Case Background
Rule 25-17.0021, Florida Administrative
Code (F.A.C.), Goals for Electric Utilities, implements the Commission’s
statutory mandate to adopt goals for electric utilities, approve utility plans,
and collect periodic reports from utilities related to promoting efficiency and
conservation of electric energy as provided in Sections 366.80-366.83 and
403.519, Florida Statutes (F.S.), known together as the Florida Energy
Efficiency and Conservation Act (FEECA). The Commission is required by FEECA to
establish goals at least once every five years for utilities subject to FEECA.
The utilities are required to develop plans and programs to reach those goals
and submit them for approval by the Commission.
The six electric utilities currently
subject to FEECA are Florida Power & Light Company (FPL), Duke Energy
Florida, LLC (Duke), Tampa Electric Company (TECO), Florida Public Utilities
Company (FPUC), JEA, and Orlando Utilities Commission (OUC).
In the 2019 goal-setting proceeding, the
Commission chose to continue the goals established by its 2014 goal-setting
decision for the period 2020-2024 and directed staff to review the FEECA
process for potential updates and revisions. This rulemaking was initiated at the
direction of the Commission following the 2020 DSM plan-approval proceeding.
FEECA’s
Requirements
The
Legislature adopted FEECA in order to promote four key priorities: (1) reducing
the growth rates of weather-sensitive peak demand and electricity usage, (2) increasing
the efficiency of the production and consumption of electricity and natural
gas, (3) encouraging demand-side renewable energy systems, and (4) conserving
expensive resources, particularly petroleum fuel. The Legislature emphasized that it is
critical to utilize “efficient and cost-effective” conservation systems.
The
Legislature set forth in Section 366.82, F.S., appended as Attachment C,
specific statutory guidelines for the Commission to implement FEECA’s
objectives through the establishment of conservation goals for utilities and
approval of utility plans to meet those goals.
The
Commission’s goal-setting and plan-approval proceedings are conducted pursuant
to Sections 120.569 and 120.57, F.S., affording all parties whose substantial interests
are affected the opportunity to participate in discovery, to offer testimony
and other evidence, and to conduct cross-examination of witnesses at the
administrative hearings.
FEECA’s
Goal-Setting Process for Electric Utilities
Section
366.82(2), F.S., directs the Commission to “adopt appropriate goals for
increasing the efficiency of energy consumption and increasing the development
of demand-side renewable energy systems.” It further provides that the
Commission should specifically include goals designed to increase the
conservation of expensive resources, such as petroleum fuels; to reduce and
control the growth rates of electric consumption; to reduce the growth rates of
weather-sensitive peak demand; and to encourage development of demand-side
renewable energy resources.
The
Commission is required by Section 366.82(3), F.S., in the process of developing
conservation goals, to “evaluate the full technical potential of all available
demand-side and supply-side conservation and efficiency measures.” The
Commission is further directed by that section, in establishing the goals, to
take into consideration:
(a)
The costs and benefits to customers participating in
the measure.
(b)
The costs and benefits to the general body of
ratepayers as a whole, including utility incentives and participant contributions.
(c)
The need for incentives to promote both customer-owned
and utility-owned energy efficiency and demand-side renewable energy systems.
(d)
The costs imposed by state and federal regulations on
the emission of greenhouse gases.
As
mentioned above, the Commission is required to review the goals at least every
five years, and the Commission may change the goals for reasonable cause.
FEECA’s
Electric Utility Plan Approval Process
Section
366.82(7), F.S., addresses the Commission’s process for approving utility plans
and programs to meet the conservation goals. Utility programs may include any
measure “within the jurisdiction of the [C]ommission which the [C]ommission
finds likely to be effective.” In approving plans and programs for cost
recovery, the Commission “shall have the flexibility to modify or deny plans or
programs that would have an undue impact on the costs passed on to customers.”
When a utility completes its plans and programs, the Commission is required to
determine what further goals, plans, and programs are warranted and adopt them.
Other Commission
Rules Implementing FEECA
The
Commission rules implementing FEECA are located in Chapter 25-17, F.A.C., including
particular rules that apply to electric utilities promoting conservation
through DSM efforts. FEECA’s emphasis on utilizing cost-effective energy
conservation is codified in Rule 25-17.008, F.A.C., which prescribes cost-effectiveness
data reporting formats for demand-side conservation programs. See also Rule 25-17.001, F.A.C. Rule
25-17.015, F.A.C, contains the filing requirements for cost recovery for
approved conservation efforts through the Energy Conservation Cost Recovery
(ECCR) proceedings.
Procedural
Issues
A
Notice of Rule Development for Rule 25-17.0021, F.A.C., appeared in the
November 24, 2020, edition of the Florida Administrative Register, Vol. 46, No.
229. No other Commission rules implementing FEECA were noticed for rule
development as part of this rulemaking.
Staff
rule development workshops were held on January 14, 2021, May 18, 2021, and on November 30, 2022. Participants at the workshops included: Duke,
FPL, Gulf Power Company, TECO, FPUC, JEA, the Office of Public Counsel (OPC),
City of Miami Beach, City of St. Petersburg, Orange County, Broward County, Advanced
Energy United (AEU) (formerly known as Advanced Energy Economy), American
Council for an Energy Efficient Economy (ACEEE), Catalyst Miami, Ceres, the
CLEO Institute (CLEO), Connected in Crisis Coalition, E4TheFuture,
Environmental Coalition of Southwest Florida (ECOSWF), Family Action Network
Movement, Florida Conservation Voters, Florida Rising, IGT Solar, Johnson
Consulting Group, League of United Latin American Citizens (LULAC), Miami
Climate Alliance, NAACP Florida State Conference, Net Plus Solar Power Group,
Real Building Consultants, Solar United Neighbors of Florida, Southeast Energy
Efficiency Alliance (SEEA), Southeast Sustainability Directors Network (SSDN),
Southern Alliance for Clean Energy (SACE), Southface Institute (Southface),
Synapse Energy Economics, Tampa Bay Energy Efficiency Alliance, Vote Solar, and
various private individuals.
