Fair Transmission & Distribution Rules
From Powerful Solutions: Seven Ways
to Switch America to Renewable Electricity, UCS,
Some have argued that a revolution in the way we make
and move electricity is developing. New generation
technologies-like fuel cells, photovoltaics, wind
turbines and natural gas microturbines-are available
in small modular units that can be sited in, on, and
around buildings where power is used. Many "distributed"
technologies also create waste heat that can be easily
used on the spot for water and space heating, boosting
their efficiency. These distributed technologies already
offer an economical alternative to building large
central station power plants and new power grids in
remote areas that do not have transmission and distribution
(T&D) systems. As the prices of the new technologies
fall, they may completely reshape existing power networks
as well. As discussed in Chapter 1, distributed generation
technologies can provide substantial non-traditional
benefits to utilities and their customers.
of the added value that distributed technologies can
provide can be critical for new technologies entering
the market. UCS's 1995 Renewing Our Neighborhoods
study looked at the Boston Edison service territory
and compared the cost of upgrading the aging transmission
and distribution system in certain neighborhoods with
the cost of installing renewable technologies. Even
though renewables tend to be higher priced than central
station power, UCS found that some renewable technologies
may already be cost-effective in areas where particularly
expensive transmission and distribution investments
can be avoided. Studies in
other parts of the country have found similar results.In
a study of potential early markets for solar photovoltaics,
the Utility Photovoltaic Group found that the potential
US market for photovoltaics at a cost of $3 per watt
is as high as 7,630 MW for distributed power applications,
compared with 1,130 MW for the potential "green market"
at this price. 
Of course, photovoltaics
is not likely to capture most or all of the potential
distributed market. It must compete with other distributed
technologies which can provide "distribution services."
These include distributed electricity storage, such
as batteries, and demand-side management technologies,
such as energy efficiency investments, which can reduce
demand in targeted regions or neighborhoods, extending
the usefulness of existing distribution equipment.
many renewable energy technologies operate intermittently
when the sun is shining or the wind blowing, there
are added difficulties in valuing their output fairly.
Traditionally, the reliability value of an electricity
generator is based on the maximum output that can
be turned on, or "dispatched," by the system operator,
especially during periods of peak electricity demand.
Because individual renewable generators may not be
dispatched at will, and cannot be guaranteed to be
available during peak times, they have frequently
been assumed to have zero reliability value.
often, however, a relatively consistent relationship
between the output of an intermittent renewable and
the level of electricity demand over time. Solar output,
for example, tends to be high on mid-afternoon on
hot sunny days, which is often when air conditioning
use is also high. Utilities have long used statistical
methods to allocate costs to classes of customers
based on a tendency to use electricity more during
high-cost vs. low-cost periods. Similar methods can
be used to allocate benefits to intermittent generators
based on a tendency to produce electricity during
high-value or low-value periods.
have closely examined the reliability value of intermittent
renewables for their systems. Fewer still have looked
at the potential value of renewables in reducing peak
demand on their distribution systems. Because the
mix of customers and the times they use electricity
may vary greatly from one neighborhood to another,
the value of intermittent technologies in deferring
or avoiding transmission or distribution expenditures
may vary greatly from location to location.
order to realize distributed technology benefits,
however, electricity distribution companies must value
distributed technologies fairly and be willing to
invest in them or encourage their customers to invest
in them when they can reduce system costs. Traditional
cost-plus regulation has not necessarily encouraged
least-cost distribution planning. Also, because methods
to value distributed generation in planning distribution
systems are new, few utilities have yet adopted them.
Utilities are beginning to show greater interest in
distributed resources, however. 
A restructured industry presents new opportunities
and barriers for distributed generation.
A more competitive industry is likely lead to specific
identification of cost centers and profit opportunities.
Location-based transmission or distribution rates,
which would be higher where there is congestion, could
lead to generation being sited in areas where it has
greater value. Independent companies that could profit
from providing distributed generation services would
have a strong incentive to seek out potential opportunities.
