04 N.C. Admin. Code 11 R08-60A - BIENNIAL INTEGRATED RESOURCE PLANNING AND CARBON PLAN FILINGS
(a) Purpose. -
The purpose of this rule is to implement the provisions of G.S. 62-2(a)(3a),
62-110.1 and G.S. 62-110.9. The Carbon Plan constitutes the least cost
integrated resource planning process for electric public utilities subject to
G.S. 62-110.9 and the process for assessing and updating the integrated
resource plan and the Carbon Plan for those utilities are therefore
consolidated. The consolidated integrated resource plan and Carbon Plan (CPIRP)
shall be reviewed every two years and may be adjusted as necessary in the
determination of the Commission and the electric public utilities.
(b) Applicability. - This rule is applicable
to Duke Energy Progress, LLC, and Duke Energy Carolinas, LLC, each of which is
an "electric public utility" as defined in G.S. 62-110.9.
(c) Definitions. - As used in this rule, the
following definitions shall apply:
(1) "Base
Planning Period" shall mean the 15-year period from the start of the year
following the date the CPIRP is filed.
(2) "Carbon Neutrality Planning Horizon"
shall mean the period beyond the Base Planning Horizon that is designed to
ensure that the electric public utilities remain on the least cost path towards
achieving carbon neutrality (as defined by G.S. 62-110.9(ii)) consistent with
the requirements of G.S. 62-110.9.
(d) Consolidated Carbon Plan and Integrated
Resource Plan. - An electric public utility shall develop and keep current a
proposed CPIRP to determine the planned generation and resource mix that
complies with the requirements set forth in G.S. 62-110.9. The CPIRP shall
incorporate, at a minimum, the following:
(1)
Base Planning for Native Load Requirements and Firm Planning Obligations. - The
CPIRP shall include a forecast of native load requirements for the Base
Planning Period (including known and quantified load reduction measures taken
by wholesale customers pursuant to their FERC-jurisdictional wholesale power
contracts) and other system capacity or firm energy obligations extending
through at least one summer and one winter peak; supply-side resources
(including owned or leased generation capacity and firm purchased power
arrangements) and grid edge resources (including demand-side management
programs, rate designs, voltage control, customer-sited generation and storage,
and energy efficiency) expected to satisfy those loads; and the reserve margin
thus produced.
(2) Long-Term
Planning for Carbon Neutrality. - The CPIRP shall include a longer-term
planning forecast beyond the Base Planning Period that is designed to ensure
that the electric public utilities remain on a path that complies with the
provisions set forth in G.S. 62-110.9. For purposes of analyzing resource needs
to achieve carbon neutrality beyond the Base Planning Period, the electric
public utilities may use simplifying assumptions and analytical approaches
recognizing the inherent uncertainty in long-range planning and the ability to
make planning adjustments in future updates to the CPIRP.
(3) Modeling Resource Needs Over Base
Planning Period and Carbon Neutrality Planning Horizon. - The CPIRP shall
include, at a minimum, a comprehensive analysis of all resource options
(demand-side and supply-side) considered by the electric public utilities to
serve native load requirements and firm planning obligations during the Base
Planning Period and the Carbon Neutrality Planning Horizon in a manner that
maintains or improves upon the adequacy and reliability of the existing grid as
required by G.S. 62-110.9(3). The electric public utilities shall analyze
potential resource options and combinations of resource options to serve its
system needs, taking into account the sensitivity of their analysis to
variations in future estimates of peak load, energy requirements, and other
significant assumptions, including, but not limited to, the risks associated
with extreme weather conditions, fuel costs, construction/implementation costs,
and the costs of complying with environmental regulations. Additionally, this
analysis should account for, as applicable, system operations, compliance with
state and federal regulations, and other qualitative factors.
(4) Resource Portfolios. - Each updated CPIRP
shall include several resource portfolios developed with the purpose of fairly
evaluating the range of demand-side, supply-side, energy storage, and other
technologies available to meet the electric public utilities' service
obligations during the Base Planning Period and the Carbon Neutrality Planning
Horizon. For each resource portfolio, the electric public utilities shall
identify planned resource additions and retirements, projected carbon emission
reductions, present value revenue requirements over the Base Planning Period
and the Carbon Neutrality Planning Horizon and explain whether, and if so to
what extent, the electric public utilities plan to use offsets as allowed by
G.S. 62-110.9 as part of the least cost path to achieving carbon neutrality. In
addition, each CPIRP filed prior to 2030 shall include at least one resource
portfolio that achieves the 70% reduction in carbon dioxide emissions by 2030.
