CANADIAN ENERGY VECTOR EXPORTS AND GREENHOUSE GASES

Transcription

1 CANADIAN ENERGY VECTOR EXPORTS AND GREENHOUSE GASES prepared for NATURAL RESOURCES CANADA by T. J. McCann and Associates Ltd. September 2001 McC+A

2 SYNOPSIS Bases NRCan (1999) Export Forecasts; Ziff Energy (September 2001) U.S. Energy Use Changes, without Canadian electricity nor gas and McC+A/Clearstone File and Literature GHG/energy unit factors. Note: Canadian electricity net exports now represent about 1% of U.S. demands; gas exports are in order of 15% of U.S. needs. U.S. Changes (Ziff Energy) 2002 to 2010 Transition Period with much oil until LNG availability sufficient to replace Canadian electricity and natural gas (along with minor use of unused coal and nuclear generating capacity and return of major northwest U.S. hydraulic electricity). The study assumes an arbitrary 25% of new LNG from Alaska rest from Caribbean, Africa and Far East GHG Changes with no Electricity or Canadian Gas (Median Estimates - Megatonnes) Canada U.S. Deep Sea Marine Foreign Production Total Global Estimate Range Canadian Change Related Canadian Electricity Generation -3 NA Minor Minor -3 (-10 to 0) Candian Natural Gas Production NA NA -39 (-52 to -26) U.S. Change Related Decreased Canadian Gas NA -202 NA NA -202 (-214 to -190) Increased U.S. Coal NA +4 NA NA +4 (3 to 5) Increased U.S. LNG Use NA +248 NA NA +248 (-265 to -230) U.S. LNG Production/Transport NA NA +23 (15 to +30) Foreign LNG Production/Transport NA NA (55 to 120) TOTAL (80 to 135) Note: No GHG's attributable to nuclear or hydraulic electricity. Interim Period Emissions Special Notes Over the transition period 2002 to 2010 to full LNG replacement (by 2010), total global GHG changes expected to be within +20% of 2010 estimates. The table assumes continuing U.S. coal available to Ontario generation, but does allow the U.S. credit for no transit of Canadian gas to Ontario and for no gas exports (already minor) to Ontario. No impacts of Canadian gas exports on gas processing byproduct changes were considered e.g., reduced exports of Alberta petrochemical, of LPG s and of diluted heavy crude/bitumen s. The study briefly notes Canadian export/import balances of energy vectors other than oil and gas, but without any related GHG attributions crude oils, refined products and LPG s. Only direct use uncertainties are at the + of 5 to 10% level, all others are +30% or higher, hence the ranges shown. STUDY OUTPUTS MUST BE USED WITH GREAT CAUTION. - i -

3 DISCLAIMER The conclusions, recommendations and data developed in this study are the responsibility of T. J. McCann and Associates Ltd. and may not represent the views or opinions of Natural Resources Canada. - ii -

4 TABLE OF CONTENTS PAGE SYNOPSIS...i DISCLAIMER...ii 1.0 EXECUTIVE SUMMARY Introduction Canadian GHG Changes Relative to Electricity and Natural Gas No Electricity Exports No Gas Exports U.S. Replacement Energy Vectors Foreign GHG Changes Canadian Coal and Oil Use Changes LNG to U.S U.S. Imported Oil Global GHG Change Estimates Other Credits Uncertainties INTRODUCTION Terms of Reference Related Reports Methodologies CANADIAN RELATED GREENHOUSE GAS IMPACTS IF NO ELECTRICITY EXPORTS Introduction New Brunswick Quebec Ontario Canadian Side U.S. Electricity and Coal to Ontario Manitoba Bases No Electricity Export Cases Alberta/Saskatchewan British Columbia Bases No Electricity Export Case Summary Re Canadian Non-Export of Electricity Non-North American GHG Changes Due to No Canadian Electricity Exports CANADIAN GHG IMPACTS OF NO NATURAL GAS EXPORTS Introduction Nova Scotia Ontario Canadian Supply U.S. Gas Supply to Ontario Saskatchewan Alberta British Columbia Canadian Summary U.S. Summary Due to Supply to and Transit of Canadian Gas iii -

5 5.0 U.S. GHG VALUE OF CANADIAN ELECTRICITY AND NATURAL GAS Introduction Oil Sources Coal Sources LNG U.S. GHG Impacts FOREIGN IMPACTS RELATIVE TO U.S. CHANGES Introduction Only LNG Preamble Heavy Fuel Oil to New England Light Fuel Oils to Midwest and the Pacific Coast CRUDE OILS Preamble Credit in U.S. for Canadian Crude Use U.S. Emissions Relative To Canadian Crude Transit Offshore GHG Charges for Canadian Crude Imports REFINED PETROLEUM PRODUCTS Preamble Greenhouse Gases Attributable to Canada U.S. Impact of No Canadian RPP s RPP Imports to Canada and Greenhouse Gases LIQUEFIED PETROLEUM GASES Propane and Butane Ethane COAL MISCELLANEOUS ENERGY VECTORS Uranium Petroleum Coke Metallurgical Coke Methanol / MTBE Fuel Ethanol Carbon Dioxide Hydrogen Wood Derivatives CONCLUSIONS AND RECOMMENDATIONS Natural Gas Byproduct Relationships Marginal Versus Average Factors Other Fossil Fuel Vectors Synthetic Crude Oil Credit? Uncertainty Reduction iv -

