A decarbonization strategy for the electricity sector: New-source subsidies

ARTICLE IN PRESS Energy Policy 38 (2010) 2499–2507

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A decarbonization strategy for the electricity sector: New-source subsidies Kenneth C. Johnson n 2502 Robertson Rd Santa Clara, CA 95051, USA

a r t i c l e in fo

abstract

Article history: Received 25 June 2009 Accepted 16 December 2009 Available online 13 January 2010

An expedient phase-out of carbon emissions in the electricity sector could be facilitated by imposing carbon fees and applying the revenue exclusively to subsidize new, low-carbon generation sources. Since there would initially be no ‘‘new sources,’’ fees would be substantially zero at the outset of the program. Nevertheless, the program would immediately create high price incentives for low-carbon capacity expansion. Fees would increase as new, low-carbon sources gain market share, but price competition from a growing, subsidized clean-energy industry would help maintain moderate retail electricity prices. Subsidies would automatically phase out as emitting sources become obsolete. & 2009 Elsevier Ltd. All rights reserved.

Keywords: Cap and trade Carbon tax

1. Introduction According to recent global warming simulations, the end-ofcentury global temperature is expected to rise to a level ‘‘nearly double what y the world can afford in order to avert catastrophic climate change’’. This is not a ‘‘worst-case’’ projection; it is rather premised on the assumption that ‘‘industrialized and developed countries enact every climate policy they have proposed at this point’’ (Eilperin, 2009). A fundamental question for policymakers is why it makes sense, in the face of an impending threat of such magnitude, to limit emission reductions to a predetermined, politically compromised target. The cap-and-trade legislation before the US House and Senate, in particular, would subvert and impede attempts to achieve emission reductions beyond the cap target by allowing any such reductions to be nullified by equivalent emission increases elsewhere. Complementary emission-reduction efforts would be exploited, and their environmental benefits forfeited, for the benefit of the regulated entities who would accrue surplus emission allowances resulting from such actions.1 The ‘‘least-effort’’ regulatory paradigm underlying cap and trade favors cost reduction over emission reductions even when costs are well within acceptable limits and when emission targets do not approach sustainability requirements. For example, the US SO2 trading program, enacted under the 1990 Clean Air Act Amendments, has continued to focus regulatory incentives on

n

Tel.: + 408 244 4721. E-mail address: [email protected] 1 The legislation authorizes states to ‘‘require surrender y of emission allowances’’ to demonstrate compliance with states’ cap-and-trade regulations (Waxman and Markey, 2009, p. 1018; Kerry and Boxer, 2009, p. 744), but does not provide a mechanism for setting aside and retiring surplus allowances resulting from other types of state programs such as vehicle emissions regulations, renewable energy standards, and financing or incentive programs. 0301-4215/$ - see front matter & 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2009.12.044

further cost reductions, rather than further emission reductions, even when costs have been only a fraction of original forecasts, and even when the societal benefits of further emission reductions would exceed costs by a factor of 25 (CATF, 2001, 2004; EIP, 2007; Ellerman, 2003, pp.16–19; USEPA 2005, p. 1–1). The clear lesson of the SO2 program is that the policy objective of achieving an environmental goal at least cost leads to perversely inefficient regulatory incentives when the ‘‘goal’’ is narrowly construed to mean attainment of a mandated interim target that is insufficient to achieve environmental sustainability. The ‘‘environmental certainty’’ of cap and trade does not ensure attainment of environmental sustainability goals when the emission-reduction target falls short of sustainability requirements. A sensible and pragmatic alternative policy objective would be to minimize emissions within defined limits of cost acceptability. This ‘‘best-effort’’ policy paradigm is embodied by pricing instruments such as carbon taxes, which create stable economic incentives for carbon reduction that are not limited by a predetermined reduction target (CBO, 2008). But carbon taxes have been handicapped by the perception, reinforced by tax proponents as well as opponents, that taxes function intrinsically to extract revenue from regulated industries (Shapiro et al., 2008). Pricing instruments are not inherently more costly to industry than cap and trade. For example, if a carbon fee applied to electricity generation is used to subsidize new, renewable energy sources, it could give new renewables an immediate $100-per-ton price advantage over fossil fuels even though the carbon fees would initially be substantially zero (because there would initially be no new sources). A $100-per-ton marginal incentive does not necessitate imposition of $100-per-ton carbon fees if the fee revenue is applied to subsidize emission reductions in the regulated industry. This paper describes a regulatory approach for facilitating expedient decarbonization of the electricity industry by applying carbon fee revenue to subsidize low-carbon power generation.