(5) Evaluation of Resource Options.
- As part of its CPIRP process, each electric public utility shall consider and
compare a comprehensive set of potential resource options, including both
demand-side and supply-side options, to determine the least cost combination
(on a long-term basis) of resource options for reliably meeting the anticipated
needs of its system in achieving the State's authorized carbon reduction goals.
The CPIRP should include an assessment of power generation, transmission and
distribution, grid modernization, energy storage, energy efficiency measures,
demand-side management, and the latest technological breakthroughs to achieve
the least cost path consistent with the requirements of G.S. 62-110.9.
(6) Ensuring Resource Adequacy and
Reliability. - Each updated CPIRP shall describe how the proposed CPIRP ensures
that generation and resource changes presented in the plan maintain or improve
upon the adequacy and reliability of the existing grid. This analysis should
address the electric public utilities' assessment of and plans to maintain
appropriate planning reserve margins and maintain or improve the resource
adequacy of their systems.
(7)
Resource Selection. - Each updated CPIRP shall identify the generation
facilities and other resources proposed to be selected by the Commission
pursuant to and subject to the requirements of G.S. 62-110.9(2). To the extent
resources are selected based upon resource diversity, the electric public
utilities shall provide additional support for their decisions based on the
costs and benefits of alternatives to achieve the authorized carbon reduction
goals and meet the requirements of G.S. 62-110.9.
(8) Execution. - Each updated CPIRP shall
include a near-term action plan that the electric public utilities propose to
execute over the near term, identifying specific demand-side and supply-side
development, procurement, and retirement activities, including upgrades to the
transmission system necessary to interconnect new supply-side resources. The
proposed near-term action plan should identify whether it is sufficient to
support all of the resource portfolios identified pursuant subsection (d)(4).
If the proposed near-term action is not sufficient to support any of the
identified resource portfolios, the CPIRP shall identify any additional
activities that would be necessary. The CPIRP should also identify longer-term
resource planning risks, strategies, or other considerations that the electric
public utilities are monitoring that could impact achieving the State's carbon
reduction goals in a manner that complies with the requirements set forth in
G.S. 62-110.9.
(e)
Filings.
(1) By September 1, 2023, and every
two years thereafter, the electric public utilities shall file with the
Commission their proposed CPIRP, together with all information required by
subsection (f) of this rule. This CPIRP shall propose resources to be selected
and a near-term action plan to be approved by the Commission for execution
prior to Commission approval of the next succeeding CPIRP. Contemporaneous with
filing the CPIRP, the electric public utilities make available complete CPIRP
modeling input and output data files, as well as their method underlying the
use of all modeling software and process steps utilized in the CPIRP, to the
Public Staff and intervenors, subject to appropriate confidentiality
protections.
(2) Each CPIRP shall
include an update on the progress the electric public utilities have made to
advance the near-term action plan in the most recently approved CPIRP.
(3) If an electric public utility
considers certain information in its biennial comprehensive CPIRP to be
proprietary, confidential, and within the scope of G.S. 132-1.2, the electric
public utility may designate the information as "confidential" and file it
under seal.
(f) Contents
of Biennial CPIRP. - The electric public utilities shall include in each
updated CPIRP the following:
(1) Forecasts of
Load, and Demand-Side and Supply-Side Resources. - The forecasts filed as part
of the CPIRP shall include descriptions of the methods, models, and assumptions
used by the electric public utilities to prepare their gross and net peak load
in megawatts (MW) and energy sales (MWh) forecasts and the variables used in
the models. The forecasts filed by the electric public utilities shall include,
at a minimum, the following:
(i) The most
recent ten-year history and a forecast of customers by each customer class, the
most recent ten-year history and a forecast of energy sales (MWh) by each
customer class, and the most recent ten-year history and a forecast of the
electric public utility's summer and winter peak load (MW);
(ii) A detailed calculation of the impact of
grid edge resources on gross load, including comparably quantified and verified
information provided by wholesale customers within the electric public
utility's balancing area, and an explanation of why those resources are treated
as load modifying or as a resource modeled on the supply side;
(iii) The electric public utility's forecast
for at least the Base Planning Period, including peak loads for summer and
winter seasons of each year, annual energy forecasts, reserve margins, and load
duration curves, with and without projected demand-side or supply-side resource
additions. The forecast shall also indicate the projected effects of grid edge
resources on the forecasted annual energy and peak loads on an annual basis for
the Base Planning Period, and these effects also may be reported as an
equivalent generation capacity impact; and
(iv) For new technologies that may have
significant impacts on the electric public utility's net load forecast, such as
sector or process electrification or load modifying technologies, the electric
public utility should provide a description of the forecast methodology and
projections.
