2. Energy Market Impacts

Greenhouse Gas Emissions and Allowance Prices

Figure Data

Figure Data

Figure Data

Compliance with the GHG regulations imposed by H.R.5049 slows GHG emissions growth after 2009, the assumed first year of the bill’s allowance program.  Total projected greenhouse gas emissions⁷ under the three policy cases continue to rise slowly after 2009, but at a slower rate than in the AEO2006 reference case (Figure 2.1).   In 2030, total GHG emissions range from 6 to 10 percent lower across the policy cases (Table 2.1). 

While the bill effectively caps GHG emissions by issuing a given level of emissions allowances, the projected emissions continue to rise after the program is in place.   Emissions rise because some emissions sources are assumed to be exempt from the allowance program and because offsetting emission credits are assumed to be issued for approved increases in carbon sequestration, as provided under Sec. 7.  In addition, the safety-valve program provides for unlimited, supplementary sales of emission allowances at a specified price to control the potential cost of the program. 

The trading price for emission allowances, reflecting the marginal cost of emission abatement, is projected to reach the safety-valve level between 2016 and 2018 in the three policy cases (Figure 2.2).  In the H.R.5049A case, covered GHG emissions from 2009 to 2017, less the offset for increased carbon sequestration, match the assumed covered emissions cap of 6,956 million metric tons carbon dioxide equivalent. Once the allowance price reaches the safety-valve price in 2018, additional allowances are issued and purchased each year, and so covered emissions are no longer constrained, but emissions continue to be influenced by the allowance cost incentive.  As a result, projected GHG emissions begin to grow faster beginning in 2018, but at a slower rate than in the AEO2006 reference case.  

In both the H.R.5049A and H.R.5049B cases, the projected allowance prices first reach the safety-valve level in 2018.  After 2018, the safety-valve program continues to limit the allowance market trading price.  However, in the H.R.5049A case, the real dollar safety-valve price grows at a rate of 1.3 percent per year, as called for under Section 5(a).⁸ In the H.R.5049B case, the safety-valve price is assumed to grow at 2.3 percent per year, as could occur under Section 5(b).  With higher allowable permit prices projected in the H.R.5049B case, GHG emissions are reduced by a greater amount than in the H.R.5049A case, and higher levels of carbon sequestration are projected (Figure 2.3).

In the No-Safety case, the allowance price continues to grow throughout the projection, reaching $30 per metric ton carbon dioxide equivalent (2004 dollars) in 2030, compared to $8 per metric ton in the H.R. 5049A case and $10 per metric ton in the H.R. 5049B case.  In the No-Safety case, covered GHG emissions, less offsets for carbon sequestration, remain at the 2009 level through 2030.

Figure 2.3 compares the emissions-related impacts of the policy cases relative to the AEO2006 reference case, including the estimated carbon sequestration effects.  A large share of the emissions impacts in the policy cases are attributed to the gases other than energy-related CO2 and to carbon sequestration.  The projected impacts from the non-CO2 sources are based on marginal abatement cost curves derived from EPA analyses.  The analyses suggest that substantial emissions reductions are economical in the range of GHG allowance prices considered in this analysis.  

In the H.R.5049A case, the combined reduction in non-CO2 gases and carbon sequestration accounts for 80 percent of the total GHG impacts in 2020 and 64 percent in 2030.  While the non-CO2 abatement curves reflect emission reductions that are economical based on engineering cost analyses, the market response to those opportunities may be significantly less.  The H.R.5049C case assumes 50 percent lower abatement response for the non-CO2 gases and holds the carbon sequestration abatement curves at the same level.⁹   The percentage contribution of the non-CO2 sources in the H.R.5049C is 74 percent in 2020 and 54 percent in 2030.  Initially, projected allowances prices are driven higher in the H.R.5049C case, as more pressure is put on energy markets to reduce emissions of CO2.  As a result, the allowance price first reaches the safety-valve level in 2016 in the H.R.5049C, 2 years earlier than in the other cases. 

Energy Sector Impacts

H.R.5049 requires producers and importers of fossil fuels—coal, natural gas, and petroleum—to submit emission allowances equal to CO2 emissions that will result from the use of the fuel supplied.  While the Federal government will distribute up to 10 percent of the allowances for free to the oil, natural gas, and coal industries, the suppliers will need to purchase most of the allowances from other recipients.¹⁰  EIA assumes that energy suppliers will pass on the actual or opportunity cost of the allowances by raising energy prices by a surcharge proportional to the CO2 emissions per unit of energy.   As a result, the delivered prices to final consumers of using fossil fuels will reflect the cost of allowances needed. 

Because fuel suppliers pass on their allowance costs in the prices they charge, the delivered prices of coal, natural gas, petroleum, and electricity all increase in the policy cases relative to the AEO2006 reference case.¹¹  In percentage terms, coal prices are most affected by allowance costs:  the projected average delivered coal price in the H.R.5049A case is 46 percent above the reference case price in 2030.  In comparison, projected average gasoline prices are higher by 3 percent in 2030, natural gas by 5 percent, and electricity by 6 percent. 

The demand for energy adjusts to higher energy prices, thereby reducing the associated CO2 emissions.  The demand adjustments are varied and include short- and long-term changes in the energy consumption sectors.  The energy sector also responds to the macroeconomic effects resulting from higher energy prices and the government’s collection and distribution of allowance revenue.

Figure Data

Figure Data

Energy demand across each of the energy consumption sectors—residential, commercial, industrial, transportation, and electricity—will respond in different degrees to the energy price changes (Figure 2.4).  The electricity sector is projected to be most responsive to changes in fossil fuel prices, as fuel prices represent a significant share of its operating costs, and the ability to switch from coal to less carbon-intensive energy sources is greater.