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The regulation would apply specifically to the electricity industry, and would be focused exclusively on the narrow objective of providing the highest feasible price incentive for new-source, low-carbon electricity generation (and commensurate disincentive for new, high-carbon generation) within limitations of cost acceptability. But this approach is also illustrative of a broadbased regulatory strategy that would be similarly applicable to other industries. Such a strategy would not require ‘‘economy-wide’’ regulatory instruments; instead it could employ sector-specific pricing instruments, which would generally be revenue-neutral within each sector. In the context of cap and trade, the purpose of economy-wide linkage is to minimize costs; but if the policy objective is cost acceptability, and not cost minimization, then this rationale does not apply. In the context of conventional carbon taxes, economy-wide price homogenization can avoid competitiveness imbalances between regulated jurisdictions; but preservation of revenue neutrality within regulated sectors would mitigate such imbalances and could even give more strongly regulated economies a competitive advantage as the costs of clean energy diminish—and the costs of fossil fuels increase. The revenue neutrality, price certainty, and narrow scope of sectoral pricing regulations could mitigate political opposition and avoid disputes over revenue allocation; and limiting the scope of legislative initiatives to specific industry sectors such as electricity might tend to minimize consolidation of political opposition. In the context of global climate policy, international treaties based on the ‘‘best reasonable effort’’ paradigm underlying sectoral pricing policy may be less contentious and more workable than trying to impose binding emission targets or harmonized carbon prices. Sectoral pricing policies such as new-source subsidies for electricity could potentially be employed in conjunction with a federal cap-and-trade system to achieve emission reductions beyond the cap target, provided that federal legislation establishes a mechanism for setting aside and retiring surplus allowances resulting from such complementary policies. The remainder of this paper is organized as follows: Section 2 provides a brief conceptual description of new-source subsidies and discusses their policy rationale and operating characteristics. Sections 3–5 describe the subsidy mechanism in more specific detail, comparing it to a conventional carbon tax and an outputbased refunded tax. Section 6 discusses ‘‘source vintage,’’ the criteria for classifying electricity sources as ‘‘new’’ or ‘‘old’’. Section 7 states the conclusion. Appendix A reviews literature relating to the output-based tax refunding mechanism discussed in Section 4 and Appendix B provides mathematical formulas underlying Sections 3–5.

2. Conceptual overview New-source subsidies would be financed primarily by carbon fees on ‘‘old’’ electricity generation sources. Significantly higher carbon fees would also be applied to new high-emission sources, but the new-source fees would not be expected to generate much revenue—their primary function would be to deter expansion of fossil-fuel-based generation capacity. The fee level would be continuously updated according to a formula that would give new, low-emission sources a stable, high price advantage relative to new high-emission sources (e.g., of order $100-per-ton CO2), but since there would initially be no ‘‘new’’ sources the fees would start out at zero. As new, renewable sources gain market share, the per-megawatt-hour fees on emitting sources would gradually increase, and the per-megawatt-hour subsidies for low-carbon energy would correspondingly diminish, in such a way that both

revenue neutrality and the relative price advantage of new renewables are maintained. The fee and subsidy formulas, which are specified in Section 5, essentially amount to an output-based refunded tax, but modified to eliminate cross-subsidies between old sources. (The tax-refund balance is a fee if positive, and a subsidy if negative.) Fees would only become significant after new sources have gained significant market share, by which time market competition from a growing, subsidized clean-energy industry would deter fossil-fuel generators from passing carbon fee costs on to ratepayers. Consumer interests would be protected not by allocating fee revenue to consumer dividends or to ‘‘tax shifting,’’ but rather by ensuring an adequate supply of competitively priced, clean energy. A tax-and-dividend policy, by contrast, would severely dilute the carbon pricing incentive. For example, if 10% of electricity generation came from renewable sources and 90% came from coal, then a $10-per-ton carbon fee could be applied to give renewables a $100-per-ton price advantage, whereas tax-and-dividend would only result in a $10-per-ton incentive. Ratepayers would accrue dividends in the form of energy savings resulting from clean-energy subsidies. Subsidies would be financed by gradually escalating fees similar to escalating allowance prices under the pending US federal climate bills (Waxman and Markey, 2009; Kerry and Boxer, 2009) or escalating taxes under carbon tax proposals (Stark, 2009; Larson, 2009; Inglis, 2009). But in contrast to these systems, the clean-energy price subsidy would start out at a high level and would thereafter diminish. Thus, maximum incentives would be provided immediately, when the renewable energy industry is most in need of the subsidy, and would automatically decrease as economies of scale and market maturation make the industry less dependent on subsidies. The high initial subsidy level could obviate the need for renewable energy standards and other governmental support mechanisms. New-source subsidies operate to provide renewable energy incentives, but in keeping with their narrow policy focus the subsidy mechanism does not discriminate between source technologies (e.g. renewables, nuclear, sequestration). It only discriminates based on emissions and source vintage. The emissions performance rating may take into account upstream emissions in fuel extraction and transportation (depending on whether those emissions are accounted for under other greenhouse gas regulations), and separate legislative measures could discriminate between technologies based on policy criteria other than greenhouse gas emissions. The allocation of fee revenue exclusively to new sources avoids extraneous costs and helps ensure political viability of the program. Legacy low-carbon sources (primarily large hydro and nuclear) would not receive new subsidies under the program, but the carbon fees would make legacy clean energy relatively more cost-competitive than fossil-fuel energy. As high-carbon energy is phased out, the new-source subsidy would automatically diminish until it is eliminated and non-emitting new sources no longer have preferential regulatory status. The fee revenue is used to subsidize generation output, rather than financing capacity expansion, to protect ratepayers from investment risk and to ensure that carbon fees are balanced by subsidized, low-carbon generation. The subsidies function to make investments in clean-energy capacity expansion attractive to equity markets, but the subsidies do not directly finance investment—they only apply to output. Consequently, the subsidies will influence dispatch decisions in favor of maximal renewable capacity utilization. The subsidy program would be revenue-neutral within the electricity sector, with all fee revenue going to low-carbon, newsource generation. (This ‘‘sectoral revenue neutrality’’ is more