6 1.0 EXECUTIVE SUMMARY 1.1 Introduction This study provides an understanding of the greenhouse gas (GHG) value of Canadian electricity and natural gas sales to the U.S. NRCan provided basic export rate scenarios and a parallel study by Ziff Energy provided estimates of U.S. energy vector changes in events of no Canadian electricity or gas exports. This study converted these forecasts into units of GHG. The emphasis here has been on 2005 and 2010, with brief looks at early 2001 data to confirm or provide estimate bases e.g., relative gas exports by border point. "Net Canadian electricity exports are now forecast at only 1% of U.S. demand, Canadian gas exports to be about 15% of U.S. needs. This study considered only GHG value of now exported Canadian electricity and gas, it did NOT consider increasing U.S. energy demands, nor of impacts due to changes in natural gas processing byproduct exports. Even using Natural Resources Canada s production/export/import rates and Ziff Energy new U.S. rates, uncertainties are high in virtually all GHG estimates of this study, due to uncertainty in most GHG per unit factors. This brief study relied on prior studies and literature and on judgment relative to such factors. Replacement energy sources are especially undefined, along with their related GHG emissions and even Canadian GHG emissions factors aside from fuel use have uncertainties in the +30% range. Hence, ranges are provided for most predicted GHG changes. Table briefly summarizes NRCan s prediction of business as usual Canadian electricity and gas exports to the U.S. Tabel NRCan Forecasts of Canadian Electricity and Natural Gas Exports Energy Early 2001 Rates/Annualized (a) Electricity (net) Exports GWh 26,955 28,568 23,800 (6-month average) Natural Gas Exports BCFY 3,500 3,800 3,740* (5-month average) (a) NEB report data. * With slight adjustment for ethane and propane extracted in U.S. from Alliance "rich" gas export. 1.2 Canadian GHG Changes Relative to Electricity and Natural Gas No Electricity Exports Due to a likely revised mix of generation in the event of no electricity exports, some GHG reductions are predicted in New Brunswick in order of 3 to 5 megatonnes a year, due to reduced use of imported oil and possibly coal. In Ontario there would probably be no GHG emission change, except a small amount due to assumption of no imports from the U.S. unless no U.S. thermal coal were to be available. In the latter case, some reduction in Canadian GHG would occur, as added interprovincial hydro electricity transfers and/or added gas use in generation may be assumed to offset loss of coal imports. CANADIAN GHG IMPACTS McC+A Page 1

7 1.2.2 No Gas Exports Canadian emissions upstream of border crossings will obviously decrease very significantly. Ironically, so too will certain relatively small U.S. GHG emissions due to current transit of part of Ontario s needs from western Canada via the U.S. (This study did not examine possible related reductions in rates of petrochemicals, LPG and heavy crude/bitumen exports, nor in the related GHG emission impacts in Canada or the U.S.) 1.3 U.S. Replacement Energy Vectors During the transition period, to say 2010, exports of both electricity and natural gas were forecast by NRCan to increase. At the same time, Ziff Energy predict use of some now unused Midwest nuclear and coal power capacity and renewed availability of 30 rising to 50,000 GWh of northwest U.S. hydraulic electricity capacity (the latter almost twice-forecast Canadian electricity exports). That new West Coast electricity would back-out 210 to 350-BCFY of natural gas demand (7 to 8% of previously predicted Canadian natural gas exports). The GHG reductions from these changes offset those for the oil used in the interim period until LNG is fully available. Figure provides median estimates of related U.S. GHG changes over the 2002 through 2007 period. 1.4 Foreign GHG Changes Canadian Coal and Oil Use Changes There would likely be less coal imported into Atlantic Canada in event of no electricity and/or no gas exports thus small GHG reductions in South America and on the high seas. There could also be some reduction in Atlantic Canadian heavy fuel imports and offshore GHG emissions, perhaps including emulsified bitumen, from the Caribbean LNG to U.S. LNG production, transport, and regasification related GHG emissions will be above those voided in a no Canadian gas export case, due to the lower efficiency from foreign well (through LNG plant and marine transport) to U.S. consumer. Precise numbers are impossible, given the worldwide LNG sourcing potential, with varying LNG tankering distances and onboard containment technology improvements. Thus, the estimates in Tables and must be considered as highly uncertain. (Marine GHG s are noted separately, as it is not clear who will finally include these in national emissions.) Alaskan LNG (from the existing and probably new facilities) has been estimated to provide approximately 25% of the 2010 LNG imports specific to Canadian electricity and gas replacement. Except for this Alaskan LNG and new Australian sources, incremental LNG would come from non-annex 1 countries. 1 1 If Nigerian LNG is imported to the U.S. there would actually be a credit due to capture for LNG of now flared gas. CANADIAN GHG IMPACTS McC+A Page 2

8 1.4.3 U.S. Imported Oil In the transition period, on balance, light and heavy fuel oils would be imported to the U.S. to provide the incremental needs. (U.S. refining capacity is very tight and expected to continue that way). Thus, there would be added GHG s from incremental foreign crude production and refining and from tanker movements, until about 2010 when LNG is seen as the only replacement fuel. 1.5 Global GHG Change Estimates The pattern of GHG emissions appears likely to change over time, especially in the U.S. were Canadian electricity and gas exports to end. Tables and provide this study s 2005 and 2010 estimates of global GHG changes through Table GHG Changes (Median Estimates Megatonnes) Canada U.S. Deep Sea Marine Foreign Production Total Global Estimate Range Canadian Change Related Canadian Electricity Generation -3 NA Minor Minor -3 (-10 to 0) Candian Natural Gas Production NA NA -36 (-48 to -22) U.S. Change & Transport Related Decreased Canadian Gas NA -186 NA NA -186 (-194 to -178) Increased HFO NA (65 to 90) Increased LFO NA (50 to 66) Increased Coal NA +26 NA NA +26 (20 to 32) Increased LNG Use NA +113 NA NA +113 (105 to 125) Increased LNG Production/ Transport NA NA (32 to 70) TOTAL (66 to 135) Table GHG Changes (Median Estimates - Megatonnes) Canada U.S. Deep Sea Marine Foreign Production Total Global Estimate Range Canadian Change Related Canadian Electricity Generation -3 NA Minor Minor -3 (-10 to 0) Candian Natural Gas Production NA NA -39 (-52 to -26) U.S. Change Related Decreased Canadian Gas NA -202 NA NA -202 (-214 to -190) Increased U.S. Coal NA +4 NA NA +4 (3 to 5) Increased U.S. LNG Use NA +248 NA NA +248 (-265 to -230) U.S. LNG Production/Transport NA NA +23 (15 to +30) Foreign LNG Production/Transport NA NA (55 to 120) TOTAL (80 to 140) Figure indicates a nearby constant increase over time in global GHG emissions in the event of no Canadian electricity or gas exports. (The 2002 and 2007 data are based on Ziff Energy indicated rate changes and the same GHG factors as in the above tables.) CANADIAN GHG IMPACTS McC+A Page 3