In the H.R.5049A case, reductions in CO2 emissions in the electricity sector account for 68 percent of the total energy-related carbon dioxide reductions in 2030, compared to the AEO2006 reference case.  When the CO2 emissions from electricity are apportioned to the end-use sectors, the industrial sector has the largest emission reduction, while transportation has the least (Figure 2.5). 

In the end-use sectors, the demand for energy is relatively insensitive to changes in price, especially in the short term, for a variety of reasons.  Adoption of more efficient, less carbon-intensive technologies may require higher initial costs, and cost-effective adoption of further efficiency improvements is delayed by the long lifetimes of the existing stock of vehicles, equipment, buildings, and appliances.  As a result, the effect on projected end-use sector fossil fuel demand in the policy cases is modest in most areas but tends to grow over time.   Projected consumption of petroleum and natural gas combined in the four end-use sectors in the policy cases is reduced by less than 1 percent in 2030, relative to the AEO2006 reference case.  

The most significant change in end-use sector energy consumption occurs to coal in the industrial sector.  The projected demand for industrial coal is 14 percent lower in 2020 and 26 percent lower in 2030 in the H.R.5049A case than in the reference case.   In the AEO2006 reference case, industrial coal use is projected to grow rapidly in the latter half of the projection as coal-to-liquids plants are introduced.  Under the policy cases, the cost of coal reduces the economic potential for these plants, curtailing the associated growth in coal use, along with the associated CO2 emissions.  As a result, domestic petroleum supply from coal-to-liquids plants is 445 thousand barrels a day lower in 2030 in the H.R.5049A case, compared to the reference case.  Because the coal–to–liquids plants are also combined heat–and–power plants, the projected generation of end-use sector electricity is also reduced under the policy cases.

Figure Data

In the electric power sector, projected changes in the policy cases include shifts in the types of new power plants added, with an increased reliance on natural gas, renewable energy, and nuclear power to supply electricity and less reliance on coal and petroleum (Figure 2.6).   These changes accumulate over time and, as a result, the most significant impacts are reflected at the end of the projection period. 

In the AEO2006 reference case, coal generation in the power sector increases from 1,954 in 2004 to 3,205 billion kilowatthours in 2030, providing 58 percent of the total power sector generation in 2030.  In the H.R.5049A case, projected coal generation in 2030 is 2,920 billion kilowatthours, 9 percent lower than in the reference case, but still a 49-percent increase over the 2004 level.  While carbon capture and storage technologies could allow coal-fired plants to be more competitive under a GHG allowance program, the allowance prices are not sufficiently high in the policy cases to compensate for the increased capital and operating costs.  As a result, no power plants using carbon capture and storage are projected to be built within the 2030 time frame in the policy cases.

Projected power-sector generation from natural gas, which emits lower CO2 emissions per kilowatthour generated than coal, increases from 822 billion kilowatthours in 2030 in the reference case to 893 billion kilowatthours in the H.R.5049A case.  While over the longer-term, natural gas generation is higher in the policy cases than in the reference case, natural gas fuel use in the electric power sector is lower in the near-term between 2011 and 2020.  Older, less efficient steam plants fueled by natural gas and oil are projected to be used less or retired to a greater extent under the proposed bill.  However, as more combined-cycle plants are added in the latter half of the projection under the policy cases, natural gas use in the policy cases approaches levels in the reference case.

Projected power-sector generation from renewable sources, mainly biomass and wind, changes most in percentage terms under the policy cases compared to the reference case.   Renewable generation in 2030 is 644 billion kilowatthours in the H.R.5049A case, 28 percent higher than the 504 billion kilowatthours in the reference case.  Biomass generation, exempt from the bill’s CO2 allowance requirement, accounts for 82 percent of the change in generation between the two cases, while wind accounts for 15 percent. 

In the AEO2006 reference case, 6 gigawatts of new nuclear capacity is projected, partly spurred by subsidies called for in the Energy Policy Act of 2005.  Under the policy cases, the comparative economics of nuclear power is improved because its use requires no emission allowances.  Projected nuclear additions by 2030 are 19 gigawatts in the H.R.5049A case and 25 gigawatts in the H.R.5049B case. 

The allowance allocation provisions of the bill may influence electricity prices in ways that have not been quantified in this analysis.  While electricity suppliers are not required to submit allowances based on their fossil fuel use, their fuel suppliers would include the allowance cost in the prices charged.  As a result, it is assumed that electricity suppliers would price electricity according to their higher fuel cost, generally passing on their higher cost to consumers.  However, H.R.5049 calls for the electricity industry to receive up to 5 percent of the GHG allowances created. This transfer would subsidize the industry but have an uncertain effect on electricity prices, particularly for unregulated companies.  Regulated utilities, however, would probably be directed to pass on most of the allowance proceeds to rate-payers.  As a result, electricity prices, particularly in heavily regulated regions, might not increase as much as reflected in this analysis. 

Other impacts on energy supply markets are most noteworthy for the coal industry.  Projected coal production in the H.R.5049A case in 2030 is 1,511 million short tons, 11 percent lower than in the reference case.  The change in projected coal supply in 2030 is greater for coal mined west of the Mississippi, a source of much of the incremental supplies in the projections.  Western coal production in 2030 is 13 percent lower, from 1,070 million tons in the reference case to 933 million tons in the H.R.5049A case.  Eastern coal production in 2030 declines by 9 percent between cases, from 633 million tons in the reference case to 578 million tons in the H.R.5049A case. 

2. Energy Market Impacts Table

Notes and Sources