In 1998, the OCAA hired energy analyst Steven Diener to examine the cost of replacing some of Ontario’s coal-fired generating units with substantially cleaner natural gas fired units.  Below are the results of that study.

 

Financial Support for the Study Provided by:

AES Kingston Inc.
Canadian Niagara Power
Commission for Environmental Cooperation
Environment Canada
Great Lakes Power
Independent Power Producers’ Society of Ontario
Municipal Electric Association
Ontario Hydro
Ontario Natural Gas Association

Diener Consulting Inc., in association with

Acres International Limited
Toronto, Canada

November 9, 1998

ACKNOWLEDGMENTS

 The consultants wish to acknowledge the assistance provided by Jack Gibbons of the OCAA and by the OCAA Advisory Committee, including Tim Adamson, the Ontario Natural Gas Association; Bruce Ander, the Independent Power Producers’ Society of Ontario; Don Bartlett, AES Kingston Inc.; Bud Carruthers, Great Lakes Power; Helen Howes, Ontario Hydro; Manfred Klein, Environment Canada; Nick Nikkila, Commission for Environmental Cooperation; Fred O’Brien, Canadian Niagara Power; and John Wiersma, Municipal Electric Association.

The consultants also express their thanks for the cooperation and assistance provided by Hy-Hien Tran of Natural Resources Canada, and Angelo Castellan, Kevan Jefferies and Barbara Reuber of Ontario Hydro.

 

 

 TABLE OF CONTENTS

EXECUTIVE SUMMARY

Study Background and Objectives

Study Methodology and Input Data

2.2.1 NRCan Forecast for Ontario’s Electricity Sector
2.2.2 Other Input Data

Study Findings

3.2.1 Higher and Lower Gas Prices
3.2.2 Lower Nuclear Generation
3.2.3 Higher and Lower Load Growth

APPENDICES

Appendix A Sources of Air Pollution Emissions in Ontario

Appendix B Spreadsheet (EXCEL) Model

 


 

EXECUTIVE SUMMARY

Study Objectives

A conservative (that is, upper-bound) estimate of the cost of reducing Ontario’s electricity-related emissions can be obtained by determining the cost of building and operating new natural gas-fired generating stations to replace some of the output of Ontario Hydro’s coal-fired generating stations. The current study was intended to provide the OCAA with an analytic tool in the form of a computerized “spreadsheet”model that would simulate the cost and emission impacts of replacing coal-fired with natural gas-fired generation. The model was designed to (i) assess the cost of establishing caps for Ontario’s electricity-related sulphur dioxide emissions which are (a) 25 percent; (b) 50 percent; (c) 75 percent; and (d) 90 percent lower than Ontario Hydro’s status quo sulphur dioxide emission cap (175 kilotonnes, or kT) by replacing some of Ontario Hydro’s coal-fired generation with natural gas-fired generation; and (ii) assess the reductions in carbon dioxide, nitrogen oxides and air toxics emissions associated with achieving the sulphur dioxide reductions. Throughout, it was assumed that gas-fired generation would be based on “best-practice”, that is, the most cost-effective, technology for natural gas-fired power generation. As well, the study adopted conservative assumptions to ensure that the costs of gas substitution would not be understated. These included the choice of study period (2002-2014) during which no new coal plant investments would be made and hence, no major quantum of avoided capital costs would accrue as benefits to the “gas option”. (See Section 1.2 for a list of these conservative assumptions.)

Model Logic

The following algorithm was developed for the spreadsheet model. The model first translates user-specified percent reductions in the sulphur dioxide (SO2) cap (initially set at 25, 50, 75 and 90 percent) into an upper limit for SO2 emissions. This upper limit, along with emission coefficients applicable to Ontario Hydro’s coal plants, determines the required reductions, if any, in coal-fired electricity generation. In turn, this decrease in kilowatt-hours (kWh) generated from existing coal-fired plants defines the quantum of electric energy “deficit” to be met by new gas plants, using combined cycle technology. Based on the energy deficit and the relevant capacity factors (provided by Ontario Hydro), the model determines the capacity, measured in Megawatts (MW), of new gas plants required.

Gas fuel costs and coal cost savings are calculated using heat rates and fuel price projections. The annual net gas substitution costs are discounted to 1998 and expressed in terms of (i) the net present value (NPV) of costs and (ii) the levelized costs (also known as the supply price) per unit of electric energy consumption in Ontario.

Emissions of SO2, nitrogen oxides (NOx), carbon dioxide (CO2) and the toxics are also calculated both in absolute terms, in terms of changes from the business as usual case, and as costs per cumulative tonne of emission savings. (Note that all NOx emission values are measured in terms of nitric oxide, or NO.)