9 Fig CO 2 E Emissions Changes with No Canadian Electricity or Gas Exports Global 80.0 MT CO2E Foreign United States Canada Year Global US Foreign Canada CANADIAN GHG IMPACTS McC+A Page 4

10 1.6 Other Credits This study did not attempt to quantify the impacts of a no gas export scenario on reduced Alberta petrochemical, LPG and diluted heavy crude bitumen exports. This study emphasized electricity and natural gas and did not look in detail at other Canadian energy vectors, often with balances in Canada s favour, e.g., refined petroleum products and crude oils. A brief look indicated no documentable case was seen for reduced GHG due to use of Canadian synthetic crude oils in the U.S. versus say, a Venezuelan-based source. 1.7 Uncertainties This report considers only Canadian electricity and gas export related GHG changes, and as the Ziff Energy report notes, increasing energy demands in the U.S. will require other energy vector changes than considered here. While burner to combustion GHG factors are generally accurate to +4%, most other GHG factors per unit of production of importance here e.g., production, processing transport of natural gas and its liquid version LNG seldom have uncertainties of less than 30%. Thus, the data in Tables and and throughout this report must be used very cautiously; use of ranges is the correct approach. CANADIAN GHG IMPACTS McC+A Page 5

11 2.0 INTRODUCTION 2.1 Terms of Reference This study was commissioned by T. J. McCann and Associates Ltd. (McC+A) in mid July 2001 by Natural Resources Canada relative to GHG attributions to energy vector exports and U.S. GHG impacts in the very theoretical events of no Canadian supply of electricity or natural gas. Ziff Energy prepared a parallel study for NRCan on energy sector changes re such scenarios. The intent of this study was not to discuss policy, but rather to present GHG data and their settings, for NRCan consideration of GHG credits/debits in cross-border energy vector trade. In this study, McC+A extends Ziff Energy s August 30 th U.S. energy balance change estimates re likely U.S. GHG emission changes for scenarios without Canadian electricity or gas exports. All data and comments presented, herein, should be considered as directional as all have not been well confirmed, and as, often noted, uncertainties are high for all GHG estimates, except where only emissions due to final combustion are discussed. Mr. Hertsel Labib has been the NRCan sponsor and primary communications link. Tom Woods of Ziff Energy in Houston provided Ziff Energy s U.S. change bases. Dave Picard provided Clearstone s assistance re natural gas and Phil Magee analyzed NRCan s forecasts. Tom McCann has been the principal McC+A consultant. This report is presented in English units except for greenhouse gases, where tonnes of CO 2 equivalent are used, consistent with national reporting. Methane and nitrous oxide equivalencies to CO 2 of 21 and 310 on weight bases: totals of greenhouse gases are reported in CO 2 Equivalent (CO 2 E) terms. 2.2 Related Reports NRCan provided their 1999 forecasts through 2020 of Canadian crude oils, natural gas, LPG s and electricity supply and demand with exports. The export/import rates from that forecast have been used throughout this report (with the occasional comments, where there is significant variance with current balances). National Energy Board (NEB) monthly export electricity, natural gas, propane/butane and refined petroleum product reports used for most current export rate information with some data from U.S. Energy Information Administration forecasts e.g., Energy Outlook 2000 and historic reports e.g., EIA Coal Supply and Demand Report 1999, and other source data as pertinent. 2.3 Methodologies This study focused on day-to-day operational GHG emissions, neglecting those related to construction and reclamation. Over time, the latter group of emissions are usually below 2 or 3% of full cycle emissions and occur only at infrequent intervals. This study is based on average emission factors across the Canadian or U.S. economics, regionalized as appropriate. Marginal emission factors were NOT considered, as they would introduce even more uncertainty than the average approach used here and such an approach would raise many questions re protocols. CANADIAN GHG IMPACTS McC+A Page 6

12 A variety of McC+A and Clearstone Engineering prior studies and file data have been used to select appropriate GHG per unit of energy factors, time permitted no new analyses. Allocation of GHG emissions from multi-product facilities is always a major issue. Here emissions from natural gas processing, including those from straddle plants, were attributed to natural gas per se, except for minor quantities, specifically required for ethane, LPG and pentanes plus processing. Likewise, the objective of oil refineries was assumed to be transport fuels gasoline/jet/diesels, with heavy fuel oil, asphalt and petrochemicals as byproducts with only nominal GHG attributions. These are the same approaches McC+A uses in its various fossil energy GHG life cycle analyses, but may introduce unwarranted/undesired biases re GHG s attributed to certain energy vectors. The data from the analysis of GHG attributions outside Canada and the U.S. do not have the same qualities of databases as available for Canada and the U.S. In the most important case of LNG there are multiple source options, all with differing GHG attributions at point of production and relative to transport to the U.S. Uncertainties are very important in emission accounting and virtually all GHG per unit of energy factors used in this study appear to have high uncertainties. (There are also possibly uncertainties in the Ziff Energy U.S. rate change estimates not considered here.) The uncertainties are such that emission rate ranges are the proper presentation approach the use of median and of +% s for uncertainties do not properly convey the level of uncertainty. This study relied on the McC+A team s judgment relative to uncertainties and no claim is made as to the quality of these used herein. CANADIAN GHG IMPACTS McC+A Page 7

