ML12339A609

Official Exhibit - ENT000481-00-BD01 - David Harrison, Jr. & Eugene Meehan, Potential Energy and Environmental Impacts of Denying Indian Point'S License Renewal Applications (Mar. 2012)

ML12339A609
Person / Time
Site:	Indian Point
Issue date:	03/31/2012
From:	Foss A, Harrison D, Hodges N, Meehan E, Nichols A NERA Economic Consulting
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
RAS 22161, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML12339A609 (118)

Text

United States Nuclear Regulatory Commission Official Hearing Exhibit Entergy Nuclear Operations, Inc.

In the Matter of: ENT000481 (Indian Point Nuclear Generating Units 2 and 3)

Submitted: March 30, 2012 ASLBP #: 07-858-03-LR-BD01 Docket #: 05000247 l 05000286 Exhibit #: ENT000481-00-BD01 Identified: 10/15/2012 Admitted: 10/15/2012 Withdrawn:

Rejected: Stricken:

Other:

March 2012 Potential Energy and Environmental Impacts of Denying Indian Points License Renewal Applications

Project Team David Harrison, Jr., Ph.D.

Eugene Meehan Albert L. Nichols, Ph.D.

Andrew Foss Nicholas Hodges NERA Economic Consulting 200 Clarendon Street, 11th Floor Boston, Massachusetts 02116 Tel: +1 617 927 4500 Fax: +1 617 927 4501 www.nera.com

Contents Executive Summary ................................................................................................................ E-1 I. Introduction and Background................................................................................................... 1 A. NRCs Final Supplemental Environmental Impact Statement .......................................... 1 B. New York States Contention 37 ..................................................................................... 4 C. Objectives of This Report................................................................................................ 6 D. Organization of This Report ............................................................................................ 6 II. New York States Electricity System and Implications for the Energy and Environmental Impacts of the No-Action Alternative .............................................................................. 7 A. Overview of New York States Electricity System........................................................... 7 B. Government Support for Existing Renewables and Energy Efficiency Programs ............. 9 C. Costs of Additional Generation in No-Action Alternative .............................................. 14 D. Implications of Relative Costs on the Mix of Replacement Energy in No-Action Alternative .................................................................................................................... 23 E. Adverse Environmental Impacts of Generation Alternatives .......................................... 25 F. Conclusions Regarding the Likely Adverse Environmental Impacts of the No-Action Alternative .................................................................................................................... 33 III. Quantitative Modeling of the Potential Energy and Adverse Environmental Impacts of the No-Action Alternative ............................................................................................. 35 A. Overview of NEMS....................................................................................................... 35 B. Baseline Conditions....................................................................................................... 36 C. Projected Energy Market Impacts of No-Action Alternative .......................................... 37 D. Projected Adverse Environmental Impacts of No-Action Alternative............................. 39 IV. Evaluation of New York State Contention 37...................................................................... 41 A. Overview of Major Flaws in NYS-37 ............................................................................ 41 B. Conflation of Baseline and No-Action Alternative......................................................... 42 C. Failure to Account for the Indirect Effects of a Modified Baseline on the Energy and Environmental Impacts Under the No-Action Alternative.............................................. 53 D. Summary Evaluation of the Energy and Environmental Claims of NYS-37 ................... 59 V. Conclusions.......................................................................................................................... 61 References ................................................................................................................................ 62 Appendix A: Information on Recent Energy Developments in New York State......................... 68 Appendix B: The National Energy Modeling System ................................................................ 93 Appendix C: Information on Potential Canadian Hydro and Associated Transmission ............ 101 NERA Economic Consulting i

List of Figures Figure 1. U.S. Wind Capacity Additions and Availability of Federal Renewable Energy Subsidies .........................................................................................................................9 Figure 2. Renewable Portfolio Standard Budgets ......................................................................12 Figure 3. NYSERDA Analysis of Potential Contributions to Meeting 15 x 15 Conservation Goal

......................................................................................................................................13 Figure 4. Energy Efficiency Portfolio Standard Budgets ...........................................................14 Figure 5. Hypothetical Analysis of Change in Generation from Baseline to No-Action Alternative ....................................................................................................................16 Figure 6. EIA's Estimates of Levelized Costs for New Capacity, Exclusive of Government Support..........................................................................................................................17 Figure 7. Impact of Additional Renewables on Subsidy Rates per MWh ...................................19 Figure 8. EEPS Energy Efficiency Supply Curve Cost $ per MWh Versus Cumulative GWh....22 Figure 9. Height Comparison of Wind Turbine and Other Structures.........................................29 Figure 10. Location of Current and Proposed Wind Farms in New York...................................30 Figure 11. Hypothetical Illustration of Change in Baseline Generation......................................43 Figure 12. Hypothetical Analysis of Impact of No-Action Alternative with Revised Baseline ...44 Figure 13. NYISO Projections of New York State Electricity Sales...........................................47 Figure 14. Annual Generation Capacity Additions (MW)..........................................................49 Figure 15. Potential Generation Projects in Current Interconnection Queue (MW) ....................50 Figure 16. Impact of More Baseline Renewables on the Marginal Cost of Additional Renewables

......................................................................................................................................55 Figure 17. Impact of Reduced Demand in Baseline on Marginal Cost of Fossil Generation to Replace IPEC ................................................................................................................57 Figure A-1. Potential Contributions toward Energy Efficiency Goal Based on NYSERDA Analysis ........................................................................................................................73 Figure A-2. Historical and NYISOs Expectation of Savings from Energy Efficiency Programs74 Figure A-3. NYISO Projections of New York State Electricity Sales ........................................77 Figure A-4. NYISO Zones ........................................................................................................78 Figure A-5. NYISO Projections of Downstate (Zones G-K) Electricity Sales ............................79 Figure A-6. Annual Generation Capacity Additions (MW)........................................................81 Figure A-7. Cumulative Generation Capacity Additions Since 2000 (MW) ...............................82 Figure A-8. Geographic Distribution of Cumulative Generation Capacity Additions Since 2000 (MW) ............................................................................................................................83 Figure A-9. Potential Generation Projects in Current Interconnection Queue (MW) ..................84 Figure A-10. Geographic Distribution of Projects in Current Interconnection Queue (MW) ......85 Figure A-11. AEO Projections of Henry Hub Natural Gas Prices ..............................................87 Figure A-12. AEO Projections of Delivered Natural Gas Prices to Electricity Generators in New York State .....................................................................................................................88 Figure B-1. Structure of NEMS................................................................................................94 NERA Economic Consulting ii

List of Tables Table 1. Estimates of Marginal Costs of Generation..................................................................23 Table 2. Air Pollutants by Generation Plant Type......................................................................25 Table 3. Average Emission Rates..............................................................................................26 Table 4. Direct Air Emissions from Wood Residue Biomass Facilities (lbs/MWh)....................31 Table 5. Projected U.S. Baseline Generation by Fuel Type........................................................37 Table 6. IPECs Lost Output and Projected U.S. Market Responses in No-Action Alternative (2016-2025) ..................................................................................................................38 Table 7. Projected Changes in Generation in No-Action Alternative (2016-2025) .....................39 Table 8. Projected Increases in Average Annual U.S. Air Emissions in No-Action Alternative (2016-2025) ..................................................................................................................40 Table A-1. New Yorks 30 x 15 Renewable Energy Goal (million MWh)..............................69 Table A-2. Production Subsidies for Main Tier Generators .......................................................71 Table A-3. Implicit Subsidies from New Yorks RPS................................................................71 Table A-4. Original and Current In-Service Dates for Projects in Interconnection Queue (MW)86 Table C-1. Contaminants projected to be released during construction of the Lower Churchill facilities and their associated local transmission lines. ................................................. 103 NERA Economic Consulting iii

List of Acronyms AEO: Annual Energy Outlook ARRA: American Recovery and Reinvestment Act of 2009 CHP: Combined Heat and Power DOE: U.S. Department of Energy EEPS: Energy Efficiency Portfolio Standard EIA: Energy Information Administration FSEIS: Final Supplemental Environmental Impact Statement IPEC: Indian Point Energy Center IP2: IPEC Unit 2 IP3: IPEC Unit 3 NEMS: National Energy Modeling System NGCC: Natural Gas Combined Cycle generating unit NRC: Nuclear Regulatory Commission NYS-37: Contention 37 filed by New York State NYSERDA: New York State Energy Research and Development Authority PTC: Production Tax Credit RGGI: Regional Greenhouse Gas Initiative RPS: Renewable Portfolio Standard SBC: System Benefits Charge SEIS: Supplemental Environmental Impact Statement NERA Economic Consulting iv

Executive Summary A central issue addressed in the Final Supplemental Environmental Impact Statement (FSEIS) regarding the license renewal for Indian Point Energy Center (IPEC) is the comparative environmental impacts between renewal of IPECs operating licenses by the Nuclear Regulatory Commission (NRC) and the no-action alternative in which the IPEC licenses would not be renewed. In order to evaluate the differences in environmental impacts between these two scenarios, we must first identify the baseline electric market supply that would be used to meet New York demand (i.e., assuming continued IPEC operations). We must then assess how the no-action alternative would change this supply to account for the lost baseload IPEC generation. Electricity market analysis is required because the environmental impacts of moving from the baseline to the no-action alternative depend primarily upon what power sources would clear the competitive markets and be dispatched to replace the substantial amount of baseload generation that is currently supplied by IPEC. We performed such an electricity market analysis both by assessing the relative costs of alternative power sources and by conducting empirical modeling with a state-of-the-art and widely used energy market model.

Under the no-action alternative, our analyses show that IPEC baseload generation would be replaced primarily by fossil-fueled generation from existing natural gas and coal facilities.

These results establish that (1) the adverse environmental impacts of the no-action alternative assessed in the FSEIS are, if anything, underestimated; and (2) New York State is incorrect in its claimsunsupported by any empirical analysisthat the FSEIS overstates environmental impacts because replacement generation would be primarily renewable energy and conservation.

A. Background

1. Overview of FSEIS Conclusions The FSEIS identifies and assesses the potential environmental impacts of various sources of replacement energy if IPEC were not available. These alternatives include new natural gas fired plants, purchased power, conservation, and combinations of replacement energy sources.

The FSEIS also notes that NEPA requires consideration of feasible, non-speculative alternatives, and that alternatives that are economically impractical are excluded. The role of NEPA review in the license renewal process is circumscribed, as the NRC indicated when it promulgated its regulations:

Given the uncertainties involved and the lack of control that the NRC has in the choice of energy alternatives in the future, the Commission believes that it is reasonable to exercise its NEPA authority to reject license renewal applications only when it has determined that the impacts of license renewal sufficiently exceed the impacts of all or almost all of the alternatives that preserving the option of license renewal for future decision makers would be unreasonable.

(Environmental Review for Renewal of Nuclear Power Plant Operating Licenses, 61 Fed. Reg. 28,467, 28,473 (June 5, 1996) (NYS000127))

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The FSEIS concludes that the adverse environmental impacts of license renewal for IP2 and IP3 are not so great that preserving the option of license renewal for energy planning decision makers would be unreasonable. FSEIS at 9-8 (NYS00133C).

2. New York State Critique of the FSEIS Conclusions The State of New York, in its Statement of Position on Admitted Consolidated Contentions NYS-9, 33, and 37 (collectively, NYS-37) argues that the FSEIS is deficient because it ignores New York States comments that the environmental impact of the no-action alternative would be much less than assumed in the FSEIS and less than the environmental impacts of license renewal. The core of the NYS-37 argument is that the FSEIS should have evaluated environmental impacts on the presumption that baseload IPEC generation would be largely replaced by additional renewable generation and energy conservation, rather than by substantial fossil-fuel generation as assumed in many of the FSEIS alternatives. NYS-37 points to various recent energy and related developments allegedly ignored by the FSEIS, including existing New York State programs to encourage renewables and energy conservation as well as recent reductions in projected electricity demand and natural gas prices. NYS-37, however, does not include any empirical analyses to support its assertions.

3. Report Objectives The principal objective of this report is to provide the results of our analyses of the potential energy and environmental impacts of the no-action alternative. As noted, it is necessary to consider the impacts on the electricity system because environmental impacts will be driven primarily by the mix of generation that would replace the lost baseload IPEC generation if licenses were not renewed.

Information on the likely market-driven electricity impacts of the no-action alternative allows us to compare our findings to those in the FSEIS and to evaluate the arguments provided by the State of New York and its experts. To assess the validity of the central argument of NYS-37, it is necessary to conduct economic analyses of alternative sources of power as that is the only way to determineas NYS-37 and its experts allegeif the conservation/renewable alternative is so dominant that other alternatives, including those relying on fossil generation, would not play a significant role in replacing lost IPEC generation.

B. Conclusions Regarding Potential Energy and Environmental Impacts of the No-Action Alternative IPEC is a highly efficient nuclear generating facility that operates over 90 percent of the time and provides approximately 10 percent of the total electricity consumed in New York State.

Under the no-action alternative, its baseload energy would have to be replaced. To identify the environmental impacts of the generation that would likely be used to replace IPEC baseload power, we developed two related evaluations. First, we considered the wholesale electric market structure in New York Statewhich emphasizes minimizing the costs of meeting electricity demand while satisfying all reliability and operating requirementsand the implications of the NERA Economic Consulting E-2

relative cost of replacement alternatives. Second, we developed empirical estimates of likely replacement generation based upon modeling results from a state-of-the-art energy modelthe National Energy Modeling System (NEMS)developed and operated by the Energy Information Administration (EIA) within the U.S. Department of Energy. NEMS allows us to develop estimates of the changes in generation by type as well as the changes in various emissions that would occur if IPEC generation were not available.

1. Conclusions Regarding the Power Mix That Would Be Dispatched If IPEC Baseload Generation Were Lost The following are our conclusions regarding the generation that would likely be dispatched under the no-action alternative.

 Replacement energy would come primarily from natural gas and coal power plants, with a much smaller amount from renewables and energy conservation, because:

The costs of increasing the utilization of existing natural gas and coal power plants, or building new natural gas plants are lower than renewables or conservation; and Hundreds of millions of dollars of additional annual State subsidies (ultimately paid by New York States electricity consumers through their monthly utility bills) would be required to force additional renewables and energy efficiency into the electricity system to overcome their higher costs;

 The developments cited in NYS-37, including New York States 30 x 15 renewable energy goal and 15 x 15 energy efficiency goal, would render renewables and conservation even less economic relative to other alternatives, and thus even less viable than under the conditions noted in the FSEIS.

2. Conclusions Regarding Environmental Impacts of the Replacement Power Mix Electricity market modeling can be used to predict the resources that would likely replace IPECs baseload generation and thus would determine the potential adverse environmental impacts of this replacement energy. In examining in detail the environmental impact of what we believe is the most likely replacement mix, we are not suggesting a departure from the NRC practice of examining many replacement alternatives. However, the most likely source of replacement energy should be accorded significant weight. A review of the adverse environmental impacts of this scenario also is important because it places NYS-37 in proper context.

Even were renewable sources to play a major role as replacement generation for IPEC which as we demonstrate, they would notNYS-37 implies that renewable replacement sources do not have environmental impacts. This is not accurate. Thus, we also provide information on NERA Economic Consulting E-3

the general environmental impacts of renewable generation to provide full and accurate information.

Our analyses produce the following conclusions:

 The most likely mix of replacement powerprimarily fossil-fired unitswould lead to significant increases in air emissions, including an increase in annual carbon dioxide emissions of about 13.5 million metric tons per year (which is nearly as large as the Regional Greenhouse Gas Initiatives (RGGI) 15 million metric tons of planned CO2 emission reduction between 2012 and 2018); and

 Replacement alternatives that involve renewables would have adverse environmental impacts including incremental impacts resulting from the new transmission infrastructure that would be required to deliver energy produced by renewables to southeastern New York where it is needed.

C. Conclusions Regarding the Fundamental Flaws in NYS-37 and Related Expert Testimony NYS-37 and its experts come to completely different conclusions regarding the likely sources of replacement energy for IPEC generation. However, no analyses were provided to support their assertions. We evaluated the limited information they provided. Our review leads us to conclude that the materials in NYS-37 and the related expert reports have four fundamental flaws.

1. Failure to recognize market forces and cost-minimization. NYS-37 and the expert reports fail to account for the key role that market forces would play (and hence the importance of relative costs and cost-minimization) in determining the resources that would be dispatched under the no-action alternative. It is critical to recognize that New York State has a competitive electricity market. As a result, decisions regarding new investments are largely made by merchant entities that would tend to build low-cost facilities, and facilities are dispatched to provide energy at minimum cost while meeting reliability and operating requirements. Market forces and cost-minimization mean that lower-cost fossil generation rather than higher-cost renewable generation or energy efficiency would constitute the bulk of generation to replace IPECs baseload generation.

2. Conflation of developments that affect the baseline, not the no-action alternative. NYS-37 and its supporting witnesses mention a host of developments that they claim were not considered by the NRC staff in developing the FSEIS and that they claim would lead to different conclusions regarding the energy mix and environmental impacts of the no-action alternative. These developments include New York States renewable and energy efficiency goals, lower electricity demand due to the recession, recent increases in electricity generation capacity and transmission system expansions, and lower natural gas prices. The flaw pervasive in the NYS-37 reasoning is that these developments represent part of the baseline conditions that would occur irrespective of IPECs status. Put another NERA Economic Consulting E-4

way, the various factors identified by NYS-37 and its expertssuch as the additional renewable generation or energy efficiency resulting from New York State goalswould not be available to replace the baseload IPEC generation if the IPEC generation were not available because they would already exist.

3. Failure to evaluate the impacts of baseline changes. To the extent that the developments they cite affect the baseline, those developments would if anything reduce the roles of conservation and renewables as IPEC replacements under the no-action alternative. The developments emphasized by NYS-37, including lower electricity demand and lower natural gas prices, would tend to increase the subsidies that would be necessary to fund the higher marginal costs of those alternativeswhile at the same time decreasing the marginal costs of fossil resourcesthereby making renewables and energy efficiency less economic relative to fossil-fueled power options.

4. Failure to provide empirical modeling. NYS-37 and the experts fail to provide any studies or other analyses quantifying how the electric system would respond under the no-action alternative. In contrast, our analysis using NEMS shows that conservation (in the form of response to higher prices) and renewables would play minor roles, and that the primary impact would be increased generation from fossil-fired sources. This deficiency on the part of NYS-37 and its experts is important since, without some empirical modeling, they cannot provide a reasonable basis for evaluating which alternatives actually would be developed and dispatched if IPEC generation were not available.

D. Overall Conclusions As noted above, our analyses lead us to conclude that, contrary to the claims in NYS-37 and its accompanying documents, additional conservation and renewables would be unlikely to play significant roles under the no-action alternative. In contrast, our analyses and empirical modeling indicate that the replacement mix would be dominated by fossil-fuel generation, including natural gas and coal generation, with modest contributions from energy conservation and additional renewables.

Thus, our analyses demonstrate that the range of scenarios considered in the FSEIS was sufficient. Our analyses further demonstrate that the conclusion reached in the FSEISthat the impacts of license renewal did not exceed the impacts of all or almost all of the alternatives, including the no-action alternativewas reasonable. If anything, the FSEIS understates the likely adverse environmental impacts of the no-action alternative for two primary reasons:

1. Our assessments show that the combination scenarios that the FSEIS evaluates overstate the roles that renewables and conservation would be likely to play and understate the likely role of fossil sources, with significant implications for the potential adverse environmental impacts of the no-action alternative.

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2. The FSEIS assumes that increased fossil generation would be provided primarily by new, highly efficient and tightly controlled natural gas combined cycle units. In fact, a significant amount of the replacement fossil power would be likely to come from unused capacity of older natural gas-fired units or coal-fired units, both of which tend to have higher emission rates than new natural gas units, and thus, more adverse environmental impacts.

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I. Introduction and Background IPEC is a nuclear power station in Buchanan, New York consisting of two operating units (IP2 and IP3)1 with total net summer capacity of approximately 2,040 megawatts (MW) and total net generation in 2010 of approximately 16.3 million megawatt-hours (MWh)

(NYISO 2011c, p. 34). IPECs capacity utilization rate in 2010 was thus over 90 percent.2 IPECs generation in 2010 was approximately 10 percent of New York States total electricity consumption and approximately 17 percent of total consumption in southeastern New York State (assumed to comprise NYISO Zones G-K) (NYISO 2011c, p. 21).

The NRC is currently considering renewal of IPECs operating licenses. The term of IP2s current license extends to September 28, 2013, and the term of IP3s current license extends to December 12, 2015. As part of the renewal process, in December 2010, NRC staff issued an FSEIS concerning site-specific environmental issues at IPEC (NRC 2010). In December 2011, the State of New York filed NYS-37 and pre-filed testimony challenging the adequacy of the FSEIS. NYS-37 claims, among other things, that the FSEIS relies on out-of-date information and as a result gives inadequate consideration to conservation3 and renewable energy as possible sources of replacement for electricity output from IPEC under the no-action alternative.

A. NRCs Final Supplemental Environmental Impact Statement This section provides information on the energy alternatives to license renewal addressed in the FSEIS. It begins with information on the no-action alternative, which does not specify potential replacements for IPECs baseload energy. This section then provides information on alternatives if IPECs baseload energy is not available.

1. No-Action Alternative The NRC evaluates a no-action alternative in Section 8.2 of the FSEIS. The FSEIS states in the context of the no-action alternative that if IPECs licenses were not renewed, The power not generated by IP2 and IP3 during the license renewal term would likely be replaced by (1) power supplied by other producers (either existing or new units) using generating technologies that may differ from that employed at 1

Unit 1 has not operated since 1974.

2 16,300,000 MWh / (2,040 MW

• 8760 hours0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br /> per year) = 91 percent 3

Some observers distinguish between energy efficiency and conservation. Efficiency may be used to mean technologies that provide essentially the same services but with lower energy use, such as reducing the electricity consumed by a refrigerator without affecting its cooling ability or other features. Conservation may be used to mean behavioral changes that affect the service provided to reduce energy consumption, such as turning up the thermostat in the summer to a less comfortable temperature to reduce electricity consumption. This distinction is irrelevant to discussions of total electricity demand. Thus, we use these terms interchangeably herein and often refer simply to conservation.

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IP2 and IP3, (2) demand-side management and energy conservation, or (3) some combination of these options (FSEIS p. 8-22).

Section 8.2 of the FSEIS evaluates the environmental impacts of the no-action alternative without any specific assumptions about energy replacements.

2. Alternative Energy Sources The NRC evaluates alternative energy sources in Section 8.3 of the FSEIS. The five subsections of this part of the FSEIS relate to (1) natural gas-fired combined cycle generation; (2) purchased power; (3) conservation; (4) alternatives dismissed from individual consideration; and (5) combinations of alternatives. These five categories of alternative energy sources are discussed in turn below.

a. New Gas-Fired Combined-Cycle Units The FSEIS includes an alternative that would involve the construction of five new natural gas-fired combined cycle (NGCC) units with a combined capacity of 2000 MW. This alternative was also considered in Entergys Environmental Report and in the Draft SEIS. The FSEIS assumes that these units would have low CO2 emission rates relative to other fossil units (because of their relatively high fuel efficiency) and would be tightly controlled for emissions of conventional pollutants. Some of the potential environmental impactsincluding impacts related to land use, ecological, and waterdepend on the siting of the NGCC units.

b. Purchased Power In the FSEIS, the purchased power alternative relates to bringing power into southeastern New York where IPEC provides energy for consumers. The FSEIS notes that New Yorks transmission system has limited capacity to bring in large amounts of power from outside the downstate area, though the FSEIS points to some proposed projects that could, if built, increase transmission capacity. The FSEIS states in very general terms the kinds of environmental impacts that could be associated with new transmission projects, but does not evaluate them formally, noting that each such project will require its own environmental review process by other State and Federal agencies. As a result, the FSEIS does not present a summary analysis of the environmental impacts of the purchased power alternative.

c. Conservation The FSEIS mentions several electricity conservation programs, including New Yorks Energy Efficiency Portfolio Standard, which is intended to assist in achieving the States goal of reducing energy use from forecasted levels by 15 percent by 2015 (15 x 15). Although it does not identify or address the feasibility of specific incremental conservation measures that could be used to make up for lost baseload IPEC output, the FSEIS concludes that the environmental impacts would generally be small.

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d. Alternatives Dismissed from Individual Consideration The FSEIS notes the alternatives that NRC considered but deemed individually inadequate to replace IPECs baseload energy. The alternatives that NRC dismissed, for various reasons, from further consideration are renewables (including wind, solar, geothermal, and other types of renewables), combined heat and power, oil-fired generation, supercritical coal-fired generation, and delayed retirement of other power plants.

e. Combination Alternatives As the FSEIS (p. 8-59) notes, [t]here are many possible combinations of alternatives that could be considered to replace the power generated by IP2 and IP3. The FSEIS evaluates two possible combinations and presents summary tables with qualitative assessments of various categories of impacts.

i. Combination Alternative 1 Combination Alternative 1 involves:

 continued operation of either IP2 or IP3;

 obtaining 600 MW(e) from renewable energy sources (primarily wind with smaller amounts of hydropower, biomass, and possibly landfill gas); and

 implementing 600 MW(e) of conservation programs based on the States 15 x 15 energy conservation program and other efforts to improve energy efficiency or increase conservation (FSEIS p. 8-60).