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constraining than the ‘‘revenue neutrality’’ of tax-and-dividend.) Furthermore, the program can be designed to preserve regional revenue neutrality so that ratepayers in Kentucky, for example, are not subsidizing wind turbines in California. The subsidies are intended to facilitate decarbonization via cross-subsidies between generation sources, not between ratepayers; but the policy could create inequities between ratepayer classes if it induces crosssubsidies between generators that cannot compete in the same markets (e.g. Kentucky and California). As a consequence of the program’s sectoral revenue neutrality, any increase in electricity rates would be expected to be reflective only of higher technology costs for new clean-energy sources, and an efficient regulatory design would ideally distribute those costs equitably as a uniform per-megawatt-hour price increment. The price increment would initially be small because there would be few new sources, and the benefits of technology advancement and economies of scale would tend to keep prices low as clean energy gains market share. An argument against this type of subsidy program is that if full carbon pricing costs (not just technology costs) are not passed on to ratepayers, then there will be little incentive for consumers to moderate their energy consumption (Isaksson and Sterner, 2006, Section 5). But trying to pass a $100-per-ton carbon tax to consumers may not be politically feasible. (The pending federal climate bills, as well as tax-and-dividend proposals, are constructed specifically to protect consumers from the impact of carbon pricing.) On the other hand, marginal incentives on the order of $100-per-ton for energy conservation could perhaps be induced by applying revenue-neutral sectoral policies to energyconsuming commodities. In some cases, the direct cost-saving benefits of energy efficiency already create incentives of that order (McKinsey 2008, p. 15), indicating that efficiency technologies are limited not by lack of a carbon price, but rather by lack of efficient financing mechanisms. The new-source subsidy mechanism will be described below, after first reviewing two policy alternatives: a simple carbon tax and an output-based refunded tax. Numerical examples and graphical illustrations are provided, but these are only intended to help elucidate the concepts and are not intended to be quantitatively accurate.

Table 1 Carbon tax at $100/MT. Source category

Emission intensity (MT/MWh)

Tax ($/MWh)

Coal NG Non-emit.

1 0.5 0

100 50 0

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3. A carbon tax Under a simple carbon tax, each regulated source is characterized by its emissions (measured in CO2-equivalent metric tons, or ‘‘MT’’) and generation output (measured in megawatt hours, or ‘‘MWh’’) during a particular compliance period. The ratio of emissions to generation defines the source’s ‘‘emission intensity’’ ðemission intensity; MT=MWhÞ ¼

ðemissions; MTÞ ðgeneration; MWhÞ

The tax per unit output ($/MWh) is determined by applying a mandated emission price ($/MT) to the emission intensity ðtax; $=MWhÞ ¼ ðemission price; $=MTÞðemission intensity; MT=MWhÞ

ð2Þ A tax operates to extract revenue from the regulated sector. It also incentivizes a shift to low-carbon sources, but the revenue extraction can make a high emission price politically unviable. The operational characteristics of a carbon tax and other policy alternatives will be illustrated in relation to a hypothetical electricity market comprising three sub-sectors: Coal, Natural Gas (NG), and Non-emitting. The approximate emission intensities and tax rates for these source categories are outlined in Table 1, based on a $100/MT emission price. Fig. 1 illustrates a hypothetical market scenario in which fossil fuels are progressively phased out, losing half their market share between 2012 and 2030 and being entirely displaced by nonemitting sources by 2050. Each rectangle in the figure represents a particular source category (e.g., Coal). The rectangle width represents cumulative generation capacity (or market share); the height represents the applicable carbon tax in $/MWh units; and the area represents tax revenue. (Zero-height or zero-width rectangles are represented as bars.) In this scenario, the tax rate remains constant but tax revenue diminishes as fossil fuels are phased out.

4. Output-based refunded tax Tax revenue can be refunded in proportion to generation output to make the policy revenue-neutral within the electricity sector. This can make a higher emission price, and hence higher clean-energy investment incentives, politically viable. The rationale for output-based refunding is that it has no impact on the relative cost competitiveness of different energy sources. All receive the same per-megawatt-hour subsidy, so price differences between low-carbon and high-carbon energy are unaffected by the refund. With output-based refunding, each regulated source pays a fee (tax minus refund), which depends on how its emission intensity compares to the average emission intensity within some

2030

2012

2050

100 Tax, $/MWh

Coal Coal

Coal NG

NG

ð1Þ

Non- emit.

NG Non-emit.

0 Generation, MWh Fig. 1. Carbon tax.

Non-emit.

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Table 2 Output-based refunded tax at $100/MT. Source category

Emission intensity (MT/MWh)

Market share (%), 2012

Fee ($/MWh), 2012

Market share (%), 2030

Fee ($/MWh), 2030

Market share (%), 2050

Fee ($/MWh), 2050

Coal NG Non-emit.