13 3.0 CANADIAN RELATED GREENHOUSE GAS IMPACTS IF NO ELECTRICITY EXPORTS 3.1 Introduction The Data in this section target Canadian and non-u.s. greenhouse gas (GHG) changes in the event of no Canadian electricity exports. Brief sections discuss Quebec, Manitoba, Saskatchewan/Alberta, and British Columbia, with New Brunswick and Ontario, giving special attention due to the mix of energy vectors used to produce electricity in New Brunswick and the question of availability/non-availability of U.S. coal in Ontario. 2 Table presents the NRCan predicted rates generation energy input vectors are shown in Table and Tables 3.1-2, and illustrate early 2001 trade routes. Province Table Electricity Cross-border Trade Data NRCan Forecast (GWh) NEB Data First Half 2001 (GWh) Year Domestic Use Net Exports Exports Imports Net Exports New Brunswick , ,913 * ,095 3,150 * ,311 3, ,815 3, ,287 3,150 Quebec ,962 2,416 7,546 * ,808 12,896 * ,928 15, ,958 9, ,848 5,768 Ontario ,981 1, * ,162 0 * , ,835-1, ,853-1,330 Manitoba , ,536 * ,148 8,780 * ,668 9, ,618 10, ,518 8,870 Saskatchewan (a) Alberta (a) British Columbia ,815 5,580-2, ,896 2, ,963 1, ,093 1, , CANADA ,139 10,255 11,884 * ,480 26,966 * ,090 28, ,618 27, ,219 17,438 Note: NRCan forecast no export/trade for Newfoundland, Nova Scotia, PEI, Saskatchewan nor Alberta. Total Domestic Use, include these provinces. * Years relevant to this study. (a) No international trade forecast. 2 No similar restriction on Canadian uranium sale to the U.S. has been considered. CANADIAN GHG IMPACTS McC+A Page 8

14 Table Canadian Electricity Energy Sources Province Hydro Coal Oil Gas Nuclear Biomass/Wind Newfoundland Nova Scotia Prince Edward Island (minor) New Brunswick Quebec minor Ontario minor Manitoba Saskatchewan Alberta minor British Columbia Canada Table Destinations of Canadian Electricity Exports - January/June 2001 (GWh) From To British New Alberta Saskatchewan Manitoba Ontario Quebec Columbia Brunswick Alaska <1 Arizona 9 California 2, Colorado 1 Idaho 2 2 Maine 807 1,966 Mass. 139 Michigan 73 Minnesota 220 North Dakota & Minnesota 70 4,868 New England 1,136 2,011 New York 551 5,825 Oregon 26 7 Texas 4 Vermont 1,179 Washington Source: NEB Monthly Reports CANADIAN GHG IMPACTS McC+A Page 9

15 Table Imports of Electricity In Canada - January/June 2001 (GWh) To From British Columbia Alberta Saskatchewan Manitoba Ontario Quebec New Brunswick California <1 Maine <1 53 Michigan 1,137 Minnesota 14 Montana <<1 North Dakota/Minnesota 332 New England 1,271 New York 250 1,144 North Dakota 447 Oregon 1 Washington 5, The uncertainties of the GHG factors and of the various cases themselves are to be noted. Ranges are provided in all overall summaries. In reporting electricity exports to the NEB, New Brunswick, Ontario and British Columbia do not report sources in ratio of provincial average production in this study, NRCan s original electricity generation energy source balances have been assumed. Prospects for electricity carried offshore from New Brunswick and Nova Scotia to New England/New York areas were not considered. 3.2 New Brunswick Table presents New Brunswick s generation bases currently and as forecasted. New Brunswick and Ontario are the major challenges in estimating GHG s relative to electricity exports, as both have major combustion sources. New Brunswick appears very likely to continue to have significant electricity exports, but has the most complex generation pattern as noted in Table CANADIAN GHG IMPACTS McC+A Page 10

16 EXPORTS Table New Brunswick Generation Bases Canadian Coal 3 0 (a) 0 0 Hydraulic* Imported Coal Imported Oil Natural Gas Nuclear TOTAL PERCENTAGE TOTAL GENERATION 21,870 22,350 25,180 NET EXPORT GWh (NRCan forecast) 3,150 3,150 3,150 Notes: * Includes "other" reported to NEB (a) Only imported coal assumed in this study. Reported to NEB for June Export % NRCan Forecast New Brunswick Generation Bases 2005 % 2010 % 2015 % Note: The local refinery has traditionally sold low sulphur HFO to the U.S. and New Brunswick Power has purchased Caribbean HFO for generation. Table presents cases considered in event of no New Brunswick electricity exports with approximate GHG emission Canadian charges. Foreign charges are noted in Table CANADIAN GHG IMPACTS McC+A Page 11

17 Table No Electricity Export Cases Electricity Energy Source A B C D Oil No Oil 2005/2010 Base Case None Coal Reduced to Balance Provincial Demand Base Case None Gas No Change Reduced to balance As Needed Nuclear No Change New Brunswick Hydro No Change Quebec Hydro No Change + 5,000-GWh + 5,000 No Change Preliminary New Brunswick Change Estimates 10 6 /tonnes/year Electricity Energy Source Factor Base A B C D Base A B C D Oil Coal Gas Nuclear Hydro TOTAL (NRCan) (a) to Base (b) (b) (8.1) (8.0) * 0.4 Factor may be too low, as some existing thermal plant changes (to gas) likely with lower efficiency. Note: (a) Discrepancies between McC+A GHG and NRCan factors to be explored - emphasis here on differences. (b) Gas factor here does not reflect any significant cogen credits. In Case D incremental N.S. emissions shown here. (c) High uncertainties in all cases!! CANADIAN GHG IMPACTS McC+A Page 12

