implemented in 2009 through 2015. From 2015 until 2019, the cap is reduced linearly so that emission levels in 2019 are capped at 10 percent below current levels. The Program Case allows a limited number of emission offsets to be purchased by affected generators and used for compliance. The Program Case assumes that all RGGI states extend current annual levels of public benefit expenditures on end-use energy efficiency programs through 2025. Further, the public benefit programs are assumed to continue to deliver annual electricity end-use reductions at the same incremental cost as reported in most recent years. This assumption results in regional electricity demand in each year being lower in the Program Case than in the BAU Case.
Several types of results between the Program Case and the BAU Case are compared including generation mix, net electricity imports, changes in generation capacity, CO2 emissions, CO2 allowance prices, and wholesale and retail electricity price impacts.
The generation mix in New York under the Program Case reflects the continuation of energy efficiency projects and the change in build mix. Electricity generation from gas-fired units in 2021 is about 10,600 GWh or 16 percent lower in the Program Case than in the BAU Case. Net imports into New York in 2021 are projected to be about 4,000 GWh or 40 percent higher in the Program Case than in the BAU Case. However, the projected imports in 2021 in the Program Case are about 7,000 GWh or 33 percent lower than BAU Case imports in 2006. The total electricity requirement (generation plus net imports) is lower in the Program Case by about 7,000 GWh (3.7 percent) in 2021, due to the higher level of end-use energy efficiency expenditures assumed in the Program Case.
Relative to the BAU Case, total capacity additions in the Program Case are 757 megawatts lower (10 percent) in 2015 and 918 megawatts lower (eight percent) in 2021. The block of avoided capacity additions due to RGGI is comprised almost entirely of gas-fired combined-cycle units.
CO2 emissions from New York generators are projected to be 5.1 million tons (8.7 percent) lower in 2021 for the Program Case as compared to the BAU Case. The initial cap level, which stabilizes emissions at current levels, is proposed to be implemented in 2009 through 2015. From 2015 until 2019, the cap is reduced linearly so that emission levels in 2019 are capped at 10 percent below current levels. CO2 emissions from the electricity sector are projected to remain approximately flat between 2006 and 2021, rather than decreasing, as might be suggested by the decreasing cap level over the last five years of this period. This result is expected because RGGI-affected sources are allowed to bank emission allowances in the early years of the policy for use in later years when the cap becomes more stringent. Further, a portion of the cap is projected to be achieved by the use of offsets based on emission reduction projects implemented in sectors outside the electricity sector. Through 2021, about 70 percent of the CO2 emission reductions resulting from RGGI are projected to be achieved by on-system reductions by the electricity sector, while about 30 percent are projected to be achieved by purchasing emission offsets.
CO2 allowance prices (the cost of complying with RGGI) are projected to increase from approximately $2/ton in 2009 to about $3.00/ton in 2015 and about $4.45/ton in 2021. The availability of emissions offsets to meet a limited portion of the emission reduction requirement (as allowed by the Program) contributes significantly to maintaining CO2 allowance prices below the $7/ton offset expansion threshold specified.
Under the Program Case, New York's wholesale electricity prices (including both energy and capacity costs) are projected to be $1.04/MWh higher in 2015 and $1.51/MWh higher in 2021, than the BAU Case. RGGI is projected to increase wholesale electricity prices by about 1.6 percent in 2015 and 2.4 percent in 2021. For a typical New York residential customer (using 750 kWh per month), the projected increase in wholesale electricity prices in 2015 (1.6 percent) translates into a monthly retail bill increase of about 0.7 percent or $0.78. In 2021, the projected increase in wholesale electricity prices (2.4 percent) translates into a monthly residential retail bill increase of about 1.0 percent or $1.13. For commercial customers, the projected retail price impact of RGGI is about 0.9 percent in 2015 and 1.2 percent in 2021. For industrial customers, the projected retail price impact of RGGI is about 1.7 percent in 2015 and 2.4 percent in 2021.6
The analysis conducted by ICF did not identify any New York generation facilities as candidates for retirement due to the costs imposed by the Program. DPS, NYSERDA and the Department developed a two phase analysis to test that result. The analyses focused on generating units that are considered necessary to the reliable operation of New York State's bulk power system. The selection of those units was based on provisions in the New York State Reliability Council's reliability rules which require their operation under certain conditions.