Findings

The base case results follow from “business as usual” inputs on natural gas prices, load growth and generation mix, provided by Natural Resources Canada (NRCan) and shown in Section 2.2.1. As shown in Table 3-1, the 1998 present valued costs (in 1998$) of meeting the SO2 reduction targets range from $282 million (25 percent reduction in the cap) to $1,820 million (90 percent reduction).The levelized costs range from about 0.03 cents/kWh (25-percent reduction) to about 0.2 cents (90-percent case). In terms of impact on monthly residential bills, the costs of meeting the SO2 reduction targets range from $0.28 (25-percent reduction) to $1.86 (90-percent reduction).

Emissions in the year 2014 of SO2, CO2, NOx and the air toxics are also shown in Table 3-1. In the 90-percent reduction scenario, SO2, NOx and CO2 emissions amount to 17.5, 17.3 and 18,243 kT, respectively.

Table 3-2 extends these results to show the cumulative reductions(2002 to 2014) in emissions, relative to the NRCan “business as usual” scenario. Note that for each of the pollutants, the cumulative reductions rise about tenfold as we move from a 25- to a 90-percent SO2 reduction target. In terms of emission quantities, nearly 99 percent of the total reduction is attributed to carbon dioxide – an important consideration in the context of global climate change. In other words, the lower cap on SO2 emissions would also have beneficial impacts on CO2 , as well as on other (NOx and toxics) emissions. In terms of percent reductions relative to the NRCan scenario, the cumulative savings in SO2, CO2 and NOx and toxics emissions reach 83, 51, 77 and 83 percent, respectively, in the case based on the 90-percent reduction in the SO2 cap.

Table 3-3 shows the NPV costs per unit of emission reduction for each of four classes of pollutant: SO2, CO2, NOx and the seven toxics taken together. The costs are allocated equally to the four classes – an arbitrary but simple method, hence the most reasonable of several possible approaches. In the 90-percent reduction scenario, the costs of eliminating one tonne of SO2, is about $1,900. Corresponding costs of the cumulative reductions in CO2, NOx, and the toxics are about $14, $3,600, and $61,683,000, respectively.

A particularly important sensitivity case uses a high (4 percent per year) real growth in gas prices to reflect the volume of incremental gas relative to current provincial demand. (See Table 3-4.) In this high price scenario, the costs of achieving the SO2 reduction targets range from about $0.37 billion (0.04 cents/kWh) to $2.7 billion (0.32 cents/kWh), as the reduction targets are raised from 25 to 90 percent.

Tables 3-5 and 3-6 show the impacts on emission reductions (relative to the NRCan business as usual case) stemming from lower nuclear generation and higher/lower load growth, respectively. In both cases, the “shortfall” in energy supply is met by increased gas-fired generation. As a result, the quantum of coal-to-gas switching is the same as in the NRCan case and the only impacts are on the (increased) CO2 and NOx emissions stemming from higher gas usage.

 

Study Background and Objectives

1.1 Background

Ontario’s coal-fired generating stations are responsible for a significant portion of Ontario’s total emissions of CO2 (a “greenhouse” gas), SO2 (a precursor to acid rain) and NOx (a major contributor to smog). In 1990, Ontario Hydro’s (Hydro’s) CO2 emissions accounted for 18 percent of the provincial total; its SO2 for 16 percent and its NOx for 12 percent. In addition, Hydro’s coal stations also emit 35 air toxics including mercury and six carcinogens (arsenic, beryllium, cadmium, chromium, lead and nickel). Emissions originating in the U.S. are also an important contributor to air pollution in Ontario. For example, when Ontario’s smog levels exceed 80 parts per billion (ppb), U.S. emissions are responsible for 55 percent, 25 percent and 20 percent of the nitrogen oxide levels in London, Stouffville and Ottawa respectively.

Governments and public interest groups have identified the need to achieve significant reductions in the emissions of these pollutants. For example:

  • In Kyoto, Japan in December 1997, Canada undertook to reduce its greenhouse gas emissions by 6 percent during the period 2008 to 2012 relative to its levels in 1990.
  • The Acidifying Emissions Task Group report, Towards a National Acid Rain Strategy, calls for a 75-percent reduction in SO2 emissions in eastern North America.
  • Ontario’s Smog Plan calls for a 45-percent reduction in Ontario’s NOx emissions by 2015. Furthermore, the Ontario Medical Association recommends an 85-percent reduction in Hydro’s NOx emissions.
  • The Great Lakes Binational Toxics Strategy: Canada – United States Strategy for the Virtual Elimination of Persistent Toxic Substance in the Great Lakes requires Canada to seek to reduce its mercury emissions in the Great Lakes basin by 90 percent by 2000.

