Renewable Grid Power – Endnotes
Case Study on Renewable Grid-Power Electricity
ENDNOTES
1 Separate case studies are being prepared for the other two sectors.2 This category includes biomass and excludes trash and non-renewable waste.
3 Department of Energy Strategic Plan, “Protecting National, Energy, and Economic Security with Advanced Science and Technology and Ensuring Environmental Cleanup,” Draft, August 6, 2003.
4 The International Energy Agency (IEA) maintains the Renewable Energy Policies & Measures Database for IEA member countries, available at http://library.iea.org/dbtw-wpd/textbase/pamsdb/re_webquery.htm. The Database of State Incentives for Renewable Energy (DSIRE) in the United States is available at http://www.dsireusa.org.
5 Adapted from M. Tampier, Promoting Green Power in Canada, prepared for Pollution Probe, November 2002, p. 2.
7The analytical framework is based on an analytical model, which is then translated into a numerical model using historical data and forecast information. It is the numerical model that generates the analysis used in the case study to asses the relative environmental and economic implications of the fiscal instruments.
8 In particular, the study team would like to thank the following for their timely contributions to this work: Robert Hornung (CanWEA), Dan Goldberger (CEA), Rob McMonagle (CanSIA), Martin Tampier (Environmental Intelligence), and Lynne Patenaude and Alain David (Environment Canada).
9 Source: National Energy Board (NEB) http://www.neb.gc.ca/energy/SupplyDemand/2003/index_e.htm.
10 These installed capacities are for grid-power electricity and potentially could be ECP-certifiable.
11 Includes many existing small hydro sites that may not be EcoLogo-certifiable.
12 This contrasts with efforts in the U.S. to compile a highly detailed wind atlas to assist in wind farm siting (see http://rredc.nrel.gov/wind/pubs/atlas).
13 The Canadian Electricity Association (CEA) has proposed that the eligibility of small hydro be expanded to 50 MW under Class 43.1 of the Income Tax Act.
16 Personal communication with Robert McMonagle, Executive Director, Canadian Solar Industry Association, February 19, 2004.
19 Offshore is not included due to a lack of independent estimates. See Appendix B for more details.
20 It is widely recognized that issues related to grid access, grid capacity and the costs of grid extension will be particularly influential in determining the amount of grid-power RETs that can be practically developed. While these issues are beginning to be addressed in some regions, they are far from being resolved at this time. Further consideration of these issues is well beyond the scope of this case study.
21 Cost estimates are for all OECD countries; the wide range of values shown reflects both the diversity of conditions experienced and the high levels of uncertainty.
22 It is recognized that NRCan is preparing a new baseline forecast using NEMS; however, at the time of completion of this case study the new forecast was not available.
23 The scenarios are the EFR managed instruments; they are assessed against the baseline that is defined in this report.
24 Further information on the IPM model is available on Environment Canada’s website.
25 ICF Kaiser, Analysis of Electricity Dispatch in Canada – Final Report, Environment Canada, August 19, 2003 (available on Environment Canada’s website).
26 Note: the EC study attributes zero GHG emissions to U.S. imports. While this is consistent with the approach to be used within PERRL, the actual number is greater than zero. Consequently, the results presented are conservative.
27 Current natural gas market conditions suggest that these values are probably low. However, the ICF value was used to ensure consistency with other study outputs that are used in this case study.
28 Statistics Canada, Industrial Research and Development: 2003 Intentions, Cat. No. 88-202-XIE.
29 NRCan, Renewable Energy in Canada – Status Report 2002.
30 International Energy Agency, R&D Database (http://library.iea.org/dbtw-wpd/Textbase/stats/rd.asp).
31 Fossil fuel includes coal, gas and oil in the CEOU99.
32 National Energy Board, Canada’s Energy Future: Scenarios for Supply and Demand to 2025, Appendix 3: Demand, 2003 http://www.neb-one.gc.ca/energy/SupplyDemand/003/English/ SupplyDemandAppendices2003_e.pdf.
33 While it is of course not strictly true that fossil fuel technologies will experience no further technological advances, incorporation of a positive, but slower relative rate of advance in fossil fuels would complicate the analysis without adding substantial additional insights.
34 The assumption of a single fossil energy technology is admittedly strong and requires some caveats. As long as the marginal technology exhibits constant marginal costs, the equilibrium effects on the market price and surplus are the same. The exceptions involve policies with an emissions price when emissions intensities vary across fossil technologies. For example, if coal is used by the inframarginal technology and natural gas turbines are the marginal technology, an emissions price will raise costs more for coal, but the market price will only reflect the cost increase for natural gas (unless coal becomes no longer inframarginal), implying a loss of producer surplus for coal. Policy effects on average emissions intensity will also vary, and those without an emissions price will tend to displace the lower-emitting marginal technology. We feel that this simplification allows us to capture the key qualitative results; a richer modelling is only likely to exacerbate the welfare differences of the policies.
35 Longer-term convexity of the renewable cost function is attributable to decreasing quality of available land for wind and biomass generation. Input scarcity is not a substantial longer-term issue for fossil-based production, however, justifying the simplifying assumption of constant marginal costs (i.e., constant returns to scale).
36 Note therefore that we are assuming here that firms have perfect foresight, that there are no knowledge spillovers, and that firms internalize any future returns to investments in R&D and learning by doing (LBD). For the present purposes we also assume that the costs of R&D and LBD are fully reflected in the market prices faced in making these investments. These assumptions are not meant to necessarily reflect reality, but rather to model a simplified situation upon which intuition can be developed and further modelling extensions can be built.
37 See e.g., Milliman and Prince (1989), Biglaiser and Horrowitz (1995), Jung et al. (1996), Fischer et al. (2003), Requate and Unold (2002). Dynamic problems are also treated in Petrakis et al. (1999) and Kennedy and Laplante (1999).
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