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Demand Response: Background Materials
February 2012
Scott Hempling1
This outline has background materials relating to the memorandum on demand response
dated February 29, 2012. Its purpose is to explain terms and concepts that are used in the that
memorandum, particularly: Jurisdiction, regional transmission organizations, transmission
service, market-based rates, demand response and stranded investment
I. Jurisdiction: Entities and Actions
A. FERC has jurisdiction over "public utilities" that sell transmission service or sell
wholesale power.
B. FERC has jurisdiction over "regional transmission organizations" (RTOs) because
they (a) sell transmission service and (b) organized and preside over wholesale
power markets for day-ahead energy, real-time energy, and capacity
C. States have jurisdiction over sellers of retail power. For most states, this
jurisdiction is broad. The states oversee the utility's retail obligation to serve,
including the obligations to plan for future load growth; and to carry out various
state-specified goals like universal service, energy conservation, renewable
energy, low-income assistance.
D. There are important legal differences between FERC and state commissions.
FERC is not "like a state commission, but national rather than state." Unlike state
commissions, FERC's role does not include overall concern for a service territory
or for universal service objectives. FERC's oversight role is more transactional:
it oversees transmission transactions and wholesale sale transactions, and also is
responsible for overseeing reliability performance.
E. The FERC-state difference is beginning to blur as FERC emphasizes the
importance of regional transmission planning. Regional transmission planning
efforts overlap with state-based planning efforts. FERC's interest in demand
response, which was traditionally a state level, retail matter, is an example of this
blurring.
1
[email protected]; www.scotthemplinglaw.com; 301-754-3869. This
paper was prepared at the request of The Sustainable FERC Project and was funded by a grant
from the Hewlett Foundation.
2
II. Regional Transmission Organizations
A. In general
1. Regional transmission organizations (RTOs) are voluntarily formed by
groups of utilities, encouraged (not ordered) by FERC Order 2000, issued
in 2000-01. There are presently 7 RTOs: ISO New England, New York
ISO, PJM Interconnection, MISO, Southwest Power Pool (SPP), Electric
Reliability Council of Texas (ERCOT), and California ISO.
2. In encouraging RTOs, FERC's goal was twofold: (a) make transmission
service available on a regional basis, and (b) make the provider of
transmission service independent of the providers of generation services
3. An RTO is formed when utility transmission owners commit contractually
to transfer "functional control" to the RTO. The utilities retain ownership
of their transmission assets.
4. The RTO then is the legal seller of transmission service to all the utilities
in the region. That status makes the RTO a "public utility" subject to
FERC's jurisdiction under the Federal Power Act.
5. As the legal seller of transmission service, the RTO is obligated to provide
transmission service in the region consistent with FERC Order 888 (see
below).
6. The RTO also organizes and administers energy and capacity markets.
7. The RTO has four "minimum characteristics" and eight "required
functions" (see below)
B. FERC Order 888 (1996)
1. Purpose: Remedy undue discrimination in the provision of interstate
transmission service,
2. Each owner of transmission facilities must file a tariff at FERC to provide
transmission of wholesale power (and retail power when the state has
authorized retail competition)
a. Network service (load-based)
(1) FERC's Description: "Network transmission service, in the
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Open Access Final Rule, defines rights and sets prices
based on customer load. It allows the transmission
customer to use the transmission provider's entire grid to
serve designated loads from designated resources without
having to pay a separate charge for each pairing of resource
and load. Thus, network service enables the transmission
customer to use the network flexibly to integrate its
resources and loads efficiently and to dispatch
economically its system, in the same way as the owner of
the transmission system."
(2) Customer designates load and resources.
(3) Transmission owner has planning responsibility.
(4) All network customers, including transmission provider,
bear the risk of insufficient capacity.
b. Point-to-point service (reservation-based)
(1) FERC's description: "Firm flexible point-to-point service
in the Open Access Final Rule defines rights and sets prices
based on transmission capacity reservations. The
transmission user designates points of delivery (PODs) and
points of receipt (PORs) and makes a capacity reservation
for each POD and for each POR."
(2) The customer "should be able to use any available
unreserved service without an additional charge, as long as
the use does not exceed its capacity reservation." (CRT
NOPR)
c. Summary (from FERC)
(1) "Network service provides enough transmission capacity to
satisfy a customer's consumption of electric power.
Point-to-point service sets aside as much transmission
capacity as the customer reserves. Thus, network service is
based on use, and point-to-point service is based on
reservations."
(2) "Network customers get and pay for the capacity they use,
and point-to-point customers get and pay for the capacity
they reserve. The fixed costs of the transmission system
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are allocated among network customers on the basis of use,
that is, the customers' loads. The fixed costs of the
transmission system are allocated among pointtopoint
customers on the basis of their reservations, that is, their
contract demands."
C. Four RTO minimum characteristics
1. Independence from any market participant
a. RTO and employees may not have a financial interest in any
market participant
b. Decisionmaking process independent of control
c. RTO must have exclusive and independent authority to file at
FERC for changes in rates, terms and conditions for service
provided over the facilities controlled by the RTO
d. Note: Transmission owners still can file at FERC to seek recovery
from the RTO of their individual revenue requirements.