On the other
hand, the separation of vertically-integrated utilities
into separate functional units or separate companies
providing generation, transmission, distribution,
and retail marketing services may make it harder to
identify the integrated value a distributed technology
provides in each of these areas. It is uncertain which
market players will have the resources and incentives
to make the investments to avoid a combination of
generation, transmission, and distribution costs faced
by other market players. A transition to location-based
distribution pricing, where separate distribution
prices would be charged to different neighborhoods
based on local costs, would raise significant equity
issues. Residents in a neighborhood with aging distribution
facilities (who shared the cost, under regulation,
of upgrading distribution facilities in other neighborhoods)
may well resent seeing distribution price increases
designed to induce local distributed generation.
as some utilities have avoided investing in new power
plants that risked making existing power plants economically
obsolete, some companies may resist distributed technologies
that could compete with their existing transmission
and distribution investments. In many cases, therefore,
legislators or regulators may need to establish appropriate
rules and incentives.
that have shown some interest in these issues have
been preoccupied with overall industry restructuring.
There is therefore little experience to draw on at
and Massachusetts have addressed distributed technology
issues in their restructuring processes. Connecticut's
restructuring law requires "demand-side management"
expenditures to be considered as alternatives to distribution
expenditures. Demand-side management generally refers
to technologies to reduce electricity demand, like
energy efficiency investments, or to methods that
shift demand from one period to another. Distributed
generation technologies installed in customer buildings
also reduce the system demand for electricity, however,
and could be included in regulations developed to
implement the Connecticut law.
the Department of Telecommunications and Energy has
stated that distributed generation will be considered
as part of performance-based ratemaking proceedings.
This policy, as an alternative to cost-of-service
regulation, seeks to induce utilities to reduce costs
and improve performance by linking incentives to specific
ratemaking in Massachusetts and elsewhere has generally
been implemented with a price cap. Under a price cap
per kilowatt hour, distribution companies have an
incentive to sell more kilowatt hours to increase
total revenues. Price caps provide disincentives to
reduce sales through distributed generation or energy
efficiency investments. In contrast, under a revenue
cap, total company revenues are fixed, and a company
does not lose revenues from distributed technology
investments. Prices are adjusted periodically to make
up for any unanticipated revenue shortfalls or surpluses.
Therefore, a company does not lose revenues or profits
if it encourages reduced electricity demand through
energy efficiency or distributed generation. Oregon
has adopted a revenue cap. >
environmental organizations and renewables companies
have petitioned the Public Utilities Commission to
establish distributed generation regulations. As of
November 1998, however, no formal action on the petition
had been taken.
One way of ensuring appropriate investment in distributed
technologies would be to require regulatory review
of transmission and distribution planning decisions.
Such planning reviews would be analogous to "Integrated
Resource Planning" (IRP) for generation, extended
to the distribution planning level. Investments in
the distribution system would be reviewed to ensure
they have invested in the mix of demand-side and supply
side options that provide electricity at the lowest
cost.) While there has been a trend to reduce IRP
regulatory review in favor of increasing competition
in generation, it may be appropriate to retain it
for regulated transmission and distribution companies.
Distribution IRP would be somewhat more complex than
generation IRP. Generally, however, companies will
be planning major transmission or distribution investments
in only a few areas at any given time, thus limiting
the complexity of the review. One potential model
for distribution-level IRP has been developed for
the Boston Edison Demand-Side Management Settlement
One way to insert distributed generation into the
planning process would be to require distribution
companies to competitive bids for distribution services
where new investment is required. Distributed technology
providers could then compete against traditional equipment
upgrades. Another approach would be for the system
owner to offer incentives for distributed generation
in specific parts of the system that are weak or overtaxed.
important issue likely to affect utility activities
in distributed technology is whether they can own
distributed generation. 
ownership of these technologies raises antitrust and
anticompetitive concerns. There has been some concern
that allowing utility ownership could undermine the
development of distributed generation by seeking to
be monopoly providers of distributed generation technologies.