See Jack Gibbons and Sara Bjorkquist, Electricity Competition and Clean Air, (Toronto: Ontario Clean Air Alliance; 1998) for more information.

Clearly, there now exists a need to estimate the scope for, and costs of, reducing emissions from Ontario’s electricity sector. Options to achieve these reductions include

  • energy end-use efficiency investments (for example, energy-efficient lighting) to reduce the demand for electricity
  • end-of-pipe pollution abatement technologies (for example, scrubbers); and
  • replacing some of Hydro’s coal-fired electricity generation with cleaner supply options such as natural gas-fired generation and renewable energy.

1.2 Objectives

A conservative (that is, upper-bound) estimate of the cost of reducing Ontario’s electricity-related emissions can be obtained by determining the cost of building and operating new natural gas-fired generating stations to replace some of the output of Hydro’s coal-fired generating stations. [The study analysis is conservative in a number of ways. For example, (a) all emission reductions are assumed to be achieved by new gas supply when there are many energy efficiency and some renewable energy options that can reduce emissions at a lower cost; (b) there are no coal-related avoided capital costs, although these are old plants and they will need new capital expenditures to keep operating; (c) even though in the NRCan base case scenario, NOx emissions exceed Hydro’s 38 kT cap in most years and switching to gas generation avoids the capital costs of new scrubbers, these benefits have not been included; (c) there are no coal plant shutdowns even under a 90 percent reduction scenario and the avoided coal operating and maintenance (O&M) costs may therefore be understated; and (e) the analysis has excluded avoided transmission line losses as a result of going from coal plants to gas plants that are located closer to the loads.]

The current study was intended to provide the OCAA with an analytic tool in the form of a computerized “spreadsheet”model that would simulate the cost and emission impacts of replacing coal-fired with natural gas-fired generation. In particular, the OCAA specified that the model should be capable of (i) assessing the costs of establishing caps for Ontario’s electricity-related sulphur dioxide emissions which are (a) 25 percent; (b) 50 percent; (c) 75 percent; and (d) 90 percent lower than Ontario Hydro’s status quo sulphur dioxide emissions cap (175 kilotonnes, or kT) by replacing some of Hydro’s coal-fired generation with natural gas-fired generation; and (ii) assessing the reductions in carbon dioxide, nitrogen oxides and air toxics emissions associated with achieving the sulphur dioxide reductions. It was assumed that gas-fired generation would use the most cost effective (“best-practice”) technology for gas-fired power generation.

The selected “combined-cycle” technology achieves high energy conversion efficiencies by combining a gas turbine with a waste heat boiler that, in turn, generates high pressure steam for a steam turbine.

More specifically, the model was designed to provide the following information:

  • The net present value (NPV) of achieving the four SO2 reduction targets relative to NRCan’s “business as usual” forecast and the current SO2 emission cap of 175kT.
  • The absolute dollar and approximate percent increase in Ontario’s cost of electricity for each year of the analysis for each of the four SO2 emission reduction scenarios relative to NRCan’s business-as-usual scenario.
  • Ontario’s annual electricity-related emissions of CO2, NOx, arsenic, beryllium, cadmium, chromium, lead, mercury and nickel under each of the four SO2 emission reduction scenarios and the reductions in each pollutant relative to the business as usual forecast (Note that all NOx emission values are measured in terms of nitric oxide, or NO).
  • For each emission reduction scenario, ratios expressed as the quantity of SO2, NOx, CO2 and air toxics (individually and in total) divided by the NPV of the cost of the emission reductions.

The study also included sensitivity analysis to assess the impacts of

  • higher and lower natural gas prices;
  • lower nuclear electricity generation (75 percent and 50 percent of the business as usual forecast); and
  • a lower and a higher load growth forecast.

 

2. Study Methodology and Input Data

2.1 Methodology

2.1.1 Definition of Gas Substitution Costs and Benefits

To measure the net costs of switching from coal to gas-fired generation, costs and benefits were identified as follows. The benefits of gas generation were defined as the avoided costs stemming from reduced coal generation, including coal plant fuel costs, operating and maintenance (O&M) costs and avoidable replacement or retrofit capital costs. The costs of switching to gas generation included the capital costs of the gas plant, its fuel cost and its O&M cost. Annual net cash flows were then defined as the difference between substitution benefits and costs. Note that both costs and benefits were measured in inflation-adjusted (“real”) 1998 Canadian dollars. In line with our “conservative” approach, it was assumed that coal plants would not be subject to capital costs.