Post-workshop
comments were filed after each workshop. Prior to the third workshop, staff
published a revised draft of the rule for discussion and consideration, and
post-workshop comments were filed with comments on that draft by: Duke, FPL,
TECO, ACEEE, AEU, Catalyst Miami, Alianza for Progress, Florida Conservation
Voters, Healthy Gulf, Florida Clinicians for Climate Action, Broward Climate
Alliance, Florida Immigration Coalition, and Opportunity for All Floridians,
CLEO, a group of Florida faith leaders, Google Nest, LULAC, ECOSWF, Miami-Dade
County, OPC, ReThink Energy Florida, SACE, Sierra Club, Southface, and Vote
Solar. Additionally, over 2,000 correspondence documents with comments on this
rule development have been placed in the docket from various individuals and
utility customers.
This
recommendation addresses whether the Commission should propose the amendment of
Rule 25-17.0021, F.A.C., Goals for Electric Utilities. The Commission has
jurisdiction pursuant to Sections 120.54, 366.05, and 366.82, F.S.
Discussion
of Issues
Issue 1:
Should
the Commission propose the amendment of Rule 25-17.0021, F.A.C., Goals for
Electric Utilities?
Recommendation:
Yes.
The Commission should propose the amendment of Rule 25-17.0021, F.A.C., as set
forth in Attachment A. The Commission should also certify that Rule 25-17.0021,
F.A.C., is a rule the violation of which would be a minor rule violation
pursuant to Section 120.695, F.S. (Rubottom, Thompson, Guffey)
Staff Analysis:
Rule 25-17.0021, F.A.C.,
implements FEECA’s requirement that the Commission adopt appropriate efficiency
and conservation goals for electric utilities and approve utility plans and
programs designed to meet those goals. The purpose of this rulemaking is to
improve the administrative efficiency and overall transparency of the
Commission’s goal-setting process.
The long-standing goal-setting
process has featured annual goals proposed by utilities based upon the
aggregated demand and energy savings of individual conservation measures. These
measures can include the replacement of existing technology with more energy
efficient equipment that results in electric demand and energy savings. Once
goals are approved by the Commission, utilities propose conservation plans that
bundle measures into programs to be offered to customers. For example, multiple
lighting technology measures can be bundled into a lighting program. The
existing rule, however, does not require a utility to include measures used in
its aggregated proposed goals in the programs ultimately offered to customers.
This results in a disconnect in the Commission’s annual review of utility
performance because demand and energy savings achieved from customer
participation in approved programs is compared to the measure-based goals
established by the Commission.
Additionally, the goal-setting
process under the existing rule provides the utilities with discretion to
submit their proposed annual goals based upon only their preferred
cost-effectiveness tests. This practice has resulted in limiting the breadth of
information and data on the cost-effectiveness of conservation measures and
programs that the Commission can consider as it develops and establishes goals.
Staff’s recommended rule
amendments make two primary revisions to the goal-setting process designed to
address the concerns outlined above: (1) goals would be based upon projected
savings from potential programs offered to customers rather than upon aggregated
savings from individual conservation measures; and (2) utilities would be
required to provide projected savings or goals developed under two
cost-effectiveness scenarios, rather than a single cost-effectiveness test, in
order to provide a more robust record of evidence. Specifically, staff’s
objective with the recommended amendments is to bring into the goal-setting
phase a greater focus on potential conservation programs that could be offered
to customers in order to reach a utility’s approved goals.
Staff
believes that the recommended amendments to the rule, as set forth in
Attachment A, would improve the transparency and efficiency of the goal-setting
and plan-approval processes, as well as ensure that the Commission can gather
and analyze information necessary and relevant to fulfilling FEECA’s statutory
mandate to utilize cost-effective efficiency and conservation systems.
Summary and Analysis of Recommended Amendments
Staff’s
recommended amendments to Rule 25-17.0021, F.A.C., will be discussed subsection-by-subsection
through the rule as set forth in Attachment A. For each subsection, the
discussion will first present a summary and explanation of the recommended
amendments, then a summary of comments related to that subsection as received
from stakeholders and staff’s recommendations on those comments.
As a threshold
matter, this recommendation addresses the comments staff believes to be within
the scope of Rule 25-17.0021, F.A.C.
In addition to the comments discussed below, Duke, FPL, and TECO (“Utilities”)
provided comments in support of staff’s recommended rule amendments. In
general, the Utilities agreed that the amendments would provide greater
transparency, increase administrative efficiency in the goal-setting and
plan-approval processes, and provide the Commission with additional information
and flexibility to meet FEECA’s requirements to balance costs and benefits.
Additionally,
some stakeholders submitted comments on other matters, such as supply-side and
transmission efficiency measures; amending Rule 25-17.008, F.A.C., to adopt a
“modified Total Resource Cost Test” that includes a “societal adder” to account
for non-energy benefits; replacing the Commission’s Cost Effectiveness Manual
with a National Standard Practice Manual; and the creation of a DSM Working
Group comprised of utilities and other interested stakeholders. This
recommendation does not address those issues because staff believes those
comments are outside the scope of this rulemaking.
The
majority of non-utility individuals and groups that participated in the rule
development workshops and submitted comments on the draft rule, including
individuals who submitted correspondence documents, were closely aligned in
their basic positions and suggestions. Because their comments were largely
similar in substance, those commenters will be referred to collectively as “Stakeholders”
for purposes of discussing their comments.
Subsection (1) Recommended Amendments
Subsection
(1) of the recommended amended rule addresses the frequency, nature, and basis
of the goals the Commission will set for electric utilities. Recommended amendments
clarify language related to the evidence upon which the Commission will base
the FEECA goals and how the Commission will gather the information necessary to
develop and assess potential goals. In particular, paragraph (1)(a) codifies
the statutory requirement that the Commission shall evaluate the technical
potential of available measures, as required by Section 366.82(3), F.S., and the
word “programs” was added in paragraph (1)(b) to clarify that the estimate of
reasonably achievable savings should be focused on potential DSM programs. Other
recommended amendments to subsection (1) include:
·
Language related to the frequency of
goal-setting procedures (“at least once every five years”) was moved to this subsection
from subsection (2).
·
Deleted the word “numerical” to allow the
Commission the flexibility to set non-numerical goals if appropriate under
FEECA.
·
Deleted language related to the specific
objectives of the goals because it restated language existing in Section
366.82(2), F.S.
·
General updates to language for clarity.