18 Table External CO 2E Emissions Re New Brunswick Electricity Vector Source Notes Oil South American Field/Refining* + Marine Transport to St. John/North Shore. * Heavy Fuel Oil (HFO) considered byproduct without attribution of most refinery GHG emissions. Orimulsion use might continue shown by Statistics Canada as HFO (Higher CO 2E, than coal due to 30+% H 2O content and in field due to bitumen production.) Coal Very largely South American Mine + Marine Transport and North Shore. (Neglect New Brunswick and any eastern U.S. supply.) Hydro New Brunswick with Quebec backup Small quantity of GHG from reservoirs would have only placeholder numbers marginal supply GHG factor very low in any case. Natural Gas Offshore Nova Scotia Only Nova Scotia emissions (pipeline compression there). Includes field and compression in New Brunswick figures for ease in calculations and presentations. Heavy fuel oil including Orimulsion (very heavy crude / water / chemical) and coal imports are largely from South America, although there has been some U.S. coal in the past. Here only Caribbean area sources have been assumed. This study concluded that South America oil production and refining emission would drop due to back out of HFO in all but one New Brunswick case. The foreign oil related GHG impact of the various cases in the order of -0.3 x 10 6 tonnes of CO 2 E, with 50% or so due to marine transport in international waters, say -0.2 to -0.4 x 10 6 tonnes of GHG s. Changes in South American production of coal also depend upon New Brunswick scenario. Production related GHG s of up to -0.6 x 10 6 tonnes/year and up to -0.3 for marine transport charges are rough estimates. The total non-north American GHG emission changes appear to be in the order of -0.5 to -1.8 x 10 6 tonnes a year for both 2005 and Note: Conclusions re New Brunswick Electricity There are many possible scenarios! Each needs very detailed study, but probability of a domestic GHG change of -1 to -5 x 10 6 tonnes in 2005 and 2010 apparent 3-megatonnes is generally used in this study. Note that only Case D would be common to a No Gas Export Case. 3.3 Quebec At least portions of Quebec s now exported electricity were considered available to New Brunswick and Ontario in both 2005 and 2010; arbitrarily a maximum of 5,000 GWh was assumed available to New Brunswick and 10,000 to Ontario. The maximum of 15,000 is about equal to the NRCan forecast estimated Quebec export for 2010 of 15,188, (but above that of 12,900 for 2005). This study did not investigate the transmission changes needed to redirect this electricity from the U.S. to New Brunswick and/or Ontario. There will be a minor GHG reduction in Quebec if this excess capacity is not used. GHG s relative to water reservoirs are minor and very probably not linear with small changes in output. As some of the now exported electricity appears likely to flow to New Brunswick and/or Ontario, no significant GHG changes are shown in this study, but a very low placeholder factor is used to indicate that there may be some. CANADIAN GHG IMPACTS McC+A Page 13

19 3.4 Ontario Canadian Side Ontario exports must be considered separately from imports. The NRCan forecast is for net exports, but some cross-border trade appears likely well into the future. Table Ontario Export Electricity Generation Bases EXPORTS Exports Reported to NEB for June Exports 2005 % NRCan Forecast Ontario Generation Base 2010 % 2015 % % Domestic Coal Imported Coal 84 Natural Gas Hydraulic Nuclear Biomaxx 0 0 <1 <1 TOTAL PERCENTAGE TOTAL GENERATION (GWh) 159, , ,505 NET EXPORTS (GWh) 580 * ,330 Notes: * Total first half of Ontario now buys U.S. electricity (in southwestern Ontario) roughly balancing (different timing) sales to the U.S. Ontario exported electricity is largely imported (U.S.) coal-based (as reported to the NEB). U.S. sales to Canada are assumed to be approximately 50% coal and 50% nuclear-based. As table indicates NRCan predicts minor net imports in 2010 and none in Presumably without Canadian supply, U.S. sales to Canada would stop with U.S. GHG emissions. A major question for this study was: Would U.S. thermal coal exports to Canada cease when Canadian electricity exports cease? Ontario now imports in order of 15 to 18 x 10 6 tonnes of U.S. coal for electricity generation, additionally using in the order of 4 x 10 6 tonnes of western Canadian coal largely in north western Ontario generation. U.S. coal is largely from Wyoming area, but some Appalachian is also used. Without U.S. coal imports, it can be assumed that there would be increased Quebec and Manitoba marine transfers to Ontario to balance U.S. electricity imports in The study considered four scenarios with no U.S. Coal to Ontario should such a case be needed. As developed in Table , all scenarios estimate reduced Canadian GHG emissions (as well as minor U.S. reductions due to reduced coal production and transport), due to added Quebec/Manitoba hydro and/or incremental Canadian gas use. The gas generation emissions shown include an allowance for Canadian gas production and transmission of about 25% above the assumed gas generation average GHG factor of 0.4-kg CO 2 E/KWh. Of that, add on only about one quarter would occur in Ontario due to added gas transmission (assuming an all-canadian route). CANADIAN GHG IMPACTS McC+A Page 14

20 Ontario GHG charges without Canadian electricity exports could range from zero to -15 x 10 6 tonnes, the latter assuming no U.S. coal imports. Canadian coal was held constant in the no U.S. coal cases but Quebec/Manitoba hydraulic electricity transfer increased and/or gas use changed case to case. If added Canadian coal were to replace a portion of the U.S. coal, the apparent reductions would decline (and added some Canadian coal mining and transport GHG emissions would occur). A reasonable estimate of Ontario related GHG reductions in event of no U.S. availability coal would be - 5 to -10 x 10 6 tonnes/year. With U.S. coal imports continuing there would be little change a basic assumption in this report U.S. Electricity and Coal to Ontario There are two principal sources of U.S. GHG emissions attributable to Canadian electricity generation and use, both related to Ontario. British Columbia imports (and exports) are assumed as hydraulicbased, with only very nominal related GHG emissions. Ontario imports significant electricity from Michigan, electricity derived from nuclear and coal-based generation. While nuclear predominates, this study assumed a 50/50 coal/nuclear split. In 2005, this equates to approximately 0.5 x 10 6 tonnes of CO 2 E to supply 1,000 GWh to Ontario in 2010, the figure rises to 0.9 due to the added 830 GWh transfer to Ontario. On the U.S. side, the elimination of the net electricity sales to Canada predicted for 2010 by NRCan would result in approximately x 10 6 tonnes in U.S. emissions. Elimination of U.S. thermal coal sales to Ontario would change U.S. GHG emissions by -0.5 to -1.2 x 10 6 tonnes to both 2005 and CANADIAN GHG IMPACTS McC+A Page 15