On the other hand, allowing ownership of distributed
generation provides them with an incentive to become
active in this area. Massachusetts has explicitly
allowed distribution companies to own distributed
energy generators' unique characteristics pose challenges
to designing fair transmission rules and prices. Renewables
generators must be located where the natural resources
are, and sometimes must be transmitted long distances.
The intermittent output and low capacity factor of
some renewables creates operational issues for the
transmission grid (i.e., having backup capacity if
the wind suddenly stops blowing) and pricing issues
similar to those covered above with distributed generation.
In 1996, the Federal Energy Regulatory Commission
(FERC) Order 888 required utilities to make transmission
available to all generators and customers. 
FERC has also encouraged the formation of Independent
System Operators (ISOs), groups of multiple stakeholders
to control the operation of the transmission network.
These developments should increase renewables generators'
access to customers. It should also reduce multiple
transmission charges, known as "pancaking," when power
is transmitted across more than one utility system
and each utility exacts a toll.
service is typically specified as firm or nonfirm,
with nonfirm service more interruptible in cases of
transmission constraints. FERC did not specify how
transmission prices should be set, but proposed that
all firm transmission service be based on reservations
of transmission capacity made at least one day in
advance. Generators would pay for reserved transmission
whether or not they used it. They would be subject
to penalties if they exceeded or fell short of their
reservation by more than 1.5 percent. >
This requirement would heavily penalize intermittent
generators like wind and solar, where it is hard to
predict output accurately a day in advance. If it
turns out to be windier than predicted, and not enough
transmission capacity is reserved, the wind generator
could be unable to sell all the electricity generated.
If it were less windy than expected, the generator
would be stuck paying for unused transmission. Ideally,
generators would be able to resell reserved transmission
capacity that they could not use, but this secondary
market has not really developed. Renewables generators
would have to resell transmission capacity at the
last minute, making it unlikely they would get a good
price, and transaction costs would be high. Renewables
generators could, however, bundle their output together
with power sources that can be turned on and off as
needed, such as gas turbines. But requiring such bundling
would reduce generator and marketer flexibility and
might raise total costs. 
could also buy non-firm transmission service without
a reservation. However, buyers of non-firm service
can have their transmission interrupted if the lines
get congested. And lenders may charge higher financing
costs if renewables generators do not have firm transmission
of ISOs, with multiple stakeholders, has created pressure
for more flexibility and options in transmission service,
which may benefit renewables. ISOs that include power
exchanges-spot markets for electricity sales-plan
to charge spot market prices for transmission that
is higher or lower than scheduled amounts, for example.
California is currently operating in this manner.>
as of the end of 1998, most ISOs are still in the
process of formation, with their makeup, governance,
rules and pricing still under development. The ISOs
in formation generally do not include power exchanges.
early ISO proposals have some negative implications
for renewables. A Southwest proposal would require
generators who want nonfirm transmission service to
have backup reserve capacity. A New England ISO proposal
would impose "nonusage" charges for both firm and
non-firm transmission services. 
transmission issue affecting renewables is the pricing
of "ancillary services" needed to maintain system
reliability, such as reserve generating capacity to
compensate for plant outages. The wind industry has
supported continued cost-based regulation of these
services by FERC, although some analysts suggest that
market-pricing may provide more flexible services
for renewables. 
have proposed "postage stamp" rates-one price for
transmitting power from anywhere within a region to
any other point within the region. Others have proposed
"megawatt mile" charges that vary with distance. Congestion
charge proposals also vary. The impact of these proposals
will vary with specific renewables projects. Generally,
transmission costs do not increase linearly with distance,
so loading all transmission charges onto a megawatt
mile may not treat remote projects fairly. Having
many small "postal zones" could have a similar or
worse effect, however.
>An analysis by the Lawrence Berkeley Laboratory
(LBL) shows charging for unused transmission capacity
can raise the cost of the entire electricity system.