2.1.2 Planning Horizon

The planning horizon for the study was initially defined as 2002 to 2022, taking into account the minimum lead time (4 years) necessary for the design and construction of the combined cycle gas power plant and the expected economic life of the plant. This period was shortened in the course of the study to 2002 to 2014, in order to avoid biassing the results in favour of gas substitution. (NRCan has assumed that in about 2015, a 3,300 MW “low-pollution”coal plant would be commissioned.) In other words, had the horizon included 2015, the benefits of gas for coal substitution would have included the avoided capital costs of this coal plant, significantly lowering the overall cost of substituting gas for coal generation in the 2002 to 2014 period as a whole, a major component of gas substitution benefits.

The reference or base year for discounting the cash flows is 1998. Throughout the study, the net present value (NPV) of costs means the NPV in 1998; that is, all annual cash flows are discounted to 1998, using a real discount rate noted in Section 2.2.2

2.1.3 Model Logic

For the base case scenarios using NRCan assumptions for gas prices, load growth, and nuclear generation, the following algorithm was developed for the spreadsheet model. The model translates user-specified percent reductions in the SO2 cap (25, 50, 75 and 90 percent) into an upper limit for SO2 emissions. This upper limit, along with emission coefficients applicable to Hydro’s coal plants, determines the required reductions, if any, in coal-fired electricity generation. In turn, this decrease in kWh generated from existing coal-fired plants defines the quantum of electric energy “deficit” to be met by new gas plants, based on combined cycle technology. Based on the energy deficit and the capacity factors relevant to each reduction scenario (as provided by Hydro), the model determines the capacity (MW) of new gas plants required.

Gas fuel costs and coal cost savings are calculated using heat rates and fuel price projections. Annual net cash flows are then determined using the costs and benefits noted in Section 2.1.1. Finally, the NPV of gas substitution costs are determined, both in 1998 dollars and in terms of levelized costs (also known as the supply price) per unit of electric energy consumption in Ontario. The supply price provides a constant real cost per kWh (over the period 1998 to 2014) required to amortize the NPV cost of the emission reductions.

Annual and cumulative emissions of SO2, NOx, CO2 and the toxics are determined next, using the emission coefficients applicable to Hydro’s coal plants and the new “replacement” gas plants. These emissions are calculated (i) in absolute terms, (ii) in terms of reductions from the business as usual case (both as quantities and percent changes), (iii) as total NPV costs per cumulative unit of emission savings, by pollutant, and (iv) as “supply prices” or levelized costs per cumulative tonne of emission saving, based on a user-specified allocation of costs among the four classes of pollutants (SO2, CO2, NOx, and the toxics), initially set so each class of pollutant bears 25 percent of the total costs.

In the sensitivity cases using higher and lower gas prices, the same approach is used in the model. In the remaining sensitivity cases involving different load growth and nuclear generation assumptions, the model assumes that any shortfall in energy (due to higher load growth or lower nuclear production) is met by increased gas-fired generation. But as the quantities of coal use and the degree of coal-to-gas substitution are the same as in the reference case analysis, the costs of SO2-related substitution will remain the same and hence are not displayed. However, the gas-based emissions of CO2 and NOx do increase; and the model does calculate and display these.

Appendix B contains the EXCEL-based model on floppy disk All user input values are shown in blue; if any of these input data are changed, the model automatically re-calculates all output data values. The model is self-documenting in the sense that all sources of input data are shown “behind” the relevant cells.

2.2 Input Data

Following the Terms of Reference and the consultants’ proposal, input data were obtained from a variety of sources, including Acres International Limited (consulting engineers), Environment Canada, Natural Resources Canada (NRCan), the OCAA (in particular Mr. Jack Gibbons) and Ontario Hydro. The following is a list of the sources of the key families of data and their sources (Sections 2.2.1 and 2.2.2 provide a summary of the input data used in the model; Appendix 2-A , the Model, contains the most detailed documentation of the data and their sources.)

  • SO2 Emission Cap (tonnes), Reduction Target (%), Emission Target (tonnes) (OCAA)
  • Electrical Energy Demand (Gwh) (NRCan)
  • Coal Generation and Consumption (Gwh; tonnes) (NRCan)
  • Nuclear Generation (Gwh) (NRCan)
  • Coal Calorific Value (GJ/tonne and Coal Plant Heat Rate (GJ/kWh) (NRCan)
  • SO2 Emission Coefficients: Coal and Natural Gas (tonnes/kWh) (Env. Can.)
  • CO2 Emission Coefficients: Coal and Natural Gas (Env. Can.)
  • NOx Emission Coefficients: Coal and Natural Gas (tonnes/kWh) (Env. Can.)
  • Air Toxics Emission Coefficients (arsenic, beryllium, cadmium, chromium, lead, mercury and nickel) for coal and natural gas (tonnes/kWh) (Ontario Hydro)
  • capacity factors for coal plants (Ontario Hydro)
  • gas plant operating and maintenance (O&M) cost (1998$/MW) (Acres)
  • heat rate for combined cycle gas plants (Acres)
  • base period (1998) coal price (1998$/tonne) and real (inflation-adjusted) price index (NRCan)
  • base period (1998) gas price (1998$/m3) and real price index (NRCan)
  • gas plant O&M cost (1998$/MW) (Acres)
  • avoidable non-fuel coal plant O&M cost (1998$/MW) (Acres)
  • real discount rate (OCAA)

2.2.1 NRCan Forecast for Ontario’s Electricity Sector

Forecast data was obtained from NRCan staff familiar with its document Canada’s Energy Outlook: 1996-2020, (April 1997) and its background papers.