21 Table No Electricity Export Scenarios (Considered to date) BASES: - Imports 830 GWh in 2005/2010, into total 159,162/168,014/GWh of generation 2005/ Coal - 23,580/19,500; Gas - 23,152/44,794 in 2005/2010; 5,000 GWh from Quebec. - Nuclear peak of 86,200-GWh in 1998, (75,600 in 2005 and 64,640 in 2010). - Assume 80% of coal-based generation from U.S. coal imports Canadian coal. - Assume U.S. coal NOT be available in all but Case E. - Assume U.S. electricity NOT available in all cases. - NRCan - NRCan - NRCan - Team - Team - Team Electricity Generation Energy Base A B C D E Coal Canadian Available Available Available at 20% of 2005 Coal. U.S. Available Available NOT Available NOT Available NOT Available NOT Available Gas Nuclear Ontario Hydro Quebec Hydro * Only in No Change No Change No Change No Change No Change No Change No Change Vary to Suit Provincial Balance Balance No Change No Change No Change Balance No Change No Change + 5,000 Balance No Change No Change + 10,000 Balance with Gas Rebuild to 1995 Level No Change -- Preliminary Ontario GHG Balances tonnes/year 2005 Electricity Ontario Generation Energy GHG Base A B C D E Coal Gas Nuclear Hydro TOTAL Change from Base (a) (d) (d) (b) (c) (c) Notes: (a) Includes 0.1 for emissions upstream of generation use. Factor may be low in Case D, if existing through plant converted. (b) NRCan's total estimate is 29 (compared to 32.9 in 2005) excluding item (a). (c) Placeholder GHG numbers only re Quebec Hydro transfers. Base A B 2010 C D E CANADIAN GHG IMPACTS McC+A Page 16

22 3.5 Manitoba Bases In 2005/2010 respectively, 8,780/9,360-GWh of exports out of 31,328/32,978 of production have been assumed from NRCan forecasts. Electricity from total coal and gas are forecast at 1,600 and 1,370 respectively, in 2005/2010 NRCan, but only hydro electricity is assumed exported No Electricity Export Cases Manitoba would probably promote added electricity sales to northwestern Ontario, backing out some Canadian coal and potential transmission to Saskatchewan and Alberta. GHG estimates of such transfers were considered outside scope of this study. GHG emissions from water reservoirs would drop, due to elimination of more or less reservoir area for water surge. But the GHG reduction would still be very small in national terms. 3.6 Alberta/Saskatchewan Both Alberta and Saskatchewan could receive now surplus electricity from Manitoba to back out coalbased electricity via new (DC?) lines. Economics are currently questionable, given very low-cost mine mouth coal for generation in both Alberta and Saskatchewan, and major facilities already in place. Many new gas-fired projects are underway in Alberta, with cogeneration at Alberta bitumen production operations growing dramatically. Note that Alberta and British Columbia will provide any natural gas increases that might occur due to Ontario changes, with all related GHG gas changes considered in Ontario scenarios discussed above as Ontario emissions. 3.7 British Columbia Bases NRCan forecasts exports of 2,140/1,700-GWh in 2005/2010 (with total production at 75,086/78,225), of this, only 18/21% are from gas. The rest are hydro-based with a bit from biomass. Water-based production is a mix of run of river and reservoir, with minimal GHG/kWh No Electricity Export Case Predicted exports are small in the total picture, only 2 to 3% of provincial supply. Water-based electricity is seen as taking the reduction, with no GHG impacts. CANADIAN GHG IMPACTS McC+A Page 17

23 3.8 Summary Re Canadian Non-Export of Electricity Province Nova Scotia Table Summary Canadian Non-Export of Electricity (2005 and 2010) GHG Emission Changes (10 6 tonnes a year) Notes Only if Sable gas use increases in Atlantic electrical generation. New Brunswick -2 to -5 Various new generation scenarios including possible Quebec transfer 3 used study. Quebec Minimal Due only to water electricity reduction. Ontario Minimal If U.S. coal not available 5 to 10. Manitoba Minimal Due to reduced water reservoir use. Saskatchewan Minimal No Manitoba electricity use assumed. Alberta 0 to +1.5 Includes Pipeline compression. Depends upon Ontario changes in gas for electricity (if any). No Alberta Coal mines and transport change. No Manitoba electricity use assumed. British Columbia Minimal Hydraulic bases. TOTAL -.3 to to 5 if no U.S. coal available 3 used in study. 3.9 Non-North American GHG Changes Due to No Canadian Electricity Exports In New Brunswick, this study concluded that South America oil production and refining emission would drop due to back out of HFO in all but one New Brunswick cases. Foreign GHG impact in order of -0.3 x 10 6 tonnes of CO 2 E, with 50% or so due to marine transport in international waters. Changes in South American production of coal also depend upon which New Brunswick scenario changes in production related GHG s of up to -0.6 x 10 6 tonnes/year and of -0.3 in marine transport are rough approximations. CANADIAN GHG IMPACTS McC+A Page 18