Summary of Comments Received & Staff
Response
Stakeholders
suggest that the rule should include some consideration or mechanism to
increase participation in DSM programs among low-income customers. Stakeholders
assert that the DSM goals established by the Commission should include separate
and discrete DSM goals for low-income customers. They point out that because low-income
customers generally spend a higher percentage of household income on energy,
they would experience a significant benefit from the lower electricity bills
associated with DSM program participation. They further point out that the
needs and market barriers unique to low-income customers negatively affect their
ability to participate in DSM measures. Therefore, Stakeholders want the
Commission to set discrete kilowatt (KW) and kilowatt-hour (KWH) savings goals
for low-income customers that would make it easier for low-income customers to
participate in utility-sponsored DSM programs. Suggestions for such goals also
included requiring a minimum percentage of utilities’ DSM spending to be
allocated for low-income programs.
Under the amended
rule as recommended, the Commission will establish goals for Residential
customers based on an analysis of the technical potential of available measures
and cost-effective savings reasonably achievable through DSM programs, as
required by Section 366.82(3), F.S. Staff notes, however, that the residential
market segment is not differentiated by income levels and thus, low-income
customers are already included in the technical potential and cost-effectiveness
analysis for this market segment. Therefore, staff believes it unnecessary to
require distinct goals for a customer class included within the Residential
market segment.
Further,
staff believes that codifying distinct low-income goals would unnecessarily
restrict the discretion given to the Commission by statute. As Stakeholders observe,
low-income customers have higher market barriers affecting participation in DSM
measures. FEECA contemplates overall conservation goals, DSM plans and programs
designed to meet those goals, and particular DSM measures included in those
plans and programs. See Section
366.82(2)-(3), F.S. Thus, if the Commission sets discrete goals for low-income
customers, then discrete plans, programs, and measures for low-income customers
would be required to meet those goals under FEECA. However, if low-income
customers are considered as part of the Residential market segment for
goal-setting purposes, the Commission could consider potential low-income DSM
measures as part of a portfolio within a larger Residential plan or program,
allowing greater flexibility in how utilities can account for, and the
Commission can consider, the particular needs of low-income customers. The
Commission has a history of doing just that by directing utilities to use a
“portfolio approach” that allows low-income DSM measures to be considered as
part of a “bundle” with cost-effective programs.
For these
reasons, staff does not recommend the Commission include provisions related to separate
low-income goals in the rule.
Subsection (2) Recommended Amendments
Subsection
(2) of the recommended amended rule codifies and clarifies the technical
potential study to be conducted by electric utilities and filed for the
Commission to evaluate in developing goals as required by FEECA in Section
366.82(3), F.S.
Staff’s
recommended amendments to this subsection clarify that the technical potential
study should focus on DSM measures associated with particular major end-use
categories in the Residential and Commercial/Industrial Market Segments. The
assessment of major end-use categories was moved to this subsection from subsection
(3) of the existing rule, and the lists of major end-use categories were amended
for consistency and clarity. Of particular note, the “Renewable/Natural gas
substitutes for electricity” category was deleted to avoid confusion regarding
substitution between electricity and natural gas. Because both electric and gas
energy resources are covered by FEECA with separate goals, staff believes that
electric utilities should not be encouraged to meet their own FEECA goals by
undermining FEECA’s priorities for natural gas conservation, and vice versa. In
general, staff believes load-building DSM measures—such as those substituting
one FEECA resource for another—should not be encouraged as measures to meet
FEECA goals.
Additional
recommended amendments to subsection (2) are:
·
Added language clarifying that the Commission
has flexibility to set the filing schedule for the technical potential study in
an order establishing procedure.
·
Required the utilities to assess “the full
potential of all available demand-side conservation and efficiency measures”
mirroring the statutory language in Section 366.82(3), F.S.
·
Moved language related to frequency of
goal-setting procedures (“at least once every five years”) from this subsection
to subsection (1).
·
Moved language related to the Commission’s
discretion to review and modify goals to subsection (5) of the amended rule in
order to keep the focus of subsection (2) on the technical potential study.
Summary of Comments Received & Staff
Response
Stakeholders
suggest that “efficient electricity substitutes for natural gas” should be
added as an end-use category considered in the technical potential study,
arguing that electricity is a more efficient energy source than natural gas and
would thus provide a net gain in conservation of resources. Stakeholders also
suggest adding an additional end-use category, such as “other,” as a catch-all
category to allow the Commission to consider efficiency measures related to
emerging technologies—such as electric vehicles—that do not fit under any of
the end-use categories listed in the subsection.
As stated
above, staff believes load-building DSM measures—such as those substituting natural
gas consumption for electricity—should not be encouraged as viable measures to
meet FEECA goals. Thus, staff recommends that the Commission not include in subsection
(2) the addition of an end-use category encouraging such substitution.
Additionally,
staff recommends that the Commission not include a catch-all “other” category
because it would not provide sufficient guidelines for implementation or
enforcement. As such, it could be construed as a broad claim of authority
beyond what FEECA grants. Staff believes the categories contained in the recommended
amended rule are sufficient to allow the Commission to consider the full
technical potential of all available DSM measures, as required by FEECA in
Section 366.82(3), F.S., without foreclosing the future consideration of
available measures that may not fit neatly into the end-use categories enumerated
in the rule.
Subsection (3) Recommended Amendments
Subsection
(3) of the recommended amended rule focuses on cost-effectiveness data and
prescribes information to be provided by utilities that will enable the
Commission to consider the costs and benefits of potential DSM programs and the
potential costs passed on to customers, as required by FEECA in Sections 366.81
and 366.82(3), (7), F.S.
In
particular, each electric utility is required to file proposed DSM goals
developed using the technical potential study in subsection (2). In addition to
the proposed goals, each electric utility must file DSM goals developed under
two cost-effectiveness scenarios: in one scenario, the goals must include
potential DSM programs that pass the Participant Test and the Rate Impact
Measure (RIM) Test; in the other scenario, the goals must include potential
programs that pass the Participant Test and the Total Resource Cost (TRC) Test. In
each scenario, the DSM programs may include individual DSM measures that do not
pass the cost-effectiveness tests but the program itself, comprised of various
measures, must pass the combination of tests prescribed for that scenario.
Staff
believes that the two cost-effectiveness scenarios discussed above will provide
the Commission with a broad range of information related to the costs and
benefits of available DSM measures—information that will equip the Commission
to comply with FEECA’s requirements to consider the costs and benefits of those
measures on participants, non-participants, and the general body of ratepayers
as a whole, as required by FEECA in Section 366.82(3), F.S., without relying on
the outcome of a single cost-effectiveness test.