Load Forecast. Based on NRCan, we used a base case growth rate of 1.3 percent per year; the low and high growth sensitivity cases used zero and two percent.

Coal Price. In 1998, the price of coal was estimated at $54.95 per tonne (1998$). Over our study period, NRCan is projecting zero real growth in the price of coal.

Natural Gas Price. In 1998, the price of natural gas was estimated at $3.11 per GJ (1998$). In the base case, its growth is 0.25 percent per year; in the low and high cases, we assumed 0 and 4%, based on the considerations noted in Section 3.2.1.

2.2.2 Other Input Data

SO2 Targets (Scenarios). Given the current cap of 175.0 kT, the four reduction scenarios of 25, 50, 75 and 90 percent imply SO2 limits of 131.25, 87.5, 43.75, and 17.5 kT, respectively.

Power Plant Heat Rates. Heat rates for coal and gas plants are estimated by NRCan at 0.09 Gwh/input PJ and 0.15 Gwh/input PJ, respectively.

Capacity Factors. Based on Ontario Hydro estimates of annual capacity factors for the period 2002 to 2014, for a specified range of Twh of displaced fossil generation, the model uses average capacity factors of 85 percent (25 percent SO2 reduction scenario); 82 percent (50 percent reduction); 74 percent (75 percent reduction) and 63 percent (90 percent reduction).

Gas Plant Capital and O&M Costs. Capital costs are estimated at $750/kW of capacity (1998$) and O&M costs at $5/Mwh.

Coal Plant O&M Cost (excluding fuel). Avoidable O&M cost is estimated at $4.50/Mwh (1998$).

Discount Rate. To calculate the present value of real (1998) dollar cash flows, the model uses a real discount rate of 10 percent.

Emission Coefficients. See Table 2.1.

 

TABLE 2-1
EMISSION COEFFICIENTS

(kg/MWh)

 

 

  Lambton Nanticoke Lakeview Thunder
Bay
Atikokan All Existing
Plants (weight.
avg.)
New Clean
Coal Plant
New
Gas-Fired
Plant
Capacity (MW)

1,980

3,876

1,138

310

215

7,519

3,300

3,300

SO2

3.49

4.28

6.96

3.15

3.60

4.41

0.22

0.00

CO2

921.11

1,021.06

923.03

906.37

985.58

974.16

699.12

372.62

NOx

2.00

2.64

3.16

2.19

2.05

2.52

0.17

0.19

Arsenic

4.17E-06

5.88E-06

2.70E-06

4.45E-06

3.76E-06

4.83E-06

4.50E-07

0.00E+00

Berylli-um

0.00E+00

4.52E-06

0.00E+00

6.01E-07

9.16E-08

2.36E-06

0.00E+00

0.00E+00

Cadmium

3.13E+06

9.87E-07

1.41E-06

3.72E-06

8.91E-07

1.73E-06

4.68E-07

0.00E+00

Chromi-um

1.47E-05

6.81E-05

2.21E-05

6.17E-05

1.73E-05

4.54E-05

6.30E-07

0.00E+00

Lead

0.00E+00

8.60E-06

0.00E+00

3.54E-05

7.67E-06

6.11E-06

8.10E-07

0.00E+00

Mercury

5.81E-06

4.90E-06

1.99E-05

6.21E-05

6.12E-05

1.14E-05

9.90E-08

0.00E+00

Nickel

8.93E-05

5.63E-05

2.15E-05

2.85E-05

1.77E-05

5.75E-05

3.60E-07

0.00E+00

 

 

Study Findings

3.1 Base Case Results

These results follow from the so-called “business as usual”` assumptions concerning natural gas prices, load growth and nuclear generation, as provided by NRCan and discussed in Section 2.2.1.

The first set of results, shown in Table 3-1, includes the total present valued costs, unit (per kWh) costs and cost impacts on residential consumer bills associated with achieving the 25-, 50-, 75- and 90-percent reductions in the SO2 emission cap of 175 kT. Note that the 1998$ costs of meeting these targets range from $282 million to $1,819 million. The costs are also expressed in terms of costs per kWh of total provincial electricity consumption, using the concept of “supply price” over the period 1998 to 2014. These unit costs of meeting the new caps through gas-for-coal substitution range from about 0.03 cents/kWh (in the case of 25-percent reduction) to about 0.22 cents (in the 90-percent case). Expressed in terms of monthly increases in residential bills, the cost impacts facing a typical household would range from $0.28 to $1.86.