2. Scope and regional configuration
a. reliability
b. perform required functions effectively
c. support efficient and nondiscriminatory power markets
3. Operational authority
a. divisions of authority with others permitted, but
(1) the division cannot adversely affect reliability or give any
market participant an unfair competitive advantage
(2) after two years, RTO must file a report assessing any
division of authority
b. RTO must be the "security coordinator" for the facilities it controls
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4. Exclusive authority to maintain short-term reliability
a. reliability
b. exclusive authority for receiving, confirming and implementing all
interchange schedules
c. right to order redispatch of any generator connected to
transmission facilities it operates, if necessary for reliability
d. authority to override owners's scheduled outages
e. if RTO operates within a region whose reliability standards are
controlled by another entity (like a reliability council), the RTO
must report to the Commission if these standards hinder it
D. Eight RTO required functions
1. Tariff administration and design
a. sole provider
b. sole administrator
c. sole authority to receive, evaluate, and approve or deny all requests
d. sole authority to review and approve requests for new
interconnections
e. tariff must not charge "multiple access fees for the recovery of
capital costs" for RTO-controlled facilities
2. Congestion management
a. RTO must create market mechanisms to manage transmission
congestion
b. broad participation
c. efficient price signals
d. RTO must operate the market itself or ensure the task is performed
by an entity not affiliated with a market participant
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3. Parallel path flow: develop and implement procedures
4. "Ancillary services"
a. List of ancillary services
(1) Scheduling, System Control and Dispatching services
(2) Reactive Supply and Voltage Control from Generation
Sources Service
(3) Regulation and Frequency Response Service
(4) Energy Imbalance Service
(5) Operating Reserve - Spinning Reserve Service
(6) Operating Reserve - Supplemental Reserve Service
b. RTO must be provider of last resort
c. Market participants must have the option of self-supply or
procurement from third parties
d. RTO must decide minimum required amounts, and locations where
the services must be provided
e. Providers of ancillary services must be subject to direct or indirect
control by RTO
f. RTO must ensure that its customers have access to a real time
balancing market
5. "Open access same time information service"
a. RTO must be the single OASIS site administrator
b. RTO must independently calculate total transmission capability
and available transmission capability
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6. Market monitoring
a. concerns: design flaws, market power abuses and opportunities for
efficiency improvements
b. monitor behavior
c. assess external forces, like bilateral power sales markets and
unaffiliated power exchanges
7. Planning and expansion
a. responsible for planning, and directing or arranging, transmission
expansions, additions and upgrades
b. encourage market-driven operating and investment actions for
preventing and relieving congestion
c. RTO's planning and expansion process must --
(1) accommodate efforts by state commissions to create
multi-state agreements to review and approve new
transmission facilities
(2) be coordinated with programs of existing regional groups
8. Interregional coordination
a. integration of reliability practices within an interconnection
b. market interface practices among regions
III. Market-Based Rates
A. Section 205 of the Federal Power Act requires all rates to the "just and
reasonable."
B. When a utility has a monopoly (as most do over retail service, and as many used
to over wholesale service), regulators usually set rates on an"embedded cost"
basis: They investigate the utility's prudent costs (both "sunk" capacity costs and
the expected fixed and variable costs for the next year), then calculate rates to
recover those costs.
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C. Since the early 1990s, FERC has invited wholesale sellers to apply for permission
to charge "market rates." Market rates are "whatever the seller can get" rates.
They have no necessary relationship to the seller's costs. FERC will grant an
applicant seller this permission if FERC finds the applicant has no "market
power" -- no ability, due its large market share or the indispensability of its
supply, to sustain prices above competitive levels.
D. The courts have found that market rates are consistent with the statutory "just and
reasonable" standard as long as FERC does two things: (a) subjects the seller to a
market power test prior to granting market rate permission and (b) monitors the
market to ensure that the seller continues to have no market power.
IV. Demand Response
A. Definition
A FERC report defines demand management as:
"Changes in electric usage by end-use customers from their normal
consumption patterns in response to changes in the price of electricity over
time, or to incentive payments designed to induce lower electricity use at
times of high wholesale market prices or when system reliability is
jeopardized."
Federal Energy Regulatory Commission Assessment of Demand Response and
Advanced Metering (August 2006) at viii, n.6, citing U.S. Department of Energy,
Benefits of Demand Response in Electricity Markets and Recommendations for
Achieving Them: A Report to the United States Congress Pursuant to Section
1252 of the Energy Policy Act of 2005, February 2006.
The Report describes two different categories of demand response programs:
"Demand response programs under this definition can be categorized into
two groups: incentive-based demand response and time based rates.
Incentive based demand response includes direct load control,
interruptible/curtailable rates, demand bidding/buyback programs,
emergency demand response programs, capacity market programs, and
ancillary services market programs. Time-based rates include time of use
rates, critical peak pricing and real time pricing."
Id, , Executive Summary at viii.
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B. RTO Obligation
1. FERC's Order 719 (Oct. 2008) required RTOs to:
"accept bids from demand response resources in RTOs' and ISOs'
markets for certain ancillary services on a basis comparable to
other resources;"
"in certain circumstances, permit an aggregator of retail customers
(ARC)3 to bid demand response on behalf of retail customers
directly into the organized energy market;"
2. Definition: "We will use the phrase "aggregator of retail customers," or
ARC, to refer to an entity that aggregates demand response bids (which
are mostly from retail loads)."