The
recommended amended language also provides that goal projections must provide
estimated annual demand and energy savings from potential DSM programs and
estimated annual program costs. This will allow the Commission to consider the
benefit of overall savings from DSM programs in light of the overall cost of
the programs.
The
cost-effectiveness information provided through the two scenarios and related
estimated annual program costs will give the Commission at the goal-setting
stage information relevant to its statutory mandate to assess whether potential
DSM plans and programs proposed to meet the goals may have an undue impact on
rates as required by FEECA in Section 366.82(7), F.S. Additionally, the
recommended amendments will allow the Commission to remain flexible to respond
appropriately to the availability of evolving technologies and to the shifting
market conditions as they exist at the time of each goal-setting proceeding.
Additional
recommended amendments to subsection (3) clarify that the schedule for each
utility to file proposed goals will be set by the Commission’s order
establishing procedure, and they make general updates to the language for
clarity and specificity.
Summary of Comments Received & Staff
Response
Comments
on subsection (3) addressed two principal areas: first, the rule’s prescribed cost-effectiveness
analysis and particularly the RIM Test; and second, how the Commission should
address free ridership concerns.
Cost Effectiveness & RIM Test
Stakeholders
suggest that the Commission exempt DSM programs designed for low-income
customers from its cost-effectiveness analysis.
Staff believes that exempting DSM programs for low-income
customers from cost-effectiveness analysis violates FEECA’s directives to
analyze cost effectiveness, particularly its requirement that the Commission
must consider the costs and benefits of potential DSM measures as it
establishes goals for utilities. See Section 366.82(3),
F.S. Thus, staff did not treat such programs differently in its recommended
amendments.
Stakeholders
also argue that the Commission should amend the rule to eliminate the RIM Test
from its analysis of cost-effectiveness. They assert that the RIM Test treats
customer bill savings resulting from efficiency measures as lost utility
revenue, and thus as a cost rather than a benefit. Stakeholders also argue that
the actual impact on rates resulting from lost revenues is speculative and
highly dependent on other market factors, and that because the test only
indicates the direction of resulting pressure on rates (upward or downward),
the RIM Test thus provides no meaningful information for the Commission to
assess cost effectiveness. Stakeholders argue that although the RIM Test may
limit cross-subsidization of utility-led DSM measures that put upward pressure
on rates, this concern is mitigated by simultaneous downward pressure on rates
resulting from DSM benefits such as reduced fuel use, efficient consumption,
and avoided generation investments. Further, Stakeholders contend that the RIM
Test favors DSM measures that do little to nothing to decrease energy
consumption while disfavoring measures that result in more efficient
consumption, an outcome that they argue undermines FEECA’s legislative purpose.
Stakeholders
suggest that in place of the RIM Test, the rule should require that utilities
analyze cost effectiveness using the Utility Cost Test (UCT), also known as the
Program Administrator Test, which is essentially the RIM Test analysis without
the lost revenue cost component. Stakeholders argue that this is an improvement
on current Commission practice because the UCT compares a utility’s cost of
saving energy by administering DSM measures to the utility’s cost of providing
power through supply resources. Additionally, the UCT symmetrically compares
the direct utility costs of operating DSM programs against the direct financial
benefits of efficiency which are passed on to all customers. Stakeholders suggest
that in order to include the UCT in the rule, the Commission could either amend
the Cost Effectiveness Manual
incorporated into Rule 25-17.008, F.A.C., or alternatively the Commission could
provide a standard definition of the UCT test in Rule 25-17.0021, F.A.C.
Staff recommends that the Commission not eliminate or
replace the RIM Test. Staff believes that the RIM Test provides valuable
information not provided by the UCT or any of the Commission’s other
cost-effectiveness tests, information staff believes to be relevant to the
cost-effectiveness considerations required by FEECA. In particular, as
described in more detail below, the RIM Test’s consideration of a utility’s
lost revenue is relevant to FEECA’s mandate to consider the costs passed on to
the general body of ratepayers.
FEECA declares that it is essential to utilize cost-effective
DSM and conservation systems. See Section 366.81,
F.S. Additionally, FEECA requires that in establishing goals, the Commission
must consider the “costs and benefits to the general body of ratepayers as a
whole.” See Section 366.82(3)(b), F.S. Further, FEECA requires
that in approving DSM plans and programs for cost recovery, the Commission must
examine whether they will result in “an undue impact on the costs passed on to
customers.” See Section 366.82(7), F.S.
For purposes of reporting cost-effectiveness data
required by Rule 25-17.0021, F.A.C., the three cost-effectiveness tests used by
the Commission are defined and described in Rule 25-17.008, F.A.C., which
incorporated the Commission’s Cost Effectiveness Manual. The RIM Test is one piece, but an important piece,
of the cost-effectiveness puzzle that helps the Commission discern the overall
cost-effectiveness picture of potential DSM programs along with the other tests
utilized by the Commission.
·
The
Participants Test analyzes costs and benefits of a DSM measure from the
perspective of customers participating in the measure, including the cost of
installing DSM equipment and the benefit of reduction in electricity bills.
·
The
Total Resource Cost Test measures the net costs and benefits of a DSM program
as a resource option compared to other traditional supply resources, including
the costs and benefits both to participants and the utility administering the
program. Lost revenues (bill reductions) are not considered in the TRC Test
because they are treated as a transfer payment—a cost to the utility that
exactly matches the benefit to participating customers.
·
The Rate
Impact Measure Test measures the direction of pressure on rates likely to
result from a DSM program relative to the pressure without the DSM program. It
compares the change in utility revenue to the change in utility costs to
determine whether a DSM measure will place upward or downward pressure on rates
for the general body of ratepayers, including customers not participating in
the DSM program.
The Cost Effectiveness Manual states that in
evaluating conservation programs, “the Commission will review the results of
all three tests to determine cost effectiveness.” However, Rule 25-17.008(4),
F.A.C., states that “[n]othing in this rule shall be construed as prohibiting
any party from providing additional data proposing additional formats for reporting
cost effectiveness data.”