Emissions in 2014 of SO2, CO2, NOx and the seven air toxics are also shown in Table 3-1. Emissions of all pollutants except those of NOx and CO2 drop by about 87 percent as the target SO2 reduction is raised from 25 to 90 percent. The quantities of SO2 emissions decrease from 131 kT to 17.5 kT. NOx emissions decrease by about 78 percent from 77 to 17.3 kT. As natural gas contributes significant amounts of CO2, though far less than does coal, the CO2 emissions fall by “only” about 50 percent from 33,761 to 18,243 kT as we move from a 25- to a 90-percent SO2 reduction target.

Table 3-2 extends these results to show the cumulative (2002 to 2014) reductions in emissions (in absolute and percent terms) relative to the NRCan “business as usual” scenario. For each of the pollutants, the cumulative reductions rise about tenfold as we move from a 25- to a 90-percent SO2 reduction target. In terms of emission quantities, nearly 99 percent of the total reduction is attributed to carbon dioxide – an important consideration in the context of global climate change. In other words, the lower cap on SO2 emissions would also have beneficial impacts on CO2, as well as other (NOx and toxics) emissions. In terms of percent reductions relative to the NRCan scenario, the cumulative savings in SO2, CO2 and NOx and toxics emissions reach 83, 51, 77 and 83 percent, respectively, in the case based on the 90-percent reduction in the SO2 cap.

TABLE 3-1
COSTS AND CUMULATIVE EMISSIONS : BASE CASE REDUCTIONS IN SO2 CAP

 

25 % Reduction in SO2 Cap

50 % Reduction in SO2 Cap

75 % Reduction in SO2 Cap

90 % Reduction in SO2 Cap

NPV of Gas Substitution Cost (million 1998$

Supply Price

(1998 cents/kWh)

Supply Price as % of Average Retail Electricity

Price in Ontario1

Monthly Bill Impact (1998$) for Typical Residential Consumer2

282

 

 

0.033

 

 

0.5

 

 

 

0.28

 

 

551

 

 

0.065

 

 

0.9

 

 

 

0.56

1,164

 

 

0.138

 

 

1.9

 

 

 

1.19

1,819

 

 

0.216

 

 

3.0

 

 

 

1.86

Emissions in 2014

SO2 (‘000 tonnes)

CO2 (’000 tonnes)

NOx (‘000 tonnes)

Arsenic (kg)

Beryllium (kg)

Cadmium (kg)

Chromium kg)

Lead(kg)

Mercury (kg)

Nickel (kg)

 

131.3

33,761

77.3

144

70

51

1,350

182

339

1,711

 

87.5

27,792

54.2

96

47

34

900

121

226

1,140

 

43.8

21,824

31.2

48

23

17

450

61

113

570

 

 

 

 

17.5

18,243

17.3

19

9

7

180

24

45

228

 

 

1 Average Retail Price = 7.2 cents/kWh (See: Third Interim Report of the Market Design Committee to the Honourable Jim Wilson Minister of Energy, Science and Technology, October 1998, p.1-4)

2 Average Monthly Residential Electricity Purchase = 860 kWh (ibid., Appendix 2, p.8) 

TABLE 3.2
CUMULATIVE EMISSIONS (NRCan Scenario) and CUMULATIVE EMISSION REDUCTIONS (2002 to 2014)

 

NRCan Business

as Usual

Scenario:

Cumulative

Emissions

 

Emission Reductions:

25%

Reduction in

SO2 Cap

(131.25 kT/yr)

 

Emission Reductions:

50%

Reduction in

SO2 Cap

(87.5 kT/yr)

Emission Reductions:

75% Reduction in

SO2 Cap

(43.75 kT/yr)

Emission Reductions:

90% Reduction in SO2 Cap

(17.5 kT/yr)

SO2 (‘000 t)1

1,342

(8) 105

(21) 282

(58) 773

(83) 1,114

CO2 (‘000 t)

296,444

(5) 14,256

(13) 38,525

(36) 105,467

(51) 152,018

NOx (‘000 t)

766

(7) 55

(19) 149

(53) 408

(77) 588

Arsenic (kg)

1,469

(8) 114

(21) 309

(58) 847

(83) 1,220

Beryllium (kg)

718

(8) 56

(21)151

(58) 413

(83) 596

Cadmium (kg)

525

(8) 41

(21)110

(58) 302

(83) 436

Chromium (kg)