The FSEIS notes that the renewable energy would probably be wind or biomass energy, but NRC did not perform an in-depth impact analysis of these potential replacements (FSEIS p.

8-61). It concludes that the environmental impacts of the conservation programs are likely to be negligible (FSEIS p. 8-62).

ii. Combination Alternative 2 Combination Alternative 2 involves:

 repowering an existing fossil-powered plant in downstate New York with a new 400 MW(e) to 600 MW(e) combined-cycle power plant;

 obtaining 600 MW(e) from renewable energy sources (primarily wind, biomass, new hydropower, and landfill gas); and

 implementing 1000 to 1200 MW(e) of conservation programs (FSEIS p. 8-60).

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The FSEIS notes that the environmental impacts of Combination Alternative 2 would include the same types of impacts as the alternative in which IPECs energy is replaced entirely by energy from new NGCC units, but the impacts associated with new NGCC units would be on a smaller scale in Combination Alternative 2 (FSEIS p. 8-67). It also notes that the renewable energy impacts would be similar to those in Combination Alternative 1 (FSEIS p. 8-67). It concludes that the environmental impacts of the conservation programs would be larger than in Combination Alternative 1 but are likely to be negligible (FSEIS p. 8-67).

3. Summary of Staff Recommendations Regarding the Environmental Impacts of Indian Point License Renewal The FSEIS includes the following recommendation from the NRC staff:

that the Commission determine that the adverse environmental impacts of license renewal for IP2 and IP3 are not so great that preserving the option of license renewal for energy planning decision makers would be unreasonable (FSEIS,

p. 9-8).

B. New York States Contention 37 The State of New York has submitted comments throughout the license renewal process critical of the environmental impact assessments prepared by the NRC. The December 2011 pre-filed testimony addresses the three admitted consolidated contentions (9, 33, and 37). We refer to New York States positions in these contentions collectively as NYS-37.

1. Overview of NYS-37 Core Claims The core claim in NYS-37 is that the FSEIS relies on obsolete and inaccurate data and assumptions (p. 1) about electricity demand and supply in New York. The State contends that, as a result, the FSEIS gives inadequate attention to the no-action alternative and, specifically, the availability of other sources of energynotably renewable energyand energy efficiency as replacements for IPEC. NYS-37 argues, without any supporting analyses, that when the recent changes in New York States energy market are taken into account, the no-action alternative would result in substantially lower environmental impacts than those assumed in the FSEIS (pp. 1-2).

The following excerpt from NYS-37 summarizes the States core claims.

The core claim in NYS-37 is that in the FSEIS, NRC staff have failed to present an analysis that takes a hard look at the availability and environmental impact of clean energy sources and energy efficiency and conservation measures that would replace Indian Points power if renewal licenses were not granted. The document unreasonably relies on obsolete and inaccurate information and ignores New Yorks critical comments on DSEIS that demonstrate that the environmental impact of rejecting relicensing of Indian Point will be (1) much less than that NERA Economic Consulting 4

assumed in the FSEIS and (2) will be less than the environmental impact of relicensing Indian Point (NYS-37, p. 3).

NYS-37 also criticizes the FSEIS for not providing a detailed analysis of the potential impacts of the no-action alternative.

In the absence of a complete, site-specific environmental impact analysis of the no-action alternative, the FSEIS fails to provide the public or the decision-makers with a full and fair assessment of the costs and benefits of relicensing (NYS-37,

p. 70).

2. Specific Energy Market Developments Emphasized in NYS-37 NYS-37 puts great emphasis on its claim that the FSEIS ignores various recent developments related to electricity supply and demand in New York. The following list summarizes the recent developments emphasized in NYS-37.

1. New Yorks goal of obtaining 30 percent of electricity demand from renewables by 2015 (30 by 15) and the additional renewable generation it has encouraged;

2. New Yorks goal of reducing electricity demand by 15 percent in 2015 relative to the demand forecast produced in 2007 when the goal was set (15 by 15) and the energy conservation it has spawned;

3. Significant decreases in electricity demand in New York and decreases in forecasts of future electricity demand due to the recession and the slow economic recovery;

4. New Yorks recent and proposed generation capacity additions;

5. Increased supply and lower forecast prices for natural gas; and

6. New transmission lines that increase the transfer capability that is available to deliver power to the downstate region served by Indian Point.

In addition to these policy and energy market developments, NYS-37 and the expert reports also provide estimates of the level of potential future resources that could replace generation at Indian Pointincluding renewables, energy conservation, and purchased power through transmission additions and upgradesalthough the sources of these estimates do not predict that these potential resources actually would be put in place if Indian Point generation were not available. Indeed, as discussed below, despite calling for a site-specific environmental impact analysis of the no-action alternative (p. 70), NYS-37 provides no empirical estimates of the change in the generation mix or the adverse environmental impacts that would result if IPECs baseload energy were not available.

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C. Objectives of This Report The principal objective of this report is to provide information on the potential energy and environmental impacts of the no-action alternative. As noted, it is necessary first to consider the impacts on the electricity system because environmental impacts will be driven primarily by the mix of generation that would replace the lost baseload IPEC generation if licenses were not renewed.

Information on the likely electricity market impacts of the no-action alternative allows us to compare our findings to those in the FSEIS and to evaluate the arguments provided by the State of New York and its experts. To assess the validity of the central argument of NYS-37, it is necessary to conduct economic analyses of alternative sources of power as that is the only way to determine ifas NYS-37 and the experts contendthe conservation/renewable alternative is so dominant that other alternatives, including those relying on fossil generation, should be considered relatively unimportant.

D. Organization of This Report The remainder of the report is organized into four chapters. The next chapter (Chapter II) provides an overview of New York States electricity system and the relative costs of alternative future generation, allowing us to develop assessments of the likely mix of replacement generation if IPEC baseload generation were lost. The chapter includes a discussion of the potential environmental impacts of different replacement power alternatives. Chapter III provides the results of our NEMS modeling of the potential replacement power mix and resulting environmental impacts if IPEC baseload generation were not available. Chapter IV uses the results of our analyses and other information to evaluate the contention of New York State and its experts that the FSEIS should be based upon a replacement mix dominated by renewable and energy conservation. That chapter identifies four major flaws inherent in the claims of New York State and its experts that explain the errors in their conclusions. Finally, Chapter V summarizes our conclusions.

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II. New York States Electricity System and Implications for the Energy and Environmental Impacts of the No-Action Alternative This chapter begins with an overview of New York States electricity system and the central importance of cost minimization in determining which types of generation technologies are built and dispatched to meet electricity demand. We then consider the effects of government support, focusing on New York State support for existing renewables and energy efficiency programs. We then consider the costs of potential future replacement generation if IPEC generation were not available under the no-action alternative, noting the crucial distinction between baseline conditions and changes in generation that could occur under the no-action alternative. We consider the implications of this cost information on the likely mix of replacement generation. The next section of this chapter describes in general terms the adverse environmental impacts of alternative sources of replacement generation. The final section provides our conclusions regarding the likely adverse environmental impacts of the no-action alternative based upon these analyses.

A. Overview of New York States Electricity System This section discusses the New York State electricity system and the importance of cost minimization in the development and dispatch of generation resources in New York States electricity system. We include the effects of current policies to encourage renewables and energy conservation. Note that this general overview does not include specific elements of the electricity market design or conditions (such as transmission constraints and voltage requirements) that must also be recognized when system resources are dispatched.

1. Electricity Market System and Major Actors Until late in the twentieth century, electricity throughout the United States was generated and distributed primarily by vertically integrated utilities that had an exclusive franchise within a given area and were subject to rate-of-return (cost-of-service) price regulation. Many states still rely on that traditional regulatory structure.

Starting in the 1990s, New York and several other states moved to a vertically-disintegrated system in which regulated investor-owned utilities (IOUs), such as Consolidated Edison4, buy most of the power they need to serve their customers from wholesale generating companies, such as Entergy, which rely upon market prices to obtain their revenues. These purchases can occur through spot markets administered by Independent System Operators such as the New York Independent System Operator (NYISO) that manage markets in which generators bid to provide power to the system.

4 The six IOUs in New York State are Central Hudson Gas & Electric, Consolidated Edison, New York State Electric & Gas, National Grid, Orange & Rockland Utilities, and Rochester Gas & Electric. Two other important actors in New York States electricity system are non-profit state entities: Long Island Power Authority (LIPA) and New York Power Authority (NYPA).

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2. Electricity Market Competition and Cost Minimization In New York States competitive wholesale electricity market, generators submit bids that indicate how much power they would be willing to supply at various prices. NYISO finds the price at which sufficient power will be supplied to meet demand at each time of day, and all bidders with bids at or below this market-clearing price receive this price. NYISO also must account for constraints in the electricity system to ensure the systems reliability, but in essence the market determines which units generate electricity to meet demand based on the objective of minimizing costs. In addition to the market for energy, NYISO also administers a market for firm capacity (to ensure adequate supply at times of peak demand) and markets for several ancillary services (NYISO 2011b).

NYISO also prepares studies on the need for new infrastructure in New York State.

However, NYISO lacks the authority to build new infrastructure or to require any other organization to do so. Instead, wholesale generating companies generally make decisions regarding retirement of existing capacity, the amount of new capacity to build, what type of generation capacity to build, and where to build it. Companies make these decisions with the objective of minimizing costs and maximizing revenues. Companies decide what type of generation capacity to build based on levelized costs, which express the sum of capital costs, other fixed costs, and variable costs over the lifetime of the power plant per unit of energy output (e.g., dollars per MWh).

Thus, in New York States competitive wholesale electricity market, cost minimization is central to two different decisions by power companies: (1) the type of generation capacity that will be built based on total levelized costs; and (2) for the capacity that has been built, the bid that will be submitted into NYISOs wholesale energy, capacity, and ancillary services markets based on short-run marginal costs. Companies generally will build new generation capacity only if their expected prices for energy, capacity, and ancillary services are sufficiently above short-run marginal costs to cover capital and other fixed costs (including a normal return to investors). Companies generally will bid to operate their capacity in a given time period (subject to production constraints) if the price will at least cover short-run marginal costs, which are primarily fuel costs in the case of fossil generating units. For nuclear and some types of renewables (such as wind or run-of-river hydro), marginal costs are small relative to potential market-clearing prices, so they operate virtually whenever they are available (i.e., whenever they are not shut down because of scheduled or unscheduled maintenance or because of insufficient wind or water in the case of renewable resources).5 As a result, generation generally cannot be increased at existing renewable units to provide replacement power if IPEC generation were not available as the facilities are fully utilized. In contrast, generation can often be increased at existing fossil-fueled units in order to provide replacement power under the no-action alternative.

5 Nuclear plants have fuel costs, but they are not variable in the very short run. Nuclear facilities also are bid in as baseload facilities because they cannot cycle up and down rapidly.

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B. Government Support for Existing Renewables and Energy Efficiency Programs State and federal policies affect the relative costs of different generation sources in various ways. Federal tax policies subsidize certain types of generation, particularly renewables, thus making companies more able to undertake renewable projects that otherwise would not be cost-effective and profitable. For example, a wind project that otherwise would not be economic under NYISOs market-clearing prices for energy and capacity may become economic by virtue of the Federal tax benefits and State RPS subsidies in addition to the market-clearing price that its owners will receive. Variations over time in additional funding mechanisms such as those tax benefits as well as lower market-clearing electricity prices (causing a larger gap between electricity prices and wind project costs that subsidies must fill) have led to large swings in the amount of wind power constructed in the United States, as shown below in Figure 1.

Figure 1. U.S. Wind Capacity Additions and Availability of Federal Renewable Energy Subsidies Note: Gray bands indicate expiration of federal renewable energy subsidies.

Source: Metcalf (2010)

In Fiscal Year 2010, the federal government provided $6.6 billion to support renewable energy, of which wind generators received $5.0 billion (EIA 2011c, p. xviii). Federal support mechanisms include the production tax credit, which currently provides $22/MWh in corporate tax credit to wind generators and certain other renewable energy producers for the first ten years of operation (DOE 2012). The future levels of federal subsidies and other support mechanisms are highly uncertain, however, and they may fall as part of future potential federal deficit-reduction efforts.

In addition, as discussed in detail below, NYSERDA provides RPS subsidies to renewable generation in New York State. As with federal subsidies, NYSERDAs subsidies are used to augment the market-clearing electricity price that the renewable producers receive from purchasers of their electricity. Thus, the subsidies elicit additional supply of renewable energy.

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The total amount of subsidy offered in any year is limited by a budget set by the NYPSC. The budgets are covered by fees levied by IOUs on New York States electricity consumers through surcharges on their monthly utility bills. As a result of such policies, consumers already pay a premium for renewable energy. Incremental renewable generation above and beyond the RPS program under the no-action alternative would require increased budgets and fees.

State and Federal policies also can influence the amount of electricity demanded by requiring or encouraging energy efficiency and other conservation measures. Mandatory mechanisms include appliance efficiency standards and building codes. Voluntary mechanisms include education and various subsidies. These efforts may involve distribution utilities that offer conservation programs of various types, generally in response to incentives or requirements created by their regulators. In New York, IOUs and NYSERDA collectively recover the costs of such programs through surcharges to New York consumers on their monthly utility bills.

1. New York States 30 x 15 Renewable Electricity Goal This section considers the specific effects of New York States renewable goals on electricity generation. As noted above, state policies can supplement private market forces and substantially influence the generation mix.

a. Overview of New York State Goal and Programs New York has adopted a goal of meeting 30 percent of electricity demand in 2015 (30 x

15) with renewable sources, such as wind, biomass, and hydro. Roughly two-thirds of that goal was met before it was set, because New York historically has generated substantial amounts of power from hydroelectric plants at Niagara Falls, St. Lawrence, and other locations. Those preexisting plants have provided low-cost power for many decades, and are not eligible for the subsidies discussed below. The State expects to obtain most of the incremental resources needed primarily through the RPS program administered by NYSERDA and funded by New Yorks consumers through surcharges on their monthly utility bills. 6 New Yorks RPS differs from RPS programs in many other States. Unlike most other RPSs, New York acquires its renewable resources centrally, through NYSERDA, under a system established in 2004. In 2010, NYPSC increased its original goal of 25 percent renewables by 2013 to 30 percent by 2015, set the MWh level to be achieved by 2015 and also established annual budgets for NYSERDA through 2024 to pay for subsidies it estimates will be required to obtain the additional renewable output needed to meet the goal (NYPSC 2010). New York utilities are required by the NYPSC to assess a volumetric surcharge on electricity sales and transmit the revenues to NYSERDA to pay the subsidies required to support renewable energy projects. In each year, the charge per unit of electricity sold is set so that revenues collected equal the budget for that year. However, there is no guarantee that the goals will be achieved 6

LIPA has its own separate goal, and the NYPSC expects additional resources to be obtained through a voluntary program (under which some customers volunteer to pay higher rates for power provided by renewables) and through other state agencies (NYPSC 2010, Appendix, p. 12).

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within those budgets. Unlike most State RPS programs, there are no penalties for utilities if they do not purchase sufficient energy from renewable resources (NYPSC 2004, p. 5).

NYSERDA solicits bids for production subsidies from renewable project developers and enters into contracts with successful bidders. In the main tier subsidy program, which accounts for about 97 percent of the 30 percent overall goal,7 NYSERDA holds annual auctions to select renewable sources that generally require the lowest subsidy per project (NYSERDA 2011).

These subsidies supplement the market prices (and federal subsidies) that the renewable sources will obtain, thus making construction of the sources viable.

b. Program Budgets to Achieve the Renewable Goal The NYPSC has set substantial budgets for NYSERDA to subsidize renewables through 2024 under the RPS program, as shown in Figure 2. For example, the RPS budget for 2011 was

$170 million and the budget for 2015 is $321 million in nominal dollars. The cumulative budget from 2006 to 2024 is $3.0 billion. The budgets represent the payments that NYSERDA is authorized to make to renewable generators amounts that must ultimately be recovered from New Yorks consumers. Note that these budgets cover only the RPS program to the exclusion of the additional costs of any LIPA and NYPA programs.

7 In addition to NYSERDA contracts with large main tier renewable sources, NYSERDA runs a much smaller program to encourage small-scale, customer-sited projects, such as small wind turbines or solar panels. The goal for these projects is to make up 1 percent of electricity consumption by 2015, or about 3 percent of the 30 percent overall goal. Additional information on these RPS programs is provided in Appendix A.

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Figure 2. Renewable Portfolio Standard Budgets

$350

$321 RPS Budget (million nominal dollars)

$300 $282

$244

$250 $228$227

$203 $202

$194$194

$200

$170

$160

$150 $125

$106$103

$100 $81

$57

$42

$50 $29 $30

$0 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 Source: NYPSC (2010), Appendix, Table 13 NYSERDA estimates that the average production subsidy resulting from the June 2011 offering was over $20 per MWh, or more than one-third the wholesale cost of generation (NYSERDA 2011b, p. 14). The subsidies required to elicit renewable supplies have proved higher than expected when budgets were set. By the end of 2010, NYSERDA had spent 57 percent of its budget for the period through 2015 but had secured only 39 percent of the renewable energy goal (NYSERDA 2011a, p. 21).

2. New York States 15 x 15 Conservation Goal This section describes the other major state policy that influences the electricity market in New York, New York States efforts to reduce electricity use (conservation).

a. Overview of New York State Conservation Goal In 2007, New Yorks then-Governor Eliot Spitzer set a 15 x 15 goal, which called for the State to reduce its energy consumption by 15 percent by 2015 compared to forecast business as usual electricity consumption in 2015. From the outset, there has been broad agreement that the goals of the 15 x 15 goal are substantially more ambitious than prior programs and that meeting them would require additional efforts. In announcing the plan, Governor Spitzer characterized it as the the most aggressive target in the nation (Spitzer 2007). The NYPSC, in adopting the goal and approving several programs intended to help achieve it in the electricity sector, stated that the goal is extremely aggressive (NYPSC 2007).

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In 2007, NYSERDA performed an analysis to develop appropriate contribution levels from LIPA, NYPA, the six investor-owned distribution utilities in the state based on their energy efficiency programs in 2007, NYSERDA, and other state agencies. The analysis also included contributions through codes and standards and measures for transmission and distribution. Figure 3 summarizes the NYSERDA projections as applied to electricity consumption. The jurisdictional gap represented additional reductions from new programs that NYSERDA estimated would be needed to meet the overall goal.

Figure 3. NYSERDA Analysis of Potential Contributions to Meeting 15 x 15 Conservation Goal 25,000,000 Jurisdictional Gap Energy-Efficiency Savings (MWh)

Transmission & Dist 20,000,000 Codes & Standards 15,000,000 Utilities (2007 Programs)

SBC III (NYSERDA) 10,000,000 State Agencies 5,000,000 NYPA LIPA 0

2007 2008 2009 2010 2011 2012 2013 2014 2015 Note:

Source: NYPSC (2008, Appendix 1, p. 5)

To fill this gap, NYPSC announced the Energy Efficiency Portfolio Standard (EEPS) program in 2008. Under that program, the investor-owned distribution utilities would add programs to reduce consumption by their customers and would also fund new programs at NYSERDA. The EEPS program is funded by volumetric surcharges that utilities assess to New Yorks consumers on their monthly utility bills. The NYPSC estimated how much it would cost to implement programs necessary to fill the gap and set surcharge levels to fund such programs through 2011 (NYPSC 2008). In a subsequent order issued in October 2011, NYPSC announced goals for the investor-owned distribution utilities through December 31, 2015 and set new surcharge levels that it estimated would provide sufficient funding for the IOUs and NYSERDA to achieve those goals (NYPSC 2011b).

b. Program Budgets to Achieve New York Conservation Goal The NYPSC has set substantial budgets to support conservation programs for electricity consumption through 2015 under the EEPS program, as shown in Figure 4. For example, the EEPS budget for 2011 was $159 million and the budget for 2015 is $183 million in nominal dollars. The budgets represent the payments that NYSERDA and the IOUs are authorized to make to encourage electricity conservation and the amounts that ultimately must be recovered NERA Economic Consulting 13

from electricity ratepayers in New York. Note that these budgets cover only electricity conservation programs by NYSERDA and IOUS under the EEPS programthey do not include the significant extra payments for electricity conservation by LIPA, NYPA, state government agencies, or other entities with conservation goals under New Yorks overall 15 x 15 policy.

Figure 4. Energy Efficiency Portfolio Standard Budgets

$200

$185 $183 $183 $183 EEPS Budget (million nominal dollars)

$180

$159 $159 $159

$160

$140

$120

$100

$80

$60

$40

$20

$0 2009 2010 2011 2012 2013 2014 2015 Note: Figure shows collections from electricity ratepayers for electricity programs.

Source: NYPSC (2008), Appendix 1, Table 16; NYPSC (2011), Appendix 2, Table 1 C. Costs of Additional Generation in No-Action Alternative This section provides information on the relative costs of alternative generation technologies that could be used to provide replacement generation if IPEC generation were not available. We begin with a conceptual clarification of the generation whose costs are relevant to the comparison, namely the generation that could replace IPEC generation if IPEC were not available. This distinction is important for renewables (and conservation) because of the need to be clear on the role of government support (or lack thereof) for generation beyond current commitments. We then consider information on the costs of potential candidates, including new units of various fuel types and expansion of generation at existing units of various fuel types.

1. Baseline Conditions vs. No-Action Alternative As noted above, the central issue addressed by the FSEIS is the impacts of continued operation of IPEC relative to the no-action alternative. This question relates to the difference in environmental (and other) impacts between an initial scenario in which IPEC is available and a scenario without IPEC generation.

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a. General Distinction For clarity, we define the scenario with IPEC generation as the baseline and then measure the impacts of the no-action alternative relative to that baseline.8 The impacts of the no-action alternative are thus the changes in environmental conditions relative to the baseline (with continued operation of IPEC).

We focus on electricity technologies because before environmental impacts can be evaluated, it is necessary to estimate how the no-action alternative would change the mix of electricity resources (including conservation) used to meet existing demand for electricity services in New York. Any energy developments that occur to an equal degree in both the baseline and the no-action alternative are not directly relevant to an evaluation of the environmental impacts of the no-action alternative. Whatever the baseline is, the relevant question is what incremental resources (including conservation) would replace lost baseload output from IPEC; i.e., what would be the differences in resources between the baseline and the no-action alternative.

b. Illustration of Changes under the No-Action Alternative Figure 5 illustrates how the incremental changes in generation of various types would be calculated using a hypothetical baseline. Note that the components of the stacked bars are not drawn to scale, but are purely hypothetical. The figure does not relate to any particular geographic area. On the left-hand side is a stacked bar showing a hypothetical original forecast of the baseline sources of supplyincluding conservationthat would be used to meet demand. 9 Renewables and conservation play modest roles in this baseline, with the bulk of output coming from IPEC and from fossil and other, where the latter includes power provided by other nuclear plants as well as fossil units.

8 Here we define continued operation of IPEC as our baseline, but we emphasize that the results would be no different if we defined the no-action alternative as the baseline.

9 To simplify the discussion, we treat conservation as a source of supply, although it is more properly considered as part of demand.

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Figure 5. Hypothetical Analysis of Change in Generation from Baseline to No-Action Alternative Renewables Output Conservation IPEC Fossil and other Baseline No-action Change Note: Mixes of resources (and resulting changes) are not drawn to scale and should be interpreted only in qualitative terms.

Source: Hypothetical example The middle stacked bar then shows a hypothetical no-action alternative in which IPEC generation would not be available to meet electricity demand. The final stacked bar shows the changes between the two previous stacked bars. By assumption, all of the output from IPEC would be lost, and it would be made up by some increases in the other three sources (renewables, conservation, and fossil/other sources). These changes in generation and conservation would provide the basis for analyzing the environmental impacts of the no-action alternative relative to the baseline.

The key point of this illustration is that replacement generation represents additional generation that would be forthcoming if IPEC were not available. For purposes of the cost analyses, we first provide information on the expected future levelized costs for different types of new units, excluding the effects of government support. We then assess the costs of additional renewables or additional conservation in the no-action alternative. The final subsection considers the feasibility and costs of expanding generation at existing types of facilities.