Staff believes that it is important to the
Commission’s cost-effectiveness analysis under FEECA to consider the estimated
impact of lost utility revenue that will result from potential DSM measures. A
utility’s rates are designed to recover both fixed costs and variable costs
from a projected total sales volume. When energy sales (kilowatt-hours or KWH) and
thus, total revenue, are reduced through efficiency and conservation, a
utility’s variable costs decrease but, in general, fixed costs remain
unchanged. Thus, all other things remaining equal, a utility would no longer
recover all its fixed costs from the lower revenue total. In other words, a
loss in energy sales could put upward pressure on rates for the general body of
ratepayers because the utility’s fixed costs would be spread across fewer KWH.
Therefore, an analysis of the estimated impact of a DSM measure on a utility’s
revenue helps the Commission consider the potential impact on future rates for
the general body of ratepayers, as required by FEECA in Section 366.82(3) and
(7), F.S.
Although the RIM Test does treat a reduction in the
bills of participating customers as “lost revenue,” and therefore as a cost
both to the utility and to the general body of ratepayers, bill reductions are
considered as a benefit under the Participants Test. Staff believes that eliminating the RIM Test and its
analysis of lost revenues would restrict the Commission’s statutory flexibility
to consider a wide array of cost-effectiveness data upon which to determine, in
light of variable market conditions, the overall cost effectiveness of a
potential DSM measure.
Staff also believes that the spectrum of cost-effectiveness
tests required by staff’s recommended amendments to the rule will provide the
Commission with a broad range of information related to the costs and benefits
of available DSM measures—data that will put the Commission in the best
position to comply with FEECA’s requirements to consider the costs and benefits
of those measures on participants, non-participants, and the general body of
ratepayers as a whole, as required by FEECA in Section 366.82(3), F.S. In
addition, the tests, the RIM Test in particular, will give the Commission at
the goal-setting stage information relevant to its statutory mandate to assess
whether potential DSM plans and programs may have an undue impact on rates, as
required by FEECA in Section 366.82(7), F.S.
For these reasons, staff recommends that the Stakeholders’
suggestions to eliminate the RIM Test from the Commission’s cost-effectiveness
analysis should not be accepted. Staff recommends that the Commission continue
utilizing the RIM Test as provided in the proposed amended rule in order to
establish a robust record of evidence related to cost effectiveness upon which
the Commission can set conservation goals for electric utilities in accordance
with the directives prescribed by FEECA and with the full range of flexibility
granted to the Commission by statute.
Free Rider
Considerations
Stakeholders
ask that the Commission include in the rule an explicit bar on the Commission’s
use of the two-year payback screen as a method for considering free riders. Stakeholders
argue that the payback screen as historically applied by the Commission eliminates
many of the most common and cost-effective measures available, including many
that would benefit low-income customers. They assert that eliminating the two-year
payback screen would roughly double the cost-effective savings potential of DSM
goals. Stakeholders further assert that the application of a payback screen lacks
evidentiary basis, and they suggest that the rule should require utilities to
apply evidence-based methodologies that are consistent with industry standard
practices to consider overlapping measures, rebound effects, free riders, and
interactions with building codes and appliance efficiency standards. Stakeholders
also suggest that free ridership should be addressed in the program design
phase and through post-implementation evaluation, measurement, and verification
(EM&V) to track and assess free rider concerns.
FEECA requires that in developing
the goals, the Commission must take into consideration “the costs and benefits
to the general body of ratepayers as a whole, including utility incentives and
participant contributions.” See Section
366.82(3)(b), F.S. Additionally, FEECA requires the Commission to consider the
“need for incentives to promote . . . energy efficiency and demand-side
renewable energy systems.” See Section
366.82(3)(c), F.S. Furthermore, FEECA provides in Section 366.82(5), F.S., that
the Commission shall consider information related to the pursuit of a
“least-cost strategy, including non-utility
programs targeted at reducing and controlling the per capita use of
electricity in the state” as well as the impact of building codes and appliance
efficiency standards on “the need for utility-sponsored
conservation and energy efficiency measures and programs.” (emphasis added). In
approving plans and programs for cost recovery, the Commission “shall have the
flexibility to modify or deny plans or programs that would have an undue impact
on rates.” See Section 366.82(7), F.S.
It is from these provisions that the Commission derives its statutory mandate
to consider “free riders” in analyzing the cost effectiveness of a potential
DSM measure.
In the Commission’s DSM
goal-setting and plan-approval processes, the term “free rider” describes a
utility customer who accepts a utility incentive to participate in a DSM
measure even though they would likely engage in that DSM activity without the
incentive. DSM activity has the inherent benefit to participating customers of
lowering electricity consumption and bills, a benefit that operates as a natural
incentive to engage in the activity. Thus, it is reasoned that a rational
customer would participate if the benefits outweigh the cost. However, a
utility incurs costs to administer a DSM measure, including incentives given to
customers to encourage participation in the program. These incentives are then
recovered in electric rates collected from the general body of ratepayers,
including those not participating in the DSM measure, through the ECCR clause.
Thus, the Commission has historically sought to limit incentives paid for DSM
participation to customers who would likely engage in the conservation activity
without the incentive.
The Commission has historically
used a time-based “payback screen” to screen out potential free riders. A
payback period is the time it takes for a customer to recover through bill
reductions the up-front costs of installing a DSM system or adopting a DSM
activity. It is reasoned that if a DSM measure would “pay for itself” within a
certain period of time, the customer already has enough economic incentive to
adopt that system or activity, and an incentive paid to those customers are
more likely to be ineffective or superfluous. Thus, those DSM measures are
“screened out” in order to avoid collecting through general rates or the ECCR
clause incentives paid to customers who were already sufficiently incentivized
to participate. In other words, because the incentive paid to a free rider adds
no marginal participation in the DSM measure and no marginal contribution to
FEECA’s objectives, non-participants should not be required to pay for these
incentives through increased rates.
It is important to note that there
are many market factors that can change the costs and benefits to customers and
affect the length of a payback period and whether a utility incentive is
necessary. For instance, if there are rebates or tax incentives available for
adopting a particular DSM measure, the up-front cost to the customer is
reduced, and the payback period is also reduced because it will take less time
for the DSM measure to pay for itself through reduced customer bills.
Similarly, if fuel costs are high, the customer will realize greater bill
reductions, and the DSM measure will take less time to pay for itself.