24 4.0 CANADIAN GHG IMPACTS OF NO NATURAL GAS EXPORTS 4.1 Introduction The data in this section targets Canadian changes, change in U.S. activity and changes related to Canadian supply to Canada, in the event of no Canadian natural gas exports. Only impacted provinces are discussed here. Canadian gas exports in the first five months of 2001 averaged approximately 10.5-BPFD. Of this BCFD approximately 0.1-BCFD was ethane and propane extracted from the Alliance system exported gas in the Chicago area. Thus, an effective BCFD of conventional Canadian gas was exported to the U.S. equivalent to 3,780-BCFY, quite close to NRCan s project exports in 2010 (and above the 3,500 of exports estimated for 2005). The ratio of exports by major border points was assumed the same in both 2005 and 2010, as in the early part of 2001 as shown in Table and Figure Clearstone Engineering provided preliminary calculations of field and processing GHG s for British Columbia and Alberta exported gases and for the related transport to the U.S. border. (Saskatchewan production and use are about equal, hence, no Saskatchewan exports were assumed.) Exports at Niagara Falls and Iroquois were assumed transmitted via the all-canadian route north of Lake Superior. A small adjustment was made relative to expected acid gas (CO 2 and H 2 S) reinjection in lieu of venting of all now captured CO 2 at gas plant. Approximately, 2-BCFD were assumed to transit the U.S. from prairie border points to southwestern Ontario. (This rate is only a judgement, as public data do not appear available.) In the event of no Canadian natural gas to the U.S., this 2-BCFD was assumed transported via the all- Canadian route (in lieu of the essentially equal volumes of previously exported gas carried in the same line. McC+A estimated Sable gas upstream emissions and obtained the contract pipeline fuel gas consumption up to the U.S. border. Table summarizes this study s calculations of future Canadian GHG, due to export gas production, processing and transport. CANADIAN GHG IMPACTS McC+A Page 19

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26 Table Recent Canadian Gas Exports/Imports Location Total BCF 2000 Average BCF/Day January February March April May 2001 BCF 2001 BCF 2001 BCF 2001 BCF 2001 BCF Total BCF 2001 To Date BCF/Day 2001 To Date % Gas Source % Used for Analysis of Future GHG's Exports Huntingdon % BC 9 Kingsgate % AB 22 Monchy % AB 21 Elmore (Alliance) (Minor in Other) % BC/AB 12 (a) Emerson % AB 10 Niagara Falls % AB 12 Iroquois % AB 10 St. Stephen % NS (offshore) Other % AB/SK (minor) 4 0 Export Total * % 100 Import Total NA NA ** % (b) 200 Source: NEB (Monthly) Gas Exports and Imports Notes: * 3,820-BCF export total over one year. ** 212-BCF import total over one year. (a) Alliance rate adjusted by 0.1-BCFD for portion extracted fro ethane and propane in the U.S. This adjustment also brings the net Alliance gas heating value to a level close to other Canadian gas exports. (b) All into southern Ontario - Texas/Oklahoma origin assumed. CANADIAN GHG IMPACTS McC+A Page 21

27 Table Canadian Gas Export Related GHG's (10 6 tonnes/year of CO 2 E) Export Point Pipeline Company Assumed Annual GHG* to Border Start Point 2005 (a) 2010 (b) Huntingdon Westcoast Ft. St. John Kingsgate TransCanada Edmonton Monchy Foothills Edmonton Elmore Alliance Ft. St. John/Edmonton Emerson (Exports only) TransCanada Edmonton Niagara Falls (a) TransCanada Edmonton Iroquois (a) TransCanada Edmonton St. Stephen Maritimes & Northeast Sable TOTAL (10 6 tonnes/year) Adjustment for CO 2 E Disposal (b) NET RANGE 10 6 tonnes/year of CO 2 E 26 to to 53 Notes: (a) Assumed Transmitted via all-canadian route to export point. (b) Acid gas reinjection not credited above. Increasing acid gas reinjection was assumed at gas plants in line with current practice. 4.2 Nova Scotia Sable production will drop dramatically with no gas exports, until added equivalent gas-based Atlantic electricity generation and domestic/commercial consumption is increased, e.g., current Nova Scotia electricity plants to gas and/or New Brunswick north shore and Quebec system tie. Sable exported gas related GHG emissions, including the portions of pipeline compression emissions to the Maine border appear in the order of 0.5 x 10 6 tonnes/year at 350 x 10 6 SCFD. Possible LNG imports to New Brunswick, on balance at least for export were not considered (see September 2001 press reports and Irving Oil and Chevron news releases). 4.3 Ontario Canadian Supply Ontario opens up another issue that of U.S. acceptance of transit gas from western Canada to Ontario. This study assumes that in the event of no Canadian gas exports, transiting of gas (and crude oil? and LPG s?) would not take place. Enough capacity appears available to move gas now transiting through the U.S. in the all-canadian route north of Lake Superior, as the current exports via Niagara Falls and Iroquois appear about the same as Canadian gas now transiting the U.S. 3. There will be slightly higher Ontario gas pipeline related GHG s to moving now transited gas to southwestern Ontario, due to larger 3 Added Canadian compression with added Canadian GHG s might be required in certain of the Ontario electricity generating scenarios previously considered. CANADIAN GHG IMPACTS McC+A Page 22