2. Levelized Costs of New Capacity Excluding Government Support Figure 6 displays EIAs estimates of levelized costsexpressed as dollars per MWhfor new electricity generating capacity, exclusive of government support (for example, exclusive of Federal tax credits or New York State RPS incentive payments). As discussed above, levelized costs incorporate capital costs, other fixed costs, and marginal costs over the entire lifetime of the power plant. EIAs estimates in Figure 6 suggest that, exclusive of government support, NERA Economic Consulting 16

NGCC units are the least expensive generation alternative and thus would be the most likely to be added in a market setting.10 Figure 6. EIA's Estimates of Levelized Costs for New Capacity, Exclusive of Government Support

$300.0

$243.2

$250.0

$210.7

$200.0 2009$/MWh

$150.0

$112.5

$101.7 $103.5

$94.8 $97.0

$100.0 $86.4

$63.1

$50.0

$0.0 Gas Hydro Coal Wind Geo- Gas / Oil Biomass Solar PV Wind Combined Onshore thermal Combustion Offshore Cycle Turbine Note: Figure shows EIA estimates based on AEO 2011 because EIA estimates based on AEO 2012 are not currently available; natural gas price forecasts in AEO 2012 are lower than in AEO 2011 and thus gas-fired power plants have a larger economic advantage based on AEO 2012 than shown here.

Source: EIA (2011b)

3. Costs of Additional Renewables This section considers the complications related to additional New York State renewable generation in the no-action alternative, first noting that future progress toward the current renewable goal is not relevant and then demonstrating that additional renewables are likely to be more expensive than the renewables developed under the current renewable goal.

a. Progress toward Renewable Goal NYSERDAs 2011 RPS Performance Report states that, as of December 31, 2010, generation from the programs current contracts would produce renewable energy equivalent to 39 percent of the 2015 target. Whatever renewable generation is ultimately encouraged through 10 These estimates do not account for the many complications related to location, architecture, usage, potential technological progress and other factors. See Borenstein (2011) for a discussion of these issues and comparisons of different estimates of levelized costs for alternative generation technologies.

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the program, however, that level will be reflected in the baseline. This progress is not directly relevant to IPEC license renewal. The States renewable goal and its associated programs are part of the baseline for purposes of evaluating the no-action alternative; the changes due to the goal and programs will occur regardless of whatever else occurs on the system. Thus, renewable generation elicited by the programs subsidies cannot be counted in the no-action alternative. For renewables to play a significant role in replacing IPECs generation, additional renewables, beyond the goals of the existing RPS program, would be needed.

b. Costs of Additional Renewables Using Baseline Costs per MWh As discussed below, expanding the renewables program to help replace IPECs energy would tend to increase the subsidies per MWh needed to elicit sufficient supply. But even if the subsidies per MWh did not increase, replacing all of IPECs energy with renewables would cost New Yorks electricity consumers over $500 million per year in subsidies over and above market replacement costs, based on implied costs per MWh for the NYPSCs current RPS programs. 11 That is more than the existing budget even in the peak year shown in Figure 2, which is $321 million. To meet even this cost (which is likely to be conservative), the NYPSC would have to increase its budgets and raise the monthly surcharges assessed to New York consumers commensurately.

c. Costs of Additional Renewables Accounting for the Incremental Effects on Costs per MWh As noted above, the relevant question is not the cost of renewables in the baseline, but rather the incremental cost of additional renewable generation under the no-action alternative. In New Yorks competitive market for generation, any increase in incremental costs for renewables will in turn reduce the likelihood that renewables would successfully compete with fossil power under the no-action alternative.

The qualitative rationale for expecting an increased cost for additional renewables beyond the current goal is straightforward. There is a supply curve for renewables, which is a function of the total price received per unit generated. Holding constant the market price for electricity (which is determined by gas-fired units most of the time) and federal subsidies, we can plot the supply curve as a function of the subsidy paid by NYSERDA. Figure 7 plots a hypothetical supply function. The larger the subsidy, the more renewables would participate in the market. Conversely, the larger the quantity of renewables desired, the larger the subsidy must be. Thus, as noted in Figure 7, if the quantity of renewables in the baseline (with the 30 by 15 11 This calculation uses 16.3 million MWh as IPECs annual energy (NYISO 2011a, p. 34). In 2015 (the final year for which an RPS goal is specified), the RPS program has a goal of 10.4 million MWh and a budget of

$321 million (NYPSC 2010, Appendix, Tables 13 and 17). IPECs annual energy is 57 percent larger than the RPS goal for 2015, so the necessary budget would need to be 57 percent larger: $504 million (in 2015 dollars assuming that the cost of securing substantial amounts of additional renewable resources incremental to the baseload would remain the same). Using a different year than 2015 to estimate the necessary additional budget would yield a larger estimate.

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policy in place) were QB, obtaining additional renewables to a level of QN would require an increase in the subsidy from SB to SN.

Subsidy ($/MWh)

Supply SN S

SB Q

QB QN Quantity generated by renewables Figure 7. Impact of Additional Renewables on Subsidy Rates per MWh Notes: QB: Quantity of renewables in baseline with 30 x 15 policy Q: Additional renewables desired under the no-action alternative QN: Quantity of renewables with 30 x 15 policy under the no-action alternative SB: Subsidy rate for baseline with 30 x 15 policy S: Additional subsidy required under the no-action alternative SN: Subsidy rate required with 30 x 15 policy under the no-action alternative The rising supply curve reflects the fact that different renewable projects differ in their costs, and hence in the incremental subsidy needed if they are to be built. For example, for wind projects, there may be some projects with relatively low costs, requiring relatively small subsidies. Those projects would be built first. Other projects, however, will have higher costs, perhaps because of less favorable wind conditions, more remote locations, or higher transmission costs. Those projects will not be built unless the subsidies are higher.

The implication of a rising supply curve is that the subsidy required to elicit additional renewables to replace IPEC generation would be greater than the current subsidy levels, making it even less likely that renewables would constitute a substantial share of replacement generation.

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4. Costs of Additional Conservation This section considers the complications related to additional conservation, which are analogous to those for additional renewable generation. We first note that future progress toward the current conservation goal is not relevant and then demonstrate that additional conservation is likely to be more expensive than the conservation developed under the current energy efficiency goal.

a. Progress toward New York State Conservation Goal NYS-37 and its supporting documents argue that if the 15 x 15 plan is successful, it will reduce demand by more than IPECs annual generation (NYS-37, p. 49). As part of its forecasting and planning analyses, NYISO has evaluated the likely achievement of electricity conservation in New York through 2021. NYISO (2011a, p. 21) does not expect the 15 x 15 goal to be met by 2015.12 However, even if the 15 x 15 goal is met, the comparison between program success and IPEC generation is meaningless to the issue at hand because it relates to the baseline and has no direct effect on what resources (including energy efficiency and conservation) would be used incrementally under the no-action alternative. Put another way, the conservation used to achieve the 15x15 goal will not be available to provide the additional conservation under the no-action alternative.

b. Costs of Additional Conservation Using Baseline Costs per MWh Expanding the conservation program under the no-action alternative would increase the subsidies per MWh needed to elicit sufficient supply. Even if the subsidies per MWh did not increase, attempting to replace all of IPECs energy with conservation would cost New Yorks electricity consumers about $250 million per year in additional subsidies, based on implied costs per MWh for the NYPSCs current EEPS programs.13 To meet that cost, the NYPSC would have to increase its budgets and raise or extend (or both) the monthly surcharges assessed to New York consumers commensurately..

12 NYISO (2011, p. 21) forecasts a gap of about 7,500 GWh in 2015 between necessary energy supply with expected energy efficiency achievements and necessary energy supply with full achievement of the goal. This gap represents about 28 percent of the goal (i.e., about 4 percentage points of the 15 percent goal). Appendix A provides more information on New Yorks 15 x 15 programs.

13 This calculation uses 16.3 million MWh as IPECs annual energy (NYISO 2011a, p. 34). In 2015 (the final year for which an EEPS goal is specified), the EEPS program has a goal of 12.1 million MWh (NYISO 2012, slide 5) and a budget of $183 million (NYPSC 2011, Appendix 2, Table 1). IPECs annual energy is 35 percent larger than the EEPS goal for 2015, so the necessary additional budget would be 35 percent larger than the budget for 2015: $247 million (in 2015 dollars with the same caveat as above about the uncertain ability to secure significant additional amounts of conservation incremental to the baseline at the same cost). Using a different year than 2015 to estimate the necessary additional budget would yield a larger estimate.

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c. Costs of Additional Conservation Accounting for the Incremental Effects on Costs per MWh As with renewable generation, undertaking more intensive conservation efforts would likely raise the marginal cost of additional conservation, thus further increasing the expenditures needed to secure additional conservation under the no-action alternative.

As with renewables, it is useful to summarize the variety of measures available to reduce electricity use in terms of a supply curve for conservation, which shows the marginal cost of subsidies and other programs to elicit additional conservation beyond what occurs due to prices and technological advances that lower the extra cost of more efficient equipment and structures.

As with most supply curves, the marginal cost of conservation rises as additional conservation is undertaken (Gillingham et al. 2004, p. 66).

Initial conservation efforts may yield amounts of low-hanging fruit available at relatively low marginal cost, but later efforts must employ increasing costly measures. For example, increased use of compact fluorescent lights (CFL) is widely seen as a low-cost way to reduce electricity consumption, including in New York (Maniaci 2011, slide 3). Additional conservation, however, requires higher cost measures. That conclusion appears to be supported by estimates of the cost-effectiveness of various conservation programs run by NYSERDA and New York distribution utilities. NYSERDA estimates that its CFL program reduces demand at a cost of $20 per megawatt-hour (MWh) (Maniaci 2011, slide 7).14 The average cost of other programs is $360/MWh (Maniaci 2011, slide 7).

In comments on the recent white paper prepared as part of the NYPSCs review of its EEPS program, NYISO presents an upward sloping supply curve for conservation based on recent experience in New York, as shown in Figure 8. In preparing this graph, NYISO used data in the white paper to plot the cost of the EEPS programs as a function of the cumulative gigawatt-hours (GWh) saved. The cost rises substantially as the level of energy saved increases. This graph shows results for existing programs. Incremental programs to help reduce demand to replace IPEC under the no-action alternative would require going further. Although the highest costs in the figure may represent programs that the NYPSC supports for reasons other than cost-effectiveness, the curve nonetheless illustrates that as opportunities for relatively low-cost programs are exhausted, additional demand reductions can only be secured by incurring higher costs.

14 Note that the costs of conservation measures estimated by NYISO and State agencies in New York are not comparable to avoided cost estimates for generation. The NYISO costs for conservation measures represent only the costs to utilities or program administrators and do not include the residual costs for consumers to purchase energy-efficient appliances or undertake other conservation activities. Wholesale electricity prices, however, represent the full marginal cost of producing electricity. On the other hand, these figures compare the one-time costs of the programs to annual electricity savings, whereas wholesale prices reflect costs amortized over the lives of the facilities.

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Figure 8. EEPS Energy Efficiency Supply Curve Cost $ per MWh Versus Cumulative GWh Note: Horizontal axis is cumulative energy saved per year, in GWh. The vertical measure is marginal cost per MWh saved annually. However, because the costs are incomplete and are not amortized over the effective lives of the programs, the marginal costs are not directly comparable to levelized estimates of cost per MWh generated.

Source: NYISO (2011d)

The graphical analysis of a higher baseline level of conservation is essentially the same as the analysis for renewables in Figure 7. Increasing conservation programs to help meet reduced output from IPEC under the no-action alternative would require increased rates of expenditure per unit of electricity saved, assuming that additional conservation programs could even be designed beyond those intended to meet the ambitious New York State goal at any price. The higher the baseline level of conservation assumed, the higher would be the cost per unit of electricity saved, so that the higher baseline level of conservation would make it more difficult and costly to secure any incremental conservation initiatives beyond the baseline EEPS program to be used in the no-action alternative (again assuming that additional initiatives could be identified and implemented effectively).

5. Costs of Generation at Existing Sources As noted above in the discussion of competitive electricity markets, after power plants have been built, their utilization (i.e., hours of operation per year) depends on physical constraints and their marginal costs relative to electricity prices. Apart from transmission constraints, the basic physical constraint for all power plants is their maximum rated capacity.

Wind, solar, and hydro facilities have an important other physical constraint: the availability of NERA Economic Consulting 22

wind, sunlight, and water, respectively. After these types of power plants have been built, their marginal costs of operation are virtually zero, so they generally operate during all times when physical constraints allow. The utilization of fossil fuel power plants is much more sensitive to market forces, particularly electricity prices, although many coal units are baseload units that operate virtually all of the time. If more generation is needed from the electricity system, such as in the no-action alternative, fossil fuel power plants not operating at full capacity in all time periods would be able to increase their utilization. This situation is in contrast to the situation for wind, solar, and hydro facilities.

Table 1 summarizes the situation for different fuel types and shows estimates of the marginal costs per MWh of generation (from existing facilities or facilities that would be built in the future) based on fuel price projections, heat rates (a measure of fuel input per unit of energy output), and variable operating and maintenance (O&M) costs from EIA (2011, 2012).

Marginal costs are estimated for the generation technologies that are generally capable of increasing utilization, which include fossil fuel power plants and do not include wind, solar, or hydro facilities. Based on the estimated variable costs in Table 1, coal and NGCC units are most likely to increase their utilization as replacement generation for IPEC because these two generation technologies have the lowest marginal costs.

Table 1. Estimates of Marginal Costs of Generation Capable of Increasing Utilization Marginal Costs (2011$/MWh) in Response to Market Forces? O&M Fuel Total Coal Yes $2 $21 $23 Natural Gas

- Combined Cycle Yes $2 $31 $33

- Combustion Turbine Yes $11 $47 $58 Oil Combustion Turbine Yes $17 $255 $272 Wind No - - -

Solar PV No - - -

Hydro No - - -

Note: - indicates that the variable costs are not estimated because the generation technology generally cannot increase utilization in response to market forces.

Assumed heat rates are 8,800 Btu/kWh for coal, 7,050 Btu/kWh for gas combined cycle, and 10,745 Btu/kWh for combustion turbines based on EIA estimates for new power plants. If existing power plants have higher heat rates, their fuel costs would be higher.

Source: NERA calculations based on EIA (2011) and EIA (2012)

D. Implications of Relative Costs on the Mix of Replacement Energy in No-Action Alternative This section draws on evaluations of the previous sectionsnotably the competitive nature of the electricity market in New York and the relative cost of alternative generation that could replace IPEC generationto provide assessments of the likely mix of replacement energy under the no-action alternative. The importance of market conditions in New York means that information on relative costs must be used to provide assessments of the extent to which various NERA Economic Consulting 23

generation types would be likely to replace IPEC generation in the no-action alternative, i.e., the relative size of the changes in the final bar in Figure 2.

1. Additional Fossil Fuel Generation Additional fossil fuel generation is likely to constitute the major replacement generation if IPEC generation were not available. The least expensive generation options are likely to come from increases in generation at existing units, particularly from coal and natural gas units that are not operating at full capacity. Among new units that might be added as replacement generation, new NGCC units have the lowest levelized costs (i.e., costs per MW-hr, including capital, fuel and other operating and maintenance costs).

2. Additional Renewable Generation Additional renewable generation is not likely to be a major part of IPEC replacement generation. New York State has an ambitious renewable goalaccompanied by substantial subsidy programsthat extends into the future. But that future renewable generation would be put in place regardless of IPECs status. Thus, the future renewable generation due to the New York State renewable goal is in the baseline rather than as additional generation that would be available to replace IPEC generation.

Expanding renewable generation beyond the current goal would likely require an increase in the level of subsidy beyond the current levels. The comparison of levelized costs shows that wind generationthe lowest cost renewable generation for New York Statewould be substantially more expensive than natural gas. Given the market structure in New York and its focus on minimizing the costs of additional generation, the relative cost information indicates that additional wind generation is not likely to be added as replacement generation if IPEC were not available.

3. Additional Energy Efficiency and Conservation Additional energy efficiency also is not likely to be a major part of IPEC replacement generation for reasons similar to those relevant for renewable generation. Of course, given that removal of IPEC generation would lead to increased retail electricity prices, there will be some effect on conservation through price effects. However, most studies put the price elasticity for electricity at around -0.2, which means that a 10 percent increase in retail electricity price would result in a 2 percent decrease in electricity demand (Bernstein and Griffin 2005, pp. 18, 21).

Thus, we would not expect the price effect on electricity demand to be substantial given the relatively low price elasticity of demand for electricity.

As noted above with regard to renewables, the level of energy efficiency to be achieved by New York States current programs is in the baseline, since it would be achieved regardless of IPECs status. Given the increased costs (and thus subsidies) that would be required to expand energy efficiency programs, we conclude that it is not likely that additional energy efficiency NERA Economic Consulting 24

would account for substantial IPEC replacement generation (beyond price-induced conservation).

E. Adverse Environmental Impacts of Generation Alternatives This section provides information on the environmental impacts of fossil-fuel and renewable electricity, including wind, biomass and hydroelectric sources. These assessments are general and do not relate to specific generation facilities. The following chapter provides additional specific environmental information based upon energy market modeling of the adverse environmental impacts of the no-action alternative.

1. Fossil-Fuel Generation Our analyses, including those discussed further in subsequent chapters, indicate that if Indian Point generation were not available, a substantial portion of the IPEC generation would be replaced by fossil-fuel generation (natural gas and coal). This subsection summarizes some of the potential adverse environmental impacts of fossil-fuel generation.

a. Air Pollutant Impacts Fossil-fired generating units emit various air pollutants. Table 2 summarizes the air emissions from natural gas and coal units that have been identified by EPA in recent analyses of potential air emission regulations affecting electricity generation.

Table 2. Air Pollutants by Generation Plant Type Plant Type Air Pollutant Coal Gas Nuclear CO2 and other greenhouse gases yes yes -

Sulfur dioxide (SO2) yes yes -

Nitrogen oxides (NOx) yes yes -

Particulate matter yes yes -

Mercury and other heavy metals yes - -

Carbon monoxide yes yes -

Volatile organic compounds yes yes -

Acid gases yes - -

Source: EPA (2011a), EPA (2011b)

i. Illustrative Emission Rates Table 3 shows average emission rates for three major pollutantsCO2, SO2, and NOX -

for coal and natural gas-fired electricity plants in the United States. These emission rates relate to all existing power plants in the United States for each fuel and thus are averages for different natural gas generation technologies (e.g., gas-fired turbines and combined cycle units) and different power plant ages. The emission rates will therefore differ from rates in the FSEIS, NERA Economic Consulting 25

which relate only to new natural-gas-fired power plants, which have lower rates than the average for existing units. Based on IPECs annual generation of over 16 million MWh (NYISO 2011a,

p. 34), even if only a portion of this generation is made up by fossil-fired generation, the increased emissions of these pollutants would be substantial.

Table 3. Average Emission Rates Emission Rates (lbs/MWh)

CO2 SO2 NOx Coal 2,122 8.9 3.1 Natural Gas 944 0.1 0.5 Source: NERA analysis based on eGRID (2010)

The following subsections highlight some of the potential health and other impacts associated with these three pollutants. (The size of the impacts depends upon many site-specific factors, including emission rates, meteorological conditions, population exposures, and background concentrations.)

ii. Impacts Associated with NOX and SO2 Emissions Emissions of nitrogen oxides (NOX) and sulfur dioxide (SO2) are the primary causes of acid rainwhich can lead to acidification of water bodies and other effectsand can also lead to various adverse health effects. NOX and SO2 are also important precursors in the formation of fine particles (PM2.5) and ozone (NOx only). EPA (2011b) links NOX and SO2 emissions to the following potential effects:

 Asthma complications;

 Chronic lung disease;

 Premature mortality;

 Other respiratory effects;

 Tree mortality and injury to vegetation; and

 Degradation to ecosystems.

iii. Impacts Associated with CO2 and Other Greenhouse Gases According to the Interagency Working Group on the Social Costs of Carbon (2011),

climate change induced by greenhouse gas emissions adversely affect:

 Agricultural productivity;

 Human health;

 Water table levels resulting in flood risk; and

 Ecosystem functions.

Since CO2 is a global pollutant, these effects depend upon global emissions (and concentrations) rather than emissions in New York State or the United States.

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b. Land Use Any new fossil-fired capacity built under the no-action alternative would have land use effects. The FSEIS notes that a new natural gas plant would require between 0.016 to 0.045 hectares (0.04 to 0.11 acres) of land per MW capacity (FSEIS, p. 8-29). The FSEIS also notes that new natural gas capacity could require construction of additional wells, collection stations, and pipelines (FSEIS, p. 8-30). The FSEIS indicates that 15 hectares (37 acres) would be required per megawatt of capacity due to these additional facilities.

c. Impacts Related to Hydraulic Fracturing to Extract Natural Gas Recent developments in the technologies for extracting natural gasreferred to as hydraulic fracturing or frackinghave led to some environmental concerns. In recognition of these concerns, the New York State Department of Environmental Conservation (NYSDEC) recently issued a draft supplemental environmental impact statement, stating that [h]igh-volume hydraulic fracturing, which is often used in conjunction with horizontal drilling and multi-well pad development, is an approach to extracting natural gas in New York that raises new, potentially significant, adverse impacts (NYSDEC 2011, Executive Summary, p. 1). The NYSDEC is proposing regulations to address such concerns.

2. Wind Generation NYS-37 claims that the environmental impacts associated with the no-action alternative would be less than the environmental impact of relicensing Indian Point (p. 3), presumably based upon its assumption that much of the replacement generation would come from renewable electricity. NYS-37 does not provide any information on the potential environmental effects of renewable generation. It is useful to provide information on the potential environmental effects of renewablesincluding wind in this section and biomass and hydroelectric in subsequent sectionsto provide adequate information concerning the NYS-37 claim. Although wind generation dominates the current renewable generation in New York State, all three of these types are eligible for RPS credits and are represented in current contracts.

This section summarizes some of the types of environmental impacts associated with wind capacity. Note that new wind capacity may not be built in downstate New York and thus would likely require construction of new transmission lines with their own associated adverse environmental impacts, as discussed below.

a. Bird and Bat Mortality Wind farms can cause the death of birds and bats in two main ways (Ifran 2011). First, birds and bats can collide with wind turbine blades. Second, bats can suffer internal bleeding when they fly through pockets of low pressure behind rotating blades (barotrauma).

The impacts of wind energy on birds and bats have been noted by Federal agencies, State agencies, and other organizations. The U.S. Government Accountability Office noted in 2005, NERA Economic Consulting 27

when the United States fewer wind farms than currently, that studies at wind farms in California and West Virginia indicated thousands of bird and bat mortalities per year and that studies in other regions of the country were needed (GAO 2005). The U.S. Fish and Wildlife Service notes that wind energy facilities can adversely impact wildlife, especially birds and bats, including threatened and endangered species and other protected species, such as the bald eagle (FWS 2011). The New York State Department of Environmental Conservation requires developers of wind farms in New York to evaluate potential impacts on birds and bats as part of their environmental impact statements (NYSDEC 2009).

The American Bird Conservancy has filed a petition requesting that the FWS issue regulations to address the adverse impacts of wind energy on birds (ABC 2011). The ABC cites estimates that 440,000 birds were killed by wind turbines in 2009 and at least one million birds would be killed in 2020 based on growth projections for wind energy (ABC 2011, p. 6). The ABC calls for regulations that would ensure compliance with the Migratory Birds Treaty Act, the Endangered Species Act, and the Bald and Golden Eagle Protection Act. The Bats and Wind Energy Cooperative has an analogous goal of protecting bats from the adverse impacts of wind energy (BWEC 2012). Bats aid farmers by eating insects, and bat deaths at wind facilities reduce crop sales by almost $4 billion each year (Boyles et al. 2011).

The National Wind Coordinating Collaborative indicates that wind farms in New York kill between approximately 1.5 and 6 birds per MW per year and kill between approximately 3 and 15 bats per MW per year (NWCC 2010). Assuming a 30 percent capacity utilization factor for wind turbines (NYISO 2010, p. 44), approximately 6,000 MW of wind turbines would be required to replace the 16 million MWh of annual energy output from IPEC. Based on the mortality rates from the NWCC, these wind turbines would kill between 9,000 and 36,000 birds each year and between 18,000 and 90,000 bats each year.

b. Land Requirements Wind farms can require a significant amount of land around the wind turbines and transmission stations. These land requirements can also have adverse impacts on wildlife by interfering with their habitat and migration routes (GAO 2005). The FSEIS cites the National Renewable Energy Laboratory as estimating that the total land disturbance for onshore wind energy is 1 hectares (2.5 acres) per MW, but 70 percent of this area is only disturbed temporarily for construction (FSEIS, p. 8-62). Thus, 6,000 MW of wind turbines to replace IPECs energy output would disturb 6,000 hectares (15,000 acres or over 23 square miles of likely non-contiguous area for the turbines, access roads, and maintenance buildings). Area requirements for offshore wind energy, while lower, are still substantial (FSEIS, p. 8-62).

c. Aesthetics Modern wind turbines rise hundreds of feet into the air and can be seen from great distances. Wind turbines can significantly affect the aesthetic qualities of their areas, particularly in areas with substantial aesthetic value before the construction of wind turbines, such as forests, rivers, and lakes. Figure 9 compares the height of a 550 ft. wind turbine with a typical utility NERA Economic Consulting 28

pole, transmission tower, and forest tree. If the wind turbines replacing IPEC each had a capacity of 5 MW (a common turbine size), 1,200 tall wind turbines would need to be installed with potentially significant aesthetic impacts.