Conversely, low fuel costs and an absence of rebates or tax incentives would
result in a longer payback period, and where a DSM measure has a longer payback
period, more customers are likely to require the encouragement of utility
incentives in order to participate. Thus, staff believes it is important that
the Commission maintain a flexible and responsive approach to considering free
ridership under whatever market conditions exist at the time of future
goal-setting proceedings.
Further, when a DSM measure is
“screened out” by a time-based payback screen, that in no way indicates that
the DSM measure will be entirely abandoned or that Florida’s electricity
customers will be deprived of any conservation or efficiency benefits the DSM
measure could have produced. In fact, the measures are screened out of a utility’s
DSM plan precisely because customers are likely to participate in the DSM measure
without utility incentives. To that end, the payback screen analysis provides
insight as to what types of measures the Commission could include in utility
educational programs, such as audits. By redirecting some utility DSM spending
from incentives and program administration to educational efforts that inform customers
about these quick pay-back efficiency options, the Commission can leverage the
inherent benefits of DSM activity to incentivize customers to adopt the “screened
out” measure, thereby advancing the goals of FEECA while reducing the overall
cost to be passed on to the general body of ratepayers. Thus, FEECA’s
priorities can still be advanced, and the general body of ratepayers can still experience
the associated benefits despite a measure being “screened out” of a utility’s
DSM portfolio.
Stakeholders ask the Commission to
amend the rule to expressly eliminate the use of a time-based payback screen in
favor of post-implementation EM&V practices performed by utilities, a costly
method that does not prevent free rider participation on the front end and thus
increases costs passed on to non-participants through the ECCR clause. Contrary
to Stakeholders’ assertion that the application of a payback screen lacks
evidentiary basis, the Commission has repeatedly considered testimony
supporting the application of a payback screen as a method of considering free
ridership and addressing the appropriate length of the payback period.
Importantly, the Commission has also over-ruled the results of the payback
screen and, in order to capture more potential savings through available DSM
programs, included in utilities’ residential goals DSM measures that were
initially screened out by a two-year payback screen.
Staff recommends that the
Commission not amend the rule in a way that forecloses its ability to use a
time-based payback screen and that the Commission not limit its statutory discretion
and flexibility to account for and respond to variable market factors that
impact the naturally-occurring incentives of DSM activity. While the
application of a time-based payback screen has never been prescribed by
Commission rule, and is not prescribed by the recommended rule language, the
methodology continues to offer the Commission a valuable tool for considering
free ridership and, when the Commission finds its application supported by
evidence, for avoiding undue impact on the costs passed on to non-participating
customers, as required by FEECA in Sections 366.82(3), (5), and (7), F.S.
Stakeholders
also suggest that the Commission exempt from standard free ridership
considerations DSM programs and measures designed for low-income customers in
order to expand access to utility-sponsored DSM programs.
For the
reasons stated above with respect to cost-effectiveness analysis, staff does
not recommend that the Commission exempt low-income programs from free rider
considerations. Further, staff believes that free ridership in a DSM measure
directly affects the utility incentive costs passed on to the general body of
ratepayers, and thus that exempting any measures from standard free ridership
considerations would violate FEECA’s directives under Sections 366.82(3)(b)-(c),
F.S.
Subsection (4) Recommended Amendments
In subsection
(4), the recommended amended rule addresses the filing requirements for each electric
utility to submit a plan to meet its Commission-approved DSM goals. The recommended
amendments add specificity to what information must be included in DSM plan
filings and update language for consistency. Additionally, paragraph (4)(j) was
added to the rule, requiring utilities to file in their DSM plan an estimate of
the annual amount to be recovered through ECCR proceedings. The recommended
amendment will give the Commission an opportunity at the plan-approval phase to
consider the potential costs to be passed on to customers and avoid potentially
“undue impact” in accordance with FEECA Section 366.82(7), F.S.
Additional
recommended amendments to subsection (4) update the language for consistency
and delete redundant or unnecessary language.
Summary of Comments Received & Staff
Response
Stakeholders ask the Commission to
require utilities to consider in the DSM plan design process strategies for
minimizing free ridership, in connection with the post-implementation EM&V
measures discussed above in comments on subsection (3). Additionally, Stakeholders
suggest that the rule should require utilities to consider “customer segments”
in their DSM plan filings rather than “customer classes” in order to include
low-income customers separately and distinctly from residential, commercial,
and industrial classes.
For the
reasons stated above, staff believes a consideration of free ridership is
appropriate at the goal-setting stage in connection with the Commission’s
analysis of the cost effectiveness of potential DSM measures as required by
FEECA in Section 366.82(3), F.S. Further, an estimate of the cost effectiveness
of each proposed program is required in paragraph (4)(i) of the recommended
amendments to the rule, contemplating a continuing need to account for free
riders as well as the other cost-effectiveness considerations required by subsection
(3). Thus, staff does not recommend that the Commission include additional
requirements to consider free rider concerns in subsection (4).
Additionally,
staff believes it is unnecessary and counterproductive to consider low-income
participants as a separate and distinct customer class for DSM plan-approval
purposes. As stated above, FEECA contemplates flexibility in the design of
particular measures that can be included within plans and programs that are
designed to meet approved conservation goals. Thus, considering programs for
low-income customers separately would limit the Commission’s statutory ability
to approve residential DSM programs that include less cost-effective low-income
DSM measures in a portfolio with more cost-effective measures.
Subsection (5) Recommended Amendments
Staff’s
recommended amendments to subsection (5) are to retain the provision that the
Commission has the discretion to review and modify an electric utility’s DSM
goals, language that was originally contained in subsection (2). No comments
were received on subsection (5).
Subsection (6) Recommended Amendments
Subsection
(6) of the recommended amended rule relates to the annual DSM reporting
required for each electric utility. This subsection was renumbered due to the addition
of subsection (5). It contains no substantive amendments, making only minor
updates to language for clarity and consistency. No comments were received on subsection
(6).
Minor Violation Rules Certification
Pursuant
to Section 120.695, F.S., for each rule filed for adoption, the agency head
shall certify whether any part of the rule is designated as a rule the
violation of which would be a minor violation. Rule 25-17.0021, F.A.C., is on
the Commission’s minor violation rule list because violation of the rule would
not result in economic or physical harm to a person; adverse effects on the
public health, safety, or welfare; and would not create a significant threat of
such harm. The proposed amendments to the rule would not alter the likelihood
or risk of such harms in the event of a violation. Thus, if the Commission
proposes the amendment, staff recommends that the Commission certify that Rule
25-17.0021, F.A.C., is a rule the violation of which would be a minor violation
pursuant to Section 120.695, F.S.