(2)
Generating Facilities and Energy Storage. - The electric public utilities shall
provide the following data for their owned existing and planned electric
generating facilities (including planned additions and retirements, but
excluding cogeneration and small power production) and energy storage systems:
(i) Existing Generation. - The electric
public utilities shall include a list of existing generation resources in
service, with the information specified below for each listed resource. The
information shall be provided for the Base Planning Period:
a. Type of fuel(s) used by each generating
unit;
b. Generating unit
characteristics (type of unit, i.e., CT, nuclear, etc., summer and winter
capacity ratings, in-service date, and planned retirement date, if applicable);
c. Location of each existing
generating unit;
d. A list of
generating units for which there are specific plans for life extension,
refurbishment, or upgrading. The reporting electric public utility shall also
provide the expected (or actual) date the unit is, or is expected to be,
removed from service, the general location, the capacity rating upon return to
service, the expected return to service date, and a general description of the
work to be performed on the unit; and
e.Other changes to existing generating units
that are expected to increase or decrease generation capacity of the unit in
question by an amount that is plus or minus 10%, or 10 MW, whichever is
greater.
(ii) Existing
Energy Storage. - The electric public utilities shall include a summary of
their existing energy storage in service, with the information specified below
for each technology. The information shall be provided for the Base Planning
Period:
a. Storage technology (pumped storage
hydro, battery, etc.); and
b.Aggregate power capacity and designed
storage duration.
(iii)
Planned Generation. - The electric public utilities shall include a list of
planned generation resource additions, the rationale as to why each listed
resource addition was selected, and the following for each listed addition:
a. Type of fuel(s) used by each generating
unit;
b. Generating unit
characteristics (type of unit, i.e., CT, battery, etc., summer and winter
capacity ratings, in-service date, and planned retirement date, if applicable);
c. Location of each planned
generating unit to the extent such location has been determined; and
d.Summaries of the analyses supporting any
new generation additions included in the forecast for the Base Planning Period,
including its designation as baseload capacity, if applicable.
(iv) Planned Energy
Storage Additions. - The electric public utilities shall include a list of
planned energy storage additions, the rationale as to why each listed resource
addition was selected, and the following for each listed addition:
a. Storage technology (pumped storage hydro,
battery, etc.); and
b.Aggregate
power capacity and designed storage durations.
(3) Non-Utility Generation. - The electric
public utilities shall provide a summary of all non-utility electric generating
facilities and energy storage in their service areas, including customer-owned
and stand-by generating facilities. This summary shall aggregate capacities by
generation type (solar, hydro, biomass, etc.).
(4) Wholesale Contracts for the Purchase and
Sale of Power. -
(i) The electric public
utilities shall include a list of firm wholesale purchased power contracts
currently in effect, including the primary fuel type, capacity (including the
designation as base, intermediate, or peaking capacity), location, expiration
date, treatment of the wholesale resource in CPIRP modeling after expiration,
and volume of purchases actually made since the last CPIRP for each contract.
(ii) The electric public utilities
shall discuss the results of any Request for Proposals (RFP) that the electric
public utilities have issued for purchases of solar generation from third
parties and for acquisition for utility ownership and, as applicable, RFPs for
acquisition, transfer, or engineering, procurement and construction of other
selected generation or storage resources since the last CPIRP. This discussion
shall include a description of each RFP, the number of entities responding to
the RFP, the number of proposals received, the terms of the proposals, and an
explanation of why the proposals were accepted or rejected. The discussion
shall also address how the results of the most recent RFP completed during the
biennial CPIRP period are incorporated into the electric public utilities'
analysis of their long-range energy and capacity needs. If any of this
information is readily accessible in documents already filed with the
Commission, the electric public utilities may incorporate by reference the
document or documents in the CPIRP, so long as the electric public utilities
provide the docket number and the date of filing.