1 0.5 0

50 25 25

37.50  $12.50  $62.50

25 12.5 62.5

68.75 18.75  31.25

0 0 100%

100 50 0

2012

2030

2050

Fee, $/MWh

100

Coal Coal NG NG Coal

Non -emit.

Subsidy

0 NG

Non -emit.

Non-emit. Generation, MWh Fig. 2. Output-based refunded tax.

regulated sector (e.g., a geographic region). The average emission intensity is the ratio of the aggregate emissions to aggregate generation within the sector ðavg: emission intensity; MT=MWhÞ ¼

ðagg: emissions; MTÞ ðagg: generation; MWhÞ ð3Þ

The fee is determined by applying the emission price only to a source’s excess emissions over the average rate ðfee; $=MWhÞ ¼ ðemission price; $=MTÞ ðemission intensity; MT=MWhÞ 

!

ðavg: emission intensity; MT=MWhÞ

Continuing with the preceding numerical example, consider the hypothetical market scenario illustrated in Table 1 and Fig. 1. The corresponding scenario, with output-based refunding, is illustrated in Table 2 and Fig. 2, again assuming a $100/MT emission price. (‘‘  0’’ means ‘‘approximately zero’’ and negative fees are subsidies.) The program starts out with low fees and high subsidies in 2012, and transitions to a pure tax (no subsidies) only after emitting sources are phased out. Note that the refund has no effect on fee differences between source categories. For example, in 2012 the fee difference between coal ($37.50/MWh) and non-emitting sources ($62.50/MWh) is $100/MWh, the same as a pure tax.

ð4Þ 5. New-source subsidy If the above quantity is negative the ‘‘fee’’ amounts to a net subsidy. Non-emitting sources, which have zero emission intensity, accrue a pure subsidy. The primary operational precedent for this type of pricing system is the Swedish program for stationary-source NOx emissions. Appendix A provides a brief review of this program. It should be noted that the refunded-tax approach for NOx was not primarily motivated by an aversion to high taxes. (Sweden employs unrefunded taxes for SO2 regulation.) The overriding concern was that a conventional NOx tax would put regulated entities at a competitive disadvantage in relation to unregulated foreign entities as well as small domestic generation sources, which, because of the high cost of NOx monitoring equipment, could not feasibly be regulated and thus could not be assessed the tax. (Isaksson and Sterner, 2006; Section 4) Opponents of greenhouse gas regulation raise similar competitiveness concerns, which can be ameliorated by preserving sectoral revenue neutrality. It should also be noted that the Swedish NOx program is not limited to electricity generators, and it illustrates a workable method for accommodating combined heat and power sources by defining a ‘‘useful energy’’ output metric that applies to both electricity and usable heat. (Isaksson and Sterner, 2006; Section 4)

Output-based refunding lowers the tax burden on coal sources, making a high emission price more politically viable, but an initial fee of $37.50/MWh on coal (Table 2) would still be significant. This fee would go mostly to subsidizing installed NG sources and legacy renewables (primarily large hydro and nuclear), not new capacity. But the fee formula can be modified, as outlined below, to focus subsidies exclusively on new sources. (Section 6 discusses the criteria that qualify sources as ‘‘new’’ or ‘‘old’’.) The fee formula described previously (Eq. (4)) is applied to all new sources (both emitting and non-emitting), while the fees for old-source generation would be determined differently, as follows: an average emission intensity for old sources is determined based on aggregate old-source emissions and generation ðavg: old-source emission intensity; MT=MWhÞ ¼

ðagg: old-source emissions; MTÞ ðagg: old-source generation; MWhÞ

ð5Þ

The average fee for old sources is determined by an outputbased formula similar to Eq. (4), but treating the entire old-source

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sector as a single entity ðavg: old-source fee; $=MWhÞ ¼ ðemission price; $=MTÞ ðavg: old-source emission intensity; MT=MWhÞ 

! ð6Þ

ðavg: emission intensity; MT=MWhÞ

This determines the aggregate fees collected from old sources, which are apportioned to individual entities in proportion to emissions. For a particular old-source entity, its fee is determined by taking the ratio of its emission intensity to the average oldsource emission intensity, and multiplying by the average oldsource fee ðold-source fee; $=MWhÞ ¼

ðavg: old-source fee; $=MWhÞ ðemission intensity; MT=MWhÞ  ðavg: old-source emission intensity; MT=MWhÞ

ð7Þ

At the outset of the program, when all sources are ‘‘old,’’ the average old-source fee would be zero according to Eq. (6); and hence the individual-entity fees would also be zero by Eq. (7). Old-source fees would remain low until new sources begin to gain significant market share. Assuming that the average old-source emission intensity is not less than the overall average, the old-source fees will never be negative and there will be no old-source subsidies. A perverse condition could arise if new sources have worse average emission performance than old sources, in which case Eqs. (6) and (7) imply that old sources would receive net subsidies in proportion to emissions. Under this circumstance, it would make sense to enforce revenue neutrality within the new-source category to eliminate such subsidies. Furthermore, complementary or alter-

