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Task
Force Findings
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There
is no compelling reason at this time for Kentucky to move
quickly to restructure. Despite the prospects of Congressional
legislation to mandate restructuring, actions taken by 23 states
to restructure, and the fact that some of those states are
geographically contiguous to Kentucky, there are obvious
advantages for Kentucky adopting a wait-and-see approach to
electricity restructuring. Congressional action to pass a
nationwide restructuring bill appears unlikely at this time.
Representatives from other states that have restructured as well
as experts in the field of electricity restructuring indicate
that Kentucky is in a unique position because of its existing
low electricity rates, which currently are the lowest east of
the Rocky Mountains. A wait-and-see approach allows Kentucky to
monitor the progress of restructuring in other states and to
develop options that protect Kentucky's existing low rates for
electricity.
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Restructuring
is expected to have multiple effects on Kentucky's electricity
prices.
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Restructuring would be expected to cause greater variability
in electricity rates over time. If Kentucky's electricity rates
are deregulated, price fluctuations would be expected to be
larger in magnitude than fluctuations under cost-of-service
regulation. Analysis conducted by RDI indicates that prices will
increase as the amount of
excess capacity in the generation market decreases. Electricity
rates also were found to fluctuate in response to changes in
fuel prices, particularly the cost of natural gas. Finally, RDI
analysis shows that deregulated electricity prices can
dramatically increase during "severe"
electric conditions characterized by unplanned transmission and
generation outages. During these "severe" conditions,
the potential exists for utilities to raise prices above the
competitive market price.
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Price gains from restructuring are predicated heavily upon
excess generation capacity in the electricity market. In the
short run, RDI analysis shows that as excess generation capacity
is reduced, the deregulated price of electricity rises, and the
regulated price of electricity remains relatively unchanged. The
only scenario which shows sustained price reductions over the
long run, even as capacity declines, is when improvements are
made in the transmission and generation infrastructure and a
reduction occurs in the utility's production cost.
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Increases in fuel prices are expected to make electricity
more costly than current, regulated prices. Conversely, a
reduction in fuel prices alone is expected to make electricity
prices fall in the short run. RDI's analysis shows that
when gas prices are increased by 20 percent,
and the market demands greater capacity reserves, the
deregulated price for electricity is consistently higher than
the regulated rate. When gas prices are reduced by 10 percent,
the electricity price is lowered only during the first three
years. After the third year, the deregulated price increases to
a point where both the regulated and
deregulated price converge.
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Deregulated generation rates would be expected to vary across
the state in accordance with the existing utility's current cost
of producing power. Currently, the cost of generating and
delivering electricity varies on a utility-by-utility basis. RDI
contends that some higher-cost utilities will have to reduce
their prices in order to be competitive in a deregulated market.
Conversely, customers of utilities whose current cost of
production is below the expected deregulated price of
electricity may face price increases.
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Restructuring is not expected to have a negative impact on
electricity rates in rural areas. There are three components to
the electricity bill: generation, transmission, and
distribution. According to RDI analysis, rural areas have
traditionally had higher average electricity rates compared to
customers in urban areas. The disparity in rural/urban
electricity rates is primarily due to relative differences in
distribution costs. However, RDI analysis shows that the costs
of generation would not vary in accordance with the population
density of the market. The cost of acquiring a customer in a
rural area
is the same as that of acquiring a customer in an urban
area. Therefore, rural customers are expected to have
higher distribution costs than urban customers in a restructured
market, but rural customers are expected to receive the same
generation price as urban customers in
a restructured market.
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Kentucky does not face sizable positive stranded costs in
comparison with higher-cost states; however, Kentucky does have
considerable variations in both positive and negative stranded
costs on a utility-by-utility basis.
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Positive stranded costs are comprised of purchase power
contracts and are concentrated in three utilities: Cinergy's
Union Light Heat & Power, Big Rivers, and distribution
utilities served by TVA. Their positive stranded costs
collectively could range from $295 million to over $1 billion1.
The remaining utilities are in a "negative stranded
cost" position, which means that the market value of their
generating assets and purchase power contracts is higher than
the book value for
these assets in a regulated market. Potential negative stranded
costs in Kentucky range from nearly $700 million to $3.7
billion2.
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The negative stranded cost position borne by most of the
utilities in Kentucky is the result of three principal factors:
lower-cost coal resources for generating stations, the lack of
nuclear power in Kentucky, and the use of "construction
work in progress" to finance the construction of generating stations. Construction work in
progress allows the utility to change current customers for the
cost of building a power plant before the plant goes on-line.
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The imposition of a stranded cost recovery mechanism would
probably not uniformly impact all customers in Kentucky. The
reason for this is two-fold: First, some Kentucky customers
currently served by utilities that purchase power from TVA could
not be subjected to a stranded cost recovery charge imposed by
either the legislature or the PSC. TVA customers in Kentucky,
which are served by utilities that have positive stranded costs,
are subject to the exclusive jurisdiction of the TVA.
Second, positive and negative stranded costs vary based on each
utility's cost of supplying power. Therefore, the potential
exists for electricity prices to rise at lower-cost utilities
and fall at higher-cost utilities. If the stranded cost recovery
mechanism is applied only to those customers who exit the
system, existing customers of higher-cost utilities may bear a
disproportionate burden for stranded costs.