(iii) The electric public utilities shall
include a list of the wholesale power sales contracts for the sale of capacity
or firm energy for which the electric public utilities have committed to sell
power during the Base Planning Period, the identity of each wholesale entity to
which the electric public utilities have committed itself to sell power during
the planning horizon, the number of MWs on an annual basis for each contract,
the length of each contract, and the type of each contract (e.g., native load
priority, firm, etc.).
(5) Demand-Side Management and Energy
Efficiency. - The electric public utilities shall include an assessment of the
portfolio of existing and future grid edge resources including demand-side
management and energy efficiency programs consistent with the most recently
filed DSM/EE cost recovery rider filed by the electric public utilities
pursuant to Rule R8-69 and G.S. 62-133.9(c). The electric public utilities
shall appropriately reflect grid edge resources as either load modifiers or as
a resource considered on the supply side based upon the operating
characteristics of the resource. For purposes of utility planning, the electric
public utilities shall model energy efficiency as a load modifying resource,
ensuring its priority in utility planning. The electric public utilities'
modeling of the load modification associated with energy efficiency shall
include low, base, and high cases.
(6) Transmission System Planning and
Facilities. -
(i) Transmission System
Planning - The electric public utilities shall discuss the adequacy of the
transmission system and identified future transmission needs (100 kV and
above). With respect to future needs, the electric public utilities shall
include an overview of the electric public utilities' local and regional
transmission planning process, a discussion of how the most recently approved
CPIRP was incorporated into the electric public utilities' transmission
planning processes, and discussion of the identified needs, as well as planned
transmission lines and facilities, appearing in the most recent local
transmission planning report that, as identified in that report, could
reasonably be placed into service during the Base Planning Period.
(ii) Planned Improvements - The electric
public utilities shall include a list of planned, new or to be upgraded,
transmission lines (100 kV or over) and transformers (low side voltage 100 kV
or over) which are under construction or for which there are specific plans to
be constructed during the Base Planning Period, including the capacity and
voltage levels, location, and schedules for completion and operation.
a.The electric public utilities shall
describe how applicable planned improvements may enable specific siting of new
resources or provide expected and planned impacts to other resource
interconnection constraints or operations of the systems.
(iii) Non-wires alternatives - The electric
public utilities shall provide an overall assessment methodology for non-wires
alternatives, including a descriptive summary of analysis performed or used by
the electric public utilities in the assessment of alternative solutions to
transmission constraints that may be more cost-effective, such as locating
generation in less constrained areas or strategically locating energy storage
resources or the dispatch of distributed energy resources of the wholesale
customers located within the electric public utilities' balancing area to the
extent the electric public utilities have rights to dispatch, operate, and
control such resources in the same manner as the electric public utilities' own
resources.
(7) Modeling
of System Operations. - The electric public utilities shall provide a
discussion of or applicable study addressing how electric public utility
relationships and system interconnections are modeled in the CPIRP including
how relevant planning and operation functions influence modeling, such as
modeled balancing areas and interconnections, joint dispatch agreements, energy
exchange markets, and other future operating efficiencies planned by the
electric public utilities during the Base Planning Period.
(i) The electric public utilities shall also
include, as applicable, a discussion of other planning factors influencing
CPIRP modeling, such as corporate emission reduction goals or generation
resource restrictions, legal or regulatory requirements from other authorities
or jurisdictions that materially impact the resource plan, and the impact of
these factors on the electric public utilities' long-range resource plans over
the Base Planning Period and Carbon Neutrality Planning Horizon, as applicable.
(ii) The electric public utilities
shall discuss the results that are expected from integrated (generation,
transmission and/or distribution) systems planning processes, how integrated
systems planning is used in the CPIRP process, and the impact of it and their
wholesale customers' distributed energy resources and non-traditional solutions
on resource planning and load forecasting.
(8) Modeling of Generating and Energy Storage
Resources. - The electric public utilities shall include an overall modeling
framework and methodology for existing and potential generating and storage
resources, including a descriptive summary of material assumptions and analysis
performed or used by the electric public utilities in the assessment. The
electric public utilities shall also provide general information on any changes
to the methods and assumptions used in the assessment since the most recently
approved CPIRP, including supportive studies impacting assessment and selection
of resources.
