It is becoming increasingly likely U.S. lawmakers will adopt some type of climate-change policy in the near future. Whatever the details, it almost certainly will include the power-generation sector, which represents fully one-third of U.S. greenhouse gas (GHG) emissions. Such a policy—imposed as a carbon tax or as a cap-and-trade regime—is bound to have a profound effect on power generation, on the power companies that supply electricity into the U.S. market, and on electric customers throughout the land. Carbon dioxide (CO2) price of any magnitude will lead to higher electricity prices for consumers, but also will provide suppliers with incentives over time to invest in lower-emitting and non-emitting generation, such as nuclear power, coal with capture and sequestration, and renewable technologies.
In anticipation of such changes on the horizon, EPRI organized and conducted a broad-based study of climate change policy effects on electricity generators and consumers in the Western Electricity Coordinating Council (WECC) region. A diverse collection of nine Western generation companies funded and participated in this effort, and added immeasurably to the quality of results and insights.
The results reflect the underlying structure of the WECC market, and the key uncertainties that characterize it, through an examination of alternative future scenarios. A reference case, reflecting an optimistic future, is described for baseline purposes. Also a case called “wild card,” reflecting a more pessimistic view of future events, is presented as an alternative characterization.
The behavior of the power system and electric customers was investigated over a future period 2006 through 2030, for a range of CO2 prices imposed beginning in 2012 (see Table 1). This analysis assumes that the price will remain constant (in real 2006 dollars) from 2012 through 2030.
Key conditioning assumptions of the reference case include:
• Future load growth in this market was assumed equal to the recent historical period 1995-2005, at 1.73 percent a year.
• Natural gas prices (in real 2006 dollars) were set to a recent (May 6, 2008) NYMEX Futures market curve through the year 2020, then held constant at 2020 levels.
• Capital costs for new generating plant were driven initially by EPRI estimates from 2007, but as the study progressed these estimates further were inflated 25 percent, in recognition of continued escalation in all global construction markets.
• Western state renewable portfolio standards (RPS) targets were assumed to be met in future years, per individual state law.
The data show an increasing CO2 price will drive up the power price and drive down emissions. The power price in the initial year (2012) increases almost linearly with the CO2 price, because the power system has very limited response capability in the very short term. Western markets can switch some resource usage from coal to natural gas, but it’s quite expensive due to the comparatively high price of natural gas, so the primary effect is to increase customer prices.
This is less true over time. In later years the response is both more pronounced for emissions and more limited for power prices, as the generating stock begins to turn over and new investments are made in non-emitting generation. Emissions reductions by 2030 accelerate significantly in the $50-$60 CO2 price range, when nuclear generation starts to penetrate the market (see Figure 1). Only when wholesale power prices reach the $100 range can nuclear technology expect to cover its investment and carrying costs (see Figure 2). The response of power price to CO2 price also is more moderated in later years, as low-busbar cost, non-emitting technologies enter the generation mix and temper power prices.
In general, the level of CO2 price needed to flatten emissions growth in the reference case future is in the $50 range (see Figure 3).
The EPRI study also investigated an alternative, more pessimistic case. The wild-card case represents an alternative future, one in which both events and policy responses to them work against future greenhouse gas control. The wild- card future requires a higher CO2 price than the reference case to stabilize emissions over time (closer to the $70-$80 range). Due to higher capital costs overall, as well as a nuclear penetration constraints, capital stock turnover is much more sluggish in the pre-2030 time frame, and emissions still are growing at the $50 CO2 price level.
Existing generation—coal and natural gas—necessarily is used more heavily and emissions stubbornly resist reduction. Even at a $100 CO2 price, emissions reductions in the wild-card case remain minimal. In fact, it takes a CO2 price in the range of $125-$150 to effect significant reductions under a wild-card future. Power prices are impacted as well. The wild-card future leads to a persistent $20 premium in wholesale power prices, regardless of the size of the CO2 price assumed.
On the other hand, the prospect of new technologies on the horizon can have a significant impact. While still in the laboratory today, coal with carbon capture and sequestration (CCS) has great potential, over the next 10 to 15 years, to realize its promise and to impact power markets significantly, even more so if other trends (i.e., the wild-card case) begin to unfold unfavorably.
EPRI’s analysis of Western power markets postulates several alternative futures, and examines the implications of each on suppliers and consumers. This analysis is aggregate, high-level and suggestive, and certainly glosses over many details and intricacies in an attempt to focus squarely on the larger picture. Discrepancies in detail notwithstanding, several inescapable conclusions can be drawn from this analysis.
First, given high enough CO2 price signals and sufficient time, climate- change policy could wring emissions growth out of the power sector in Western states. In the reference-case future, a price of about $50 a ton will flatten emissions growth, and a price of about $80 a ton substantially will reduce it. In the wild-card future, it will require about an $80 price to flatten growth, and a price in excess of $125 to make substantial reductions.
CO2 prices in these ranges will lead to retail power prices 40 to 80 percent (depending on CO2 price levels) higher than they are in the WECC today in the immediate aftermath of price imposition. Such levels will have significant impacts on the electricity sector and on electricity customers.
Over the study’s 18-year horizon, these higher prices also will create investment incentives for non-emitting generation, enabling such generation capacity to come online if the market functions reasonably well. This capacity will temper power-price differentials over time. In this analysis, for a CO2 price of $100 a ton, retail prices in 2030 are projected to be between 15 and 30 percent higher than the $0 a ton case, a far cry from differentials in 2012.
Additionally, customer response to price increases, including lower utilization of existing electrical devices and investment in more efficient technologies, will hold down power-price escalations. Without this effect, prices might be expected to rise even higher. However, customer response is not free and represents a real cost to consumers and loss in consumer welfare, albeit not measured explicitly in this analysis.
Finally, natural gas price and availability represent critical linchpins in this system in early years, as short-term reductions in emissions will depend on the ability of natural gas generation to fill the gaps left by coal cutbacks. This criticality will fade over time, as more non-emitting technologies—including CCS, renewable energy, and nuclear—increasingly enter the market and fill the void.