C. The RTO's obligation to accept demand response bids from ARCs is limited
FERC Regs. 35.28(g)(1)(iii): "(iii) Aggregation of retail customers. Each
Commission-approved independent system operator and regional
transmission organization must accept bids from an aggregator of retail
customers that aggregates the demand response of: (1) the customers of
utilities that distributed more than 4 million megawatt-hours in the
previous fiscal year, and (2) the customers of utilities that distributed 4
million megawatt-hours or less in the previous fiscal year, where the
relevant electric retail regulatory authority permits such customers'
demand response to be bid into organized markets by an aggregator of
retail customers. An independent system operator or regional transmission
organization must not accept bids from an aggregator of retail customers
that aggregates the demand response of: (1) the customers of utilities that
distributed more than 4 million megawatt-hours in the previous fiscal year,
where the relevant electric retail regulatory authority prohibits such
customers' demand response to be bid into organized markets by an
aggregator of retail customers, or (2) the customers of utilities that
distributed 4 million megawatt-hours or less in the previous fiscal year,
unless the relevant electric retail regulatory authority permits such
customers' demand response to be bid into organized markets by an
aggregator of retail customers."
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D. Compensation for providers of demand response = locational marginal price
Order 745 (para. 2):
"We conclude that when a demand response resource participating in an
organized wholesale energy market administered by an RTO or ISO has
the capability to balance supply and demand as an alternative to a
generation resource and when dispatch of that demand response resource
is cost effective as determined by the net benefits test described herein,
that demand response resource must be compensated for the service it
provides to the energy market at the market price for energy, referred to as
the locational marginal price (LMP)."
V. Stranded Investment
A. A traditional utility has incurred costs over decades, to carry out its obligations to
serve its captive customers. These are fixed costs, meaning they do not vary with
consumption. Most state commissions use rate designs that recover fixed costs
through variable charges. That means that when a customer reduces its purchases,
the utility is left with unrecovered costs -- costs that it prudently incurred to serve
that customer. The utility then has two choices: try to recover those costs by
raising rates to the other customers, or absorb the costs, thus reducing its profit.
B. Some states and utilities have resisted demand response programs because
customer who use those programs would avoid their responsibility for fixed costs
incurred on their behalf; shifting responsibility for those costs to other customers
or to shareholders.
C. There are at least two solutions to the problem. One is "decoupled rates": a
change in rate design that ensures the utility recovers fixed costs regardless of
declines in consumption. The other is to require customers who sell demand
response to pay their proportionate share of stranded cost. The third solution, of
course, is to prevent demand response: either by blocking customer participation
in the RTO's demand response programs, and/or to prevent initiation of
retail-level demand response programs.
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Demand Response: Can FERC and States Do More?
Scott Hempling1
February 2012
This memorandum responds to questions posed by the FERC Project, all aimed at
developing ways to press FERC and states to stimulate more demand response, especially
demand response participation in wholesale markets. I address the following seven questions:
1. What are the boundaries on FERC's authority to stimulate demand response in wholesale
power markets?
2. In addition to requiring RTOs to treat demand response comparably to generation, what
else could FERC do to stimulate demand response?
3. Given the opportunities FERC has created, what actions might states take to stimulate
demand response in wholesale power markets?
4. How might FERC and others influence state-level demand response policy?
5. Could FERC use its jurisdiction to stimulate more advanced metering?
6. Can FERC use its reliability jurisdiction to stimulate demand response?
7. What role might the Order 1000 processes play in stimulating demand response?
For readers new to this legal area and unfamiliar with the concepts in this memorandum,
particularly the concepts of jurisdiction, regional transmission organizations, transmission
service, market-based rates, demand response and stranded investment, I have prepared an
accompanying outline of background materials.
1
[email protected]; www.scotthemplinglaw.com; 301-754-3869. I
wish to acknowledge the contributions of John Moore, Allison Clements and Terry Black. I am,
however, solely responsible for the content. This paper was prepared at the request of The
Sustainable FERC Project and was funded by a grant from the Hewlett Foundation.
2
I. What are the boundaries on FERC's authority to stimulate demand
response in wholesale power markets?
Like any regulator, FERC acts on jurisdictional entities undertaking jurisdictional
actions. FERC can act on only those entities over which it has statutory jurisdiction; and,
with respect to those entities, only on those actions that trigger jurisdiction.
A. FERC’s statutory authority
The Federal Power Act gives FERC authority over the following entities
and their actions:
1. "Public utilities," when they sell transmission service in interstate
commerce or wholesale power in interstate commerce.2 See Sections 201,
205, and 206. The category of "public utilities" includes "regional
transmission organizations," because they are the providers of
transmission service.
2. The FERC-certified "electric reliability organization" and the "regional
entities," when they promulgate and/or enforce reliability standards; and
"owners, users, and operators" of the "bulk-power system," when they act
in ways that affect that system's reliability. See Section 215.
3. Applicants seeking FERC permission for preemptive transmission siting
permits. See Section 216.
4. "Public utilities" or other persons who take specified structural actions
such as merging, acquiring, disposing of, or consolidating assets subject to
FERC's jurisdiction. See Section 203.
B. "Demand response" is not on this list. Also unmentioned are "retail sales,"
"state commissions," and "retail consumers," all of which are necessary to the
provision of demand response. How, then, does FERC have authority to stimulate
demand-response activities? Thus far, FERC has relied on the following
reasoning:
1. RTOs are "public utilities" under the FPA because they are the legal
providers of transmission service within their regions. (FERC came to this
2
Section 201 restricts FERC's authority over transactions in interstate commerce. Court,
FPC, and FERC cases have found that, due to the interconnectedness of the grid, all electricity
transactions are in interstate commerce, regardless of their contractual origin or destination, with
the exception of transactions in Alaska, Hawaii, and Texas. See Federal Power Commission v.
Florida Power & Light Co., 404 U.S. 453 (1972).
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conclusion in its Order 2000, which defined "RTOs" and established the
requirements for their formation.)
