Electricity Sector Emissions, Generation, and Prices

The provisions of S. 2191 alter electric power projections by favoring low-carbon technologies such as coal plants that sequester CO2, renewable facilities, and nuclear power.  The impact of CCS technology is also affected by the provisions that provide multiple allowances to these plants for each ton of CO2 sequestered.  In several analyses of proposals to reduce greenhouse gas emissions, EIA has found that the electric power sector would first turn to increased use of nuclear and renewable fuels, before coal power plants with CCS.  However, the bonus allowances provided for CCS in S. 2191 improve its relative economics, though nuclear and renewable fuels still play a larger role.  The shifts in the generation mix lead to lower CO2 emissions from the electricity sector, higher electricity prices, and lower electricity demand than in the Reference Case.  The higher electricity prices are due to the higher capital costs of cleaner, more efficient technologies and the costs of holding allowances, both of which are partially offset by lower fuel expenditures. 

Emissions

In the Reference Case, which assumes no policy to reduce GHG emissions, power sector CO2 emissions are projected to increase 26 percent between 2006 and 2030 as the industry increases its use of fossil fuels, particularly coal (Figure 12). In the S. 2191 cases, power sector CO2 emissions are expected to be 26 percent to 52 percent below the Reference Case level in 2020 and 60 percent to 92 percent below the Reference Case level in 2030. In the S. 2191 Core Case and S. 2191 No International Offsets Case, the power sector greatly reduces the use of fossil fuels and lowers emissions by 85 to 90 percent between 2006 and 2030. In the S. 2191 High Cost and S. 2191 Limited Alternatives Cases the nuclear, renewable, and sequestration technologies are assumed less economic or unavailable, and emissions in the power sector are not reduced as significantly, but still fall by 50 to 60 percent over the forecast.

Capacity and Generation

In the Reference Case, coal plants without CCS meet a large share of new capacity requirements through 2030 (Figure 13).  Absent regulations limiting GHG emissions, coal plants tend to be the most economical option for meeting continuous, or baseload, demand.  New natural gas plants are also added in the Reference Case, but tend to be more economical for meeting intermittent loads. Most of the renewable capacity added in the Reference Case is in response to State renewable portfolio standards.

Under S. 2191, new coal builds without CCS are almost eliminated. There is also a dramatic increase in power plant retirements, with almost two-thirds of existing coal plants projected to retire by 2030 in the S. 2191 Core Case and many of the retiring plants must be replaced by new capacity to meet demand. To meet this demand, most cases build a mix of coal with CCS, nuclear, and renewable technologies, primarily wind and biomass. The bonus credits provided to CCS under S. 2191 make coal with CCS economic, with 34 to 64 gigawatts (GW) of additions projected by 2030 across the S. 2191 cases that allow CCS builds. The Reference Case projects 17 GW of new nuclear capacity by 2030, but under S. 2191, nuclear builds by 2030 range from 88 GW to 286 GW, when allowed to grow. Renewable capacity also grows significantly, representing between 21 percent and 61 percent of all new capacity by 2030 across the S. 2191 cases.  Note that the additions of new coal plants with CCS is much larger under the provisions of S. 1766 because the bonus allowances for CCS are not limited to a certain share of allowances as they are under S. 2191.

When technologies with CCS, nuclear, and biomass are constrained to Reference Case levels, the addition of new natural gas capacity grows significantly, with additions more than double that of the Reference Case by 2030.  However, in the S. 2191 Core Case, natural gas additions are below those in the Reference Case, as CCS is not as economic on combined-cycle plants as coal, and other non-fossil technologies are built instead of natural-gas-fired plants without CCS.

Changes in electricity generation are consistent with capacity choices and are influenced by the GHG allowance price (Figures 14 and 15). In the Reference Case, coal generation grows to 2,838 billion kilowatthours in 2030, an increase of 43 percent over 2006 levels, providing 54 percent of total electricity needs. In the S. 2191 cases, coal generation drops significantly, contributing less than one-quarter of total electricity generation in all cases, with the S. 2191 Limited Alternatives/No International Case seeing the biggest decline to just 5 percent of total electricity from coal in 2030.  Although new coal capacity with CCS is added in most cases, the generation from these new plants is more than offset by reductions from the retirement of existing coal capacity. In the S. 2191 High Cost and S. 2191 Limited Alternatives Cases, coal generation is above that in the Core Case, but still much lower than the Reference Case. In those cases, the higher costs or limited availability of key non-fossil technologies result in fewer coal retirements than in the S. 2191 Core Case. However, this results in higher CO2 emissions in these cases.

Nuclear generation follows the capacity additions, growing most significantly in the S. 2191 Core and S. 2191 No International Cases.  In the Reference Case, nuclear generation grows by 17 percent between 2006 and 2030, reaching 917 billion kilowatthours and providing 18 percent of total generation. In the S. 2191 Core Case, nuclear grows to 2,877 billion kilowatthours in 2030, more than triple the Reference Case level. If nuclear costs are higher than expected, then new nuclear is still projected, but at lower levels. The S. 2191 High Cost Case projects nuclear generation will be almost 60 percent higher than in the Reference Case in 2030.

In most cases, natural gas generation goes down under the provisions of S. 2191.  In the Reference Case, natural gas generation drops 8 percent by 2030, relative to 2006 levels, and in the S. 2191 Core Case natural gas generation is 47 percent below current levels. However, in the S. 2191 Limited Alternatives Case, natural gas generation more than doubles from the Reference Case level by 2030, due to the limited availability of new plants with CCS, as well as new nuclear and biomass capacity.  This case demonstrates the importance of the development and deployment of key low-carbon generating technologies like nuclear, renewables, and fossil with CCS in a timeframe consistent with the emission reduction requirements of S. 2191.  Without them, allowance prices would be higher and greater demands would be placed on natural gas markets.