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native regulatory measures might need to be imposed to reverse the increasing emissions trend. Table 3 and Fig. 3 illustrate how the fees and subsidies would change with the revised old-source fee formula, Eq. (7) in lieu of Eq. (4). (Compare to Table 2 and Fig. 2.) Note that Eq. (5) becomes indeterminate when the aggregate old-source emissions and generation both approach zero, so the two numbers with the footnote annotation in Table 3 (rightmost column) cannot be determined from the above formulas. But they can be estimated from the following alternative formula under the condition that the average old-source emission intensity is much higher than the average new-source emission intensity: If ðavg: old-source emission intensity; MT=MWhÞ greatly exceeds ðavg: new-source emission intensity; MT=MWhÞ; then

ðold-source fee; $=MWhÞ ffi ðtax; $=MWhÞ ðagg: new-source generation; MWhÞ  ðagg: generation; MWhÞ

ð8Þ

wherein the tax is defined by Eq. (2). (This is demonstrated in Appendix B, Eq. (B.17).) For the 2012 market, the new-source fees and subsidies in Table 3 are identical to the values in Table 2, but the old-source fees and subsidies are zero. In 2050, when emitting sources have been substantially phased out, the fees for new sources are the same as a pure tax (e.g., $100/MWh for coal), but based on Eq. (8) the fees for old sources are 75% of a pure tax because 75% of generation comes from new sources. (In actuality, the old-source category might be eliminated by 2050, as discussed in Section 6.) The total fee-to-subsidy revenue would initially be zero in 2012, when there are no new sources to absorb the subsidies, and would again be zero in 2050, when there are no emitting sources to provide fees. In the interim, the revenue flow would reach a maximum as the market share of non-emitting sources surpasses

Table 3 New-source subsidy at $100/MT. Source category

Old sources Coal NG Non-emit. New sources Coal NG Non-emit. a

Emission intensity (MT/MWh)

Market share (%), 2012

1 0.5 0

50 25 25

1 0.5 0

0 0 0

Fee ($/MWh), 2012

0 0 0 37.5  12.5  62.5

Market share (%), 2030

Market share (%), 2050

Fee ($/MWh), 2050

25 12.5 25

37.5 18.75 0

0 0 25%

75a 37.5a 0

0 0 37.5%

68.75 18.75 -31.25

0 0 75%

100 50 0

These values are based on Eq. (B.17) in Appendix B.

2012

2030

Fee, $/MWh

New coal Old coal

New coal

Old NG New NG

Old coal 0 Old NG

New NG Old non-emit. New non-emit.

2050 New coal Old coal

100

Subsidy

Fee ($/MWh), 2030

Old non-emit. New non-emit. Generation, MWh Fig. 3. New-source subsidy.

New NG Old NG

Old non-emit. New non-emit.

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fossil fuels, as illustrated by the 2030 conditions in Table 3 and Fig. 3. During this market ramp-up phase, it might seem that the new-source subsidies would put old non-emitting sources at a competitive disadvantage. But the fees that generate those subsidies would also give old non-emitting sources a competitive price advantage relative to fossil fuels, so the net economic impact on old non-emitting sources would tend to be neutral. Furthermore, newsource subsidies might be partially offset by higher technology costs. To put the numbers in Table 3 into perspective, the Waxman– Markey climate bill would impose a price floor on coal-generated electricity of approximately $10/MWh in 2012, rising to $64/MWh in 2050. The intent of the Waxman–Markey price structure (as well as the Stark, Larson, and Inglis carbon tax proposals) appears to be to impose an initially low and escalating carbon price that will gradually price emitting sources out of the market. The new-source subsidy mechanism, by contrast, provides an initially high and declining subsidy that would expediently price non-emitting sources into the market.

6. Source vintage The discriminatory regulatory treatment of new and old sources is based on the following policy rationale: Old nonemitting sources do not receive subsidies because this would divert economic resources from new non-emitting capacity expansion. But the new-source subsidies would automatically diminish as new sources gain market share and become less dependent on the subsidies, so the policy would not confer a longterm competitive advantage to new sources. Old high-emission sources are not subject to the same high fees as new highemission sources because it would not be feasible to start phasing out such sources until economically viable substitutes exist. As new low-emission sources become viable and gain market share, old-source fees will commensurately rise and will make old emitting sources increasingly unviable; but in the near term, deterrence of high-emission capacity expansion is more important than discontinuing existing high-emission generation. The source vintage (‘‘new’’ versus ‘‘old’’) qualification criteria should operate fundamentally to incentivize new, low-emission capacity expansion, deter new, high-emission capacity expansion, and facilitate expedient decarbonization of electricity with minimal economic disruption. Simply qualifying sources as ‘‘new’’ or ‘‘old’’ based on whether they have gone into service before a particular program start date would not comport with these objectives. For example, upgrading an old non-emitting source to increase generation capacity or extend generator lifetime would create ‘‘new’’ capacity, which should be treated as such. Several refinements of the initial service date criterion can be made to ensure that regulatory incentives are compatible with program objectives. One refinement would be to assign old sources an ‘‘expiration date’’, based on their expected lifetime, after which they would be re-classified as new sources. This ‘‘expiration rule’’ would, for example, deter investments in coal power plant upgrades that would allow them to operate indefinitely as ‘‘old’’ sources even though they have new equipment. The expiration rule would also encourage investment in old-source renewables that would extend their operable lifetime. (As a consequence of this rule all of the old-source classifications may have expired by 2050.) A new-source facility should be required to use substantially all new equipment; otherwise its new-source qualification may be delayed for a period of time based on the used portion of the facility. This would deter premature shut-down of low-emission sources just so they can be reconstructed as ‘‘new’’ sources without actually creating new generation capacity.