2. RTOs also administer wholesale power-supply markets—specifically
day-ahead and real-time energy markets and longer-term capacity markets.
3. Section 205 requires that the rates for wholesale power be "just and
reasonable" and not unduly preferential.
4. Unless demand response providers have an opportunity to sell demand
response into wholesale markets administered by the RTOs, the wholesale
power prices will not be just and reasonable, for at least two reasons:
a. Demand response competes with generation; to exclude a low-cost
competitor is to have the market clear at prices exceeding
competitive levels.
b. Most states set retail prices at the same average cost level for all
8,760 hours of the year, thus failing to communicate to consumers
the true, hour-varying cost of their consumption decisions. This
means that demand levels brought by retail load-serving entities
(LSEs) to the RTOs' wholesale markets are distorted (and usually
excessive) relative to what true competitive pricing would produce.
Distorted wholesale demand produces a distorted wholesale price.
5. To mitigate these two sources of price distortion, FERC has ordered RTOs
to (a) invite and accommodate bids from demand-response providers, and
(b) treat those bids on a basis comparable to how RTOs treat generation
bids, including paying the locational marginal price to the selected
bidders.
C. To clarify: FERC is not ordering anyone to provide demand response, because
providers of demand response are not subject to FERC’s jurisdiction. FERC is
ordering the RTOs, which are subject to its jurisdiction, to take, invite and accept
demand response bids on a nondiscriminatory basis, because FERC deems such
action necessary to ensure that wholesale power sales – which are subject to
FERC’s jurisdiction – receive prices that meet the statutory "just and reasonable"
standard.
D. The state exception: FERC has directed the RTOs not to accept demand-
response bids from aggregators in states that do not allow aggregators of demand
response to aggregate retail loads within the state and sell them at wholesale.
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E. Note: Throughout this memo, the same reasoning that applies to demand
response applies also to energy efficiency.
II. In addition to requiring RTOs to treat demand response comparably to
generation, what else could FERC do to stimulate demand response?
I list below theoretical options. If you decide some are attractive, we would need
to deepen the research and vet for feasibility. These are not necessarily recommendations
for immediate action.
A. FERC could condition each LSE's participation in RTO markets, as a buyer
or a seller, in a way that advances demand response.
1. Possible condition: The LSE must provide its customers with a rate that
reflects wholesale prices.
a. It is not consistent with just and reasonable prices to allow LSEs to
participate in these markets while that same LSE is distorting the
market by bringing an inefficient (i.e., excessive) demand level
undisciplined by prudent actions. This logic is especially strong if
the LSE also has affiliated generation in the market: Then it would
have an interest in keeping the market price high by not dampening
its load through EE programs and rate design. (There is a separate
question whether this rate should be at the customer's option versus
the customer’s having no choice but to pay the rate.)
b. FERC could reach the same result indirectly by imposing penalties
on LSEs that bring to wholesale markets demand that exceeds what
the utility would have if it undertook prudent demand-response
measures. (Again, this concept would lead either to state-level
solutions, like allowing ARCs and/or retail rate redesign, or to
state-induced and state-approved utility departures from RTOs.)
2. Possible condition: The LSE must allow ARCs access to its retail
customers. This is, of course, the opposite approach to what FERC
decided in Order 745, in which FERC ordered the RTO not to accept bids
from ARCs with load gathered from states that did authorize such
aggregation. But note that FERC would not be telling states what to do;
FERC would be acting on the LSEs as participants in FERC-jurisdictional
markets.
3. Note: These two conditions would apply not only to LSEs that are not yet
members but also to existing utilities. This latter point will require more
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research because it would likely require FERC to find that existing
RTO-LSE arrangements were not just and reasonable and then order a
change in those arrangements. It is not a proposal that anyone should
make casually, because it could have unintended consequences, like
utilities’ (pressed by their states) choosing to leave RTOs – a possibility
discussed in Part II.B below. But it does flow directly from FERC's own
findings that wholesale prices are not just and reasonable if demand
response is not properly compensated. Demand response cannot be
properly compensated if it does not even reach the market.
B. How realistic is the risk of utilities departing RTOs?
1. In the RTO regions, FERC has established markets that give
state-regulated retail utilities opportunities to make money and save
money for the benefit of their retail customers. A wise state commission,
acting properly under its state-law mandate to ensure its utilities' efficient
performance, will want its utilities to participate in these markets as long
as that participation produces benefits in excess of costs. FERC can
condition utilities' access to those markets on the utilities’ taking actions
that FERC deems necessary or helpful to the efficient workings of those
markets. Such conditioning flows from FERC's statutory obligation to
enforce every public utility's duty to take all feasible actions that produce
benefits in excess of costs. As long as FERC then ensures that each state
receives some share of that net benefit, so that no one is worse off, there is
no rational reason for a state to order its utility to withdraw from an RTO.
