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GHG Compliance Complexities

Greenhouse-gas regulation will impose vastly greater compliance difficulties than did the Acid Rain program.

Fortnightly Magazine - February 2008

difficult. Planners making 40- to 50-year investment decisions face uncertainty in many areas, including: future regulations; emission targets; costs of offsets and allowances; and availability and costs of new, unproven technologies both for generating power and for capturing and sequestering GHG emissions that will comply with regulations.

Credit and Trading Regimes

Trading in GHG credits presents another new challenge for utilities that differs from the annual Acid Rain auctions. The regulations that will determine trading markets are yet to be written, but the complexities are obvious.

First, credits will be available from worldwide sources for six chemical types, not just one, since greenhouse gases are defined more broadly. Then, emission reduction credits must be computed from protocols and certified by some acceptable international body rather than measured with instruments. As a result, the validity of the credits poses inherently greater uncertainty. There are issues about which protocols are acceptable and which bodies can certify credits. Then the credits must be audited periodically to assure legitimacy. Standards for GHG credits still are emerging with experience, as the Kyoto Protocol has demonstrated over the last several inaugural years.

The design of the GHG market, especially how allowances for emissions will be allocated, will have far greater economic consequences for utilities than did the Acid Rain program. Some of the new technologies for capturing and sequestering carbon require the equivalent of 30 percent of power output—a huge cost compared with scrubbers.

The key issue keeping utility executives awake at night—and keeping the industry somewhat divided—is the question of how emissions allowances under a cap-and-trade regime will be allocated. Unlike the legislation leading to Acid Rain regulations, the Lieberman-Warner Act does not propose to allocate allowances freely to generators of emissions. Instead, it proposes a limit on allowances, with an auction of the remainder.

Some companies, including FP&L, favor this approach and argue against so-called “free” allowances. Free allowances, they suggest, would reduce program revenues from auctions that could be used to subsidize technologies and reduce costs to consumers from investments in new, carbon-free sources.

On the other hand, an allocation formula like the one in the Lieberman-Warner bill would disproportionately penalize states in the Midwest that have high coal use, compared to states with less coal dependence coal (see Figure 1) . “Economists don’t get to the impact on coal fired plants,” says Bruce Braine, senior v.p. for analysis at American Electric Power (AEP).

As early as 2012, anticipated carbon prices of $15 per ton could lead to rate increases of 7 to 18 percent in some states with high dependence on coal. For example, in these states, Duke Energy forecasts it would have to buy allowances for between 44 and 57 percent of its total emissions from Day 1 in 2012. Such costs will be passed on to ratepayers, who later will face a second bill for the costs to deploy new technologies. Duke estimates that auctioning 100 percent of allowances would increase customers’ power bills by $1 billion annually for every $10/ton increase in allowance prices. According to Tom Williams, director of public