Under some circumstances, a source could be treated, for regulatory purposes, as two sources, one new and the other old. This kind of ‘‘split vintage’’ might be used, for example, when a generator’s old-source qualification expires. Rather than instantly terminating its old-source qualification, an increasing portion of its output and emissions could be re-characterized as ‘‘new’’ over an extended period of time. Power plant upgrades and changes in capacity utilization can have mixed environmental impacts. For example, increasing a combustion unit’s output capacity would increase emissions, but if its efficiency also improves then the capacity increase may displace less efficient generation elsewhere. Regulatory incentives and disincentives for upgrades, refurbishments, maintenance, etc. can be efficiently balanced by applying the following ‘‘vintagesplitting’’ rule: If an old source changes its generation output and/or emissions significantly from a historical baseline level, then it will be regulated as two sources, an old source whose generation and emissions are unchanged from the baseline and a new source whose generation and emissions are equal to the changes from the baseline. In other words, if an old-source generator’s baseline generation and emissions are q and e, respectively, and its generation and emissions change to q0 and e0 , then the generator would be regulated as an old source with generation and emissions q and e, and a new source with generation and emissions q0  q and e0  e. This policy is ‘‘efficient’’ in the sense that it values all changes in aggregate generation and emissions the same (i.e., as uniformly ‘‘new’’ capacity) irrespective of the source type or means by which changes are affected. For example, if a generator’s baseline performance is 1,000,000 MWh and 1,000,000 MT per year and it increases annual emissions to 1,500,000 MT without changing generation output, then it would be treated as an old source with the same 1,000,000 MWh, 1,000,000 MT baseline rating, in combination with a new source that produces zero power output and 500,000 MT of emissions. The new-source component would be subject to the full carbon price with no output refund. On the other hand, if the generator’s emissions were reduced to 500,000 MT, again without changing generation output, then the generator’s new source component would have negative emissions of 500,000 MT. A similar situation would exist if a sequestration service had been contracted to sequester half of the generator’s 1,000,000 MT emissions. An independent sequestration service could be regulated as an emission ‘‘source’’ that has negative emissions and no generation output. It would not accrue any output subsidy, but its carbon ‘‘fee’’ would be negative and would hence constitute a subsidy. Considering another example, if the generator increases its output to 1,500,000 MWh without changing its emissions (implying a one-third reduction in emission intensity), then its new-source component would generate 500,000 MWh with zero emissions, and would fully qualify for new-source subsidies. Conversely, if the generator’s output is reduced to 500,000 MWh without changing emissions (implying doubled emission intensity), then the new-source component’s output would be negative,  500,000 MWh, and the output ‘‘subsidy’’ would correspondingly be negative. The vintage-splitting rule could result in a high-emission generator receiving a residual net subsidy by shutting down the facility. The subsidy may be justified because premature closure of an operational power plant could be very costly, and the operator might not be incentivized to terminate production without compensation for lost revenue. Moreover, the subsidy would only persist until the end of the plant’s rated lifetime (based on the expiration rule), and it would also persist only as long as the other emitting sources, whose fees finance the subsidy, maintain significant market share.

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As a consequence of the vintage-splitting rule, an old nonemitting generator could accrue high marginal subsidies by increasing output, because the increased generation would qualify as ‘‘new’’. But the rule would also result in high marginal fees if output is reduced or if the generator is prematurely shut down. An economic rationale for the fees would be that they either deter such output reduction or help subsidize a compensating increase in low-emission generation elsewhere. But imposing financial penalties on old, zero-emission sources to force production would be unfair because such sources are unsubsidized. To avoid this circumstance, the following rule exception could be made for old, low-emission sources: An old source is ‘‘low-emission’’ if its emission intensity is less than the average old-source emission intensity (Eq. (5)); otherwise it is ‘‘high-emission’’. If application of the vintage-splitting rule would penalize a low-emission source (i.e. increase its fee), and if its output has not increased from the baseline, then one of the following conditions would apply: (1) If the source remains low-emission after its output and/or emissions change, then it will still be fully characterized as old-source. (2) If the low-emission source becomes high-emission as a result of the change, then it will thereafter be fully characterized as new-source until such time as it again becomes low-emission. In either case, no vintage splitting is applied. (If the source’s emission intensity becomes equal to the average old-source emission intensity, it does not matter whether the source is characterized as old or new—either option would result in the same fee. These points are clarified in Appendix B.) The above-described rule exception does not apply to highemission sources. There is a reasonable policy justification for this discrimination because the old-source classification is inherently favorable to high emitters, in that it eliminates cross-subsidies from high to low emitters that would exist under pure outputbased refunding. The old-source classification of low emitters tends to reduce the average old-source emission intensity, resulting in lower fees for high emitters, so a regulatory exception in favor of low emitters is warranted.