2. That latter point perhaps requires a clarification for the new reader. Since
the creation of RTOs under Order 2000, FERC has treated them as
voluntary organizations. It has established no Federal Power Act
obligation to join an RTO. It may seem inconsistent for FERC
simultaneously to (a) assert that RTOs help make the industry more
efficient and lower rates; and (b) declare that utilities can choose not to
form or join them—without requiring non-joiners to prove that their rates
are not unjust and unreasonable. That is, a strong pro-RTO statement,
short of mandating participation, would be for FERC to create a
presumption that joining an RTO is necessary for just and reasonable
rates, thereby requiring all non-joiners to prove that their rates are not
unjust and unreasonable due to their non-participation. FERC has chosen
not to take this path. It has treated RTOs as voluntary. Further, under
most (if not all) state laws, a utility must get its state's permission to join
an RTO, since joining means transferring control of valuable transmission
assets, long funded from retail rates, to a FERC-regulated entity. FERC
cannot—or will not—order any utility to join an RTO. Given that FERC
has not, and likely will not, order any utility to join an RTO, and given
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that a state could block a utility from joining or order a utility to depart
(departure being subject to FERC approval), FERC's remaining option is
to ensure that RTOs provide net benefits, then condition access to those
benefits on utility actions that produce all possible efficiencies. That is the
common theme in this memo.
C. Advocates could challenge the lawfulness of FERC-jurisdictional “market
prices” in RTO territories where the state has excluded demand response.
1. FERC has already said, explicitly, that unless demand response receives
an LMP price (with no reduction for the retail rate), the wholesale prices
are not just and reasonable. What FERC has not said, but which follows
necessarily, is that if LMP-compensated demand response is necessary for
just and reasonable prices, then the failure of demand response to reach
the market means the prices are not just and reasonable. It would be
inconsistent to say that specific compensation for LMP is necessary for
just and reasonable wholesale prices, but then be entirely indifferent to
how much demand response actually reaches the market. But that is the
essence of the current FERC position: FERC allows the RTO to exclude
aggregated demand response from states that ban aggregators.
2. Put another way: FERC itself has said that demand-response participation
is necessary for wholesale rates to be just and reasonable. But FERC's
order does not ensure demand response's entry; states can block entry.
FERC cannot say both things: (a) Demand response participation is
necessary for wholesale rates to be just and reasonable; and (b) demand
response is not necessary for wholesale rates to be just and reasonable
where a state blocks demand-response aggregation. The two statements
contradict themselves.
3. Given the legal vulnerability of its market-based rate program, FERC has
several options for RTO markets where states have blocked demand
response. None of these options is on sure legal ground—but neither is
the status quo of allowing market-set prices in the absence of full demand-
response participation.
a. FERC could, and should, find that organized wholesale markets do
not produce just and reasonable prices unless there are no
restrictions on demand-response participation—no restrictions
from RTO policy (FERC has taken care of this), from utility
unilateral behavior, or from state policies. To make those prices
just and reasonable, FERC would have to construct a series of
price caps that reflect what prices would be in the presence of
sufficient demand response. (This action would of course spark
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opposition from generators, who benefit from the higher prices.
It's unlikely that FERC would take this action because it wants to
encourage generation entry. But the discomfort anticipated could
stimulate FERC to come up with other ideas.)
b. FERC might (emphasis on might) find that demand response is an
"ancillary service." As Order 888 explained, "ancillary" means
ancillary to—essential to—the provision of transmission service.
Order 888 directed transmission providers to provide or procure
certain ancillary services. The RTOs, in their role as transmission
providers, procure these services through bids from generators. If
FERC were to issue such an order (assuming it has the authority to
do so—a possibility but not a certainty), it still is not clear whether
states could block their citizens from selling to aggregators. It is
possible that courts might see such state blockage as preempted by
the FPA or even as impermissibly burdening interstate commerce
(on the grounds that there are alternative ways, like stranded-cost
recovery, to protect legitimate state interests). This avenue, if
there is interest in pursuing it, is not doubt-free and needs more
research.
4. Possible antitrust law point: The effect of FERC's policy is to allow states
to allow utilities to monopolize or weaken the DR aggregation market.
That monopolization itself is not a violation of the Federal Power Act
because the demand-response market is not subject to FPA jurisdiction.
But it does raise questions under antitrust law that are worth looking at.
(This would be a major research task because it requires study of the "state
action doctrine." For now, view these thoughts on antitrust law as solely
informal.)
D. Could FERC remove Order 719's state-policy exception so that RTOs must
accept demand response from retail aggregators, regardless of whether there
is state law precluding retail aggregation?
There is no certain answer. This option means that the RTO's obligation
would conflict with state law: State-based aggregators would assert a
right to participate in the RTO markets even as state law prohibited them
from doing so. The question is whether the Federal Power Act in this
context would preempt state law. I could write a brief supporting either
side and therefore cannot guess the right answer. It is worth exploring
further, especially given the earlier point that wholesale prices are not just
and reasonable where demand response cannot reach the market (whether
due to state blockage or utility resistance or inefficient retail rates).
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E. What if a demand-response bid does not pass FERC's "net benefits" test?
1. Order 745 states that the demand response participant in RTO markets is
entitled to receive the locational marginal price, but only when the demand
response passes FERC's the "net benefits" test. That test is satisfied when
"... reductions in LMP from implementing demand response results in a
reduction in the total amount consumers pay for resources that is greater
than the money spent acquiring those demand response resources at
LMP...." Order 745 at para. 50.3
2. What happens when demand response is not cost-effective under this
test?4 FERC does not answer this question directly. My inference is that
the RTO must allow the demand-response provider to offer a lower price
that satisfies the cost-effective test, because there remains an RTO
obligation, from Order 719, to treat demand response comparably to
generation. The problem with this answer is that it suggests that demand
response could contract with the RTO outside the bidding process if it
loses—a second-bite-at-the-apple approach. It is not clear that FERC or
the RTO is obligated to make that second chance available. Clarification
from FERC on this point would be useful.
3. Further, FERC should make clear that if an RTO had programs, prior to
Order 745, that paid demand-response compensation lower than the LMP,
they should not eliminate those programs but rather modify them to make
participation available when the bid satisfies the net-benefits test.