Figure 9. Height Comparison of Wind Turbine and Other Structures Source: ABC (2011), p. 41

d. Noise The whirling blades of wind turbines can cause a noise nuisance for people living near wind turbines (Zeller 2010). This noise nuisance can affect many people if the wind turbines are located in densely populated areas. Figure 10 shows the location of current and proposed wind farms in New York. Most wind farms are located in the sparsely populated areas of upstate New York. If any new wind turbines to replace IPEC were built in the densely populated areas of downstate New York, noise from the turbine blades could be a nuisance for many people in the area.

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Figure 10. Location of Current and Proposed Wind Farms in New York Source: NYISO (2011), p. 30

e. Other Environmental Impacts An additional potential adverse impact of wind energy is ice throws (Galbraith 2008). If ice on turbine blades does not stop them from spinning, the blades can sometimes fling chunks of ice several hundred yards at high speeds.

f. Transmission As reflected in Figure 10, wind generation development has primarily been centered on three regions in western and northern New York due to wind patterns. The NYISOs interconnection queue indicates a continued pattern in this regard. Thus, assuming any significant incremental amount of wind generation development under the no-action alternative requires also taking into consideration the adverse environmental impacts associated with significant transmission upgrades. These impacts are addressed separately below.

3. Biomass Facilities This section provides an overview of the potential environmental effects of additional biomass-fired resources. As noted, a limited amount of biomass facilities are being used to meet New York States RPS requirements.

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As with fossil-fired generation, the burning of biomass results in the emissions of various air pollutants. Table 4 displays air emissions rates from biomass facilities for SOx, NOx, CO, and PM10 as reflected in National Renewable Energy Laboratory (NREL) (2003) reports.

Table 4. Direct Air Emissions from Wood Residue Biomass Facilities (lbs/MWh)

Source: NREL 2003

4. Hydro Facilities This section provides an overview of the potential environmental effects of additional hydroelectric resources. Note that new large-scale hydro development was excluded as an eligible resource under New Yorks RPS program due to its significant adverse environmental impacts (NYPSC 2004, Appendix B, page 2).

a. Greenhouse Gas Emissions Hydroelectric facilities are responsible for increases in greenhouse gas emissions during both construction and operations. Indeed, a literature review by Synapse Energy Economics notes that initial reservoir flooding leads to an initial stage of biomass decompositionreleasing both CO2 and methaneand that post-flooded biomes may remove less carbon from the atmosphere than pre-flooded biomes (Synapse 2012). A recent study performed at a newly flooded boreal reservoir in Quebec showed a rapid increase in both CO2 and methane emissions after the first year of flooding, followed by a return to natural levels within two and three years respectively (Tremblay et al. 2009). Tremblay et al. (2009) note that GHG emissions at boreal reservoirs typically return to natural levels within ten years of flooding. Hydro-Quebec provides information on life-cycle assessmentsincluding emissions from fuel extraction, processing and transportation, as well as from power plant construction and electricity generationthat shows typical greenhouse gas emission results for North American hydro facilities (Hydro-Quebec 2002).

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b. Other Emissions The construction of hydroelectric plants leads to the emissions of other compounds that are responsible for adverse environmental impacts. The International Energy Administration (IEA) lists the following types of impacts associated with emissions released during the construction of hydroelectric facilities (IEA 2002):

 Ozone layer depletion,

 Acidification,

 Eutrophication,

 Photochemical oxidant formation, and

 Ecotoxic impacts.

c. Other Impacts The IEA also notes that operation of hydroelectric facilities can lead to the following adverse environmental impacts (IEA 2002):

 Increased local humidity,

 Erosion and sedimentation of streams,

 Damages to aquatic habitat,

 Impacts to local biodiversity,

 Impacts on fish populations, and

 Aesthetic impacts.

5. Transmission Expansions Electricity demand in New York State is most heavily concentrated in the southeast part of the State, but as reflected in Figure 10 and the NYISO Interconnection Queue, the vast majority of proposed wind projects are located in western and northern New York. The existing transmission facilities between upstate and downstate already are significantly constrained. In addition, the distribution systems in the three primary areas of wind generation development in New York now face local transmission constraints, creating the potential for generation pockets in these areas. Thus, additional renewable development incremental to the RPS program in the baseline would likely require the development of significant new transmission infrastructure.

The siting and construction of new transmission lines would result in additional adverse environmental impacts such as the clearing of forested vegetation and subsequent displacement and impacts on wildlife, including impacts to fish and aquatic invertebrates due to canopy reduction and stream crossings. Transmission expansions can have adverse impacts on birds, including mortality from collisions and electrocution (ABC 2012).

The DEIS for the Hounsfield Wind Farm in Jefferson County, New York, indicated that 50.6 miles of transmission lines would have to be constructed to connect the wind farm to its regional power grid (Hounsfield DEIS 2009). Hounsfields proposed transmission corridor NERA Economic Consulting 32

entails a 150-foot wide right of way which was estimated would lead to the clearing of 360 acres of forested vegetation and subsequent displacement and impacts on wildlife, including impacts to fish and aquatic invertebrates due to canopy reduction and 53 stream crossings (Hounsfield DEIS 2009).

The Public Service Commission of Wisconsin lists 18 potential impacts associated with transmission lines. These include impacts of the following categories: aesthetics, agricultural lands, airports and airstrips, archeological and historical resources, cultural concerns, electric and magnetic fields, endangered/threatened and protected species, implantable medical devices and pacemakers, invasive species, noise and light impacts, property owner issues, radio and television reception, recreation areas, safety, stray voltage, water resources, wetlands, and woodlands (PSCW 2011).

The Joint Proposal for the Champlain Hudson Power Express transmission project (discussed in Appendix C) provides illustrative information on the types of environmental impacts from the installation of some potential transmission lines. The environmental impacts listed for the Champlain Hudson Power Express transmission project include the following (Champlain Hudson 2012):

 Dredging would be required to lay cables in the Hudson River and portions of Lake Champlain, resulting in temporary sediment resuspension and other impacts;

 Construction would result in temporary impacts to 56 acres of wetlands as well as to streams and tributaries;

 About 10.7 acres of forested wetland cover may be permanently converted to marsh or scrub-shrub communities;

 Approximately 236 acres of existing forest cover may be cleared during construction, 60 acres of which would be permanently cleared;

 Three miles of cable would be installed within the city streets in the borough of Queens, New York City; and

 138,040 linear feet of right-of-way within Agricultural Districts would be included in the Construction Zone.

F. Conclusions Regarding the Likely Adverse Environmental Impacts of the No-Action Alternative The competitive electricity market structure in New York State will lead to replacement generation being dominated by the lowest cost alternatives (subject to system constraints). Since fossil-fuel generation provides for overall lower cost power than renewables, most replacement power is likely to be fossil-fuel generation. Additional fossil-fuel generation will lead to increases in CO2 and other air emissions as well as other potential adverse environmental NERA Economic Consulting 33

impacts. Indeed, even if additional renewables could replace some of IPECs generation, such additional renewables would have adverse environmental impacts, as discussed above. The next chapter provides quantitative estimates of the likely environmental impacts of the no-action alternative based upon results from electricity market modeling.

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III. Quantitative Modeling of the Potential Energy and Adverse Environmental Impacts of the No-Action Alternative This chapter provides quantitative assessments of the potential energy and environmental impacts of the no-action alternative using NEMS, a detailed and widely used EIA model. EIA uses NEMS to perform policy analyses in response to requests from Congress, the White House, the Department of Energy, and other Federal agencies. EIA prepares an Annual Energy Outlook (AEO) with long-term projections of energy prices and quantities. NEMS is also used by the national laboratories (e.g., Cort et al. 2007), academics (e.g., Hoppock et al. 2012), think tanks (e.g., Krupnick et al. 2010), and the private sector.

As noted above, the baseline must first be established to provide the point of comparison for the no-action alternative. We used NEMS to develop estimates of the potential energy and environmental impacts of the no-action alternative by comparing NEMS results between (1) a baseline scenario in which IPEC continues to operate; and (2) a no-action alternative in which IPEC baseload generation is lost. The differences between these two runs represent NEMSs projections of how electricity markets in New York State and other regions might respond under the no-action alternative. For the baseline, we used NEMS results from EIAs AEO 2012. For the no-action alternative, we assumed that baseload generation from IP2 and IP3 would be lost in 2013 and 2015, respectively. Note that these hypothetical dates were simply assumptions used only for the purpose of conducting the modeling.

NEMS incorporates up-to-date information on national, regional, and State energy and environmental policies as well as information on existing and proposed power plants. NEMS divides the United States into 22 electricity regions, including three regions that collectively cover all of New York State.

This chapter begins with an overview of NEMS. Additional background information on NEMS appears in Appendix B. This chapter then presents NEMS results for baseline energy conditions, the potential energy impacts of the no-action alternative, and the associated potential adverse environmental impacts of the no-action alternative. The tables with NEMS results relate to the United States as a whole, but we also note significant results for New York State.

A. Overview of NEMS NEMS is a detailed energy market model that is composed of multiple modules that interact to generate projections of prices and quantities. These modules include ones that project demand and supply from various sectors. The Electricity Market Module provides projections for 22 regions across the United States. New York is modeled by three NEMS regions that cover (1)

New York City and Westchester County; (2) Long Island; and (3) the rest of the state. The Electricity Market Module projects capacity, generation, fuel use, and air emissions, among other measures for each region. The model also accounts for international trade in electricity with Canada and Mexico.

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EIA updates NEMS once a year to prepare the Annual Energy Outlook. As noted above, NEMS projections reflect Federal, regional, and State energy and environmental policies that have been enacted as of the modeling date. The energy policies include Federal subsidies for particular types of generation, including renewables subsidies. In addition, NEMS incorporates RGGI and RPS policies in various states, including New York States 30 x 15 RPS goal. We used the latest version of NEMS, AEO 2012, which was released in January 2012 (EIA 2012).

Unlike many models of electricity markets, NEMS does not treat demand projections as input data. Instead, NEMS calculates demand for electricity endogenously, reflecting various factors, including energy efficiency policies and electricity prices. NEMS also calculates prices endogenously, reflecting the interaction of supply and demand factors. NEMS incorporates planned additions and retirements of generating capacity, but also projects unplanned additions and retirements based on demand and the costs of different generation alternatives. In deciding how much capacity of different types to add, NEMS selects the least-cost alternative that can meet the demand requirements.

NEMS can be used to estimate the impact of changes in policy, such as a cap-and-trade program for greenhouse gases, air pollution regulations that would require additional control measures by some types of power plants, or policies to increase the fuel efficiency of new motor vehicles. To use NEMS to estimate the incremental impacts of policy changes, one first runs a baseline that reflects business as usual (i.e., without the policy change). Although EIA has an official baseline each year (the base case for AEO), it is possible to modify the underlying assumptions to create a new baseline. Whatever baseline is used, one then modifies inputs to NEMS to reflect the change in policy and reruns the model. Differences in the two sets of projections represent estimates of the potential impacts of the policy.

Note that modeling results from NEMS represent a reasonable estimation of what may happen based on the modeling inputs and calculations. Given the substantial uncertainty that results from the complex and dynamic nature of the various energy markets in the United States, it is impossible to forecast future energy market developments with perfect accuracy.

B. Baseline Conditions As noted above, EIA uses NEMS to produce an Annual Energy Outlook with long-term projections of prices and quantities. The AEO 2012 version of NEMS generates projections to 2040. In the AEO 2012 version of NEMS, IPEC and all other existing nuclear power plants continue to operate throughout the modeling period (i.e., through 2040).

We used the AEO 2012 version of NEMS without modification as the baseline against which to estimate the potential energy and environmental impacts of the no-action alternative.

We present NEMS results of baseline conditions in the United States for two periods (2011-2015 and 2016-2025) in order to provide comparisons with the no-action alternative, which are provided for the period from 2016 to 2025. The NEMS results reflect average annual values during each period.

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Table 5 presents average annual generation in the United States by fuel type during the two periods under baseline conditions, including continued operation of IPEC. Generation is expressed in terms of millions of MWh per year. Note that coal accounts for the largest share of U.S. generation (41.0 percent in the period 2016-2025), followed by natural gas (23.9 percent),

nuclear (21.2 percent), renewables (13.2 percent), and oil (0.7 percent). The generation mix in the period 2016-2025 is similar to the mix in 2011-2015, with renewables increasing somewhat from the first to the second period, and coal decreasing somewhat. Changes in other fuels percentages between the two periods are smaller than the changes for renewables and coal.

Table 5. Projected U.S. Baseline Generation by Fuel Type 2011-2015 2016-2025 million MWh/yr  % of Total million MWh/yr  % of Total Coal 1,673 42.3% 1,712 41.0%

Natural gas 966 24.4% 998 23.9%

Oil 27 0.7% 28 0.7%

Nuclear 811 20.5% 887 21.2%

Renewables 477 12.1% 553 13.2%

Total 3,955 100.0% 4,177 100.0%

Note: Totals differ slightly from sums of components because of independent rounding.

Source: NERA calculations based on NEMS AEO 2012 model C. Projected Energy Market Impacts of No-Action Alternative To estimate how the electricity system would operate under the no-action alternative, we ran a new NEMS case in which we modeled the baseload IP2 and IP3 generation as lost in 2013 and 2015, respectively. We made no other modifications to the AEO 2012 version of NEMS.

We compared the results for this no-action case to the baseline results to estimate the potential electricity market responses to address the lost IPEC baseload generation according to NEMS. We present results for the ten-year period beginning in 2016 (the first year in which IPEC would not operate based on our modeling assumptions for the no-action alternative) and ending in 2025.

Table 6 presents the projected changes in the no-action alternative based on the NEMS results. NEMS estimates that IPEC would produce 16.7 million MWh of baseload energy each year on average during the period 2016-2025, so the no-action alternative reflects this amount of reduced generation from IPEC. According to the NEMS results, electricity prices would rise as a result of making IPECs baseload generation unavailable. In response to these higher electricity prices, consumers would reduce their demand for electricity by 0.3 million MWh per year on average during the period 2016-2025. In addition to this sales effect, the reduced demand for electricity would involve a slight reduction in electricity net imports into the United States by 0.2 million MWh per year on average. To make up for IPECs lost output, other power plants across the United States would increase their generation by 17.4 million MWh per year on NERA Economic Consulting 37

average. Making IPEC unavailable would tend to increase the distance over which electricity would need to travel to consumers, and this would lead to increased line losses (i.e.,

dissipation of electricity in the transmission system). The sum of these four categories of market responses, accounting properly for their signs (increases vs. reductions), is equal to IPECs lost output.

Table 6. IPECs Lost Output and Projected U.S. Market Responses in No-Action Alternative (2016-2025) million MWh/yr IPEC -16.7 U.S. market responses Reduced sales 0.3 Increased net imports -0.2 (net imports decrease)

Increased generation 17.4 Reduced line losses -0.9 (line losses increase)

Total 16.7 Note: Total differs slightly from sum of components because of independent rounding.

Source: NERA calculations based on NEMS AEO 2012 model As shown below in Table 7, NEMS projects that less than half of the increased U.S.

generation in the no-action alternative would occur in New York State. NEMS estimates that generation from other power plants in New York State would increase by 6.9 million MWh per year on average during the period 2016-2025 under the no-action alternative. NEMS estimates that New York State would import more electricity from other States and (to a much lesser extent) Canada in response to the lost IPEC baseload generation. Indeed, NEMS estimates that generation in other States would increase by 10.6 million MWh per year on average during the period 2016-2025 in the no-action alternative, virtually all of which would be transmitted to New York State to make up for the shortfall there. These increased imports into New York State lead to the increased line losses across the United States shown above in Table 6.

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Table 7. Projected Changes in Generation in No-Action Alternative (2016-2025) million MWh/yr  % of Total Replacement generation New York State 6.9 39%

Other states 10.6 61%

U.S. total 17.4 100%

U.S. replacement Coal 7.5 43.1%

Natural gas 9.7 55.4%

Oil 0.1 0.5%

Nuclear 0.0 0.0%

Renewables 0.2 1.0%

Total 17.4 100.0%

Note: Totals differ slightly from sums of components because of independent rounding.

Source: NERA calculations based on NEMS AEO 2012 model The lower part of Table 7 shows U.S. replacement generation by fuel type. Note that these values reflect three effects: (1) increased utilization of power plants that exist in baseline conditions; (2) delayed retirements of existing plants relative to the baseline; and (3) construction of new power plants in the no-action alternative relative to the baseline. Note too that NEMS determines new power plant additions endogenously based on its modeling algorithms. We made no assumptions about what types of resources could be used to replace IPEC and did not constrain NEMS in any way.

As shown in the lower part of Table 7, the majority (55.4 percent) of the U.S.

replacement generation during the period 2016-2025 would come from natural gas, and most of the remainder (43.1 percent) would come from coal. NEMS projects that the increased coal generation would come from increased utilization and delayed retirement of existing coal plants rather than construction of new coal plants. Small contributions toward replacement generation would come from renewables (1.0 percent) and oil (0.5 percent). These NEMS results are in accord with the discussion of the relative costs of alternative generation technologies in the previous chapter.

D. Projected Adverse Environmental Impacts of No-Action Alternative As we have seen, NEMS projects that replacement of IPEC baseload generation lost under the no-action alternative would come primarily from fossil fuel-fired power plants. The increased combustion of fossil fuels would increase emissions of CO2 and other air emissions. In this section, we present NEMS results for the potential increase in the United States in three NERA Economic Consulting 39

types of air emissions: CO2, sulfur dioxide (SO2), and nitrogen oxides (NOx).15 As shown in the table, NEMS projects that, each year on average during the period 2016-2025 in the no-action alternative, U.S. CO2 emissions would be 13.5 million tons higher, U.S. SO2 emissions would be 6.4 million tons higher, and U.S. NOx emissions would be 3.3 million tons higher.

Table 8. Projected Increases in Average Annual U.S. Air Emissions in No-Action Alternative (2016-2025)

CO2 (million tons/yr) 13.5 SO2 (thousand tons/yr) 6.4 NOx (thousand tons/yr) 3.3 Note: CO2 is measured in millions of metric tons (1,000 kilograms), while SO2 and NOx are measured in thousands of short tons (2,000 pounds).

Source: NERA calculations based on NEMS AEO 2012 model To put the CO2 increases in perspective, they can be compared with planned CO2 emission reductions under RGGI (RGGI 2012). The programs CO2 cap for 2012 is 165 million short tons, which is equivalent to 150 million metric tons. The programs cap for 2018 is 10 percent lower, which is equivalent to a planned reduction in CO2 emissions of 15 million metric tons. Note that the AEO 2012 version of NEMS includes the effects of RGGI. The NEMS results indicate that the no-action alternative would increase U.S. CO2 emissions above baseline levels by 13.5 million metric tons, nearly as much as the planned reduction in CO2 emissions under RGGI through 2018.

15 Air emissions are the only type of environmental impact modeled by NEMS. The AEO 2012 version of NEMS includes the Cross-State Air Pollution Rule (CSAPR), which EPA issued in July 2011 to limit emissions of SO2 and NOx from power plants. (EIA based its modeling of CSAPR in the AEO 2012 version of NEMS on the original form of the regulation issued in July 2011. EPA subsequently made technical adjustments to state caps and new-unit set-asides, and the U.S. Court of Appeals for the D.C. Circuit subsequently issued a stay on the regulation.) NEMS also produces estimates of mercury air emissions from power plants, but the AEO 2012 version of NEMS does not incorporate EPAs recent Mercury and Air Toxics Standards (MATS). Thus, the model likely overstates future mercury emissions in both the baseline conditions and the no-action alternative, and we do not present them here.

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IV. Evaluation of New York State Contention 37 As noted, NYS-37 and the accompanying expert reports come to very different conclusions, without any supporting analyses, regarding the potential generation that would be added if IPEC were not available. We have evaluated NYS-37 and its accompanying documents and have concluded that the materials have four fundamental flaws that explain why they come to such different conclusions. The first section of this chapter provides an overview of the four flaws. Two of these flaws have already been discussed in previous chapters. The implications of the other two flaws on evaluating the potential adverse environmental impacts of the no-action alternative are explained in the second and third sections of this chapter.

A. Overview of Major Flaws in NYS-37 The difficulties with the NYS-37 arguments can be summarized in terms of the following four major flaws.

1. Failure to recognize market forces and cost-minimization. NYS-37 and the expert reports fail to account for the key role that market forces would play (and hence the importance of relative costs and cost-minimization) in determining the resources that would be dispatched to replace the lost baseload IPEC generation under the no-action alternative. It is critical to recognize that New York State has a competitive electricity market. As a result, decisions regarding new investments are largely made by merchant entities that would tend to build low-cost facilities, and facilities are dispatched to provide energy at minimum cost while meeting reliability and operating requirements. Market forces and cost-minimization mean that lower-cost fossil generation rather than higher-cost renewable generation or energy efficiency would constitute the bulk of generation under the no-action alternative.

2. Conflation of developments that affect the baseline, not the no-action alternatives. NYS-37 and its supporting witnesses mention a host of developments that they claim were not considered by the NRC staff in developing the FSEIS and that they claim would lead to different conclusions regarding the energy mix and environmental impacts of the no-action alternative. These developments include New York States renewable and energy efficiency goals, lower electricity demand due to the recession, recent increases in electricity generation capacity and transmission system expansions, and lower natural gas prices. The flaw pervasive in the NYS-37 reasoning is that these developments represent part of the baseline conditions that would occur irrespective of IPECs status. Put another way, the various factors identified by NYS-37 and its expertssuch as the additional renewable generation or energy efficiency resulting from New York State goalswould not be available to replace the baseload IPEC generation if the IPEC units were not available because they exist now, while IPEC continues to provide baseload electricity.

3. Failure to evaluate the impacts of potential differences in the baseline. To the extent that the developments they cite affect the baseline, those developments would if anything reduce the roles of conservation and renewables as IPEC replacements under the no-NERA Economic Consulting 41

action alternative. The developments emphasized by NYS-37, including lower electricity demand and lower natural gas prices, would tend to increase the subsidies that would be necessary to fund the higher marginal costs of those alternatives while at the same time decreasing the marginal costs of fossil resources thereby making these resources less economic relative to fossil-fueled power options.

4. Failure to provide empirical modeling. NYS-37 and the experts fail to provide any studies or other analyses quantifying how the electric system would respond under the no-action alternative. In contrast, our analysis using NEMS shows that conservation (in the form of response to higher prices) and renewables would play modest roles, and that the primary impact would be increased generation from fossil-fired sources. This failure on the part of NYS-37 and its experts is important since, without some empirical modeling, they cannot provide a reasonable basis for evaluating which alternatives actually would be developed and dispatched if IPEC generation were not available.

Two of these flawsfailure to recognize market forces and failure to provide empirical modelingrelate to the issues discussed in Chapters II and III and thus do not require additional explanation. The other two flawsrelated to the conflation of baseline conditions and the no-action alternativerequire further explanation to clarify their implications for the environmental impacts of the no-action alternative.

B. Conflation of Baseline and No-Action Alternative NYS-37 and its accompanying documents point to numerous changes that have occurred in New York States energy markets, each one of which NYS claims significantly changes the environmental impact calculus set forth in the FSEIS (NYS-37, p. 2). However, the cited developments relate to changes that have occurred already or that will occur regardless of IPECs future status. Thus, they cannot provide additional energy to make up for lost baseload IPEC generation in the no-action alternative. As a result, the cited developments are not directly relevant to evaluating the likely electricity market and environmental impacts of the no-action alternative.

The importance of distinguishing between baseline conditions and the no-action alternative was discussed above in Chapter II, and Figure 5 in Chapter II illustrates that the potential environmental impacts of the no-action alternative are based on the changes in energy resources between baseline conditions and the no-action alternative. This section elaborates on the fundamental point introduced in Chapter II by considering the implications of using different (i.e., more updated) baseline conditions.

1. Differences in Baseline Conditions This section considers alleged differences between baseline conditions assumed in the FSEIS and baseline conditions with the recent energy developments cited in NYS-37. Figure 11 illustrates such a hypothetical change in the baseline mix of generation. On the left-hand side is the Original baseline generation mix allegedly assumed in the FSEIS. In the middle is a NERA Economic Consulting 42

Revised hypothetical forecast of the baseline generation mix that takes account of the types of changes cited by NYS-37 and supporting testimony (including more renewables due to the 30 x 15 policy, more conservation due to the 15 x 15 policy, and the effect of the recession on total necessary output from power plants). Note that both baselines include continued operation of IPEC. The stacked bar on the right shows the changes in generation resources between the two baseline forecasts.