LBL developed a two-tier pricing system, which bases
transmission access charges on energy transmitted
and congestion charges on capacity reservations. The
access charges would be used to cover fixed costs-80
to 90 percent of network costs. LBL shows that this
pricing scheme would lead to a least-cost technology
mix, as well as reducing the penalty for intermittent
renewables, without creating a special condition for
EPRI, PG&E, and NREL. An Introduction to the
Distributed Utility Valuation Project, Monograph,
1993; Coles, R.L., et al. Analysis of PV benefit
Case Studies: Results and Method Used, NREL
Draft Report, May 1995.
of Concerned Scientists, 1995. Renewing Our Neighborhoods:
Opportunities for Distributed Renewable Energy Technologies
in the Boston Edison Service Territory, August.,
in Photovoltaic Commercialization: Report of the
UPVG's Phase I Efforts, Part 4, Commercialization
Strategies Work Group, Utility Photovoltaic Group,
Washington, DC, June 1994, p. 38.
for example, Taylor Moore, "Emerging Markets for
Distributed Resources," EPRI Journal, March/April
1998, cover story, p. 8.
a thorough treatment of distributed generation legal
and regulatory issues, see John Nimmons, Thomas
Starrs, Ren Orans, Joel Swisher and Joel Singer,
Legal, Regulatory & Institutional Issues
Facing Distributed Resources Development, Prepared
for the National Renewable Energy Laboratory, Central
& Southwest Services, Inc., Cinergy Corp., Florida
Power Corp., San Diego Gas & Electric, National
Renewable Energy Laboratory NREL/SR-460-21791.
Public Utilities Commission, PacifiCorp-Distribution
Only AFOR, Order No. 98-191, May 5, 1998. Available
online at www.puc.state.or.us/orders/98orders/98-191.pdf.
Yoshimura, Robert Graham, and Christopher Hebert,
La Capra Associates, An Incentive Regulatory
Framework to Encourage Cost-effective Investment
In Transmission and Distribution System Resources
in a Restructured Electric Utility Industry in Massachusetts,
Boston Edison Demand-Side Management Settlement
Board, September 28, 1995. Summary and order information
available online at www.magnet.state.ma.us/doer/utility/orderreg.htm.
et. al., ibid.
Energy Regulatory Commission, Open Access Rule,
Order 888, April 27, 1996. Promoting Wholesale Competition
Through Open Access Non-Discriminatory Transmission
Services by Public Utilities (RM95-8-000).
Energy Regulatory Commission, Capacity Reservation
Open Access Transmission Tariffs, Notice of
Proposed Rulemaking, FERC Docket No. RM96-11-000,
April 24, 1996.
more detail about the effects of transmission issues
on renewables, see Kevin Porter, National Renewable
Energy Laboratory, "What is Happening with Independent
System Operators?" Presented to Windpower '98, American
Wind Energy Association, Bakersfield, Calif., April
30, 1998, available online at www.nrel.gov/analysis/emaa/isos.pdf;
Steven Stoft, Carrie Webber, and Ryan Wiser, Transmission
Pricing and Renewables: Issues, Options and Recommendations,
Lawrence Berkeley National Lab, Berkeley, Calif.,
May 1997, available online at eetd.lbl.gov/EA/EMP/emppubs.html;
Kevin Porter, "Open Access Transmission and Renewable
Energy Technologies." National Renewable Energy
Laboratory Topical Issues Brief NREL/SP-460-21427.
September 1996 Available online at www.nrel.gov/analysis/emaa/open_access/index.html;
Steven Stoft, Carrie Webber, and Ryan Wiser, Transmission
Pricing and Renewables: Issues, Options and Recommendations,
Lawrence Berkeley National Lab, Berkeley, Calif.,
May 1997, available online at http://eetd.lbl.gov/EA/EMP/emppubs.html.
et. al., ibid.
Windpower '98, ibid.
Windpower '98., ibid.
Windpower '98, ibid
et al, ibid.