4. Note that FERC's compensation rule under Order 745 applies only to
energy market. See fn4:
"The requirements of this final rule apply only to a demand
response resource participating in a day-ahead or real-time energy
3 To apply the “net benefits” test, the RTO must determine the “price level at which the
dispatch of demand response resources will be cost-effective[;]” that is, “the monthly threshold
price corresponding to the point along the supply stack beyond which the overall benefit from
the reduced LMP resulting from dispatching demand response resources exceeds the cost of
dispatching and paying LMP to those resources.” Order 745 paras. 4, 79. All demand resources
selected (selected because their bids were below the highest-priced chosen resource) would
receive the LMP price.
4
Other DR resources would not have been selected because their bid prices were too
high relative to the competing sources (both generation and DR). Their regulatory status is,
simply, “unchosen.” The RTO would be imprudent to buy from them at their bid price. They
could still make a bilateral sale to their local utility if the state permitted such a sale.
9
market administered by an RTO or ISO. Thus, this Final Rule
does not apply to compensation for demand response under
programs that RTOs and ISOs administer for reliability or
emergency conditions..."
5. Nor does the rule apply to capacity markets. Order 745 at para. 85.
III. Given the opportunities FERC has created, what actions might states
take to stimulate demand response in wholesale power markets?
A. State solution: Establish a utility prudence obligation to pursue all efficient
DR opportunities
1. A utility whose retail load exceeds its owned generation must buy the
remainder at wholesale. In an organized market run by a regional
transmission organization, the utility bears a load-share responsibility for
the region's capacity needs. The utility must fill that responsibility by
buying bilaterally, or buying from the organized capacity market. Or it
can reduce its load-share responsibility by selling demand response.
Capacity markets produce high prices, and selling demand response can be
lucrative. Retail customers bear the high prices and benefit from the
demand-response revenues.
2. A prudent utility, therefore, will minimize its capacity purchases and
maximize its demand-response sales. The utility will have a clear
financial incentive to do so, if the state commission protects its sunk costs
while also making it financially responsible for any failure to take
advantage of demand-response opportunities. The dollars work in the
ratepayers’ favor whenever the LMP revenue the utility receives exceeds
the stranded-cost payment the customers would have to pay. That is why
states that generically cite stranded investment as a reason for banning
ARCs are missing the point.
3. In this context, the state regulatory commission should act to induce
prudent utility performance. The state commission options then would
include:
a. Require the utility to establish its own demand-response program,
where it is the sole purchaser of demand response from its
customers, and then the sole reseller of demand response to the
RTO.
10
b. Require the utility to contract with demand aggregators who
specialize in this activity, where the demand aggregator acts as the
utility's agent.
c. Authorize demand aggregators to enter the utility's service
territory, to contract directly with retail customers and then resell
the demand response to the RTO market.
d. Not require a demand-response program of the utility, but set the
revenue requirement (meaning, lower it) as if the utility had
performed prudently, thereby inducing the utility to act on its own
to reduce its capacity obligations.
e. Investigate what the best market structures are for demand
response, so as to reduce the utility's capacity obligations.
f. Establish a state-level market structure for DR that causes the most
cost-effective DR and DR providers to emerge. See the detailed
paper I authored while at NRRI: Cost-Effective Demand Response
Requires Coordinated State-Federal Actions, available at
http://nrri.org/pubs/electricity/Demand_Response_Paper-Hempling
_June-2011.pdf.
B. State solution: Establish retail rate designs that induce demand response by
exposing retail ratepayers to wholesale prices
1. The state should establish rate designs that reflect wholesale prices. Doing
so means that the compensation for a retail customer providing DR will
always be the marginal price: exactly what FERC is requiring. The FERC
policy and the state policy will be aligned. Note that in this efficient
retail-rate-design approach, the state still has to address the retail utility's
sunk costs. The state can do so by having a two-part rate: The customer
pays for the sunk cost because she needs the fixed assets (or needed them
when the utility invested in them), but she still accesses the wholesale DR
market when economically beneficial.
2. On this point there is an economics issue still to work out: If the FERC
LMP prices reflect capacity and energy costs while the state-set price is a
two-part rate with capacity separate from energy, does it still work? I
think so, because the revenue the retail customer receives through the
LMP payment defrays the fixed retail charge that the retail customer
cannot avoid.
11
C. Advocates could question whether the state bans are lawful under state
statutes
Where a state commission has banned demand-response aggregators, there
is a question as to whether the ban is permitted by state statute. It is not
obvious that entities who pay consumers not to consume are acting
inconsistently with state law granting exclusive franchises—any more than
are purveyors of energy-efficient windows, energy-saving lightbulbs, or
sweaters. Just because FERC has told RTOs, "Don't accept DR bids
representing load in states whose commissions have banned the bids" does
not mean the state commission had a state statutory basis from which to
impose the ban. FERC has no power to create state commission authority.
This avenue does not work, of course, where the ban is authorized by state
statute.
D. What about stranded investment?
1. Some states and utilities have opposed participation in wholesale demand-
response markets due to the risk of stranded investment. Stranded
investment is a possibility because retail customers selling demand
response to the wholesale market will buy less power at retail. If, as is the
case in most states, the retail variable charge recovers fixed costs, the
reduction in purchases means less recovery of fixed costs. These states
further believe that compensating demand response at LMP levels
(without subtracting the retail rate) will exacerbate the stranded-
investment problem.