Renewable generation is dramatically higher under the provisions of S. 2191, growing between 40 percent and 146 percent above generation in the Reference Case in 2030.  The vast majority of the increase is from wind generation, followed by biomass generation.  Through 2020, some of the increase in biomass generation is through increased co-firing at coal plants, but after 2020 the co-firing output begins to decline and is below the Reference Case level by 2030 in all but the S. 2191 High Cost Case.  Initially co-firing is an economic way to reduce CO2 emissions without investing in new capacity, but as the allowance price increases over the forecast, the economics shift to favor less CO2-intensive generation.  In the S. 2191 Limited Alternatives Case, biomass supplies are limited so that no increase in either dedicated plants or co-firing is possible relative to the reference case. In this case, other renewable types such as solar and offshore wind are built.

Price and Demand

S. 2191 is expected to lead to higher electricity prices and lower electricity demand, with much greater impacts in the High Cost and Limited Alternatives Cases.  In the S. 2191 Core Case, electricity prices reach 9.1 cents per kilowatthour in 2020 and 9.8 cents in 2030 (Figure 16).  These prices are 5 percent and 11 percent higher, respectively, than the prices in the Reference case.  The largest increase is seen in the S. 2191 Limited Alternatives/No International case, where electricity prices reach 14.5 cents per kilowatthour in 2030. This is due to both the higher allowance price and the higher costs of the technologies available to build.

The allocation of allowances to load serving entities in S. 2191 does limit the impact on electricity prices slightly.  EIA assumes the value of these allowances would be passed on to consumers through a reduced distribution price.  The impact of this provision is to reduce average distribution prices by around one-half cent per kilowatthour.

Total consumer expenditures for electricity in the S. 2191 Core Case are $126 billion higher than in the Reference Case over the 24-year projection period.⁴  This added expenditure is a 3-percent increase in consumers’ total electricity costs.  The higher prices stem from suppliers’ increased capital and fixed costs together with costs of holding allowances.  These higher costs are partially offset by lower quantities of fossil fuel purchased and less generation.

The higher electricity prices, which are 11 to 64 percent higher by 2030, and programs to stimulate more efficient electricity use under S. 2191 are projected to result in a damping of electricity demand by 5 to 11 percent in 2030.  The impact on electricity demand in the S. 2191 Core Case is mostly due to the demand-side efficiency programs in S. 2191, while the higher electricity prices are more important in the cases with higher allowance prices.  Projected total sales in the Reference Case increase to 4,972 billion kilowatthours in 2030, a 30-percent increase from 2006.  The S. 2191 Core Case results in a 2030 aggregate demand of 4,731 billion kilowatthours, 5 percent below the Reference Case level. 

Regional electricity prices vary for many reasons including the demand characteristics, the mix of generating sources used, the availability and delivered prices of different resources and  fuels, the regulatory regime, and the local costs of construction (Figures 17 and 18).  Generally the largest changes in prices caused by the provisions of S. 2191 would be expected in regions that are most reliant on coal and regions where electricity prices are set competitively, so that the incremental costs of allowances reflected in fuel pricing will flow directly through to consumers.  In regions with cost of service regulation, average electricity prices are moderated by the pass-through of allowance values from fossil plant owners who receive a share of allowances for free.  S. 2191 also allocates a fixed 9 percent of allowances to load-serving entities that would also help moderate the average electricity bills in both regulated and unregulated regions.

As shown in Figure 20, all regions are expected to see prices increases in most of the S. 2191 cases.  Competitively priced regions such as the Electric Reliability Council of Texas, the Mid-Atlantic Area Council, New York, and New England see especially large increases in the S. 2191 cases where alternatives are limited, because the high costs of allowances in those cases are passed directly through to consumers as higher marginal generating costs.  In contrast, cost-of-service based regions with little reliance on coal, such as California, see much smaller price increases.  In the S. 2191 Core Case, where all generating alternatives are available at the costs consistent with those of a few years ago, a couple of regions could have fairly small price increases or even small price declines in the later years relative to the Reference Case, because the stimulus to build nuclear and renewables drives their costs down over time.

Coal Market Impacts

Because coal has the highest carbon content of any of the key fossil fuels, the cost of using coal when a GHG cap–and-trade program is imposed increases dramatically (Figures 19 and 20).  For example, in 2020 the cost of using coal in a plant that does not have CCS equipment is between 161 percent and 413 greater than in the Reference Case.  By 2030 the increase in coal costs to a plant without CCS equipment is even larger, ranging from 305 percent to 804 percent greater than in the Reference Case.  The vast majority of this cost increase is due to the need to hold allowances to cover the CO2 emissions that will be generated when the coal is used to produce electricity.  The underlying delivered price of coal without the allowance costs is actually lower in the S. 2191 cases because of the reduced consumption of coal.

Coal production volumes (in tons) are projected to be 64 to 89 percent lower in the alternative cases in 2030 compared to the Reference Case.  The production levels in 2030 across the cases are consistent with the low national coal production levels last seen in the first quarter of the 20th century.  For example, in the S. 2191 Core Case, the total coal production of 414 million tons is just 28 percent of coal production projected in the Reference Case in 2030 and 36 percent of 2006 coal production. The largest decline in coal production in 2020 and 2030 occurs in the S. 2191 Limited Alternatives/No International Case which has the highest allowance costs.

Lower coal consumption in the S. 2191 cases disproportionately affects western coal producers, because they are expected to meet most of the growth in coal demand in the Reference Case.  In the Reference Case, 567 million tons of western coal is projected from the highly productive large surface mines of Wyoming’s Powder River basin in 2030.  In the S. 2191 cases, this same region is projected to supply between 8 and 77 million tons of coal in 2030.

Notes