Statement of Estimated Regulatory Costs
Pursuant
to Section 120.54, F.S., agencies are encouraged to prepare a statement of
estimated regulatory costs (SERC) before the adoption, amendment, or repeal of
any rule. Agencies are required to prepare a SERC for any rule that will have
an adverse impact on small business or that is likely to directly or indirectly
increase regulatory costs in excess of $200,000 in the aggregate within one
year after implementation. The SERC analysis includes whether the rule will,
within five years of implementation, have an adverse impact in excess of $1
million in the aggregate on economic factors such as economic growth, private
sector job creation or employment, private sector investments, or business
competitiveness, productivity, or innovation. If expected adverse impacts or
regulatory costs exceed any of the above criteria, a proposed rule may not take
effect until it is ratified by the Legislature.
A SERC was
prepared and is appended as Attachment B. The SERC concludes that the rule will
not have an adverse impact on small business and that the rule is not likely to
directly or indirectly increase regulatory costs in excess of $200,000 in the
aggregate within one year after implementation. Further, the SERC concludes
that the rule will not likely have an adverse impact on economic growth,
private sector job creation or employment, private sector investment, or
business competitiveness, productivity, or innovation in excess of $1 million
in the aggregate within five years of implementation. None of the adverse
impact or regulatory cost criteria set forth in Section 120.541(2)(a), F.S.,
will be exceeded as a result of the recommended amendments to the rule. Thus,
the rule does not require legislative ratification pursuant to Section
120.541(3), F.S. In addition, the SERC states that the rule will have no impact
on small cities or counties and will not increase the cost to the Commission to
implement and enforce the rule. No regulatory alternatives have been submitted
pursuant to Section 120.541(1)(a), F.S.
Conclusion
Based on the foregoing, staff recommends the Commission
propose the amendment of Rule 25-17.0021, F.A.C., as set forth in Attachment A.
In addition, staff recommends that the Commission certify that Rule 25-17.0021,
F.A.C., is a rule the violation of which would be a minor rule violation
pursuant to Section 120.695, F.S.
Issue 2:
Should
this docket be closed?
Recommendation:
Yes,
if no requests for hearing or JAPC comments are filed, and no proposal for a lower
cost regulatory alternative is submitted, the rule should be filed for adoption
with the Department of State, and the docket should be closed. (Rubottom)
Staff
Analysis:
If
no requests for hearing or JAPC comments are filed, and no proposal for a lower
cost regulatory alternative is submitted pursuant to Section 120.541(1)(a),
F.S., the rule may be filed with the Department of State for adoption, and the
docket should be closed.
25-17.0021 Goals for Electric Utilities.
(1) The
Commission will shall initiate a proceeding at least once
every five years to establish numerical goals for each affected
electric utility, as defined by Section 366.82(1)(a), F.S., to reduce
the growth rates of weather-sensitive peak demand, to reduce and control the
growth rates of electric consumption, and to increase the conservation of
expensive resources, such as petroleum fuels. The Commission will set
annual Overall Residential kilowatt (KW) and kilowatt-hour
(KWH) goals and annual overall
Commercial/Industrial KW and KWH goals shall be set by the Commission for
each year over a ten-year period. The goals will shall be
based on:
(a) An
assessment of the technical potential of available measures; and
(b) Aan
estimate of the total cost-effective KW kilowatt and KWH
kilowatt-hour savings reasonably achievable through demand-side
management programs in each utility’s service area over a ten-year
period.
(2) Pursuant
to the schedule in an order establishing procedure in the proceeding to
establish demand-side management goals, each utility must file a technical
potential study. The Commission shall set goals for each utility at
least once every five years. The technical potential study must be used
to develop the proposed demand-side management goals, and it must assess the
full technical potential of all available demand-side conservation and efficiency
measures, including demand-side renewable energy systems, associated with each
of the following market segments and major end-use categories.
Residential Market Segment:
(Existing Homes and New Construction should be separately
evaluated) Major End-Use Category
(a) Building
Envelope Efficiencies.
(b) Cooling
and Heating Efficiencies.
(c) Water
Heating Systems.
(d) Lighting
Efficiencies.
(e) Appliance
Efficiencies.
(f) Peak
Load Shaving.
(g) Solar
Energy and Renewable Energy Sources.
Commercial/Industrial Market Segment:
(Existing Facilities and New Construction should be separately
evaluated) Major End-Use Category
(h) Building
Envelope Efficiencies.
(i) Cooling
and Heating Efficiencies.
(j) Lighting
Efficiencies.
(k) Appliance
Efficiencies.
(l) Power
Equipment/Motor Efficiency.
(m) Peak
Load Shaving.
(n) Water
Heating Systems.
(o) Refrigeration/Freezing
Equipment.
(p) Solar
Energy and Renewable Energy Sources.
(q) High
Thermal Efficient Self Service Cogeneration.
Each utility’s filing must describe how the technical
potential study was used to develop the goals filed pursuant to subsection (3)
below, including identification of measures that were analyzed but excluded
from consideration. The Commission on its own motion or petition by a
substantially affected person or a utility may initiate a proceeding to review
and, if appropriate, modify the goals. All modifications of the approved goals,
plans and programs shall only be on a prospective basis.
(3) Pursuant
to the schedule in an order establishing procedure in the proceeding to
establish demand-side management goals, each utility must file its proposed
demand-side management goals. In a proceeding to establish or modify
goals, each utility shall propose numerical goals for the ten year period and
provide ten year projections, based upon the utility’s most recent planning
process, of the total, cost-effective, winter and summer peak demand (KW) and
annual energy (KWH) savings reasonably achievable in the residential and commercial/industrial
classes through demand-side management. Each utility must also file
demand-side management goals developed under two scenarios: one scenario that
includes potential demand-side management programs that pass the Participant
and Rate Impact Measure Tests, and one scenario that includes potential
demand-side management programs that pass the Participant and Total Resource
Cost Tests, as these terms are used in Rule 25-17.008, F.A.C. Each
utility’s goal projections projection must be based on
the utility’s most recent planning process and must shall reflect the
annual KW and KWH savings, over a ten-year period, from potential demand-side
management programs with consideration of overlapping measures, rebound
effects, free riders, interactions with building codes and appliance efficiency
standards, and the utility’s latest monitoring and evaluation of conservation
programs and measures. In addition, for each potential demand-side
management program identified in the proposed goals and in each scenario
described above, each utility must provide overall estimated annual program
costs over a ten-year period. Each utility’s projections shall be based
upon an assessment of, at a minimum, the following market segments and major
end-use categories.