Figure 11. Hypothetical Illustration of Change in Baseline Generation Recession Renewables Output Conservation IPEC Fossil and other Original baseline Revised baseline Change Note: Mixes of resources (and resulting changes between the two baselines) are not drawn to scale and should be interpreted only in qualitative terms.

Source: Hypothetical example In the figure, overall demand has fallen because of lower levels of economic activity (recession). Renewables and conservation both have increased because of various State and federal programs and subsidies. Output from IPEC is the same in the revised forecast as in the original because, in both cases, IPEC is a base-loaded resource, and thus, its generation is not affected by the total load forecast. As a result of the recession and increased conservation and renewables, forecasted generation by fossil and other sources has declined. None of these changes, however, speaks directly to the question at hand: What are the incremental changes in the resources that are likely to be used to meet demand when comparing the baseline to the no-action alternative?

a. Incremental Changes in Generation from a Modified Baseline To answer that question requires repeating the analysis illustrated in Figure 2 (in Chapter II) but with the revised baseline that we have developed in this chapter to reflect the factors identified in NYS-37. Figure 12 illustrates such a hypothetical analysis using the revised baseline. The revised baseline on the left and the revised no-action alternative in the middle both involve more conservation and renewables and less output from fossil/other than their NERA Economic Consulting 43

counterparts in Figure 2. However, the relevant comparison is between the changes due to the no-action alternative in the two figures, because those changes are what determine the net environmental impacts of the no-action alternative. The mere fact that renewables and conservation play larger roles in the revised baseline does not necessarily mean that they will play larger (or, perhaps, any) incremental roles in replacing output lost from IPEC under the no-action alternative. The change in the baseline does not, in fact, affect the nature of the change in generation mix under the no-action alternative. But as we discuss below, the changed baseline can have an indirect effect in a manner that actually refutes the NYS-37 presumptions.

Figure 12. Hypothetical Analysis of Impact of No-Action Alternative with Revised Baseline Recession Renewables Output Conservation IPEC Fossil and other Revised baseline No-Action Change Note: Mixes of resources (and resulting changes between the baseline and the no-action alternative) are not drawn to scale and should be interpreted only in qualitative terms.

Source: Hypothetical example

b. Implications of Illustrations The preceding illustrations show that developments that affect baseline conditions (i.e.,

conditions that have occurred or will occur in the future regardless of IPECs status) do not have a direct effect on the changes in generation that would occur under the no-action alternative. In our hypothetical example, the changes in generation are the same in Figure 12 as in Figure 5, i.e.,

the change in baseline has no effect on the incremental generation.

For reasons we discuss in the third section of this chapter, however, careful analysis of the indirect effects of the developments cited in NYS-37 and its accompanying documents suggest that those developments would be likely to reduce the incremental roles of renewables and conservation under the no-action alternative, in contrast to the contention in NYS-37.

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2. Developments Cited by NYS-37 Relate to the Baseline, Not Impacts of the No-Action Alternative The major developments cited in NYS-37 and accompanying documents relate to changes in the baseline (that is, the current circumstances which includes continued IPEC generation), not to what alternatives could be available to replace IPECs energy in the no-action alternative. The following are the six major developments emphasized in NYS-37 and the expert reports. (Appendix A provides updated information on these six developments.)

1. New York State renewable electricity goal. The 30 x 15 renewable electricity goal is being implemented by subsidies paid by NYSERDA to developers of renewable energy sources. These subsidies are collected from New Yorks consumers on their monthly utility bills through a volumetric surcharge for the RPS program.

2. New York State conservation and energy efficiency programs. Conservation and energy efficiency, particularly under the 15 x 15 plan, will play larger roles than projected in the past. Utility and NYSERDA conservation programs are subsidized with funds from the Systems Benefit Charge (SBC) and other volumetric surcharges imposed on sales of electricity to New Yorks consumers.

3. Lower New York State electricity demand due to economic factors. Future demand for electricity in New York is projected to be lower than earlier projections suggested, such as those available in 2006 for the report by the National Research Council on alternatives to renewing IPECs licenses, due to the recession and continuing economic pressures.

4. New York State recent and proposed generation capacity additions. New York State has added a significant amount of generation capacity in recent years (mostly natural gas and wind), and significant amounts have been proposed for construction in future years.

5. Lower natural gas prices. The price of natural gas has fallen over the past several years and is expected to remain lower than previously expected, in part because of new techniques for extracting natural gas that have sharply increased the reserves that can be extracted economically.

6. New transmission lines in New York State. New transmission lines, which did not exist at the time of the 2006 National Research Council report and allegedly were not considered by the FSEIS, will make it easier for the downstate areas served by IPEC to obtain power produced in upstate New York or in the adjoining regions.

The following subsections summarize these recent developments, analyze how they affect a properly set baseline and address whether they provide direct evidence concerning the potential adverse environmental impacts of the no-action alternative.

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a. New York State Renewable Electricity Goal is in the Baseline New York States 30 x 15 renewable electricity goal was discussed above in Chapter II. Since renewables that are induced into New York States electricity system as part of this goal are elements of the baseline regardless of IPECs status, these renewables cannot also be counted as replacements for IPEC in the no-action alternative.

Statements by the States experts (Schlissel testimony, p. 48) regarding federal support for renewable energy under the American Recovery and Reinvestment Act of 2009 (ARRA) provide another example of the conflation of changes in the baseline and changes in the incremental impact of the no-action alternative. ARRA provided temporary federal support for renewable energy as a response to the recession, and thus, is properly included in the baseline.

Several of the support mechanisms (including the Section 1603 energy grant program) have already expired (U.S. Treasury 2012). Thus, the federal support mechanisms under ARRA no longer even exist and, in any event, are not relevant to potential replacement of IPECs baseload energy with renewable energy in the years ahead.

b. New York State Energy Efficiency and Conservation Goal is in the Baseline New York States 15 x 15 conservation goal was discussed above in Chapter II. Since conservation measures that are induced in New York States electricity system as part of this goal are elements of the baseline regardless of IPECs status, these conservation measures cannot also be counted as replacements for IPEC in the no-action alternative.

In his testimony in support of NYS-37, Mr. Schlissel provides another particularly clear example of a development that relates to the baseline rather than to the impacts of the no-action alternative. He notes that ARRA spending and incentives have stimulated conservation efforts.

Any increase that has occurred as a result of ARRA, however, is part of the baseline, and in any event is subsumed under the 15 x 15 and 30 x 15 goals. Moreover, expenditures under ARRA peaked in 2010 and have declined since then. No new funding is available. Thus, it will not be a potential source of funding for incremental conservation efforts under the no-action alternative.

c. Reduced Electricity Demand Projections Due to Lower Economic Activity and Other Factors This section considers the effects of reduced electricity demand projections, first summarizing the changes in forecasts and then assessing the relevance.

i. Changes in Forecast Electricity Demand As NYS-37 (p. 38) and experts note, forecasts of electricity demand in New York have fallen substantially over the past several years. The NYISO has reported that this significant fall-off in electricity demand has been driven primarily by the recession and its after-effects. Figure 13 shows the changes over time in the NYISOs forecasts of New York State electricity demand.

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Figure 13. NYISO Projections of New York State Electricity Sales 195,000 190,000 185,000 Electricity Sales (GWh) 180,000 175,000 170,000 165,000 160,000 155,000 150,000 145,000 2006 2008 2010 2012 2014 2016 2018 2020 2006 2007 2008 2009 2010 2011 Note: All projections incorporate NYISOs projections of energy efficiency.

Source: NYISO Gold Books 2006-2011 As shown in the figure, the projections decreased significantly over the period, particularly between 2008 and 2009 as the depth of the recession was incorporated into the forecast. NYISO projected in 2006 that sales in 2016 would be 184,630 GWh, but it projected in 2011 that sales in 2016 would be only 165,319 GWh, a reduction of 10.5 percent relative to the projection from 2006.

In a presentation in May 2010, NYISO estimated that the recession reduced electricity sales between October 2008 and April 2010 (adjusted for weather) by 6,400 GWh and that lost economic growth accounted for an additional 1,500 to 2,000 GWh (NYISO 2010b, p. 2). Thus, for this historical period, the recession (including the resulting lost economic growth) was estimated to account for about 93 percent of the total reduction in electricity sales.16 ii. Changes in Forecast Electricity Demand are in the Baseline Forecasts of future electricity demand in New York State are inherently uncertain, in large part because of uncertainties regarding future economic activity in the State and thus the demand from industrial, commercial and recreational customers. These changes in overall demand will of course affect the generation sources that are used to meet future electricity 16 600 GWh of reduction was attributed to energy efficiency programs (NYISO 2010b, p. 2).

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demand. As noted above, however, IPEC provides baseload generation and, thus, the level of its generation is not affected at all by the level of economic activity. Thus, whatever changes might have occurred in the forecasts of future electricity demandor whatever changes may occur in subsequent forecastswill not influence the level of generation from IPEC that is lost under the no-action alternative. Changes in forecasted electricity demand are properly part of baseline conditions rather than changes that should be attributed to the potential loss of IPEC baseload generation.

Indeed, the same principle applies to changes in future forecasts. The baseline conditions for 2020 may change in the future due to changes in economic forecasts and thus forecast electricity demand. But the principle is the same; these changes represent changes in baseline conditions rather than conditions that directly affect the impacts of the no-action alternative. As discussed below, however, changes in the baseline can have an indirect effect on the impacts of the no-action alternative, although not the effect presumed in NYS-37.

d. Generation Capacity Additions This section summarizes information on recent and potential future electricity generation capacity additions and then considers their relevance.

i. Recent Capacity Additions According to the NYISO database of power plants in New York State, 8,348 MW of generation capacity (net available to the grid) has been added since 2000. Figure 14 shows annual capacity additions in New York State from 2000 to 2011 by energy type. Natural gas was the dominant type of new capacity in most years, but large amounts of wind have also been added in some years. Of the 8,348 MW of total additions since 2000, natural gas accounted for 6,874 MW (83 percent) and wind accounted for 1,348 MW (16 percent).

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Figure 14. Annual Generation Capacity Additions (MW) 1,800 1,600 1,400 Other Annual Additions (MW) 1,200 Solar Wind 1,000 Hydro Nuclear 800 Oil 600 Coal Natural Gas 400 200 0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Source: NERA analysis of NYISO (2011d) ii. Potential Capacity Additions The NYISO maintains an Interconnection Queue that lists proposed projects. Applying for an interconnection and being placed in the queue is merely a step in the development process.

Far less capacity is ultimately built than is entered in the queue. This is true for a variety of reasons which include assignment of transmission upgrade costs to projects which increases costs, difficulty in obtaining permits, difficulty in obtaining a contract, unwillingness to take market risk, inability to secure financing at all or at a rate that will support the project, increases in project cost from initial expectations, changed economic conditions that would reduce profitability, and the construction of new units by competitors which reduces the profitability outlook.

The NYISO Interconnection Queue dated December 31, 2011 contains 12,081 MW of potential generation projects in New York State. Wind facilities account for 5,698 MW (47 percent), and natural gas facilities account for 5,384 MW (45 percent). The total renewable capacity in the current Interconnection Queue is 5,839 MW (48 percent). Figure 15 shows the energy types and currently expected in-service dates for active projects in the Interconnection Queue. Projects in the Interconnection Queue have in-service dates as far in the future as 2017.

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Figure 15. Potential Generation Projects in Current Interconnection Queue (MW) 3,000 2,500 Potential Generation Projects (MW)

Other 2,000 Solar Wind Hydro 1,500 Nuclear Oil 1,000 Coal Natural Gas 500 0

2012 2013 2014 2015 2016 2017 2018 N/A Source: NERA analysis of NYISO (2011e)

The Interconnection Queue reveals that many projects have had significant postponements or have been withdrawn. The majority of projects that are currently expected to come in service in 2012 (in terms of MW) were originally scheduled to come in service in 2007 or earlier. Across all current in-service dates, 46 percent of projects (in terms of MW) have been postponed by four years or more, according to the queue. This is not unusual but represents the outcomes we would expect given that entering the queue preserves an option at low cost and given the decline in demand growth in New York after 2007.

The Interconnection Queue shows that 8,286 MW of wind projects have been withdrawn by developers since 2000. Thus, the wind capacity that has been built in New York State since 2000 (1,330 MW) is only 14 percent of the capacity that has been proposed. Hence, the amount of wind capacity in the Interconnections Queue is not a useful indicator of the amount of wind capacity that will be developed in the future or that may be developed in response to the no-action alternative. That will depend on the ability of the projects to obtain permits, the actual costs of development, on the relative economics of these projects versus the gas-fired units in the queue, the market price outlook, the availability of federal and State subsidies (and the associated levels), and the transmission costs ultimately assigned to these units. The recent developments cited in NYS-37 such as reductions in demand growth and lower gas prices make these units less likely to be competitive with gas units and, despite their presence in the queue, less likely to be replacements for IPEC in the no-action alternative.

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iii. Capacity Additions are in the Baseline Recent capacity additions represent additions to the facilities that could in theory provide additional generation to replace lost IPEC baseload generation to the extent and only to the extent that these units would not be operating at full output were IPEC to continue to operate.

These capacity additions do not otherwise represent the changes that would take place under the no-action alternative. Rather, these additions represent changes in the baseline conditions.

Whether additional generation to replace lost IPEC generation would come from these recently-added units depends upon their capacity utilization under baseline conditions and the cost per megawatt-hour of additional generation as well as the ability of the transmission system to deliver the power to the relevant demand regions. Note that since wind capacity is used whenever it is available because the marginal cost is virtually zero, additional recent wind capacity in the baseline would not provide greater opportunities for wind to be used as replacement power even assuming there was adequate transmission to deliver it.

The possibility of future capacity additions also does not by itself represent changes that would result from the no-action alternative. Potential future capacity additions, such as those in the queue, are simply alternatives that may or may not serve as a replacement. Whether particular units will be added in the future will depend primarily upon their relative costs; this principle applies both in the baseline (e.g., as a response to increased electricity demand) and in the no-action alternative. As analyses in Chapters II and III show, renewable generation is generally not economically competitive with the marginal costs of existing unutilized fossil capacity or with the levelized cost of new fossil capacity.

In summary, recent capacity additions are part of the baseline conditions rather than indications of the generation that would be dispatched in the no-action alternative. Potential future capacity additions represent alternatives that would only be realistic if such additions would be economically competitive.

e. Lower Natural Gas Prices This section summarizes information on recent decreases in forecast natural gas prices and then considers their relevance.

i. Changes in Forecast Natural Gas Prices As NYS-37 (p. 35) notes, natural gas prices have fallen in recent years. From 2008 to 2010, the average price of natural gas at Henry Hub dropped from about $9/MMBtu to about

$4/MMBtu (in 2010 dollars), a fall of roughly 56 percent (EIA 2011a). Moreover, natural gas prices are expected to rise only modestly in the future, as increased demand is offset by a number of factors, including increased production using new low-cost techniques. In AEO 2009, for example, EIA forecast that the price of natural gas in 2020 would be about $8/MMBtu (in 2011 dollars) (EIA 2009). EIAs projection in AEO 2011 was that the price of natural gas in 2020 will be only about $5/MMBtu in 2011 dollars (EIA 2012), a decline of more than 35 percent.

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ii. Changes in Natural Gas Prices are in the Baseline Lower natural gas prices will reduce the cost of electricity generated using that fuel, in both the baseline and under the no-action alternative. Those lower costs will increase the relative competitiveness of gas-fired generation, leading to greater use in both states of the world. They also will reduce incentives to replace existing gas-fired sources with new, more efficient units, because the incremental cost savings will be smaller. These effects will apply equally to both the baseline and the no-action alternative, and thus are not directly relevant to the incremental impacts of the no-action alternative. As we discuss below, however, lower natural gas prices are likely to reduce the role of renewables in the no-action alternative and to increase the role of fossil fuel generation, which runs directly counter to NYS-37s claim that the FSEIS should have considered scenarios with less gas-fired generation and more conservation and renewables.

f. Transmission Capacity to Downstate New York This section summarizes information on recent transmission capacity additions in New York State and then considers their relevance.

i. Changes in Transmission Capacity NYS-37 (p. 52) criticizes the FSEIS for failing to consider recent developments in transmission capacity to downstate New York. These developments include three projects that will or (if not yet constructed) might provide additional capacity to import power from units in New Jersey and other States that are part of the PJM system:

1. Linden variable frequency transformers in New Jersey, which became operational in 2009

2. Hudson Transmission Partners line from New Jersey to New York City, which has received a contract, is now under construction and is currently expected to be completed in 2013; and

3. Cross-Hudson Project, which is in the permitting process and is scheduled for completion in 2015.

In addition, NYS-37 and its accompanying documents fault the FSEIS for including the New York Regional Interconnect, a project that has been withdrawn, but then cite the Champlain Hudson Power Express project, which would allow the transmission of power from Quebec to New York City. Issues related to Canadian transmission lines and hydro facilities in the context of this proposed project are discussed in Appendix C.

ii. Changes in Transmission Capacity are in the Baseline The Linden and HTP projects will increase the ability to obtain more power from outside downstate New York when it is more economical than generating electricity within the critical NERA Economic Consulting 52

zones. Moreover, while NYS is correct that the NYRI Project was withdrawn, it nonetheless can be used genericallyto the extent such projects are economic on a purely merchant basisto represent a major transmission project. The key point, however, is that any transmission developments that occur, including any major transmission projects increasing the transfer capability into the Downstate area, are in the baseline, and thus, have no incremental effects for purposes of the no-action alternative. As with other energy developments, these transmission changes are not directly relevant to the question of what energy and environmental impacts could occur in the no-action alternative. As we discuss below, to the extent that there is excess transmission capacity in the baseline, it could affect the mix of resources used to replace output lost from IPEC under the no-action alternative. The environmental consequences of increases in purchased power will depend on the mix of sources used to generate that power relative to the mix that would otherwise supply it from in-region sources.

C. Failure to Account for the Indirect Effects of a Modified Baseline on the Energy and Environmental Impacts Under the No-Action Alternative This section provides a qualitative evaluation of a major claim of NYS-37that recent energy developments mean that the FSEIS overstates the potential environmental effects of the no-action alternative. The documents submitted in support of NYS-37 emphasize various developments that the State alleges the FSEIS did not incorporate. Consideration of those developments, NYS-37 claims, indicates that the FSEIS should have devoted more attention to alternatives that rely more heavily, if not exclusively, on conservation and renewables, rather than fossil-fired generation.

As discussed above, NYS-37 and its accompanying documents fail to distinguish between developments that influence the baseline (that is, conditions that exist or are planned independent of the no-action alternative) and what incremental changes in resources would be used to replace lost IPEC baseload generation under the no-action alternative. Most of the developments they cite relate to changes in the baseline and hence are not directly relevant to the effects of the no-action alternative relative to the baseline.

Changes in the baseline do not themselves represent impacts that would occur if IPEC generation were not available. But baseline changes can indirectly affect which resources are likely to change incrementally under the no-action alternative. For example, new transmission lines may make power imported from other states part of the replacement generation if those new lines are not fully utilized in the baseline. However, the indirect effects of changes in the baseline can also have counterintuitive effects. For example, as we explain below, a baseline with high levels of conservation is likely to have higher costs of additional conservation as part of replacing IPEC than a baseline with lower levels of conservation. Thus, a baseline with the higher levels of conservation that NYS-37 argues are more accurate than in the FSEIS would make it more expensive and therefore less likely that substantial amounts of additional conservation would be used to replace IPECs baseload energy.

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The following sections provide assessments of the indirect effects of the various energy developments emphasized in NYS-37 on the type of generation likely to replace IPEC generation under the no-action alternative.

a. Increased Renewable Requirements Accounting for increased renewable requirements in the baseline would tend, if anything, to decrease the likely role of renewables in replacement generation under the no-action alternative. We can explain this using a diagram to illustrate the indirect effects of a changed baseline. Figure 16 below (a variation on Figure 7 in Chapter II) relates the total quantity (MWh) of renewable generation in New York State to the subsidy rate per MWh necessary to elicit renewable generation.17 The upward-sloped supply curve indicates that increasing the total quantity of renewable generation requires increasing the subsidy rate per MWh.

17 As noted above, under the RPS program, NYSERDA provides payments to renewable energy producers in order to increase the quantity of renewable energy produced in New York State. These payments ultimately are borne by New York States electricity consumers through surcharges on their monthly utility bills.

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Figure 16. Impact of More Baseline Renewables on the Marginal Cost of Additional Renewables Subsidy Supply S1N S1B S0N S0B

Q Q Q0B Q0N Q1B Q1N Quantity generated by renewables Notes: Q0B: Quantity of renewables in original baseline without 30 x 15 policy Q: additional quantity of renewables desired under the no-action alternative S0B: Subsidy rate for original baseline S0N: Subsidy rate required to elicit additional renewables under no-action alternative Q1k and S1k: corresponding quantities and subsidies under revised baseline.

Suppose that under the original baseline without the 30 x 15 RPS program, the subsidy is set at S0B and it elicits Q0B units of renewable generation. Thus, the incremental cost of securing additional renewables under the no-action alternative would start at S0B and increase incrementally to the extent that the government wanted to replace lost IPEC output with renewables. If the desired increase were Q, the subsidy rate required would rise to S0N. To provide the additional renewables under the no-action alternative would require raising the subsidy rate, as well as increasing the quantity on which the subsidy is paid, both of which would raise the budget needed.

Now suppose that new renewable programs of the type cited in NYS-37 and its supporting documents are implemented. The baseline quantity of renewables rises from Q0B to Q1B. To elicit that additional supply, the subsidy must be higher, S1B in the new baseline.

Similarly, under the no-action alternative, if the desire is to increase renewable output by Q, the required subsidy rises to S1N. As the figure illustrates, the more ambitious the goal in the revised baseline, the higher the subsidy that is needed to elicit additional supply of renewables in the no-action alternative. The higher subsidy required to obtain additional renewables means that NERA Economic Consulting 55

renewables would be less likely to be added as replacement power under the no-action alternative.

b. Increased Electricity Conservation Requirements The analysis of the indirect effect of a higher baseline level of conservation on the likelihood of additional conservation in the no-action alternative is essentially the same as the analysis for renewables in Figure 16. Increasing conservation programs under the no-action alternative would require increased rates of expenditure per unit of electricity saved, assuming that additional conservation programs could even be designed beyond those intended to meet the ambitious New York State goal. The higher the baseline level of conservation assumed, the higher would be the cost per unit of electricity saved, so that the higher baseline level of conservation cited by NYS-37 and its accompanying documents in fact would make it more difficult and costly to secure any incremental conservation initiatives beyond the baseline EEPS program to be used in the no-action alternative (assuming that additional initiatives could be identified and implemented effectively).

c. Lower Projected Future Electricity Demand Lower electricity demand forecasts due to lower levels of economic activity apply to the baseline and do not have a direct impact on the mix of resources that likely would be used under the no-action alternative. Their indirect effect, however, is likely to make fossil sources more attractive as incremental sources of supply under the no-action alternative. As with our analyses of renewables and conservation, we can illustrate this logic with a supply curve.

The supply of fossil-generated electricity is rising as a function of the market price; higher prices elicit more supply, as illustrated in Figure 17. In the figure, the initial baseline quantity of fossil generation is Q0B, corresponding to a market price of P0B. Under the no-action alternative, if Q additional units of fossil were used to replace lost IPEC output, the price would rise to P0N.

Now consider the effects of lower demand in the baseline as a result of lower levels of economic activity. Lower demand means that less fossil will be used in the baseline. In addition, higher levels of renewables and conservation also will reduce the amount of fossil used in the baseline. In the figure, the reduced quantity of fossil in the revised baseline is Q1B and the corresponding market-clearing price is P1B, which is lower than in the baseline. In other words, a lower-cost facility meets the required demand and sets the market-clearing price lower on the supply curve. As a result, the cost to replace lost IPEC output under the no-action alternative also would fall, making fossil a more attractive option than under the original baseline. Because the new baseline would lower the market-clearing price, it would increase the subsidies required to meet any given target for renewables. It also would make conservation less attractive because lower market prices would make conservation less cost-effective for customers.

