| (a) Purpose and applicability. This section allows
an electric utility that owns and operates a transmission or distribution
system to file a resiliency plan to enhance the resiliency of the
electric utility's transmission and distribution system. The requirements
of this section will be construed, to the extent practicable, to reflect
the following:
(1) Each transmission and distribution system has different
system characteristics and faces different resiliency events and resiliency-related
risks. The ability to precisely define, measure, and address these
events and risks varies. Terms such as "event," "risk," "criteria,"
and "metric" will be construed pragmatically to provide each utility
with the flexibility to develop a well-tailored and systematic approach
to improving the resiliency of its system.
(2) A utility seeking approval of a resiliency plan
bears the burden of proof on each aspect of its resiliency plan. Nothing
in this section categorically limits the type of evidence that a utility
may use to meet this burden. The weight given to each piece of evidence
will be determined by the commission on a case-by-case basis based
on the relevant facts and circumstances. Provisions contained in this
section addressing the weight of certain types of evidence are advisory
only.
(b) Definitions. The following terms, when used in
this section, have the following meanings unless the context indicates
otherwise.
(1) Distribution invested capital -- The parts of the
electric utility's invested capital that are categorized or properly
functionalized as distribution plant and, once they are placed into
service, are properly recorded in Federal Energy Regulatory Commission
(FERC) Uniform System of Accounts 303, 352, 353, 360 through 374,
391, and 397. Distribution invested capital includes only costs: for
plant that has been placed into service or will be placed into service
prior to rates going into effect; that comply with PURA, including §36.053
and §36.058; and that are prudent, reasonable, and necessary.
Distribution invested capital does not include: generation-related
costs; transmission-related costs, including costs recovered through
rates set pursuant to §25.192 of this title (relating to Transmission
Service Rates), §25.193 of this title (relating to Distribution
Service Provider Transmission Cost Recovery Factors (TCRF)), or §25.239
of this title (relating to Transmission Cost Recovery Factor for Certain
Electric Utilities); indirect corporate costs; capitalized operations
and maintenance expenses; and distribution invested capital recovered
through a separate rate, including a surcharge, tracker, rider, or
other mechanism.
(2) Resiliency cost recovery rider (RCRR) billing determinant
-- Each rate class's annual billing determinant (kilowatt-hour, kilowatt,
or kilovolt-ampere) for the most recent 12 months ending no earlier
than 90 days prior to an application for a Resiliency Cost Recovery
Rider, weather-normalized and adjusted to reflect the number of customers
at the end of the period.
(3) Resiliency event -- an event involving extreme
weather conditions, wildfires, cybersecurity threats, or physical
security threats that poses a material risk to the safe and reliable
operation of an electric utility's transmission and distribution systems.
A resiliency event is not primarily associated with resource adequacy
or an electric utility's ability to deliver power to load under normal
operating conditions.
(4) Resiliency-related distribution invested capital
-- Distribution invested capital associated with a resiliency plan
approved under this section that will be placed into service before
or at the time the associated rates become effective under this section,
and that are not otherwise included in a utility's rates.
(5) Resiliency-related net distribution invested capital
-- Resiliency-related distribution invested capital that is:
(A) adjusted for accumulated depreciation and any changes
in accumulated deferred federal income taxes, including changes to
excess accumulated deferred federal income taxes, associated with
all resiliency-related distribution invested capital included in the
electric utility's RCRR;
(B) reduced by the amount of net plant investment associated
with any distribution invested capital included in a utility's rates
that is retired or replaced, at the time the associated rates become
effective under this section, by resiliency-related distribution invested
capital; and
(C) further adjusted to remove accumulated depreciation
and accumulated deferred federal income taxes associated with distribution
invested capital included in a utility's rates that is retired or
replaced, at the time the associated rates become effective under
this section, by resiliency-related distribution invested capital.
(6) Weather-normalized -- Adjusted for normal weather
using weather data for the most recent ten-year period prior to the
year from which the RCRR billing determinants are derived.
(c) Resiliency Plan. An electric utility may file a
plan to prevent, withstand, mitigate, or more promptly recover from
the risks posed by resiliency events to its transmission and distributions
systems. A resiliency plan may be updated, but the updated plan must
not take effect earlier than three years from the date of approval
of the electric utility's most recently approved resiliency plan.
(1) Resiliency measures. A resiliency plan is comprised
of one or more measures designed to prevent, withstand, mitigate,
or more promptly recover from the risks posed to the electric utility's
transmission and distribution systems by resiliency events, as described
in subsection (d) of this section. Each measure must utilize one or
more of the following methods:
(A) hardening electric transmission and distribution
facilities;
(B) modernizing electric transmission and distribution
facilities;
(C) undergrounding certain electric distribution lines;
(D) lightning mitigation measures;
(E) flood mitigation measures;
(F) information technology;
(G) cybersecurity measures;
(H) physical security measures;
(I) vegetation management; or
(J) wildfire mitigation and response.
(2) Contents of the resiliency plan. The resiliency
plan must be organized by measure, including a description of any
activities, actions, standards, services, procedures, practices, structures,
or equipment associated with each measure.
(A) The resiliency plan must identify, for each measure,
one or more risks posed by resiliency events that the measure is intended
to prevent, withstand, mitigate, or more promptly recover from.
(i) The resiliency plan must explain the electric utility's
prioritization of the identified resiliency event and, if applicable,
the prioritization of the particular geographic area, system, or facilities
where the measure will be implemented.
(ii) The resiliency plan must include evidence of the
effectiveness of the measure in preventing, withstanding, mitigating,
or more promptly recovering from the risks posed by the identified
resiliency event. The commission will give greater weight to evidence
that is quantitative, performance-based, or provided by an independent
entity with relevant expertise.
(iii) A resiliency plan must explain the expected benefits
of the resiliency measures including, as applicable, reduced system
restoration costs, reduction in the frequency or duration of outages
for customers. and any improvement in the overall service reliability
for customers, including the classes of customers served and any critical
load designations.
(iv) The electric utility must identify if a resiliency
measure is a coordinated effort with federal, state, or local government
programs or may benefit from any federal, state, or local government
funding opportunities.
(v) The resiliency plan must explain the selection
of each measure over any reasonable and readily-identifiable alternatives.
The resiliency plan must contain sufficient analysis and evidence,
such as cost or performance comparisons, to support the selection
of each measure. In selecting between measures, whether a measure
would support the plan's systematic approach may be considered.
(vi) The resiliency plan must identify any measures
that may require a transmission system outage to implement. The electric
utility must coordinate with its independent system operator before
implementing these measures. Upon request, the electric utility must
provide its independent system operator, using mutually-agreed to
transfer and data security procedures, a complete copy of its resiliency
plan.
(B) Resiliency events.
Cont'd... |