The first phase of the analysis was performed by DPS using plant specific data, combined with zone-specific modeling output (i.e. projected kWh, energy prices, etc.) from IPM®. This assessment predicted that the Program would result in small decreases in net operating revenue for certain of the units being studied while others actually did better under a future with RGGI, and supported ICF's conclusion that the units would not retire. The second phase of the analysis conducted by the DPS consisted of more detailed modeling with General Electric's MAPS model. The second phase analysis confirmed the results of the first phase analysis. In summary, the two-phase reliability analysis concluded that the Program would not adversely affect system reliability.
A macro-economic impact study of the Program was also conducted at the direction of the RGGI state agencies through the Massachusetts Division of Energy Resources to estimate the potential impact of the Program on the economies of participating states.7 The study used a computer model called the Regional Economic Models, Inc. (REMI) model. The study concluded that the economic impacts of RGGI on the economies of the participating states, including New York, were very small and generally positive.
NYSERDA currently administers, through the New York Energy $mart Program, energy efficiency and clean energy technology programs that are very similar to those that will be funded with auction proceeds under the CO2 Allowance Auction Program. A 2006 Macroeconomic Impact Analysis of the New York Energy $mart Program concluded that expenditures under that program created approximately 4.8 new sustained jobs per $1 million of program funds spent. The following chart illustrates the breakdown of jobs created per sector:
| Economic Sector | % of Total Added Jobs Through 2006 |
|---|---|
| Agriculture, Forestry, and Mining | 0.60% |
| Construction | 10.52% |
| Products Manufacturing | 5.07% |
| Equipment and Instrument Manufacturing | 6.46% |
| Transportation, Communication, and Other Public Services | 3.30% |
| Wholesale and Retail Trade | 30.86% |
| Personal and Business Services | 52.81% |
| Electric utilities | -9.63% |
| Total | 100% |
The results of the Macroeconomic Impact Analysis were published in the March 2007 New York Energy $mart Evaluation Report, which is available on NYSERDA's website at: http://www.nyserda.org/Energy_Information/evaluation.asp.
Regions of adverse impact
A statewide analysis was performed for the Program and the modeling predicts that the statewide average increase in wholesale electricity prices will be 1.6 percent in 2015 and 2.4 percent in 2021.
Minimizing Adverse Impact
The Department is implementing the Program through a cap-and-trade program. Allowance based cap and trade systems are the most cost effective means for implementing emission reductions from large stationary sources. By implementing the Program through an allowance based cap and trade system, the Department has attempted to minimize the adverse economic impacts including the adverse employment impacts of the Program.
Self-Employment Opportunities
Not applicable.
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1 In addition to New York, the other states participating in RGGI are: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, Rhode Island, and Vermont.
2 REMI Impacts for RGGI Policies based on the Std REF & Hi-Emission REF" by the Economic Development Research Group, dated November 17, 2005.
3 REMI.
4 The modeling assumptions document and the tabular results for each modeling run are located at http://www.rggi.org/documents.htm
5 Russel S. Berry and Jack C. Martin (RMB consulting and Research, Inc.) and Charles E. Dene (Electric Power Research Institute). "CEMS Analyzer Bias and Linearity Effects Study." rmb-consulting.com/newpaper/cable/cable.htm
6 Typical customer usage numbers from U.S. Department of Energy, Energy Information Administration (EIA). Average electricity prices from NYSERDA, Patterns and Trends (December 2005).
7 REMI.