Residential Market Segment:
(Existing Homes and New Construction should be separately
evaluated) Major End-Use Category
(a) Building-Envelope
Efficiencies.
(b) Cooling
and Heating Efficiencies.
(c) Water
Heating Systems.
(d) Appliance
Efficiencies.
(e) Peakload
Shaving.
(f) Solar
Energy and Renewable Energy Sources.
(g) Renewable/Natural
gas substitutes for electricity.
(h) Other.
Commercial/Industrial Market Segment:
(Existing Facilities and New Construction should be separately
evaluated) Major End-Use Category
(i) Building
Envelope Efficiencies.
(j) HVAC
Systems.
(k) Lighting
Efficiencies.
(l) Appliance
Efficiencies.
(m) Power
Equipment/Motor Efficiency.
(n) Peak
Load Shaving.
(o) Water
Heating.
(p) Refrigeration
Equipment.
(q) Freezing
Equipment.
(r) Solar
Energy and Renewable Energy Sources.
(s) Renewable/Natural
Gas substitutes for electricity.
(t) High
Thermal Efficient Self Service Cogeneration.
(u) Other.
(4) Within 90
days of a final order establishing or modifying goals, each utility must
file its demand-side management plan that includes the programs to meet the
approved goals, along with program administrative standards that include a
statement of the policies and procedures detailing the operation and
administration of each program. or such longer period as approved by the
Commission, each utility shall submit for Commission approval a demand side
management plan designed to meet the utility’s approved goals. The
following information must shall be filed submitted
for each demand-side management program included in the utility’s
demand-side management plan for a ten-year projected horizon period:
(a) The program
name;
(b) The program
start date;
(c) A
statement of the policies and procedures detailing the operation and
administration of the program;
(c) (d)
The total number of customers, or other appropriate unit of
measure, in each class of customer (i.e. residential, commercial,
industrial, etc.) for each calendar year in the planning horizon;
(d) (e)
The total number of eligible customers, or other appropriate unit
of measure, in each class of customers (i.e., residential, commercial,
industrial, etc.) for each calendar year in the planning horizon;
(e) (f)
An estimate of the annual number of customers, or other
appropriate unit of measure, in each class of customers projected
to participate in the program for each calendar year of the planning horizon,
including a description of how the estimate was derived;
(f) (g)
The cumulative penetration levels of the program by calendar year
calculated as the percentage of projected cumulative participating customers,
or appropriate unit of measure, by year to the total customers eligible
to participate in the program;
(g) (h)
Estimates on an appropriate unit of measure basis of the per customer and
program total annual KWH reduction, winter KW reduction, and summer KW
reduction, both at the customer meter and the generation level, attributable to
the program. A summary of all assumptions used in the estimates and a list of
measures within the program must will be included;
(h) (i)
A methodology for measuring actual KW kilowatt and KWH kilowatt-hour
savings achieved from each program, including a description of research design,
instrumentation, use of control groups, and other details sufficient to ensure
that results are valid;
(i) (j)
An estimate of the cost-effectiveness of the program using the
cost-effectiveness tests required pursuant to Rule 25-17.008, F.A.C. If the
Commission finds that a utility’s conservation plan has not met or will not
meet its goals, the Commission may require the utility to modify its proposed
programs or adopt additional programs and submit its plans for approval.
(j) An
estimate of the annual amount to be recovered through the energy conservation
cost recovery clause for each calendar year in the planning horizon.
(5) The
Commission may, on its own motion or on a petition by a substantially affected
person or a utility, initiate a proceeding to review and, if appropriate,
modify the goals. All modifications of the approved goals, plans, and programs
will be on a prospective basis.
(6) (5)
Each utility must shall submit an annual report no later than
March 1 of each year summarizing its demand-side management plan
and the total actual achieved results for its approved demand-side
management plan in the preceding calendar year. The report must shall
contain, at a minimum, a comparison of the achieved KW and KWH
reductions with the established Residential and Commercial/Industrial goals,
and the following information for each approved program:
(a) The name of
the utility;
(b) The name of
the program and program start date;
(c) The calendar
year the report covers;
(d) The tTotal
number of customers, or other appropriate unit of measure,
by customer class for each calendar year of the planning horizon;
(e) The tTotal
number of customers, or other appropriate unit of measure,
eligible to participate in the program for each calendar year of the
planning horizon;
(f) The tTotal
number of customers, or other appropriate unit of measure,
projected to participate in the program for each calendar year of the
planning horizon;
(g) The
potential cumulative penetration level of the program to date calculated as the
percentage of projected participating customers to date to the total eligible
customers in the class;
(h) The actual
number of program participants and the current cumulative number of
program participants;
(i) The actual
cumulative penetration level of the program calculated as the percentage of
actual cumulative participating customers to the number of eligible customers
in the class;
(j) A comparison
of the actual cumulative penetration level of the program to the potential
cumulative penetration level of the program;
(k) A
justification for any variance variances greater larger
than 15% from for the annual goals established by the Commission;
(l) Using
on-going measurement and evaluation results the annual KWH reduction, the
winter KW reduction, and the summer KW reduction, both at the meter and the
generation level, per installation and program total, based on the utility’s
approved measurement/evaluation plan;
(m) The per
installation cost and the total program cost of the utility;
(n) The net
benefits for measures installed during the reporting period, annualized over
the life of the program, as calculated by the following formula:
annual benefits = Bnpv × d/[1 - (1+d)-n ]
where
|
Bnpv
|
=
|
cumulative present value of the net benefits over the life of
the program for measures installed during the reporting period.
|
|
d
|
=
|
discount rate (utility’s after tax cost of capital).
|
|
n
|
=
|
life of the program.
|
Rulemaking Authority 350.127(2),
366.05(1), 366.82(1)-(4) FS. Law Implemented 366.82(1)-(4) FS.
History–New 4-30-93, Amended .