7. Conclusion New-source subsidies represent a market-based regulatory alternative for inducing expedient decarbonization of electricity generation, which would provide the following benefits:

 Price stability would create market conditions conducive to    



sustained, long-term investments in clean energy. High production subsidies for clean energy would provide immediate, high incentives for large-scale commercialization of renewables. Regulatory costs would be comparatively low in relation to the regulatory price incentive (actually starting out at zero). Market competition from subsidized low-emission sources would tend to minimize ratepayer impacts as low-carbon energy gains market share. In contrast to ‘‘economy-wide’’ market instruments, the limited scope and narrow policy objective of new-source subsidies could make them more politically manageable and less susceptible to consolidated political opposition. International climate treaties could establish a collaborative global climate strategy based on domestic policies such as new-source subsidies.

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Appendix A. The Swedish NOx program The primary operational precedent for emission pricing with output-based refunding is the Swedish program for stationarysource nitrogen oxide (NOx) emissions. The program taxes NOx emissions and refunds practically all of the tax revenue to regulated entities in proportion to ‘‘useful energy output’’, e.g., MWh for electricity. The following publication excerpts provide an overview of the program’s operational performance. ‘‘In the two years between the approval and the activation of the Act on NOx, many companies began extensive efforts to reduce emission levels in anticipation of the charges they would face in 1992. y Overall, the Swedish NOx feebate policy can be described as having surpassed the best expectations set when it was introduced in 1992. Emission levels have plunged much faster than was ever anticipated, with the 35% reduction target set for 1995 (from 1990 levels) achieved two years early in 1993. Thanks to the rebate system, for many firms the installation of NOx-reducing equipment has been a profitable venture’’ (Barg et al., 2000, p. 49). ‘‘Although the charge system only became official in 1992, steps to reduce emissions of nitrogen oxides had actually started to be taken two years earlier, after the passing of a bill in Parliament in June 1990. Between 1990 and 1995 specific emissions from the affected plants dropped from an average of about 160 milligrams of NOx per megajoule (mg/MJ) of useful energy to 60 mg/MJ, or by about 60 per cent. The total from all plants did not come down quite as much, however, the reduction being more like 50 per cent – since the total output of energy had in the meantime ˚ increased by almost a quarter’’ (Agren, 2000, p. 3). ‘‘y The Swedish retrofitted unit y, in contrast, demonstrates that NOx levels well below the Swedish standard (and also below the German or United States standards) are achievable y The Swedish regulatory system incorporating an economic incentive y clearly motivates [the Swedish plant] to achieve minimal NOx rates rather than just comply with the applicable emission standard’’ (USEPA, 1997, p. 37). ‘‘y a tax of the same high level as the REP charge level of 6000 $/ton would, in addition to the 40% reduction in emission coefficients, have achieved a further reduction of one percentage point due to lower product demand. y A tax would have been successfully resisted and if a pure tax had been used at all, it would most likely have been at a level of just a few hundred $/ ton. Such a tax would have given insignificant output effects and much smaller abatement effects than the high fee made possible by refunding’’ (Isaksson and Sterner, 2006, p. 104). ‘‘y With the rebate, however, a similar calculation finds a price rise of less than $0.0004 per KwH. This is one-fifth the rise without a rebate, or an increase in price of between 0.5 and 1.0 percent if Swedish electricity sells for $0.05 to $0.10 per KwH. y the actual price rise was not of much practical concern’’ (Wolff, 2000, p. 6).

Appendix B. Formulas Following the definitions and notation in Johnson (2007), the electricity sector comprises generation sources, wherein source i generates emissions ei (MT CO2-equivalent) in connection with generation output qi (MWh) during a particular compliance period. A carbon tax ti ($) applied to emissions ei would be ti ¼ pei

ðB:1Þ

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K.C. Johnson / Energy Policy 38 (2010) 2499–2507

wherein p is the mandated emission price ($/MT). The tax per unit output ($/MWh) is

fi ¼

ti e ¼p i qi qi

ðB:2Þ

wherein the ratio ei/qi is the emission intensity of source i (Eq. 1). Eq. (2) paraphrases Eq. (B.2). Aggregate emissions and output are indicated as E and Q, respectively, X X ei ; Q ¼ qi ; ðB:3Þ E¼ i

i

With output-based refunding, source i receives a tax refund ri that is proportionate to output ri ¼ p

E q Q i

ðB:4Þ

The ratio E/Q is the average emission intensity (Eq. (3)), and the proportionality factor pE/Q is determined to maintain revenue neutrality X X ti ¼ ri ðB:5Þ i

The old-source fees are proportionate to emissions

i

The fee fi for source i (or subsidy, if negative) is the balance between the tax and refund fi ¼ ti ri

ðB:6Þ

The fee per unit output is   fi e E ¼p i qi qi Q

ðB:7Þ

(cf. Eq. (4)). For the new-source subsidy, the regulated sector is divided into two categories, ‘‘New’’ and ‘‘Old,’’ and aggregates over these categories are indicated as 9 P P E½New ¼ i A New ei ; Q ½New ¼ i A New qi > = P P E½Old ¼ i A Old ei ; Q ½Old ¼ i A Old qi ðB:8Þ > ; E ¼ E½New þ E½Old ; Q ¼ Q ½New þ Q ½Old Aggregate fees are similarly indicated as 9 P F ½Old ¼ i A Old fi > = P F ½New ¼ i A New fi > ; F ¼ F ½New þF ½Old New-source fees are determined by Eq. (B.7)   fi e E ¼p i ; i A New qi qi Q