28 pipelines say, 0.5-megatonnes of CO 2 E a year. U.S. emissions would, however, drop by roughly 1.5 x 10 6 tonnes/year without gas transiting U.S. Gas Supply to Ontario U.S. gas imports have assumed in this study at 45-BCFY in future years, as per NRCan, although as Table indicates, the rate was roughly 210-BCFY in the early part of The GHG attributions were assumed similar to Alberta production delivered an equal distance to southwestern Ontario. 4.4 Saskatchewan Saskatchewan gas production and consumption are close to a balance, hence, contribute little or no exports and trade was neglected herein. 4.5 Alberta Alberta production will be down by about 2,800-BCF a year in Assuming average GHG factors for Alberta production and pipelining to border points (other than those in Ontario), and eliminating approximately that quantity of exports at various British Columbia, Saskatchewan and Manitoba border points, there will be a reduction of 20 to 28 x 10 6 tonnes a year of GHG relative to Alberta gas only in 2010, slightly less in Note re Side Effects in Alberta (and British Columbia) This study only notes that there may be drops in Alberta petrochemical exports given possible ethane reduction (and/or higher ethane costs) due to reduced gas moving through ethane extraction facilities. All Alliance-rich gas flow would stop, leaving potential for more ethane, propane and butane at some ethane extraction facilities. This study did not attempt to estimate the new ethane, propane and butane balances with no gas export but LPG exports may well decrease on a net basis. Pentanes plus would drop without gas export. They are very largely removed in Canada before the Alliance and all other gas pipeline systems. But supply for heavy crude dilution is now very tight and almost any gas cutback feels very likely to impact diluted heavy crudes and bitumen exports. This study did not attempt a pentanes plus supply/demand balance. 4.6 British Columbia A no gas exports case would reduce British Columbia field and pipeline related GHG emissions, as sales gas will drop by very roughly 1,000-BCF. Using average factors 6 to 10 x 10 6 tonnes a year is estimated for the related CO 2 E change in British Columbia GHG. (See note above re possibly reduced Canadian LPG and diluted heavy crude/bitumen exports not considered here. The ethane/propane-rich Alliance export only system starts in British Columbia and its shutdown likely create increases in Canadian propane and butane production, even with the overall British Columbia gas reduction.) CANADIAN GHG IMPACTS McC+A Page 23

29 4.7 Canadian Summary Table No Canadian Gas Export - Canadian GHG Impacts (10 6 tonnes/year of CO 2 E) Province 2010 Change (a) Note Nova Scotia -0.5 Ontario +0.5 (Until domestic demand reaches current export volume.) (Gas now exported at Iroquois and Niagara Falls replaced in all-canadian route by gas to south western Ontario.) Saskatchewan See Alberta Pipeline emission decreases. Alberta +0.5 Replace current imports from U.S. '-20 to -28 Reduced production and processing and pipelining. ( lower in 2005) B.C. -6 to -10 Reduced production and processing and pipelining.( lower in 2005) TOTAL CANADIAN CHANGES -30 to -45 Note high uncertainty! Note: 2005 would have a total change of about -25 to U.S. Summary Due to Supply to and Transit of Canadian Gas Table No Canadian Gas Export - Canadian GHG Impacts (10 6 tonnes/year of CO 2 E) Item 2005/2010 Note No supply to south western Ontario -0.5 From U.S. southwest. No transit of 2+BCFD of gas western Canada to Ontario. -3 to -4 Canadian gas exported from Ontario assumed carried via all-canadian route. TOTAL U.S. CHANGES RE CANADA GAS USE -3 to -5 CANADIAN GHG IMPACTS McC+A Page 24

30 5.0 U.S. GHG VALUE OF CANADIAN ELECTRICITY AND NATURAL GAS 5.1 Introduction Due to the integration of U.S. electricity production and gas use, this analysis has been combined relative to scenarios without Canadian exports. NRCan s forecast exports to the U.S. are repeated in Table for ease in interpreting the Ziff forecasts. Table NRCan Canadian Natural Gas and NGL Export/Import Forecasts (10 3 BCF) Notes Natural Gas (10 9 SCF) Exports 3,500 3,800 3,800 3,800 Imports Gas Plant NGLs (10 3 barrels per day) Net Exports Very minor imports. Table indicates the key rate estimates of Ziff Energy for 2002, 2005, 2007 and While this study concentrates on 2005 and 2010, the data for the other years are important to understand Ziff Energy s prediction of trends in U.S. energy vectors. (The study excluded consideration of U.S. electricity generation relative to growth in U.S. demands while Ziff Energy provided energy-input estimates, these are largely separate from replacement of relatively constant rates of Canadian electricity and natural gas.) CANADIAN GHG IMPACTS McC+A Page 25

31 Region Replacement Table Replacement Fuel Forecasts (Ziff Energy) Energy Annual Year Base Rate Notes Northeast Canadian Electricity Canadian Gas Heavy Fuel Oil Heavy Fuel Oil 10 6 Bbls 10 6 Bbls In under used plants. 0.0 LNG LNG (on balance) BCF BCF * * * * * * * * Mid West Coal (to Electricity) TBTU's Note no LNG or equal use. Canadian Electricity Currently, under used plant Nuclear (Electricity) TWh capacity for coal and nuclear generation. Coal TBTU's Canadian Gas Light Fuel Oil 10 6 Bbls LNG (on balance) BCF * * * * Pacific Coast Canadian Electricity Canadian Gas No Change Hydraulic (Electricity) TWh Return to normal. (a). Light Fuel Oil 10 6 Bbls OVERALL U.S. LNG BCF 370 1,940 3,500 5,260 (b) Source: T. Woods Personal Communication. Notes: (a) The return to normal Northwest U.S. hydraulic electricity frees up roughly 210-BCFY in 2002 and 350 in 2005 and later years. (b) Ziff Energy did not provide regional LNG imports - only the totals shown. The 2002 to 2010 interval is a transition period in allowing U.S. systems to match a sudden drop in imports and then to develop a mature new configuration by Oil Sources As discussed later in Section 5, U.S. refineries east of the Rockies are running at capacity and the added heavy fuel oil and light fuel oil needs of the transition period would come from offshore sources, likely from refineries in Africa, Mediterranean and Caribbean. Such supplies are considered available, but prices of at least the heavy fuel oil would rise due to the low sulphur requirement on the East Coast. (U.S. light fuel oil sulphur specifications appear likely to go down only after 2007.) It is to be noted that heavy fuel oil replaces part of Canadian gas in New England due to Ziff Energy s assumption of such gas largely relative to electricity generation. 5.3 Coal Sources The added Midwest coal needs in the interim period can be assumed available from the Wyoming/North Dakota area. Note that the continuing added coal (and nuclear) generation in the Midwest is based currently on unused capacity. CANADIAN GHG IMPACTS McC+A Page 26