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Restructuring is not expected to negatively impact the coal
industry in Kentucky. Approximately 77 percent of Kentucky's
coal is sold out of state and would not be affected by a
decision to restructure Kentucky's
electric utility industry. The remaining 20 percent of
Kentucky's coal market could be affected by a decision to
restructure Kentucky's electric utility industry. But, given the
relatively low cost of producing power at Kentucky's coal-fired
generators, restructuring is not expected to reduce in-state
sales of Kentucky coal. Power plants in
Kentucky that use Kentucky coal are well-positioned in a
restructured market. Not only are Kentucky coal plants not
expected to face retirement, but these plants may increase their
coal utilization rates. Current declines in the production
of both western and eastern Kentucky
coal are primarily related to other factors affecting the coal
industry such as stricter air emissions controls promulgated by
the U.S. Environmental Protection Agency (EPA), decreasing
transportation costs
for coal, and price differentials between Kentucky and coal from
the western U.S., such as that of Powder River Basin
(Wyoming). Restructuring is not expected to affect any of
these other factors.
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Restructuring is not expected to reduce the importance of
natural gas in new generating capacity in Kentucky. Within the
past ten years, all new capacity in Kentucky has been gas-fired.
The last coal-fired generation unit, LG&E's Trimble County
plant, came on-line during the
early 1900s. As the cost advantage for gas-fired generation
continues to increase, and demand for electricity continues to
grow during summer peaking months, the expectation is that new
capacity will be gas-fired combustion turbines. These gas units
would be used exclusively for peaking purposes.
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Restructuring is not expected to lead to dramatic outflows of
Kentucky electricity to higher-cost states. Approximately 7.5
percent of Kentucky's total generation has been exported since
1995. However, RDI analysis shows that exports of electricity
are expected to increase
to 9 percent in the short-term if the Midwest Independent System
Operator (ISO) becomes functional. This is because formation of
the ISO is expected to lead to a single "postage
stamp" type rate that will eliminate "pancaking"
(the multiple rates charged by each transmission owner when
transporting power for another supplier). RDI estimates that as
demand for power grows within Kentucky, exports will decline to
5-7 percent of total generation over the long-term.
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Absent new market rules for conduct and cost allocation
between regulated utilities and unregulated affiliates, the
potential exists for an uneven playing field to develop between
unregulated affiliates and existing firms in competitive,
unregulated product and service markets. Regulated
electric utilities are reorganizing and expanding their
unregulated holdings at a very rapid rate. Unregulated holdings
are being concentrated in energy-related businesses such as
electricity commodity sales, metering and billing, energy
conservation, electrical
contracting, heating, ventilation and cooling (HVAC), related
fuels, and appliance repair. On a nationwide basis, unregulated
businesses of regulated utilities are putting competitive
pressure on existing firms. According to RDI, there is an
inherent conflict in a utility's organization between the need
for stricter, sometimes-burdensome
compliance mechanisms and the drive to succeed in newly
competitive electricity markets. To prevent cross-subsidy of
competitive businesses by the regulated utility and to protect
customers from potential abuses of market power, some states
have put restrictions on an affiliate's use
of name and logo, prescribed cost allocation guidelines,
established a code of conduct, and required periodic compliance
audits. The Kentucky Public Service Commission is addressing
these and other related issues
in Administrative Case No. 369.
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Under severe market conditions, larger utilities in Kentucky
such as AEP and TVA may have significant market share and
control over transmission assets to withhold generation supplies
and significantly
distort electricity prices. Smaller utilities do not have the
market share or control over transmission assets to withhold
generation supplies and significantly distort electricity
prices.
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When a utility exerts market power, it is able to
significantly increase profitability by 5 percent or more over a
wide range of demand conditions. Because the East Central Area
Reliability (ECAR) is comprised of a highly interconnected
transmission system that poses fewnbarriers to entry by new market entrants in generation, very few
companies in Kentucky have the ability to sustain profits above
those seen in a perfectly competitive market.
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With the exception of TVA and AEP under certain limited
circumstances, no utility in Kentucky currently has the
potential to exert market power. However, AEP may have
sufficient market presence to exercise market power during peak
demand conditions. According to RDI, merger and acquisition
activities are likely to continue in the future, and
consolidation of existing utilities in the region does pose the
threat of creating future market power situations.
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Utilities in Kentucky may be able to exert market power in
areas known as "load pockets." Load pockets constitute
smaller geographic areas that are not as well interconnected to
the transmission grid and sometimes arise out of unplanned
transmission outages or constraints. Because competitive
suppliers are unable to reach customers in the load pocket, and
because there is no regulation over the generation supplier in a
deregulated market, the potential exists for utilities to charge
above the competitive price of electricity in that market.
Task Force Recommendations
- The Task Force recommends that no action be taken during the
2000 session of the General Assembly to restructure Kentucky's
electric utility industry.
- The Task Force recommends that the General Assembly continue
to study the issue of retail competition. The Task Force also
recommends that the General Assembly monitor actions taken in
other states that have
opened their retail market to competition and to address other
issues, such as reliability of service, transmission, and
consumer education. Action should be taken during the 2000
session of the General Assembly to reauthorize the Special Task
Force on Electricity Restructuring.
Footnotes:
1The range for positive stranded cost values are predicated on
results obtained using RDI scenario analysis. For more
information, please consult RDI interim report no.2.
2The range for negative stranded cost values are predicated on
results obtained using RDI scenario analysis. For more
information, please consult RDI interim report no. 2.
Click
here to read more (including committee minutes) about the
Special Task Force on Electric Restructuring at the Kentucky
Legislative Research Commission's web site.
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