ðB:9Þ

F ½Old ei ; E½Old

iA Old

ðB:14Þ

(The proportionality factor F[Old]/E[Old] is determined to match aggregate old-source fees to F[Old], which is determined by Eq. B.13.) The fee per unit output can be expressed as fi F ½Old e =q ¼ ½Old ½Oldi i½Old ; qi Q E =Q

ðB:15Þ

(cf. Eq. (7)). Eq. (B.13) has the following alternative, equivalent form:  ½Old  F ½Old E E½New Q ½New ðB:16Þ ¼ p  Q Q ½Old Q ½Old Q ½New If the average old-source emission intensity is much higher than the average new-source emission intensity, then the following condition follows from Eqs. (B.16) and (B.15):  ½Old  ½New 8 ½Old F E Q > > ; > ½Old ffi p < ½Old ½New Q Q Q ½Old E E c ½New ðB:17Þ ½New ½Old > fi Q Q ei Q > > ; i A Old : ffip qi Q qi (cf. Eq. (8)) If the old-source aggregate output is also much less than the new-source output, the old-source fee becomes approximately equivalent to a simple carbon tax 8 ½New Q > > > ffi 1; < ½Old ½New Q E E c ½New ; Q ½Old {Q ½New ½Old f e > Q Q > > i ffi p i ; i A Old : qi qi ðB:18Þ With substitution of Eq. (B.13) in (B.15), the result can be compared to Eq. (B.10)   9 fi e E ¼p i  ; iA New > = qi qi Q   ðB:19Þ fi ei E ei =qi > ; iA Old ; ¼p  ½Old ½Old qi qi Q E =Q This comparison makes it clear that the new- and old-source fee formulas are identical when ei =qi ¼ E½Old =Q ½Old , i.e., when the source emission intensity is equal to the average old-source emission intensity. For high-emission sources (ei 4 ðE½Old = Q ½Old Þ qi ), the old-source formula yields a lower fee, and for

ðB:10Þ

e

This implies that average new-source fees are determined by a similar equation  ½New  F ½New E E ¼ p  ðB:11Þ Q ½New Q ½New Q

iA Old

source i (qi, ei)

(e = (E[Old]/Q[Old]) q) high-emission (e > (E[Old]/Q[Old]) q)

(This result is readily obtained by clearing qi and Q[New] denominators in Eqs. (B.10) and (B.11).) Fees are required to be revenue-neutral within the regulated sector F ¼F

½New

þF

½Old

¼0

average-intensity line

q

ðB:12Þ

Based on Eqs. (B.11) and (B.12), average old-source fees are defined by  ½Old  F ½Old E E ¼ p  ðB:13Þ Q ½Old Q ½Old Q The factor E[Old]/Q[Old] is the average old-source emission intensity (Eq. (5)), and Eq. (6) paraphrases Eq. (B.13).

low-emission (e < (E[Old]/Q[Old]) q)

Fig. 4. Emissions versus output.

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(qi ,ei)

(qi′, ei′) e = (E[Old] / Q[Old])q

e

q

illustrated, application of the vintage-splitting rule would penalize the source because both points are above the dashed line through (qi, ei) and parallel to the average-intensity line. Furthermore, the output level does not increase in either case (q0 i rqi, q00 i rqi), so the rule exception applies. For point (q0 i, e0 i), the source remains lowemission, so there is no change in its vintage status. For point (q00 i, e00 i) the source becomes a high emitter, so it is re-characterized as a new source. (If the new (q, e) point is on the average-intensity line, it does not matter which of the two fee formulas in Eq. (B.19) is used. Both will yield the same result.) References

(qi′ - qi, ei′ - ei)

Fig. 5. Vintage-splitting rule.

e = (E[Old] / Q[Old])q

e

(qi′′, ei′′)

2507

(q′i, ei′)

(qi, ei) q

Fig. 6. Vintage-splitting rule exception.

low-emission sources (ei o ðE½Old =Q ½Old Þ qi ), the new-source fee is lower. These conditions are illustrated in Fig. 4. Source i is represented as a vector with coordinates (qi, ei) in a (q, e) (output, emissions) parameter space. The average-intensity line e ¼ ðE½Old =Q ½Old Þ q separates high- and low-emission sources. Fig. 5 illustrates the vintage-splitting rule described in Section 6. A source with baseline (q, e) coordinates (qi, ei) changes its output and emissions to (q0 i, e0 i). The source is treated as two sources, an old source with output and emissions (qi, ei), and a new source with output and emissions (q0 i  qi, e0 i  ei). The newsource qualification of the second source will increase the fee if point (q0 i, e0 i) is above the dashed line through (qi, ei) and parallel to the average-intensity line; and it will decrease the fee if the point is below the dashed line. (Note: The aggregates Q[Old] and E[Old], which define the average-intensity line, depend on qi and ei, but they are defined by the baseline quantities and are hence unaffected by the change.) Fig. 6 illustrates the vintage-splitting rule exception for a lowemission source with baseline output and emissions (qi, ei). If its output and emissions change to either (q0 i, e0 i) or (q00 i, e00 i), as

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