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Figure 17. Impact of Reduced Demand in Baseline on Marginal Cost of Fossil Generation to Replace IPEC Price Supply P0N P0B P1N P1B

Q Q Q1B Q1N Q0B Q0N Quantity generated by fossil Notes: Q0B: Quantity of fossil generation in original baseline with relatively high demand Q: Difference in fossil generation between baselines with relatively high and low demand P0B: Market price in original baseline with relatively high demand P0N: Market price in original baseline under no-action alternative Q1k and P1k: corresponding quantities and prices under revised baseline.

d. Recent Generation Capacity Additions Recent and proposed capacity additions in New York are primarily a baseline issue . The capacity additions may displace high-cost power plants in the electricity markets supply curve, but IPEC remains a source of baseload energy even with the capacity additions. Thus, the capacity additions have not and would not reduce the amount of energy that IPEC supplies to the New York electricity system (and thus the amount of energy that would have to be replaced if IPEC were not available).

The indirect effects of New York States recent and proposed capacity additions are likely to include decreases in the market price of electricity that would in turn be likely to increase the attractiveness of fossil-fired generation relative to renewables or conservation. As discussed above, in the near term the market price for a given demand period would be determined by the NERA Economic Consulting 57

short-run marginal cost of the marginal generator, where the marginal generator is the highest cost unit generating during the period. In New York, that marginal generator is almost always gas-fired, typically an older, relatively inefficient unit (although that has changed somewhat over time with the operation of new combined cycle facilities in New York). Newer units are likely to have lower marginal costs of generation than those older units. As a result, generation from new capacity is likely to continue to displace generation from the older, marginal units for some demand periods as already has been seen in New York (except if the gas prices remain very low).

These older, fossil fired units will run at even lower capacity factors than before or will be retired. Their marginal output will be replaced by units with lower marginal costs, which will reduce the market clearing prices.

This decrease in the market price of electricity would have an indirect effect on the mix of incremental resources likely to be used to replace IPEC output under the no-action alternative.

As discussed earlier, the subsidy required to elicit additional renewable generation is the projected difference between the levelized cost of the incremental renewable resource and the (appropriately weighted) wholesale price of electricity. Thus, lower prices will increase the subsidies needed to achieve renewable targets. Similarly, lower prices will make conservation a less attractive option for consumers, requiring higher subsidy rates to achieve baseline conservation goals. These higher subsidy costs are likely to reduce the roles that renewables or conservation would play under the no-action alternative.

e. Lower Forecasted Natural Gas Prices Lower natural gas prices will shift down the supply curve for gas-fired units. As discussed earlier, lower natural gas prices are likely to increase the amount of gas-fired generation in the baseline and to reduce the extent to which older gas-fired units are replaced with new, fuel-efficient models (because the new investment is no longer economic). Lower gas prices are also likely to lower market-clearing electricity prices in the baseline, because gas-fired units are the marginal units during most time periods. As noted above in the context of capacity additions, lower market-clearing electricity prices are likely to require larger expenditures on conservation programs to achieve baseline targets and to increase the subsidies needed to meet baseline targets for renewables.

Lower natural gas prices also will reduce the incremental cost of increasing gas-fired generation under the no-action alternative. Thus, they make it more likely that gas-fired units rather than renewables or utility-sponsored conservationwould be used. As a result, incorporating lower projected gas prices into the analysis produces market results that are directly contrary to the unsupported contention in NYS-37 that the FSEIS overemphasizes the use of fossil fuel, natural gas in particular, to generate replacement power.

f. New Transmission Lines to Downstate New York Additional transmission lines can reduce constraints on buying power from outside New York State and thus could result in more imports in the baseline because more out-of-state units would be able to bid in the NYISO auctions. To the extent that these developments create new NERA Economic Consulting 58

interconnection opportunities that would not otherwise be fully utilized in the baseline, they also could produce additional imports under the no-action alternative.

The two recently added transmission lines that are cited by NYS-37 and its supporting documentsLinden and Neptunewill allow greater imports from New Jersey and the rest of the PJM region to the west of New York. PJM generates a higher percentage of its power from coal than New York does. In PJM, coal is the marginal producer approximately 74 percent of the time (and natural gas is on the margin the remaining 26 percent), whereas in New York State the marginal producer is almost always natural gas (FERC 2012). Thus, the recently added transmission capacity seems likely to increase the role of coal generation in the baseline conditions. To the extent that these opportunities are exhausted in the baseline, however, this additional transmission would not necessarily lead to greater coal generation in the no-action alternative. If additional low-cost coal generation from PJM were available, however, the additional transmission would lead to a greater role for coal generation under the no-action alternative. As with other projections, the key consideration is the relative cost of alternative generation sources under the no-action alternative.

The same general principles apply when evaluating the effects of potential additional transmission as in evaluating the effects of recent transmission changes. If additional transmission projects such as the Champlain Hudson Power Express Project go forward, they would provide the opportunity for additional imports of power from outside New York State.

These opportunities would be present both in the baseline case and in the no-action case. To the extent that the cost-effective opportunities for additional imports are exhausted under baseline conditions, however, the additional transmission lines would not lead to additional imports under the no-action alternative. Moreover, because the effects of the no-action alternative depend in large part on relative costs of different generation sources, it would generally be necessary to model the change in electricity market conditions under the no-action alternative to determine the net effect of any change in transmission on incremental generation.

D. Summary Evaluation of the Energy and Environmental Claims of NYS-37 NYS-37 and its supporting documents claim that the FSEIS ignores important recent developments and, as a result, gives insufficient weight to the roles that conservation and renewable energy could play under the no-action alternative. As we discussed above, most of those developments affect the baseline but are not directly relevant to the mix of resources under the no-action alternative.

We also analyzed how those developments and their impacts on the baseline would be likely to indirectly affect the mix of replacement resources in the no-action alternative. We found that for the most part they would increase the costs of using conservation or renewables, reduce the cost of fossil-fired alternatives, or both. Moreover, several of the developmentsin particular lower fossil use in the baseline and lower gas priceswould be likely to increase the attractiveness of using older fossil sources (by delaying retirements or increasing utilization) rather than the new, more efficient NGCC units assumed in several of the FSEIS alternatives, NERA Economic Consulting 59

under the no-action alternative. Increased use of older sources and reduced use of new sources would generally increase the environmental impacts of the no-action alternative beyond those identified in the FSEIS. Increased generation and transmission capacity may not have any impacts on the incremental effects of the no-action alternative if the capacity would be fully utilized in baseline conditions. If certain capacity is not fully utilized, its role in the no-action alternative would depend largely upon its relative costs as a potential source of additional supply to replace IPEC generation.

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V. Conclusions A central issue in the FSEIS for IPEC license renewal is the comparative environmental impacts between renewal and the no-action alternative. Evaluating the environmental impacts requires evaluating the mix of generation that would replace lost IPEC baseload generation in the no-action alternative, since it is the changes in generation that would determine the likely environmental impacts. We evaluate the likely replacement generation mix using information on the relative costs of different generation alternatives as well as the results of NEMS modeling.

For the no-action alternative, our analyses show that the IPEC replacement generation would be replaced primarily by fossil-fueled generation, both from existing natural gas and coal units and from some additional units that would be added (or units whose retirement would be postponed). Our analyses indicate that both additional renewable generation and additional conservation would constitute small shares of replacement generation.

NYS-37 provides a very different vision of likely replacement generation, although the statement and the associated expert declarations do not provide any empirical analyses. We reviewed these materials and concluded that their conclusions were erroneous due to four fundamental flaws: (1) failure to account for the importance of market forces; (2) conflation of baseline conditions and the no-action alternative; (3) failure to consider the implications of the criticisms they made on the alleged use in the FSEIS of outdated information on energy demand and supply conditions; and (4) failure to develop empirical information.

In summary, our results establish two propositions regarding the potential environmental impacts of the no-action alternative:

1. The adverse environmental impacts of the no-action alternative assessed in the FSEIS, if anything, underestimated the likely environmental impacts if IPEC baseload generation were lost; and

2. New York State is incorrect in its claims that the FSEIS overstates environmental impacts because replacement generation would not, in fact, be primarily renewable energy and conservation.

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Appendix A: Information on Recent Energy Developments in New York State This appendix summarizes recent information regarding the six major developments regarding New York State energy markets and policies emphasized in NYS-37:

1. New York State renewable energy goal;

2. New York State energy efficiency goal;

3. New York State electricity demand projections;

4. New York State generation capacity additions;

5. National and New York State natural gas prices; and

6. New York State transmission investments.

The implications of these developments for the environmental impacts of the no-action alternative are discussed in the body of the report.

A. New York State Renewable Energy Goal This section provides background information on New Yorks 30 x 15 renewable energy goal.

1. Overview of Goal New York officially established a goal for renewable energy in a 2004 order issued by the NYPSC. The original goal was to increase renewables share of retail electricity consumption to 25 percent by 2013, relative to a 2004 baseline of roughly 19 percent. In 2010, NYPSC increased the goal to 30 percent and extended the deadline to 2015.

Table A-1 summarizes the 30 x 15 renewable energy goal. Note that the level of renewables implicit in the goal is relative to the forecasted load assuming full achievement of the States 15 x 15 energy efficiency goal (discussed below). NYPSCs January 2010 order states that [i]f the expected energy efficiency achievements are ignored, a 30 percent goal for 2015 would result in a substantially higher and more costly renewable energy target (NYPSC 2010b,

p. 10).

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Table A-1. New Yorks 30 x 15 Renewable Energy Goal (million MWh) 15 x 15 Renewable Energy Baseline State Voluntary NYSERDA Load Goal Resources Agencies Programs LIPA / IOUs

[A] [B] = [A]

• 30% [C] [D] [E] [F] [G]

= [C]+[D]+[E]+[F]+[G]

152.4 45.7 31.5 0.32 1.5 1.9 10.4 Notes: 15 x 15 Load is total consumption assuming reductions in load corresponding to full achievement of New Yorks 15 x 15 energy efficiency goal. The load is in terms of sendout, which represents gross energy supply to the grid. Sendout exceeds sales because some supply is lost in transmission.

Baseline Resources refer to renewable energy from facilities built before 2004.

Source: NYPSC (2010b, Appendix, p. 12)

As shown in Table A-1, the NYPSCs 2010 Order set the renewable energy goal in 2015 as 45.7 million MWh. Baseline resourceswhich refer to renewable energy from generators built before 2004 (including the Niagara Power Project and other hydropower in upstate New York)are expected to produce 31.5 million MWh in 2015, or 69 percent of the goal.18 The rest of the goal is to be made up by four sets of incremental policy-led efforts. First, renewable energy projects at State agencies will need to produce 0.32 million MWh in 2015.

Second, voluntary green marketing programs, in which electricity customers choose to pay a premium to support renewable energy, will need to induce 1.5 million MWh of renewable energy in 2015. Third, LIPA will need to contract for 1.9 million MWh of renewable energy in 2015.

The remaining 10.4 million MWh of the 30 x 15 goal will need to come from programs administered by NYSERDA. The NYPSC oversees these NYSERDA programs through the Renewable Portfolio Standard (RPS).19

2. RPS Administration New Yorks RPS differs from programs in most other states in that it lacks an enforcement mechanism. Instead of the NYPSC penalizing distribution utilities for failing to procure minimum percentages of their electricity from renewable sources, the NYPSC provides funding for renewable energy by collecting a non-bypassable volumetric wires charge (NYPSC 2004) from retail customers of investor-owned utilities and then using those funds to subsidize sources of renewable generation selected through a competitive bidding process administered by NYSERDA. The RPS charge is a volumetric charge that is in addition to, and separate from, New Yorks systems benefit charge (SBC).

The RPS maintains two separate sets of eligible generators: (1) utility-scale Main Tier generators; and (2) Customer-Sited Tier (CST) distributed, smaller-scale generators. Main Tier resources consist of biogas, biomass, liquid biofuel, fuel cells, hydroelectric (limited to 18 Renewable energy from baseline resources is not tracked each year under the 30 x 15 policy. Thus, the goal is to increase renewable energy above the assumed level from baseline resources so as to achieve the total level shown in Table A-1.

19 Note that the RPS does not represent the entire statewide goal for renewable energy.

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upgrades and new low-impact run-of-river plants less than 30 MW and, thus, expressly excluding large hydro projects), solar photovoltaics, tidal ocean power, wind turbines, and any wind, biomass direct combustion, or run-of-river (less than 5 MW) hydro plants that demonstrate need to receive RPS financial support to operate. CST resources consist of fuel cells, solar PV, solar thermal (added as a qualifying technology in the 2010 Order), and wind turbines less than 300 kW (NYPSC 2010a, Appendix B). Only generators that have been constructed since 2003 can qualify for funding under either tier. The main tier is expected to contribute 9.8 million MWh of the 10.4 million MWh goal, with the remainder coming from CST.

3. Projected Budgets The Commission specified a total program budget through 2024 of $2.998 billion, or

$157.6 million per year on average (NYPSC 2010a, Appendix, Table 15). The bulk of the funds are allocated to Main Tier programs. The annual budget peaks in 2015 at $321 million and declines steadily to $42 million in 2024.

4. Progress toward New Yorks Renewable Energy Goal NYSERDAs 2011 RPS Performance Report states that, as of December 31, 2010, generation from the programs current contracts would produce renewable energy equivalent to 39 percent of the 2015 target. Main Tier programs currently under contract were expected to reach 3,930,000 MWh by 2015 (40 percent of the Main Tier target), and CST programs currently under contract were expected to reach 76,945 MWh by 2015 (12 percent of the CST target). Of the total 1,526 MW of Main Tier renewable capacity already added or under development by the end of 2010, 1,456 MW were wind, 47 MW were hydro, and 43 MW were biomass (NYSERDA, 2011a, p. 9). Incremental capacity (installed or under contract) from CST programs totaled 36 MW. NYSERDA expects capacity from CST programs to increase to 284.5 MW by 2015, resulting in the achievement of the CST portion of the 2015 goal (NYSERDA, 2011a, p. 15).

NYSERDAs 2011 Performance Report does not assess whether Main Tier programs are expected to meet their portion of the 2015 goal.

5. Costs of New Yorks Renewable Energy Measures NYSERDA (2011a, p. 21) notes that by the end of 2010 it had expended 57 percent of its budget for the period through 2015 but had secured only 39 percent of the renewable energy goal. Thus, assuming the goal canbe met at all, unless NYSERDA can fund less costly renewable energy projects than it has funded so far (an outcome that is unlikely for the reasons laid out in detail in the body of this report), the program is unlikely to achieve the 2015 goal within budget.

Main Tier production subsidies have amounted to around $20 per MWh, or about one third of New Yorks average wholesale electricity price in 2010 (NYISO 2011c, p. 21). Table A-2 shows the weighted-average production subsidy for all of the Main Tier solicitations to date.

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Table A-2. Production Subsidies for Main Tier Generators Weighted Average Round Date Subsidy ($/MWh) 1 January 2005 $22.90 2 February 2007 $15.52 3 January 2008 $14.75 4 December 2009 $19.76 5 March 2010 $19.50 6 June 2011 $22.01 Source: NYSERDA (2011b, p. 14)

We can estimate the expected cost to customers for the remainder of the program using approved targets and goals. Table A-3 shows the results of such a calculation.

Table A-3. Implicit Subsidies from New Yorks RPS Cost Target Average Cost per MWh Year (Approved Budget) (MWh) (Implicit Subsidy) 2011 $170,450,216 4,572,910 $37.27 2012 $202,989,832 6,052,842 $33.54 2013 $243,944,012 7,392,550 $33.00 2014 $281,544,225 8,895,160 $31.65 2015 $321,157,589 10,397,854 $30.89 Cumulative $1,220,085,874 37,311,316 $32.70 Note: Production subsidies (in Table A-2) are the amounts generators receive, whereas implicit subsidies (in Table A-3) are the total amount paid by customers per MWh of electricity.

Source: NYPSC (2010a), Appendix and NERA calculations As shown in the table above, from 2011 to 2015, IOU customers can expect to pay an additional $1.2 billion cumulatively to help to achieve the RPS goal. This is equivalent to about

$33 per MWh, which is more than half the 2010 average price of wholesale electricity in New York. However, as the Main Tier solicitations to date show, actual costs have been higher and achieved levels of renewable generation have been lower than approved budgets and targets.

Thus, the $33 per MWh figure is likely to be conservative with no assurance that the program goals (which are, in any event, part of the baseline) can even be met.

B. New York State Energy Efficiency Goal This section provides background information on New York States 15 x 15 energy efficiency goal.

1. Overview of Goal Governor Eliot Spitzer announced the 15 x 15 energy efficiency goal in April 2007. At that time, NYPSC forecasted that New York would consume 166 million megawatt-hours NERA Economic Consulting 71

(MWh) of electricity in 2015. The 15 x 15 goal calls for reducing consumption in 2015 by 15 percent of the forecast, or 25 million MWh, resulting in total consumption of 141 million MWh (NYPSC 2008, Appendix 1, p. 4).20 Governor David Paterson reaffirmed this goal in his State of the State address in January 2009.

Achieving the 15 x 15 goal will require contributions by various organizations across the State. NYSERDA performed an analysis in 2007 to develop appropriate contribution levels for LIPA, NYPA, the six investor-owned utilities in the state based on their energy efficiency programs in 2007, NYSERDA, and other state agencies. The analysis also included contributions through energy efficiency codes and standards as well as energy efficiency measures for transmission and distribution. The NYSERDA analysis suggested that these contributions would cover about 73 percent of the total energy efficiency goal (i.e., 11 percentage points out of the 15 percent reduction). NYSERDA expected that the remainder of the necessary energy efficiency (i.e., 4 percentage points out of the 15 percent reduction), which was labeled the efficiency gap or jurisdictional gap, would be achieved through new programs administered by investor-owned utilities and NYSERDA which were funded by electricity rate surcharges authorized by NYPSC.

Figure A-1 shows the potential contributions toward the 15 x 15 energy efficiency goal based on NYSERDAs analysis.

20 The goal can also be expressed in terms of sendout, which represents gross energy supply to the grid. Sendout exceeds sales because some supply is lost in transmission. In 2007, the Commission forecasted that sendout in 2015 would need to be 179 million MWh. The 15 x 15 policy calls for reducing sendout in 2015 by 15 percent of the forecast, or 27 million MWh, resulting in total sendout of 152 million MWh (NYPSC 2008, Appendix 1,

p. 4).

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Figure A-1. Potential Contributions toward Energy Efficiency Goal Based on NYSERDA Analysis 25 Jurisdictional Gap Electricity Savings (million MWh)

Transmission & Dist 20 Codes & Standards 15 Utilities (2007 Programs)

SBC III (NYSERDA) 10 State Agencies 5 NYPA LIPA 0

2007 2008 2009 2010 2011 2012 2013 2014 2015 Source: NYPSC (2008, Appendix 1, p. 5)

In an order issued in June 2008, NYPSC announced the Energy Efficiency Portfolio Standard (EEPS) program with goals through December 31, 2011 for the six investor-owned utilities under its jurisdiction and NYSERDA. In the same order, NYPSC set surcharge levels on New York State electricity bills that it estimated would achieve those goals (NYPSC 2008). The total energy efficiency goal for the investor-owned utilities and NYSERDA through that date would completely close the jurisdictional gap estimated by NYSERDA. In a subsequent order issued in October 2011, NYPSC announced revised goals for the investor-owned utilities through December 31, 2015 and set surcharge levels that it estimated would achieve those further goals (NYPSC 2011a).

2. Assessments of Energy Efficiency Savings Limited information exists on whether New York State will achieve its energy efficiency goal for 2015. To our knowledge, there are no publicly available assessments of total statewide progress on energy efficiency goals. NYISO tracks several programs, but it does not examine transmission and distribution savings, codes and standards, 2007 utility programs, or State agencies. NYPSC only tracks progress on the EEPS portion of the statewide goal.

It is possible to roughly gauge electricity savings by comparing actual electricity system demand to forecasts from earlier years and making adjustments for impacts on the economy and projected growth. In 2010, weather-normalized electricity sendout in New York was 161.6 million MWhsix percent lower than the level of demand for 2010 that NYISO forecasted in NERA Economic Consulting 73

2007, when the Commission set the 15 x 15 baseline (NYISO 2011a).21 The demand reduction is due primarily to the lower economic activity as a result of the recent recession and, to a much smaller degree, energy efficiency programs, as discussed in the next section of this appendix.

As noted above, NYISO tracks energy efficiency achievements from a subset of programs and develops expected levels of future achievements for its load forecasting and planning purposes. NYISO reviews various data on energy efficiency, including: (1) program evaluation reports submitted by investor-owned utilities, LIPA, and NYPA; (2) long-term forecasts provided by LIPA, Consolidated Edison, and other investor-owned utilities; and (3)

U.S. Energy Information Administration projections of the demand impacts of efficiency codes and standards (NYISO 2011a, p. 6). Figure A-2 shows NYISOs estimates of cumulative savings (in terms of sendout) through 2011 for EEPS, NYPA, and LIPA, as well as NYISOs expectations of cumulative savings for these programs through 2015 and their goals for 2015 under the 15 x 15 policy.

Figure A-2. Historical and NYISOs Expectation of Savings from Energy Efficiency Programs 16.3 18 Electricity Savings (million MWh) 16 12.1 14 12 10.5 10 8.4 7.9 8

5.4 6 3.0 4.6 3.7 4 4.1 2.8 0.2 0.7 1.7 2 0.9 0.4 2.3 1.9 0

EEPS: EEPS: EEPS: NYPA LIPA Total IOUs NYSERDA Total Cumulative Savings Through 2011 NYISO's Expectation of Cumulative Savings Through 2015 2015 Goal Notes: Savings are in terms of sendout. Cumulative savings are defined as overall savings in 2011 resulting from program expenditures in previous years through 2011. The EEPS: NYSERDA savings include the NYSERDA Energy Smart program. The programs included in the figure account for about 60 percent of the total 15 x 15 goal.

Source: NYISO (2012), slide 5 21 NYISO and NYPSC make independent forecasts of electricity sales.

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Figure A-2 shows that through the end of 2011, EEPS programs had achieved 31 percent of their 2015 goal (3.7 million MWh out of 12.1 million MWh in terms of sendout). NYISO expects EEPS programs to achieve 70 percent (8.4 million MWh) of their goal by the end of 2015. NYISO does not expect NYPA or LIPA to meet their energy efficiency goals for 2015 either. Collectively for the EEPS programs, NYPA, and LIPA, cumulative savings through 2011 were 28 percent of the total 2015 goal (4.6 million MWh out of 16.3 million MWh), and NYISO expects them to achieve 64 percent (10.5 million MWh) of their total goal by the end of 2015.

In its official comments on the NYPSC EEPS White Paper, NYISO stated that full achievement of the [EEPS] program goals by 2015 is not feasible (NYISO 2011b). Note that NYISOs forecasts reflect the organizations judgment regarding inherently uncertain variables.22 The NYPSC, on the other hand, maintains that there is a reasonable expectation that the EEPS goal will be met by 2015 (NYPSC 2011b, p. 1). A recent NYPSC white paper reports that

[s]avings achieved, as a percentage of total targets, are running ahead of dollars spent as a percentage of total budgets. As of February 28, 2011, statewide electricity savings represented 49.1% of the cumulative targets to date while combined program spending represented 38.9%

of budgets to date (NYPSC 2011b, p. 8). Moreover, the white paper notes that, in the NYPSCs estimation, the savings achieved through 2010 and 2011 should not be used to predict future savings, since the EEPS program is in transition (NYPSC 2011b, p. 1).

3. Costs of New Yorks Energy Efficiency Measures As noted above, limited information is available on the statewide progress toward meeting the 15 x 15 energy efficiency goal. This makes it difficult to make statewide assessments of the total costs of energy efficiency measures in New York. Information is available on energy efficiency measures by investor-owned utilities and NYSERDA as part of the EEPS program, however.

NYPSC administers the EEPS program and funds it through surcharges on retail electricity rates that are assessed to New Yorks consumers on a monthly basis. As noted above, NYPSC set savings goals and budgets for EEPS programs at each utility and NYSERDA through 2011 in an order issued in 2008. NYPSC set new goals and budgets from 2012 through 2015 in an order issued in October 2011.

In comments submitted while NYPSC was considering alternatives for the second phase of the EEPS program from 2012 to 2015, NYISO (2011b) noted that the EEPS program would require significantly more funding each year from 2012 to 2015 than during the first phase in order to achieve the cumulative goal by 2015 ($370 million per year on average during the second phase versus a maximum of $250 million during the first phase). NYISO also showed a supply curve that combined the savings from all EEPS programs through June 2011 and their cost per MWh. About half of the savings were achieved by incurring costs above $150/MWh, 22 An energy expert at the Natural Resources Defense Council has also concluded that New York is not on track to meet the 15 x 15 energy efficiency goal (Wald 2011).

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and several programs had costs above $1,000/MWh. For comparison, the average wholesale electricity price in New York in 2010 was $59/MWh (NYISO 2011c, p. 21), and the average retail price was $163/MWh (EIA 2012). The costs of energy efficiency measures can also be compared with the avoided cost, which is the sum of wholesale cost, distribution cost, and externalities. If externalities are relatively small per MWh, the avoided cost is generally close to the retail price. Thus, many energy efficiency programs through June 2011 were costly relative to electricity prices and avoided costs.

