POWER October 2012 - 61

THE FUTURE OF COAL
to close a generating unit often involves state
regulators forming a triangle with the power
generator and the EPA and state agencies in the
other two corners. After all, in regulated power
markets, electric power generators are granted
certificates of " convenience and necessity "
similar to the one Wyoming regulators granted
to Black Hills Power to build its Cheyenne Prairie
Generating Station project. This changes the
dynamic from a two-way relationship between
the utility and the EPA to a more complex threeway
relationship that in instances of regulated
markets includes state regulators.
In some circumstances, Tierney said, state
regulators will apply a strict least-cost planning
approach when deciding among options
for generating units, which may include installing
scrubbers, pursuing demand-side
management strategies, or relying on marketbased
power purchases. She said that parts of
the country that follow traditional regulatory
approaches (such as the Southeast and the
Rocky Mountain states) " play a huge role "
in determining the types of investments their
regulated utilities may pursue. By contrast,
many states that are in the PJM pool, or in the
Midwest (including Texas), operate competitive
power markets, where power plant owners
bear the responsibility of making business
decisions on how best to comply with EPA
regulations. " It's much more a competitive
market issue in those states, " she said.
Ron Binz, a former Colorado public utility
commission chair and Denver-based public
policy consultant, said the EPA's current slate
of rules represents the " last nail in the coffin "
for many older coal-fired power plants. Key
factors to consider in predicting which units
are most likely to be retired include their inservice
date, heat rate and unit efficiency.
Binz largely agreed with Tierney's asser3266
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tion that the role of state regulators in deciding
whether or not a unit may close can vary
widely and depends on factors that include
market openness, the level of the regulator's
authority, and the willingness of the regulatory
agency to exercise its authority. In Kentucky,
for example, regulators lack authority
to approve a utility's integrated resource
plan (IRP), the documents that are filed every
few years and that lay out the utility's
plan for its generating mix. Binz said Kentucky's
utilities are on their own to pursue
their IRP, and the commission's authority
is limited to reviewing whether the utility
complied with its own plan. Other states,
like Colorado, have broader authority to approve,
disapprove, or modify a utility's IRP.
As an example, Binz cited Colorado's action
in 2010 to decide the fate of 2,000 MW
of coal capacity based on projected EPA
regulations. Those statutory limits and regulatory
mindset figure in the latest round of
generating capacity review triggered by the
EPA's 2011 Cross State Air Pollution Rule
(CSAPR) as well as MATS.
Characterizing Generating Units
Given that regulatory and business calculus,
it's possible to broadly characterize power
plants that may be most vulnerable to shutdown
decisions. This may be done via a
relatively simple analysis to consider several
critical factors. Before turning to that analysis,
however, it may be useful to review the
basics of CSAPR.
CSAPR (which was overturned in August
by a federal appeals court) addresses emissions
of SO2
and NOx
from fossil fuel power
plants in the eastern U.S. that contribute to
downwind formation of fine particulate matter
and ground-level ozone. The rule comes under
Clean Air Act Section 110(a)(2)(D), which
prohibits air pollutants from being emitted in
an upwind state that " contribute significantly "
to poor air quality in a downwind state.
The EPA announced the final CSAPR on
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POWER October 2012

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