13,803

(8) 1,075

(21) 2,905

(58) 7,953

(83) 11,463

Lead (kg)

1,860

(8)145

(21) 391

(58) 1,072

(83) 1,545

Mercury (kg)

3,463

(8)270

(21) 729

(58) 1,995

(83 )2,875

Nickel (kg)

17,489

(8)1,362

(21) 3,681

(58) 10,077

(83)14,524

 

1 Figures in parentheses show emission reductions expressed as a percent change from the NRCan scenario

 

The costs per unit of emissions are shown in Table 3-3. The emissions have been grouped into four classes (SO2, CO2, NOx and the seven toxics taken together) and the NPV costs arbitrarily allocated such that each class of pollutant bears 25 percent of the costs. The unit costs are based on the supply price concept (see Section 3.1); the emission reductions are also in present value terms. In other words, both the numerator and denominator of the ratio reflect values discounted at ten percent over the period 2002 to 2014. In the case where a 90-percent SO2 reduction target is used, the cost of eliminating one tonne of SO2 is shown to be $1,875.

TABLE 3-3
UNIT COST OF CUMULATIVE EMISSION REDUCTIONS (1998$/tonne)1

 

POLLUTANT

 

90% Reduction in SO2 Cap (17.5kT/yr)

Sulphur Dioxide (SO2)

 

1,875

Carbon Dioxide (CO2)

 

14

Nitrogen Oxides (NOx)

 

3,556

Toxics: Arsenic, Beryllium, Cadmium, Chromium, Lead , Mercury, Nickel

 

61,683,000

 

1 Unit costs are based on the “supply price” concept, whereby both the costs and the cumulative emission reductions(2002-2014) are discounted to 1998, using a ten-percent discount rate and 1998 dollars.

 

3.2 Sensitivity Cases

3.2.1 Higher and Lower Gas Prices

Clearly, the cost of substituting natural gas for coal will be influenced by the price of natural gas. In our study, this sensitivity analysis of price has a particular significance as the potential volumes of gas substitution in the base case alone may be high enough to dictate a price impact on gas. When we assess sensitivity cases involving higher load growth and lower nuclear generation, these incremental gas volumes will be even greater in both absolute terms and relative to current gas consumption in Ontario, about 1,000 petajoules (PJ), where 1 PJ is 1012 joules. For example, in the base case, the range of reductions in SO2 caps (25 to 90 percent), translates into incremental gas volumes of about 16 to 190 PJ in 2012, or about 1.5 to 19 percent of current demand. In sensitivity cases involving a 50-percent reduction in nuclear generation, the incremental gas demands reach about 280 to 450 PJ as the SO2 cap is reduced by 25 to 90 percent. These gas volumes represent about 28 to 45 percent of current demand. See Appendix B for details of incremental gas consumption associated with the various sensitivity cases.

The magnitudes of these new demands for gas will ensure that additional transmission capacity will will be required over the study horizon. Preliminary discussions with a gas industry consultant have confirmed that whether the source of the “new” gas is North, South, West or East, delivered prices of gas will rise due to the costs of both additional supply and pipeline capacity. This conclusion holds even more strongly if rolled-in pipeline transmission tariffs are replaced by incremental pricing. For all these reasons, we have chosen a conservative 4-percent real growth rate for our high price scenario (a doubling of gas prices in about 18 years) and a zero real growth rate in the low price scenario.

The costs associated with these cases are summarized in Table 3-4. Note that the quantity of coal-to-gas substitution remains the same as in the base case; hence the emissions and emission reductions are not shown. The more likely high-price scenario yields present valued costs ranging from $0.370 billion to $2.7 billion; the unit costs (supply prices) per kWh are 0.04 cents to 0.32 cents (as we move from the 25- to 90-percent reduction scenarios).

In the low-price scenario, the costs of achieving the SO2 targets range from $0.28 billion to $1.8 billion. The supply prices (unit costs) range from 0.03 cents to 0.21 cents

TABLE 3-4
COSTS OF ACHIEVING SO2 REDUCTIONS: HIGH AND LOW GAS PRICES

 

25 % Reduction in SO2 Cap

50 % Reduction in SO2 Cap

75 % Reduction in SO2 Cap

90 % Reduction in SO2 Cap

HIGH GAS PRICES

(4% real growth)

NPV of Gas Substitution Cost (million 1998$

Supply Price

(1998 cents/kWh)

 

 

 

370

 

 

0.04

 

 

 

790

 

 

0.09

 

 

 

1,782

 

 

0.21

 

 

 

2,698

 

 

0.32

LOW GAS PRICES

(O% real growth)

NPV of Gas Substitution Cost (million 1998$)

Supply Price

(1998 cents/kWh

 