C. New York State Electricity Demand Projections This section provides background on recent demand projections for New York State in terms of electricity sales (measured in gigawatt-hours: GWh). We do not include demand projections in terms of peak load because this measure of demand relates to reliability rather than replacement energy but the latter is the focus of the environmental impact analysis under the no-action alternative.

1. Electricity Sales Projections This section provides information on electricity sales projections first for New York State and then for downstate zones that are most relevant for IPEC (Zones G, H, I, J, and K).

a. New York State Figure 13 shows projections of New York State electricity sales from NYISO Load &

Capacity reports (Gold Books) from 2006 to 2011. As shown in the figure, the projections decreased significantly over the period, particularly between 2008 and 2009 as the depth of the recession was incorporated into the forecast. NYISO projected in 2006 that sales in 2016 would be 184,630 GWh, but it projected in 2011 that sales in 2016 would be only 165,319 GWh, a reduction of 10.5 percent relative to the projection from 2006.

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Figure A-3. NYISO Projections of New York State Electricity Sales 195,000 190,000 185,000 Electricity Sales (GWh) 180,000 175,000 170,000 165,000 160,000 155,000 150,000 145,000 2006 2008 2010 2012 2014 2016 2018 2020 2006 2007 2008 2009 2010 2011 Note: All projections reflect NYISOs projections of energy efficiency.

Source: NYISO Gold Books 2006-2011

b. Downstate Zones Figure A-4 provides a map of NYISO zones.

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Figure A-4. NYISO Zones Source: FERC (2012)

Figure A-5 shows projections of downstate (Zones G-K) electricity sales from NYISO Gold Books from 2006 to 2011. The figure has a similar pattern to the New York State figure.

The projection for 2016 from 2011 (98,200 GWh) is 10.8 percent lower than the projection from 2006 (110,135 GWh).

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Figure A-5. NYISO Projections of Downstate (Zones G-K) Electricity Sales 115,000 110,000 Electricity Sales (GWh) 105,000 100,000 95,000 90,000 85,000 2006 2008 2010 2012 2014 2016 2018 2020 2006 2007 2008 2009 2010 2011 Note: All projections incorporate NYISOs projections of energy efficiency.

Source: NYISO Gold Books 2006-2011

2. Effect of Recession According to the National Bureau of Economic Research, the recent recession began in December 2007 and ended in June 2009 (NBER 2010). NYISO notes in its Power Trends 2011 report that New York State electricity sales decreased by 1 percent in 2008 relative to sales in the previous year, decreased by 4 percent in 2009, and increased by 3 percent in 2010 (NYISO 2011c, p. 18).

NYISO discusses the effect of the recession on demand projections in its most recent Reliability Needs Assessment (RNA), which was published in September 2010. It compares projections in the 2010 RNA with projections in the previous RNA, which was published in January 2009 and was based on modeling performed before the worst part of the recession.

NYISO notes that its base case projection in the 2010 RNA for electricity sales in 2015 is about 10,800 GWh (6.1 percent) lower than in the 2009 RNA due to the 2009 recession and subsequent lower economic growth projections (NYISO 2010a, p. 10). New energy efficiency policies to help achieve the 15 x 15 goal also contributed to a much less significant degree to lower projections.

In a previous presentation in May 2010, NYISO estimated that the recession reduced electricity sales between October 2008 and April 2010 (adjusted for weather) by 6,400 GWh.

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Energy efficiency programs accounted for an additional 600 GWh of reduction, and lost economic growth for 1,500 to 2,000 GWh (NYISO 2010b, p. 2). Thus, for this historical period, the recession (including the resulting lost economic growth) was estimated to account for about 93 percent of the total reduction in electricity sales.

D. New York State Generation Capacity Additions This section provides background information on recent and proposed capacity additions in New York based on NYISOs list of power plants (NYISO 2011d) and its current Interconnection Queue (NYISO 2011e).

1. Capacity Additions Since 2000

a. Annual Additions According to the NYISO data, 8,348 MW of generation capacity has been added in New York State since 2000. The following figures illustrate recent additions.

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Figure 14 shows annual capacity additions in New York State from 2000 to 2011 by energy type. As shown in the figure, natural gas was the dominant type of new capacity in most years, but large amounts of wind was also added in some years, most predominantly in 2008.

Figure A-6. Annual Generation Capacity Additions (MW) 1,800 1,600 1,400 Other Annual Additions (MW) 1,200 Solar Wind 1,000 Hydro Nuclear 800 Oil 600 Coal Natural Gas 400 200 0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Source: NERA analysis of NYISO (2011d)

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b. Cumulative Additions Figure A-7 shows the cumulative capacity additions in New York State from 2000 to 2011 by energy type. Of the 8,348 MW of total additions, natural gas accounted for 6,874 MW (83 percent) and wind accounted for 1,348 MW (16 percent).

Figure A-7. Cumulative Generation Capacity Additions Since 2000 (MW)

Wind, 1,348, 16% Solar, 0, 0%

Other, 111, 1%

Hydro, 15, 0%

Nuclear, 0, 0%

Oil, 0, 0%

Coal, 0, 0%

Natural Gas, 6,874, 83%

Source: NERA analysis of NYISO (2011d)

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2. Geographic Distribution Figure A-8 shows the geographic distribution of cumulative capacity additions in New York State from 2000 to 2011. No additions have been built in Zone G (Hudson Valley), Zone H (Millwood), or Zone I (Dunwoodie). Thirty percent of additions have been built in Zone J (New York City), and 16 percent have been built in Zone K (Long Island).

Figure A-8. Geographic Distribution of Cumulative Generation Capacity Additions Since 2000 (MW)

Zone G: Hudson Zone H:Millwood, Zone I:

Valley, 0, 0% 0, 0% Dunwoodie, 0, 0%

Other Zones, 4,459, 54% Zone J: New York City, 2,520, 30%

Zone K: Long Island, 1,370, 16%

Source: NERA analysis of NYISO (2011d)

3. Current Interconnection Queue

a. Annual Proposed Additions The NYISO Interconnection Queue dated December 31, 2011 contains 12,081 MW of potential generation projects in New York State. Wind facilities account for 5,698 MW (47 percent), and natural gas facilities account for 5,384 MW (45 percent). The total renewable capacity in the Interconnection Queue is 5,839 MW (48 percent). The following figures and tables illustrate the energy types, timing, and location of potential generation projects in the Interconnection Queue.

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Figure 15 shows the energy types and currently expected in-service dates for active projects in the Interconnection Queue. Projects in the Interconnection Queue propose to become commercially operational as far in the future as 2017.

Figure A-9. Potential Generation Projects in Current Interconnection Queue (MW) 3,000 2,500 Potential Generation Projects (MW)

Other 2,000 Solar Wind Hydro 1,500 Nuclear Oil 1,000 Coal Natural Gas 500 0

2012 2013 2014 2015 2016 2017 2018 N/A Source: NERA analysis of NYISO (2011e)

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b. Geographic Distribution Figure A-10 shows the geographic distribution of active projects in the Interconnection Queue. Zone G accounts for 1,681 MW (14 percent). Neither Zone H nor Zone I has any projects. Zone J accounts for 4,451 MW (37 percent), and Zone K accounts for 1,681 MW (14 percent). Thus, the downstate zones collectively account for 65 percent of the active projects in the Interconnection Queue.

Figure A-10. Geographic Distribution of Projects in Current Interconnection Queue (MW)

Zone G: Hudson Valley, 1,681, Other Zones, 14% Zone H:Millwood, 4,269, 35% 0, 0%

Zone I:

Dunwoodie, 0, 0%

Zone J: New York City, 4,451, 37%

Zone K: Long Island, 1,681, 14%

Source: NERA analysis of NYISO (2011e)

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c. Original versus Current In-Service Dates Table A-4 shows original and current in-service dates for projects in the Interconnection Queue (in terms of MW). Many projects have had significant postponements. The majority of projects that are currently expected to come in service in 2012 (in terms of MW) were originally scheduled to come in service in 2007 or earlier. Across all current dates, 46 percent of projects (in terms of MW) have been postponed by four years or more.

Table A-4. Original and Current In-Service Dates for Projects in Interconnection Queue (MW)

Current Date Original Date 2012 2013 2014 2015 2016 2017 2018 N/A Total 2005 78 6 0 0 0 0 0 0 84 2006 235 704 0 0 0 0 0 0 939 2007 1,238 0 0 0 0 0 0 297 1,536 2008 500 99 200 0 0 0 0 117 916 2009 90 210 0 0 0 0 0 73 373 2010 442 300 794 374 0 0 0 2 1,912 2011 0 47 90 0 0 0 0 619 756 2012 247 0 59 0 656 0 0 0 962 2013 0 655 151 0 660 0 0 0 1,465 2014 0 0 1,536 0 0 0 0 0 1,536 2015 0 0 0 810 0 601 0 0 1,411 2016 0 0 0 0 174 0 0 0 174 2017 0 0 0 0 0 0 0 0 0 2018 0 0 0 0 0 0 0 0 0 N/A 0 10 0 0 0 0 0 7 17 Total 2,830 2,031 2,830 1,184 1,490 601 0 1,115 12,081 Postponements 0 years 1 year 2 years 3 years 4 years 5 years 6 years >6 years 3,421 151 1,150 1,140 2,160 1,711 435 788 10,956 31% 1% 10% 10% 20% 16% 4% 7%

Cumulative 0 years 1 year 2 years 3 years 4 years 5 years 6 years >6 years 10,956 7,535 7,384 6,235 5,095 2,935 1,223 788 100% 69% 67% 57% 46% 27% 11% 7%

Source: NERA analysis of NYISO (2011e)

4. Wind Projects Withdrawn from Interconnection Queue Since 2000 The Interconnection Queue shows that 8,286 MW of wind projects have been withdrawn by developers since 2000. Thus, the wind capacity that has been built in New York State since 2000 (1,330 MW) is 16 percent of the capacity that has been withdrawn and 14 percent of the total wind projects originally proposed.

E. National and New York State Natural Gas Prices This section provides background on recent national price projections for natural gas (measured in 2011 dollars per million British thermal units 2011$/MMBtu).

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1. Henry Hub Price Projections Figure A-11 displays EIAs Annual Energy Outlook reference case projections of the Henry Hub spot price for natural gas for the report years from 2007 to 2012. The most recent projection for future natural gas prices is between $1 to $3 per MMBtu cheaper than previous projections due to the expanding availability of unconventional gas.

Figure A-11. AEO Projections of Henry Hub Natural Gas Prices 9.00 8.00 7.00 6.00 2011$/MMBtu 5.00 4.00 3.00 2.00 1.00 0.00 2012 2013 2014 2015 2016 2017 2018 2019 2020 2007 2008 2009 2010 2011 2012 Note: AEO 2006 Henry Hub projection not available Source: Annual Energy Outlook 2007-2012 (reference case)

2. New York State Delivered Prices to Electricity Generators Figure A-12 displays EIAs Annual Energy Outlook reference case projections of the delivered price that electricity generators in New York State will pay for natural gas for the report years from 2006 to 2012. As in the previous figure, it can be seen that the most recent projection for future natural gas prices is between $1 to $3 per MMBtu cheaper than previously forecasted.

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Figure A-12. AEO Projections of Delivered Natural Gas Prices to Electricity Generators in New York State 9.00 8.00 7.00 6.00 2011$/MMBtu 5.00 4.00 3.00 2.00 1.00 0.00 2012 2013 2014 2015 2016 2017 2018 2019 2020 2007 2008 2009 2010 2011 2012 Note: AEO 2011 & 2012 region is Northeast Power Coordinating Council/Upstate New York. For all other years, AEO reported Northeast Power Coordinating Council/New York.

Source: Annual Energy Outlook 2007-2012 (reference case)

F. New York State Transmission Projects This section provides background information on recent, proposed, and canceled transmission projects in New York.

1. Recently Completed Transmission Projects

a. Neptune Regional Transmission System Status: Began operation in 2007 Route: Sayreville, NJ to New Cassel (Long Island), NY Capacity: 660 MW Env Impacts:

Other: Operates under a long-term agreement with LIPA Website: neptunerts.com/

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b. Linden Variable Frequency Transformers Status: Began operation in December 2009 Route: Linden, NJ (PJM) to NYC Capacity: 315 MW Env Impacts:

Other: The variable frequency transformers are technologies that facilitate sending additional power from NJ to NYC using existing transmission lines.

Website: green.blogs.nytimes.com/2009/03/11/a-new-valve-for-controlling-flows-of-electricity/

2. Proposed Transmission Projects

a. Hudson Transmission Partners Status: NYPSC approved certificate for the line in September 2010 Construction began in May 2011 and is expected to finish in 2013 Route: Ridgefield, NJ (PJM) to NYC Capacity: 320 MW initially Env Impacts: NYPSC Order notes that market simulations for 2013 indicate higher air emissions in PJM with HTP (pp. 27-32); NYS does not include this section in its excerpt documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId={CAFAD145-3C87-4E33-ACDF-45D87B7A76C6}

Other: Will operate under a long-term agreement with NYPA Website: hudsonproject.com/

documents.dps.state.ny.us/public/MatterManagement/CaseMaster.aspx?MatterSeq=29123

b. Champlain Hudson Power Express Status: Settlement agreement filed in Article VII proceeding on February 24, 2012; litigation phase has now commenced Route: Quebec to NYC Capacity: 1000 MW Env Impacts:

Other:

Website: chpexpress.com/

http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId={C5F63E41-5ED5-46A2-99A5-F1C5FC522D36}

c. Cross-Hudson Cable Status: Project has been pursued since 2001; scheduled to begin operation in 2015 but currently no open bay positions if HTP completes construction Route: PSEG territory (NJ) to NYC Capacity: 700 MW Env Impacts: The projects Environmental Management and Construction Plan appears to include only direct impacts and no indirect impacts in the electricity market (e.g., air emissions from increased generation by fossil units) http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId={E95EEDCF-56F9-4CFD-B775-D895D6A9D9C7}

Other:

Website: http://www.cavalloenergy.com/page2/page2.html NERA Economic Consulting 89

http://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?MatterSeq=19111

3. Canceled Projects

a. New York Regional Interconnect Status: Request for certificate was withdrawn in April 2009 Route: Oneida County, NY to Orange County, NY Capacity: 1200 MW Env Impacts:

Other:

Website: http://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?MatterSeq=29900 G. References Database of State Incentives for Renewables and Efficiency (DSIRE). 2011. New York.

http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=NY03R&state=N Y&CurrentPageID=1&RE=1&EE=1 .

Federal Energy Regulatory Commission (FERC). 2012. New York Independent System Operator. http://www.ferc.gov/images/market-oversight/mkt-electric/reg-maps/2007_ny_elect_map.gif National Bureau of Economic Research (NBER). 2010. Business Cycle Dating Committee, National Bureau of Economic Research. September 20.

http://www.nber.org/cycles/sept2010.html New York Independent System Operator (NYISO). 2010a. 2010 Reliability Needs Assessment.

http://www.nyiso.com/public/webdocs/newsroom/press_releases/2010/2010_Reliability_Nee ds_Assessment_Final_09212010.pdf New York Independent System Operator (NYISO). 2010b. 2010 Q1 - Energy Update.

http://www.nyiso.com/public/webdocs/committees/bic_espwg/meeting_materials/2010 28/2010_Q1_-_Energy_Update_Revised_May_25,_2010.pdf New York Independent System Operator (NYISO). 2011a. 2011 Load & Capacity Data (Gold Book). April. http://www.nyiso.com/public/webdocs/services/planning/

planning_data_reference_documents/2011_GoldBook_Public_Final.pdf New York Independent System Operator (NYISO). 2011b. Comments on Case 07-M-0548.

August 22.

http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId={42E788F9-A36F-4406-B450-078ED98F1652}

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New York Independent System Operator (NYISO). 2011c. Power Trends 2011: Energizing New Yorks Legacy of Leadership. April.

http://www.nyiso.com/public/webdocs/newsroom/power_trends/Power_Trends_2011.pdf New York Independent System Operator (NYISO). 2011d. 2011 NYCA Generating Facilities. April 21. http://www.nyiso.com/public/webdocs/services/planning/

planning_data_reference_documents/2011_NYCA_Generating_Facilities_Final.xls New York Independent System Operator (NYISO). 2011e. Interconnection Queue.

December 31. http://www.nyiso.com/public/webdocs/services/planning/

nyiso_interconnection_queue/nyiso_interconnection_queue.xls New York Independent System Operator (NYISO). 2012. 2012 Long-Term Forecast Update.

Draft. March 6.

http://www.nyiso.com/public/webdocs/committees/bic_espwg/meeting_materials/2012 06/2012_Long_Term_Forecast_Update.pdf New York State Energy Research and Development Authority (NYSERDA). 2011a. New York State Renewable Portfolio Standard Performance Report: Program Period December 31, 2010. http://www.nyserda.ny.gov/Page-Sections/Energy-and-Environmental-Markets/Renewable-Portfolio-Standard/~/media/Files/Publications/NYSERDA/2011-rps-annual-report.ashx New York State Energy Research and Development Authority (NYSERDA). 2011b. Main Tier Solicitations. http://www.nyserda.ny.gov/en/Page-Sections/Energy-and-Environmental-Markets/Renewable-Portfolio-Standard/Main-Tier-Solicitations.aspx New York State Energy Research and Development Authority (NYSERDA). 2011c. RPS Solicitations. http://www.nyserda.org/rps/PastSolicitations.asp .

New York State Public Service Commission (NYPSC). 2004. Order Regarding Retail Renewable Portfolio Standard. Case 03-E-0188. Issued and Effective September 24, 2004.

http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId=%7BB1830060-A43F-426D-8948-F60E6B754734%7D.

New York State Public Service Commission (NYPSC). 2008. Order Establishing Energy Efficiency Portfolio Standard and Approving Programs. Case 07-M-0548 - Proceeding on Motion of the Commission Regarding an Energy Efficiency Portfolio Standard. June 23.

http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId=%7BD9F7E0DF-A518-4199-84CC-C2E03950A28D%7D New York State Public Service Commission (NYPSC). 2010a. Order Authorizing Customer-Sited Tier Program through 2015 and Resolving Geographic Balance and Other Issues Pertaining to the RPS Program. Case 03-E-0188. Issued and Effective April 2, 2010.

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http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId=%7BC05CD0D 6-8EA5-4CB9-A9FA-6ADD3AECB739%7D.

New York State Public Service Commission (NYPSC). 2010b. Order Establishing New RPS Goal and Resolving Main Tier Issues. Case 03-E-0188. Issued and Effective January 8, 2010.

http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId=%7B30CFE590-E7E1-473B-A648-450A39E80F48%7D.

New York State Public Service Commission (NYPSC). 2011a. Order Authorizing Efficiency Programs, Revising Incentive Mechanism, and Establishing a Surcharge Schedule. Case 07-M-0548 - Proceeding on Motion of the Commission Regarding an Energy Efficiency Portfolio Standard; Case 07-G-0141 - Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of National Fuel Gas Distribution Corporation for Gas Service. October 25.

http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId=%7BC0BD1A5B-6E4F-4C4A-A0E9-BC78799DAA23%7D New York State Public Service Commission (NYPSC). 2011b. Energy Efficiency Portfolio Standard Program Review White Paper. Case 07-M-0548 - Proceeding on Motion of the Commission Regarding an Energy Efficiency Portfolio Standard. July 6.

http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId=BDD432F1-2C88-4375-A18D-A2047CCCAFF4 U.S. Energy Information Administration (EIA). 2012. State Electricity Profiles. January 20.

http://www.eia.gov/electricity/state/

Wald, Matthew L. 2011. How Essential Is Indian Point? The New York Times. October 18.

http://green.blogs.nytimes.com/2011/10/18/how-essential-is-indian-point/

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Appendix B: The National Energy Modeling System This appendix provides details on the National Energy Modeling System (NEMS). The text and figures are adapted from documentation developed by the U.S. Energy Information Administration (EIA) for its Annual Energy Outlook 2011 (EIA 2011). We used the AEO 2012 version of NEMS for our modeling in this study, but EIA has not yet released a document summarizing the assumptions in the AEO 2012 version.

A. Overview NEMS is developed and maintained by the EIA Office of Energy Analysis to provide projections of domestic energy-economy markets in the long term and perform policy analyses requested by decision-makers in the White House, Congress, Department of Energy, and other government agencies. These projections are also used by analysts and planners in other government agencies and outside organizations.

The time horizon of NEMS is approximately 25 years, the period in which the structure of the economy and the nature of energy markets are sufficiently understood that it is possible to represent considerable structural and regional detail. Because of the diverse nature of energy supply, demand, and conversion in the United States, NEMS supports regional modeling and analysis in order to represent the regional differences in energy markets, to provide policy impacts at the regional level, and to portray transportation flows. The level of regional detail for the end-use demand modules is the nine Census divisions. Other regional structures include production and consumption regions specific to oil, natural gas, and coal supply and distribution, the North American Electric Reliability Corporation (NERC) regions and sub-regions for electricity, and the Petroleum Administration for Defense Districts (PADDs) for refineries.

For each fuel and consuming sector, NEMS balances the energy supply and demand, accounting for the economic competition between the various energy fuels and sources. NEMS is organized and implemented as a modular system, as shown in Figure B-1 below.

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Figure B-1. Structure of NEMS Macroeconomic International Oil & Gas Activity Module Energy Module Residential Supply Module Demand Module Gas Transmission & Commercial Distribution NEMS Demand Module Module Integrating Module Transportation Coal Market Demand Module Module Renewable Industrial Fuels Module Electricity Petroleum Demand Module Market Module Market Module SUPPLY CONVERSION DEMAND Source: Adapted from EIA (2011)

The modules represent each of the fuel supply markets, conversion sectors, and end-use consumption sectors of the energy system. NEMS also includes a macroeconomic and an international module. The primary flows of information between each of these modules are the delivered prices of energy to the end user and the quantities consumed by product, region, and sector. The delivered prices of fuel encompass all the activities necessary to produce, import, and transport fuels to the end user. The information flows also include other data such as economic activity, domestic production, and international petroleum supply availability.

The integrating module of NEMS controls the execution of each of the component modules. To facilitate modularity, the components do not pass information to each other directly but communicate through a central data storage location. This modular design provides the capability to execute modules individually, thus allowing decentralized development of the system and independent analysis and testing of individual modules. This modularity allows use of the methodology and level of detail most appropriate for each energy sector. NEMS solves by calling each supply, conversion, and end-use demand module in sequence until the delivered prices of energy and the quantities demanded have converged within tolerance, thus achieving an economic equilibrium of supply and demand in the consuming sectors. Solution is reached annually through the projection horizon. Other variables are also evaluated for convergence such as petroleum product imports, crude oil imports, and several macroeconomic indicators.

Each NEMS component also incorporates the impacts of federal and state laws and regulations that affect the sector. Annual Energy Outlook 2012: Early Release, the baseline scenario for this analysis, reflects laws and regulations through late 2011.

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B. Component Modules The component modules of NEMS represent the individual supply, demand, and conversion sectors of domestic energy markets and also include international and macroeconomic modules. In general, the modules interact through values representing the prices of energy delivered to the consuming sectors and the quantities of end-use energy consumption.

This section provides brief summaries of each of the modules.

1. Macroeconomic Activity Module The Macroeconomic Activity Module (MAM) provides a set of macroeconomic drivers to the energy modules and receives energy-related indicators from the NEMS energy components as part of the macroeconomic feedback mechanism within NEMS. Key macroeconomic variables used in the energy modules include gross domestic product (GDP),

disposable income, value of industrial shipments, new housing starts, sales of new light-duty vehicles, interest rates, and employment. Key energy indicators fed back to the MAM include aggregate energy prices and costs. The MAM uses the following models from IHS Global Insight: Macroeconomic Model of the U.S. Economy, National Industry Model, and National Employment Model. In addition, EIA has constructed a Regional Economic and Industry Model to project regional economic drivers, and a Commercial Floorspace Model to project 13 floorspace types in 9 Census divisions. The accounting framework for industrial value of shipments uses the North American Industry Classification System (NAICS).

2. International Module The International Energy Module (IEM) uses assumptions of economic growth and expectations of future U.S. and world petroleum liquids production and consumption, by year, to project the interaction of U.S. and international liquids markets. The IEM computes world oil prices, provides a world crude-like liquids supply curve, generates a worldwide oil supply/demand balance for each year of the projection period, and computes initial estimates of crude oil and light and heavy petroleum product imports to the United States by PADD regions.

The supply-curve calculations are based on historical market data and a world oil supply/demand balance, which is developed from reduced-form models of international liquids supply and demand, current investment trends in exploration and development, and long-term resource economics. The oil production estimates include both conventional and unconventional supply recovery technologies.