2. The stranded-investment concern is a valid concern. Its roots are in
economic efficiency, inter-customer fairness, and customer-shareholder
fairness. If a retail customer faces typical rates that recover fixed costs in
the variable charge, she strands those fixed costs when she forgoes
consumption. Those fixed costs, incurred prudently by a utility under its
obligation to serve, then fall on the shareholders (through reduced return
on equity arising from the reduced payment) or on other retail customers.
That effect is a problem of equity, not economic efficiency. It becomes a
problem of economic efficiency if the customer, and/or her aggregator,
incurs their own new costs to enable the DR transaction. Those new costs
could be equipment on the customer's premises or equipment used by the
ARC to aggregate. The result is redundant equipment—the utility's
stranded capacity and the customer's or ARC's new equipment.
12
3. Retail decoupling, in any one of several forms, eliminates this problem
because by definition it ensures recovery of fixed costs regardless of
variable usage.
4. State commissions also can eliminate the stranded-cost concern directly:
by requiring those who access the RTO's demand-response market to pay
a stranded-cost charge.
a. There will be hours in which the LMP compensation will exceed
the stranded-cost charge. While requiring stranded-cost payment
would reduce the amount of demand response sold, it would not
reduce it below economically efficient levels if actual consumption
bears its proper environmental cost through carbon taxation or
other means. Without carbon taxation, the stranded-investment
charge will reduce demand response, but it is a necessary step
given that the stranded costs were incurred on the customer's
behalf. It is no different from the homeowner needing to pay off
her existing home before buying a new one.
b. Stranded-cost charges are not a new challenge. States that
authorized retail competition have dealt with it. Demand response
is sufficiently similar to retail competition (it provides customers
with a cost-saving alternative to buying from the incumbent utility)
that the stranded-investment processes used by retail-competition
states should provide useful models. Given the experience with
these calculations and charges, stranded investment is not a
persuasive reason for states to block the full participation of
demand response in wholesale markets. (States have offered a
second reason—wholesale DR's interference with utility-run
demand-response programs. That concern is worth addressing in a
separate paper.)
5. To summarize: The solution to stranded investment is not to change
FERC's compensation policy, which properly allows the full LMP price
without subtracting the retail rate. (FERC explains that subtracting the
retail rate—i.e., worrying about the retail customer's full compensation—
is equivalent to inquiring into a market-based generation seller's cost
structure—something the FERC does not and will not do.) Rather than
urge FERC to distort the DR compensation at wholesale, the state should
solve the problem at retail: by making the retail DR participant
responsible for her pro rata share of sunk capacity costs. The state-level
solution would involve addressing the stranded cost problem surgically as
noted above, imposing on the utility a prudence obligation to maximize
DR savings, and fixing retail rate design. The additional federal-level
13
solution would be for FERC to regulate utilities by making their efficient
behavior a condition of participating in RTO markets.
IV. How might FERC and others influence state-level demand-response
policy?
A. Could FERC require or induce states to choose among one or more of these
options: (a) requiring their utilities to establish in-state demand-response
programs (that is, programs that do not necessarily involve the utilities selling
demand response into the RTO market), (b) authorizing independent aggregators
to aggregate retail demands and sell them into RTO markets, or (c) permitting (or
requiring) their utilities to participate in the RTO's FERC-approved DR programs
(i.e., having the utilities act as the demand-response aggregators for their
customers)?
B. As discussed in Part II above, the Federal Power Act gives FERC no authority to
require states to act. FERC's chief way for acting within RTO markets is its
jurisdiction over RTO activities. FERC cannot mandate that a utility, even a
utility member of an RTO, take a particular action. But as discussed in Part II
above, FERC can condition a utility's right to participate in an RTO—as a
transmission owner, a power seller or a power buyer—on the utility's taking
actions or forgoing actions as necessary to ensure that rates are just and
reasonable and not unduly discriminatory.5
C. Other possible options
1. FERC could press Congress to preempt state laws blocking demand
response's entry into wholesale markets. This action, while nettlesome to
some states, would benefit all states by lowering wholesale prices.
Lowering wholesale prices can help prevent political backlash to FERC's
wholesale-market efforts—which Congress has supported with its past
actions. (FERC does not have independent authority to preempt a state
ban; nor does the Federal Power Act itself preempt the state ban directly,
because demand response is not a service subject to the FPA.) The best
path for states concerned about the efficacy of FERC’s wholesale market
efforts is to open paths for demand response, so that those wholesale
4
The confusion about FERC’s lack of authority over states is understandable, given that
states sometimes complain about FERC “impinging” on their authority and “preempting” them.
These are legal impossibilities. FERC can act only on regulated entities—“public utilities” as
defined by the FDA—by ordering them to do things, or by establishing conditions they must
meet before receiving permissions that FERC has authority to grant or deny. The Federal Power
Act does not allow FERC to reduce or preempt state authority. Only Congress can do that.
14
market efforts can work. Otherwise prices will be higher than they need to
be.
2. Individual consumers could self-organize into cooperatives that then sell
the combined demand. But state law might block these efforts.
3. Advocates could challenge FERC's directive that excludes state-banned
ARCs from selling to RTOs. This approach is not politically feasible, and
also has a legal dead end. All that FERC is saying is "Don't accommodate
bids from entities whose bidding action would be illegal under state law."
FERC's very statement has no legal consequence because if the bid is
illegal under state law, FERC can’t make it legal.