 

 

277

 

 

0.03

 

 

 

539

 

 

0.06

 

 

 

1,132

 

 

0.13

 

 

 

1,772

 

 

0.21

 

 

 

3.2.2 Lower Nuclear Generation

Table 3-5 shows the results of sensitivity analysis on cases involving nuclear generation that is 25 and 50 percent below the base case figures. As noted in Section 2.2.2, the shortfall in energy supply is met solely by increased gas generation and the magnitude of coal-to-gas switching remains the same as in the base case. Hence the only impact is on increased CO2 and NOx emissions stemming from the increased use of natural gas. These emissions under each SO2 reduction scenario are compared to the emissions in the NRCan business as usual scenario to provide values for “Cumulative Emissions Reductions”. Note that CO2 reductions may be negative (that is, they increase) in some cases; however, both CO2 and NOx emission savings rise as the SO2 cap is progressively reduced.

3.2.2 Lower and Higher Load Growth

Table 3-6 shows the results of sensitivity analysis on cases involving higher and lower load growth respectively. Similar to the lower nuclear generation case, the higher load growth case involves only increased gas consumption and hence, increased emissions of CO2 and NOx. With lower load growth, the quantities of all pollutants decrease. The cumulative reductions in emissions are calculated, as in Section 3.2.2, with reference to the NRCan business as usual scenario. As in the case of lower nuclear generation, the case of higher load growth may be associated with negative CO2 reductions, but again these emission reductions rise as the SO2 cap is lowered.

TABLE 3-5
CUMULATIVE EMISSIONS AND REDUCTIONS: LOWER NUCLEAR GENERATION

 

25 % Reduction in SO2 Cap

50 % Reduction in SO2 Cap

75 % Reduction in SO2 Cap

90 % Reduction in SO2 Cap

25% Lower Nuclear Generation

Cumulative Emissions

(2002 to 2014)

CO2 (’000 tonnes)

NOx (‘000 tonnes)

Cumul. Emission Reductions from Business as Usual (NRCan) Case 1

CO2 (‘000 tonnes)

NOx (‘000 tonnes)

_______________

50% Lower

Nuclear Generation

Cumulative Emissions

(2002 to 2014)

CO2 (’000 tonnes)

NOx (‘000 tonnes)

Cumul. Emission Reductions from Business as Usual (NRCan) Case

CO2 (‘000 tonnes)

NOx (‘000 tonnes)

 

 

 

 

 

380,000

760

 

 

 

 

-83,542

+5

 

 

 

 

 

 

478,000

810

 

 

 

 

-181,340

-45

 

 

 

 

356,000

666

 

 

 

 

-59,273

+99

 

 

 

 

 

 

454,000

716

 

 

 

 

-157,071

+49

 

 

 

 

289,000

408

 

 

 

 

+7,669

+358

 

 

 

 

 

 

387,000

458

 

 

 

 

-90,129

+308

 

 

 

 

242,000

228

 

 

 

 

+54,220

+538

 

 

 

 

 

 

340,000

278

 

 

 

 

-43,578

+488

 

 

 

APPENDIX A

Shares of Total Ontario Emissions Contributed by Ontario Hydro and U.S. Sources
Table A-1
ONTARIO HYDRO’S EMISSIONS AS A PERCENTAGE OF ONTARIO’S TOTAL EMISSIONS, 1990

 

 

 

ONTARIO HYDRO

ASSOCIATED HEALTH AND/OR ENVIRONMENTAL PROBLEMS
SULPHUR DIOXIDE 16% acid rain, respiratory diseases, premature mortality
NITROGEN OXIDES 12% acid rain, ground-level ozone (smog), respiratory illnesses, premature mortality
CARBON DIOXIDE 18% climate change
MERCURY 10%* brain, liver, and kidney damage; reproductive failure and behavioural abnormalities in wildlife (e.g. loons)
CARCINOGENS N.A. cancer

 

 

 

* The mercury emission estimate is with respect to 1995.

Table A-2

Estimated source-receptor matrix for the percent contribution of each emission source region to the total NOx load observed at each of the selected receptor sites when the observed O3 concentrations are > 80 parts per billion (ppb).

 

 

 

RECEPTOR SITE

 

SOURCE REGION

 

USA

 

ONTARIO
LONDON (SW ONT)

 

55

 

45
STOUFFVILLE (Central ONT)

 

25

 

75
OTTAWA (Eastern ONT)

 

20

 

80

 

 

Source: Commission for Environmental Cooperation, Long-Range Transport of Ground-Level Ozone and its Precursors: Assessment of Methods to Quantify Transboundary Transport within the Northeastern United States and Eastern Canada, (1997), p.53.

 

APPENDIX B

Spreadsheet of calculations