In interacting with the rest of NEMS, the IEM changes the world oil pricewhich is defined as the price of foreign light, low sulfur crude oil delivered to Cushing, Oklahoma (in PADD 2)in response to changes in expected production and consumption of crude oil and product liquids in the United States.

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3. Residential and Commercial Demand Modules The Residential Demand Module projects energy consumption in the residential sector by housing type and end use, based on delivered energy prices, the menu of equipment available, the availability and cost of renewable sources of energy, and housing starts. The Commercial Demand Module projects energy consumption in the commercial sector by building type and non-building uses of energy and by category of end use, based on delivered prices of energy, availability of renewable sources of energy, and macroeconomic variables representing interest rates and floorspace construction.

Both modules estimate the equipment stock for the major end-use services, incorporating assessments of advanced technologies, including representations of renewable energy technologies, and the effects of both building shell and appliance standards, including the 2009 and 2010 consensus agreements reached between manufacturers and environmental interest groups. The Commercial Demand Module incorporates combined heat and power (CHP) technology. The modules also include projections of distributed generation. Both modules incorporate changes to normal heating and cooling degree-days by Census division, based on a 10-year average and on State-level population projections. The Residential Demand Module projects an increase in the average square footage of both new construction and existing structures, based on trends in new construction and remodeling.

4. Industrial Demand Module The Industrial Demand Module (IDM) projects the consumption of energy for heat and power, feedstocks, and raw materials in each of 21 industries, subject to the delivered prices of energy and the values of macroeconomic variables representing employment and the value of shipments for each industry. As noted in the description of the MAM, the value of shipments is based on NAICS. The industries are classified into three groups (1) energy-intensive manufacturing; (2) non-energy-intensive manufacturing; and (3) nonmanufacturing. Of the eight energy-intensive industries, seven are modeled in the IDM, with energy-consuming components for boiler/steam/cogeneration, buildings, and process/assembly use of energy. The use of energy for petroleum refining is modeled in the Petroleum Market Module (PMM), as described below, and the projected consumption is included in the industrial totals.

A generalized representation of cogeneration and a recycling component also are included. A new economic calculation for CHP systems was implemented for AEO2011. The evaluation of CHP systems now uses a discount rate, which depends on the 10-year Treasury bill rate plus a risk premium, replacing the previous calculation that used simple payback. Also, the base year of the IDM was updated to 2006 in keeping with an update to EIAs 2006 Manufacturing Energy Consumption Survey.

5. Transportation Demand Module The Transportation Demand Module projects consumption of fuels in the transportation sector, including petroleum products, electricity, methanol, ethanol, compressed natural gas, and NERA Economic Consulting 96

hydrogen, by transportation mode, vehicle vintage, and size class, subject to delivered prices of energy fuels and macroeconomic variables representing disposable personal income, GDP, population, interest rates, and industrial shipments. Fleet vehicles are represented separately to allow analysis of other legislation and legislative proposals specific to those market segments.

The Transportation Demand Module also includes a component to assess the penetration of alternative-fuel vehicles. The Energy Policy Act of 2005 (EPACT2005) and Energy Improvement and Extension Act of 2008 (EIEA2008) are reflected in the assessment of impacts of tax credits on the purchase of hybrid gas-electric, alternative-fuel, and fuel-cell vehicles. Representations of corporate average fuel economy (CAFE) standards and of biofuel consumption in the module reflect standards enacted by the National Highway Traffic Safety Administration (NHTSA) and U.S. EPA, and provisions in EISA2007.

The air transportation component of the Transportation Demand Module explicitly represents air travel in domestic and foreign markets and includes the industry practice of parking aircraft in both domestic and international markets to reduce operating costs, as well as the movement of aging aircraft from passenger to cargo markets. For passenger travel and air freight shipments, the module represents regional fuel use in regional, narrow-body, and wide-body aircraft. An infrastructure constraint, which is also modeled, can potentially limit overall growth in passenger and freight air travel to levels commensurate with industry-projected infrastructure expansion and capacity growth.

6. Electricity Market Module There are three primary submodules of the Electricity Market Module: (1) capacity planning; (2) fuel dispatching; and (3) finance and pricing. The capacity expansion submodule uses the stock of existing generation capacity; the menu, cost, and performance of future generation capacity; expected fuel prices; expected financial parameters; expected electricity demand; and expected environmental regulations to project the optimal mix of new generation capacity that should be added in future years. The fuel dispatching submodule uses the existing stock of generation equipment types, their operation and maintenance costs and performance, fuel prices to the electricity sector, electricity demand, and all applicable environmental regulations to determine the least-cost way to meet that demand. The submodule also determines transmission and pricing of electricity. The finance and pricing submodule uses capital costs, fuel costs, macroeconomic parameters, environmental regulations, and load shapes to estimate generation costs for each technology.

All specifically identified options promulgated by the EPA for compliance with the Clean Air Act Amendments of 1990 (CAAA90) are explicitly represented in the capacity expansion and dispatch decisions; those that have not been promulgated (e.g., fine particulate proposals) are not incorporated. All financial incentives for power generation expansion and dispatch specifically identified in EPACT2005 have been implemented. The AEO 2012 Reference case also reflects the new Cross State Air Pollution Rule (CSAPR). The AEO 2012 Reference case does not, however, incorporate the upcoming Mercury and Air Toxics Standard (MATS).

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7. Oil and Gas Supply Module The Oil and Gas Supply Module represents domestic crude oil and natural gas supply within an integrated framework that captures the interrelationships among the various sources of supplyonshore, offshore, and Alaskaby all production techniques, including natural gas recovery from coal beds and low-permeability formations of sandstone and shale. The framework analyzes cash flow and profitability to compute investment and drilling for each of the supply sources, based on the prices for crude oil and natural gas, the domestic recoverable resource base, and the state of technology. Oil and natural gas production activities are modeled for 12 supply regions, including six onshore, three offshore, and three Alaskan regions.

The Onshore Lower 48 Oil and Gas Supply Submodule evaluates the economics of future exploration and development projects for crude oil and natural gas at the play level. Crude oil resources are divided into known plays and undiscovered plays, including highly fractured continuous zones, such as the Austin chalk and Bakken shale formations. Production potential from advanced secondary recovery techniques (such as infill drilling, horizontal continuity, and horizontal profile) and enhanced oil recovery (such as CO2 flooding, steam flooding, polymer flooding, and profile modification) are explicitly represented. Natural gas resources are divided into known producing plays, known developing plays, and undiscovered plays in high-permeability carbonate and sandstone, tight gas, shale gas, and coalbed methane.

Domestic crude oil production quantities are used as inputs to the PMM in NEMS for conversion and blending into refined petroleum products. Supply curves for natural gas are used as inputs to the Natural Gas Transmission and Distribution Module (NGTDM) for determining natural gas wellhead prices and domestic production.

8. Natural Gas Transmission and Distribution Module The NGTDM represents the transmission, distribution, and pricing of natural gas, subject to end-use demand for natural gas and the availability of domestic natural gas and natural gas traded on the international market. The module tracks the flows of natural gas and determines the associated capacity expansion requirements in an aggregate pipeline network, connecting the domestic and foreign supply regions with 12 U.S. lower 48 demand regions. The 12 regions align with the nine Census divisions, with three subdivided and Alaska handled separately. The flow of natural gas is determined for both a peak and off-peak period in the year, assuming a historically based seasonal distribution of natural gas demand. Key components of pipeline and distributor tariffs are included in separate pricing algorithms. An algorithm is included to project the addition of compressed natural gas retail fueling capability. The module also accounts for foreign sources of natural gas, including pipeline imports and exports to Canada and Mexico, as well as liquefied natural gas (LNG) imports and exports.

9. Petroleum Market Module The PMM projects prices of petroleum products, crude oil and product import activity, and domestic refinery operations, subject to demand for petroleum products, availability and NERA Economic Consulting 98

price of imported petroleum, and domestic production of crude oil, natural gas liquids, and biofuelsethanol, biodiesel, biomass-to-liquids (BTL), CTL, and gas-to-liquids (GTL).

Costs, performance, and first dates of commercial availability for the advanced alternative liquids technologies are reviewed and updated annually.

The module represents refining activities in the five PADDs, as well as a less detailed representation of refining activities in the rest of the world. It models the costs of automotive fuels, such as conventional and reformulated gasoline, and includes production of biofuels for blending in gasoline and diesel. Fuel ethanol and biodiesel are included in the PMM, because they are commonly blended into petroleum products. The module allows ethanol blending into gasoline at 10 percent or less by volume (E10), 15 percent by volume (E15) in States that lack explicit language capping ethanol volume or oxygen content, and up to 85 percent by volume (E85) for use in flex-fuel vehicles.

The PMM includes representation of the Renewable Fuels Standard (RFS) included in EISA2007, which mandates the use of 36 billion gallons of renewable fuel by 2022. Both domestic and imported ethanol count toward the RFS. Domestic ethanol production is modeled for three feedstock categories: corn, cellulosic plant materials, and advanced feedstock materials.

Corn-based ethanol plants are numerous (more than 180 are now in operation, with a total operating production capacity of more than 13 billion gallons annually), and they are based on a well-known technology that converts starch and sugar into ethanol. Ethanol from cellulosic sources is a new technology with only a few small pilot plants in operation.

Fuels produced by gasification and Fischer-Tropsch synthesis and through a pyrolysis process are also modeled in the PMM, based on their economics relative to competing feedstocks and products. The five processes modeled are CTL, GTL, BTL, CBTL, and pyrolysis.

10. Coal Market Module The Coal Market Module (CMM) simulates mining, transportation, and pricing of coal, subject to end-use demand for coal differentiated by heat and sulfur content. U.S. coal production is represented in the CMM by 41 separate supply curvesdifferentiated by region, mine type, coal rank, and sulfur content. The coal supply curves respond to capacity utilization of mines, mining capacity, labor productivity, and factor input costs (mining equipment, mining labor, and fuel requirements). Projections of U.S. coal distribution are determined by minimizing the cost of coal supplied, given coal demands by region and sector, environmental restrictions, and accounting for minemouth prices, transportation costs, and coal supply contracts. Over the projection horizon, coal transportation costs in the CMM vary in response to changes in the cost of rail investments.

The CMM produces projections of U.S. steam and metallurgical coal exports and imports in the context of world coal trade, determining the pattern of world coal trade flows that minimizes production and transportation costs while meeting a specified set of regional world coal import demands, subject to constraints on export capacities and trade flows. The international coal market component of the module computes trade in three types of coal for 17 NERA Economic Consulting 99

export regions and 20 import regions. U.S. coal production and distribution are computed for 14 supply regions and 16 demand regions.

11. Renewable Fuels Module The Renewable Fuels Module (RFM) includes submodules representing renewable resource supply and technology input information for central-station, grid-connected electricity generation technologies, including conventional hydroelectricity, biomass (dedicated biomass plants and co-firing in existing coal plants), geothermal, landfill gas, solar thermal electricity, solar photovoltaics (PV), and wind energy. The RFM contains renewable resource supply estimates representing the regional opportunities for renewable energy development. Investment tax credits (ITCs) for renewable fuels are incorporated, as currently enacted, including a permanent 10-percent ITC for business investment in solar energy (thermal nonpower uses as well as power uses) and geothermal power (available only to those projects not accepting the production tax credit (PTC) for geothermal power). In addition, the module reflects the increase in the ITC to 30 percent for solar energy systems installed before January 1, 2017, and the extension of the credit to individual homeowners under EIEA2008.

PTCs for wind, geothermal, landfill gas, and some types of hydroelectric and biomass-fueled plants also are represented. They provide a credit of up to 2.1 cents per kilowatt-hour for electricity produced in the first ten years of plant operation. For AEO2011, new wind plants coming on line before January 1, 2013, are eligible to receive the PTC; other eligible plants must be in service before January 1, 2014. As part of the American Recovery and Reinvestment Act (ARRA), plants eligible for the PTC may instead elect to receive a 30-percent ITC or an equivalent direct grant. AEO 2012 also accounts for new renewable energy capacity resulting from State renewable portfolio standard (RPS) programs, mandates, and goals.

C. References U.S. Energy Information Administration. 2011. Assumptions to the Annual Energy Outlook 2011. http://www.eia.gov/forecasts/aeo/assumptions/pdf/0554(2011).pdf.

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Appendix C: Information on Potential Canadian Hydro and Associated Transmission One of the developments cited in NYS-37 and the accompanying expert reports concerns the proposed Champlain Hudson Power Express transmission project. In this appendix, we examine the following issues: (1) whether the Champlain Hudson project and potential associated construction of new hydroelectric generation in Canada would represent potential alternatives to IPEC generation in the no-action alternative; and, (2) if additional hydro resources and associated transmission were assumed to be part of the replacement generation, what environmental impacts they would have.

A. Consideration of Transmission and Canadian Hydro as Alternatives to IPEC Generation

1. Overview of the Champlain Hudson Project Champlain Hudson is proposing to establish a 1,000 MW DC connection from the New York-Quebec border to New York City. On February 24, 2012, parties to the permitting proceeding before the NYPSC submitted a joint proposal (settlement document) and supporting documents to the New York Public Service Commission that if accepted by the NYPSC would result in issuance of a Certificate of Environmental Compatibility and Public Need and authorize construction and operation of the Champlain Hudson project. The project, if constructed, would facilitate delivery of power from Quebec and perhaps Labrador to New York City (Champlain Hudson 2012). Although the project sponsors have recently affirmed that there are no supply contracts for the project, there are plans for the development of new large-scale hydro facilities in Quebec and Labrador, as discussed below.

2. Overview of Canadian Hydro Projects Hydro-Quebec currently is constructing two large hydro projects, both of which will generate in excess of 8 million MWh per year (Hydro-Quebec 2009). The first, the Eastmain A/Sarcelle/Rupert project, is under development and is scheduled to be completed in 2012. The second project, the Romaine Complex, is also already committed and is proceeding. Hydro-Quebec is also planning other hydro projects as part of its Northern Plan. In addition, Nalcor Energya utility owned by the government of Newfoundland and Labradoris currently exploring the Lower Churchill Falls project in Eastern Canada.

3. Baseline Conditions vs. No-Action Alternative We understand that there is substantial uncertainty regarding whether or not the Champlain Hudson project and any future Canadian hydro projects will be constructed. As with other energy developments discussed in the report body, however, these projects are not relevant to evaluation of the potential adverse environmental impacts of the no-action alternative unless they affect how electricity systems would respond to loss of IPECs baseload generation. If they are constructed under baseline conditions, they would not be counted as replacements for IPEC 101

under the no-action alternative. The Canadian hydro projects that have already begun construction are clearly part of the baseline, even if the Champlain Hudson project were to be developed and the output of these two hydro projects sent to New York. In that case, the hydro generation from these two projects would simply be diverted from other regions (e.g., New Brunswick, New England, Ontario) with the net environmental effect determined by the incremental generation that would be added in those regions to make up for the loss in the hydro generation that otherwise would have been used.

Even if additional new hydro facilities were developed in Quebec after the Champlain Hudson line was in place (assuming that the line was constructed), whether or not generation from Canadian hydro facilities would constitute part of the net replacement for IPEC generation would depend upon the net changes in the overall electricity system and, in particular, whether these hydro resources would otherwise have been used to displace fossil generation in other regions. As with other questions related to the impacts of the no-action alternative, the answer depends largely upon details regarding the relative costs of the different generation alternatives to meet electricity demands in different regions and different time periods.

Even if Canadian hydro resources did constitute the net resources added in response to the loss of IPEC generation, the maximum additional potential hydro generation that could be transmitted over the Champlain-Hudson Power Express Project would represent only 40 percent of the IPEC energy that would need to be replaced in the no-action alternative. Moreover, an expansion of Canadian hydro generation (and any related transmission) in the no-action alternative would have adverse environmental impacts of its own, as discussed below. Note that NYS-37 does not provide any information on the potential energy and environmental impacts of the no-action alternative if these Canadian transmission and hydro projects were implemented.

B. Adverse Environmental Impacts of Canadian Hydro This section outlines the environmental impacts of three illustrative Canadian hydro projects, the Eastmain-1-A/Sarcelle/Rupert project and the Romaine Complex project, which are currently under construction, and the Lower Churchill project, which is in the permitting phase.

These environmental impacts provide an indication of the potential impacts if additional Canadian hydroelectric were to constitute part of the replacement generation under the no-action alternative.

1. Greenhouse Gas Emissions All three hydro projects would lead to increases in GHG emissions, based upon estimates developed by Hydro-Quebec and Nalcor Energy. The Eastmain-1-A/Sarcelle/Rupert project would lead to peak increases in gross CO2e emissions of between 128,000 to 685,000 annual tones (Hydro-Quebec 2004). The Romaine Complex would lead to peak increases in gross CO2e emissions of between 150,000 to 475,000 annual tons (Hydro-Quebec 2008). The Lower Churchill project, a larger project than the other two, is expected to contribute more than 1,000,000 tons of CO2e emissions over ten years of construction and peak increases in net CO2e emissions of between 938,000 tons to 1,160,000 annual tons during operations (Nalcor Energy 102

2009). Indeed, even at year 20, the Lower Churchill facilities are projected to contribute between 121,000 to 125,000 tons of net CO2e emissions (Nalcor Energy 2009).

2. Other Emissions The EIS for the Lower Churchill project quantifies other air emissions during the construction of the facilities and their associated local transmission lines, including particulate matter (PM), sulfur dioxide (SO2), nitrogen oxides (NOX), carbon monoxide (CO), and volatile organic compounds (VOC).

Emissions of NOX and SO2 are the primary causes of acid rainwhich can lead to acidification of water bodies and other effectsand can also lead to various health effects. NOX and SO2 are also important precursors in the formation of fine particles (PM2.5), and ozone is formed by complicated atmospheric photochemical reactions involving NOx, VOC, and sunlight.

CO is a poisonous gas that aids in the formation of CO2 and ozone. PM and ozone are associated with significant adverse health effects.

Table C-1 displays the quantities of air emissions that are expected to be released during the construction of the Lower Churchill facilities and their associated transmission lines to deliver energy generated at these remote locations to the Canadian border.

Table C-1. Contaminants projected to be released during construction of the Lower Churchill facilities and their associated local transmission lines.

Contaminant Tonnes PM 1,391 SO2 1,301 NOx 19,791 CO 4,264 VOC 1,615 Source: (Nalcor Energy 2009)

3. Other Adverse Environmental Impacts The Eastmain-1-A/Sarcelle/Rupert EIS details a number of environmental impacts. For example, the project will lead to increased mercury bioaccumulation in fish 23, which will not return to current levels for all species until 2028 (Hydro-Quebec 2004). This will lead to heightened consumption restrictions for local human populations. The project will also change rates of erosion and sedimentation in the various affected waterbodies, ultimately reducing the sediment supply in the Rupert estuary by two-thirds (Hydro-Quebec 2004). A third example of note is the fact that the flooding of the diversion bay will lead to a loss of 18,810 hectares of vegetation, eliminating nearly 383,930 green metric tones of wood (Hydro-Quebec 2004).

23 Decomposition associated with reservoir flooding causes increased microbial activity which converts mercury into methylmercury (Nalcor Energy 2009). Methylmercury is a toxic form of mercury that bioaccumulates in fish.

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The Romaine Complex EIS also details a number of environmental impacts. For example, the project will have major impacts to fish communities because such communities will be permanently transformed (Hydro-Quebec 2008). The project will also lead to a threefold to sevenfold increase in fish mercury bioaccumulation, which could take up to 30 years to return to present levels (Hydro-Quebec 2008). The Romaine facilities will also result in impacts on 21,746 hectares of land, including 12,021 hectares of lost coniferous forest and a net 626 hectare loss of wetlands (Hydro-Quebec 2008). And as with the Eastmain facility, the Romaine complex will also change rates and patterns of erosion and sedimentation in the various affected waterbodies (Hydro-Quebec 2008).

The Lower Churchill EIS also details a number of environmental impacts. For example, mercury concentrations in fish are expected to increase and peak at 1.5 to 4.5 times natural levels, depending on the type of fish (Nalcor Energy 2009). It is expected to take up to 35 years for mercury concentrations in all fish types to return to current levels. The Churchill facilities will also entail habitat clearing in the form of 368 km of roads and 263 km of new transmission lines (Nalcor Energy 2009). Furthermore, temporary construction camps and quarries and borrow pits will entail habitat clearing of a 16 km2 area (Nalcor Energy 2009). 8,400 hectares of habitat will be cleared in order to fill the Gull Island reservoir associated with the project (Nalcor Energy 2009). Finally, as with the other facilities, the Lower Churchill project will changes rates and patterns of erosion and sedimentation in the various affected waterbodies (Nalcor Energy 2009).

C. Adverse Environmental Impacts of Transmission Lines from Canada Additional transmission lines would be required if new Canadian hydropower were to be exported to the Northeast United States. There are currently two such lines that have been proposed, one of which is the Champlain Hudson line discussed above. As noted, this would establish a 1,000 MW DC connection from the New York - Quebec border to New York City. A second transmission line is the Northern Pass Transmission Project, which would establish a 1,200 MW DC connection from the New Hampshire - Quebec border to southern New Hampshire. This subsection outlines some of the adverse environmental impacts expected to occur from construction of these transmission lines.

Champlain Hudsons Joint Proposal details some of the environmental impacts that are anticipated from the installation of the proposed transmission line. These impacts include the following (Champlain Hudson 2012):

 Dredging would be required to lay cables in the Hudson River and portions of Lake Champlain, resulting in temporary sediment resuspension and other impacts;

 Construction would result in temporary impacts to 56 acres of wetlands as well as to streams and tributaries; 104

 About 10.7 acres of forested wetland cover may be permanently converted to marsh or scrub-shrub communities;

 Approximately 236 acres of existing forest cover may be cleared during construction, 60 acres of which would be permanently cleared;

 Three miles of cable would be installed within the city streets in the borough of Queens, New York City; and

 138,040 linear feet of right-of-way within Agricultural Districts would be included in the Construction Zone.

Northern Pass Presidential permit application contains a preliminary assessment of the environmental impacts of the transmission project. According to the application, potential U.S.

impacts of the project include the following (Northern Pass 2010):

 Approximately 5.5 miles of wetlands will be traversed along the preferred route; however, at this time the quantity of forested wetlands that will be traversed may be underestimated.

 State endangered species that occur within 1,000 of the preferred route include the northern harrier, wild comfrey, golden fruited sedge, and the muskflower. State threatened species that occur within the same range of the preferred route include the Klams lobelia, the peregrine falcon, Pickerings bluejoint, the black racer (snake), and the wild lupine.

Northern Pass also submitted an addendum to their application specifying that their preferred route would span the Connecticut River, a Designated River and American Heritage River. It would also cross at least three other perennial streams (Sullivan 2011).

D. References Champlain Hudson. 2012. Champlain Hudson Power Express, Inc. Joint Proposal. Case No.: 10-T-0139. February 24, 2012.

2012.http://www.poughkeepsiejournal.com/assets/pdf/BK185815227.pdf Hydro-Quebec. 2004. Eastmain-1-A Powerhouse and Rupert Division: Environmental Impact Statement. Hydro-Quebec. Volume 4, Chapters 16-25, December 2004.

http://www.hydroquebec.com/rupert/en/pdf/vol_04_en_web.pdf Hydro-Quebec. 2008. Romaine Complex: Environmental Impact Statement. Hydro-Quebec, Aubust 2008. http://hydroforthefuture.com/docs/sizes/4dc98ad1333fe/source/2008E064-ANG-Rom-RES-03.pdf 105

Hydro-Quebec. 2009. Strategic Plan: 2009 - 2013.

http://www.hydroquebec.com/publications/en/strategic_plan/pdf/plan-strategique-2009-2013.pdf Joint Review Panel. 2011. Report of the Joint Review Panel: Lower Churchill Hydroelectric Generation Project, Nalcor Energy, Newfoundland and Labrador. Executive Summary and Recommendations. August 2011. http://www.ceaa.gc.ca/050/documents/51706/51706E.pdf Nalcor Energy. 2009. Lower Churchill Hydroelectric Generation Project: Environmental Impact Statement. February 2009. http://www.ceaa.gc.ca/050/document-eng.cfm?document=41653 Northern Pass. 2010. Application of Northern Pass Transmission LLC for Presidential Permit.

United States of America before the Department of Energy Office of Electricity and Energy Reliability. Northern Pass Transmission LLC: Docket No. PP-371. October 14, 2010.

http://www.northernpasseis.us/Document_Library/documents/USDoEPresidentialPermitAppl ication101410.pdf Sullivan, Mary Ann. 2011. Northern Pass Transmission LLC: Docket No. PP-371: Addendum to Application. February 15, 2011.

http://www.northernpasseis.us/Document_Library/documents/Northern_Pass%20_Addendu m_to_Application_Docket_No_PP-371.pdf 106