V. Could FERC use its jurisdiction to stimulate more advanced metering?
A. For present purposes I will define "AMI" informally as "gadgetry installed by a
utility or other retail seller on a retail customer's premises to provide that
customer information about usage and cost, and to provide the utility or other
retail seller information about the retail customer's consumption." AMI can
facilitate the use of demand response in markets for energy, ancillary services,
and capacity.
B. As indicated in Part I above, FERC can issue orders only to the entities named in
the FPA. That category does not include "providers of AMI" or "recipients of
information generated by AMI." The question, therefore, given the desirability of
AMI, is “How can FERC exercise its jurisdiction over the various entities and
their services to produce more AMI?”
C. One possibility (placed here solely for purposes of discussion) is for FERC to
declare that AMI and its associated services is an "ancillary" service subject to
FERC's jurisdiction over providers of transmission service. This is uncharted
legal territory. The FPA denies FERC jurisdiction over "local distribution
service."6 Looked at between the eyes, a home-installed gadget is not
"transmission." It is more likely "local distribution," a service that Section 201(b)
expressly excludes from FERC jurisdiction. But the analysis does not end there.
Each of these "ancillary services," the provision of which FERC regulates under
its "transmission" jurisdiction, is actually a "generation" service; yet the same
Section 201(b) denies FERC jurisdiction over "generating facilities." But in
6
Section 201(b): FERC "shall not have jurisdiction, except as specifically provided in
this Part and the Part next following over facilities used for the generation of electric energy or
over facilities used in local distribution...."
15
Order 888, FERC has found that those ancillary services are essential to
transmission service:
"[They] are "needed to accomplish transmission service while maintaining
reliability within and among control areas affected by the transmission
service."
...
"They range from actions taken to effect the transaction (such as
scheduling and dispatching services) to services that are necessary to
maintain the integrity of the transmission system during a transaction
(such as load following and reactive power support). Other ancillary
services are needed to correct for the effects associated with undertaking a
transaction (such as energy-imbalance service)."
D. The question, then, is whether AMI can somehow be viewed by FERC (and
upheld by the courts) as "essential" to transmission service. If so, FERC could
deem AMI to be an "ancillary service." This memo does not shut the door on the
idea, but technical work would be necessary, including calling expert witnesses,
gathering facts, and marshaling arguments that support "essential" status.
E. Here is a start on the reasoning: AMI, when it transmits wholesale price signals,
is essential to the efficient working of wholesale markets. Without proper retail
price signals, just as without cost-effective DSM, retail customers' demand will
exceed economically efficient levels, thereby driving up the marginal price of
both capacity and demand. As with DR and EE, there is a legal theory under
which FERC could (a) deny LSEs the right to participate in RTO markets unless
their customers had AMI and (b) require the RTO to accept and accommodate the
electronic information coming from AMI installed at retail. On this point,
consider how FERC in Order 745 connected, unambiguously, the absence of
proper price signals with unjust and unreasonable conditions:
"47. ... [W]hen a demand response resource has the capability to balance
supply and demand as an alternative to a generation resource, and when
dispatching and paying LMP to that demand response resource is shown to
be cost-effective as determined by the net benefits test described herein,
payment by an RTO or ISO of compensation other than the LMP is unjust
and unreasonable. When these conditions are met, we find that payment of
LMP to these resources will result in just and reasonable rates for
ratepayers. As stated in the NOPR, we believe paying demand response
resources the LMP will compensate those resources in a manner that
reflects the marginal value of the resource to each RTO and ISO."
16
F. Based on this language, it is worth continuing to argue that FERC has authority—
and an obligation—to impose conditions on RTOs and other sellers of
transmission service and wholesale power as necessary to ensure that demand and
supply curves in wholesale markets meet at marginal cost. Those conditions,
when imposed in LSE members of RTOs, could include the condition of installing
AMI equipment. (Then a large question arises as to what type of equipment and
who pays for it.)
VI. Can FERC use its reliability jurisdiction to stimulate demand response?
A. I doubt it. FERC's reliability jurisdiction is set forth in Section 215. This
jurisdiction is limited to approving standards and penalties imposed by the
FERC-certified "electric reliability organization" (ERO) and/or the "regional
entities" to which the ERO has delegated authority. Further, the standards and
penalties subject to FERC's jurisdiction relate only to the statutorily defined "bulk
power system."
B. To have demand response, energy efficiency, or advanced metering infrastructure
trigger FERC's Section 215 jurisdiction, we would have to show a link to
reliability and to the standards and penalties. This is doubtful, less because of the
bulk-power-system screen (since demand response certainly affects the demand
placed on the system, even if demand's origins are at the distribution level), but
more because the ERO—which is the initiator of all standards (under the statute,
FERC cannot initiate the standards; it can only approve or disapprove them) is
focused on achieving the twin reliability objectives of adequacy and security:
there must be enough infrastructure to meet demand, and the infrastructure must
be available every minute. The ERO does not concern itself with how the users,
owners, and operators of the bulk power system achieve adequate infrastructure,
i.e., what resources they develop to meet their demand or dampen demand; the
ERO focuses on defining the goals rather than decreeing how to achieve them.
For these reasons, I doubt that FERC's reliability authority gives it any handle for
pressing actors toward more demand response.
VII. What role might the Order 1000 processes play in stimulating demand
response?
A future paper could address whether FERC can and should use the Order
1000-mandated regional transmission planning process, and FERC's jurisdiction
to approve transmission cost recovery, to require proponents of transmission cost
recovery to demonstrate that the transmission cost represents the best solution,
taking into account all other feasible options, including demand response, energy
efficiency, and AMI.
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