In the absence of federal leadership, Northeastern and Western states have implemented regional cap and trade systems, and now a consortium of Midwestern states has signed an agreement to develop a cap and trade program. Minnesota is part of that agreement. As debate over capping and trading greenhouse gas continues, there will be concerns about the economic impact in Minnesota. This report assumes any Midwestern cap and trade system would be similar in scope to the Northeast Regional Greenhouse Gas Initiative and would be limited to greenhouse gas emissions from power plants.
A major controversy is over the impact on the price of electricity and the resulting economic implications. The main factors that determine the impact of a cap and trade system on the price of electricity are:
* Carbon prices in the allowance market
* Carbon intensity of power plants
* Passing through of carbon costs.
The Price of Carbon Permits
Supply and demand factors determine carbon prices. The cap and trade design determines the number of carbon permits by setting the cap on carbon emissions and the possibilities for borrowing and banking of permits. Carbon permit demand depends on projected emissions. The projected emissions from power plants are determined principally by economic growth, weather, abatement options, and energy prices.
The Carbon Intensity of Power Production in Minnesota
Figure 1 presents power generation sources in Minnesota. It shows the share of coal and nuclear in power production amounted to 63 and 24 percent respectively, while natural gas accounted for 5 percent. Minnesota’s generation mix varies significantly from the national average. Nationwide, power share generated from coal and natural gas is 50 and 19 percent respectively.
The average carbon intensity of total power production in Minnesota in 2005 was 1558 lbs/MWh. This compares to a national average of 1320 lbs/MWh. The average carbon intensity of natural gas-fired power generation is 1135 lbs/MWh, while coal-fired power generation produces twice as much carbon dioxide. But the carbon intensity of Minnesota’s generation mix should look different in the future since enactment of the Renewable Energy Standard requires 25% of the electricity produced by Minnesota’s utilities to be generated by renewable energies by 2025. If the standard is achieved entirely through wind power, it is expected that the State would need between 5,500 and 6,300 MW in new wind power projects. Progress towards this goal is being made with Xcel Energy recently announcing a partnership with enXco to construct 351 MW of wind power.
Assuming marginal supplier costs determine electricity prices, it is important to identify the technology those suppliers use during base load and peak periods. In Minnesota, current opposition to base load power and coal-fired plants as a solution to base load power needs means natural gas plants will be relied on to meet power needs during these periods. Minnesota utilities will rely heavily on natural gas if the proposed Mesaba IGCC and Big Stone II projects fail. Figure 2 shows Minnesota’s dramatic shift in construction of new plant capacity to natural gas and wind for generation of electricity. Natural Gas, in particular is attractive because of its cleaner operation, low capital costs and shorter construction lead times.
A joint IEA/NEA study (2005) determined that, in the absence of a cap and trade program, nuclear is generally the cheapest power production technology, followed by coal and natural gas. So, the merit order in Minnesota during base load and peak periods is nuclear, coal, and lastly natural gas. A cap and trade program in Minnesota would at some point change the merit order to make coal more expensive than natural gas (production has half the carbon intensity of coal-fired production). Therefore, a cap and trade program, in the short-run, would encourage shifting power generation from existing coal-fired plants to existing gas-fired plants. The switching point would be where the marginal costs of coal-fired generation exceed the marginal costs of gas-fire generation. In the long-run, a cap and trade program would encourage existing coal-fired plants to shut down and new gas-fired plants to go online. However, the switching point would be very plant-specific because each existing coal plant would have different opportunities to reduce carbon intensities.
Some are concerned with a cap and trade program’s impact on the relative price of coal to natural gas. Increasing power production from natural gas may result in higher natural gas prices. The upward pressure on the price of natural gas has the potential to result in higher home heating costs for Minnesota families. Reliance on natural gas would also potentially inject more volatility into the electricity market. These effects are observed in the European electricity market which rely heavily on gas-fired plants for electricity. Figure 3 shows the strong impact of natural gas price prices on electricity prices in Europe and extreme volatility in the European electricity market.
Carbon Costs Pass Through
The degree to which carbon permit prices are passed through to electricity prices is contingent on changes to power production technologies’ merit order. As previously mentioned, electricity costs depend on a marginal supplier’s marginal costs. Where there is no change in the merit order, price changes will equal carbon permit costs of the marginal supplier. Where there is a change in merit order, the electricity price change will always be less than the new marginal supplier’s carbon permit costs. This would be the scenario in Minnesota where, under a cap and trade program, coal-fired plants would be the marginal supplier for base load and peak periods. The resulting implication is that studies (like the Heritage Foundation’s The Economic Costs of the Lieberman-Warner Climate Change Legislation), which treat carbon permit costs as a tax and assume that power prices would increase by the amount of the tax, overestimate the pass through of carbon costs and the negative impact on the economy because they do not account for the likelihood of a switch in the merit order.
The passing through of carbon costs to the price of electricity is also affected by carbon-saving technological innovations. For instance, carbon capture and sequestration technology (not yet economically viable) or efficiency-enhancing investments in existing coal-fired plants would lower carbon cost pass through. Critics of cap and trade programs point to speculative nature of these technologies.
The extent to which carbon prices are passed on also depends on the regulation of the electricity market. Minnesota’s utilities do not receive the market price of electricity regardless of their actual costs, and would not be able to engage in opportunity cost pricing. Therefore, the opportunity costs of using carbon permits to generate electricity instead of selling the permits in a climate exchange market would not pass through to electricity prices.
In a perfectly competitive market, power producers would pass through carbon costs (including opportunity costs) to the electricity price. However, the market for electricity is complex and there are a number of reasons why producers cannot simply set power prices. The incomplete pass through of carbon costs implies that cap and trade programs would not increase electricity prices in Minnesota to levels predicted by many studies not accounting for incomplete pass through. Therefore, secondary effects on the Minnesotan economy from higher energy prices would not be as dire. More worrisome is the potential heavy reliance on natural gas for generation of electricity in Minnesota under a cap and trade program. But this would be mitigated by bolstering renewable energies in Minnesota.