(i) To the extent that an
updated unit retirement analysis is conducted as a part of the CPIRP, the
electric public utilities shall include a descriptive summary of material
assumptions and analysis performed that may impact the retirement date modeled
such as transmission requirements or replacement resource needs to enable
executable retirement of resources.
(9) Maintaining or Improving Upon the
Adequacy and Reliability of the Existing Grid. - The electric public utilities
shall provide a description of, and justification for, the methodology by which
the CPIRP will demonstrate that adequacy and reliability of the system will be
maintained or improved throughout the Base Planning Period and Carbon
Neutrality Planning Horizon. To the extent that the electric public utilities'
standards for quantifying that the reliability of the system has been
maintained has changed, the electric public utilities shall discuss the reasons
for the changes to these standards, including impacts to resource adequacy
studies, effective load carry capability studies, or other applicable
reliability studies. The electric public utilities shall also describe
coordination efforts with their wholesale customers to utilize their resources
to maintain or improve reliability.
(10) Load, Capacity, and Reserve Tables. -
The electric public utilities shall provide a table for a reference portfolio
that shows, for both winter and summer peaks, the available capacity, wholesale
purchases and sales, capacity from non-utility generation, load (gross and net
of grid edge resources), retirements, new capacity additions, and estimated
reserve margin for each year of the Base Planning Period.
(i) The electric public utilities shall
calculate and provide a description of, and justification for, the methodology
by which the electric public utilities determine a first year of avoidable
capacity need (First Year of Avoidable Capacity).
(11) Evaluation of Resource Portfolios and
Selection of Resources. - The electric public utilities shall provide a
description and a summary of the results of their analyses of potential
resource options and combinations of resource options (demand-side and
supply-side), including relevant information pertaining to portfolio costs
(present value of revenue requirements and average retail customer bill impact
analyses), operability and reliability, and CO2 emissions. Taking into account
the resource portfolios presented in the proposed CPIRP, the electric public
utilities shall designate resources for selection by the Commission as the
proposed near-term action plan for implementation by the electric public
utilities following the Commission's final order on the proposed CPIRP. The
near-term action plan required by this Rule should discuss the specific actions
the electric public utilities propose to take over the near-term to progress
carbon emissions reductions in a least-cost manner, while maintaining or
improving reliability of the grid and continue executing least cost planning,
including actions to preserve optionality for future potential resources that
could help achieve these objectives in future updates to the CPIRP.
(12) Stakeholder Engagement Report - The
electric public utilities shall provide a summary of its stakeholder engagement
conducted pursuant to the plan described in section (h).
(g) Procedure for Review.
(1) At the time the electric public utilities
file their proposed CPIRP with the Commission pursuant to subsection (e), the
electric public utilities shall also file with the Commission testimony and
exhibits of expert witnesses supporting the proposed CPIRP.
(2) No later than 180 days after the later of
either September 1 or the filing of the electric public utilities' CPIRP, the
Public Staff and intervenors may file testimony and exhibits of expert
witnesses commenting on, critiquing, or giving alternatives to the electric
public utilities' proposed CPIRP.
(3) No later than 45 days after the filing of
intervenor testimony and exhibits, the electric public utilities may file
rebuttal testimony and exhibits of its expert witnesses.
(4) The Commission shall schedule an expert
witness hearing to review the CPIRP proposals beginning on the second Tuesday
in May following the electric public utilities' proposed CPIRP filing. The
scope of any such hearing may be limited to issues as identified by the
Commission. The Commission will also schedule one or more hearings to receive
testimony from the public at a time and place of the Commission's designation.
(5) The Commission will issue an
order adopting the next CPIRP by no later than December 31 of the year after
the year in which the proposed CPIRP is filed with the Commission.
(h) The electric public
utilities individually or jointly shall provide notice to the Commission of
their plans for engaging with interested parties at least 200 days in advance
of its planned biennial CPIRP. The notice to the Commission should provide, at
a minimum, information on how the utilities:
(1) Determined the timing, frequency, and
location of stakeholder meetings, as well as whether to hold meetings
virtually;
(2) Selected
facilitators for the meetings;
(3)
Notified stakeholders about the meetings; and
(4)Planned the structure and content of the
meetings.
Notes
State regulations are updated quarterly; we currently have two versions available. Below is a comparison between our most recent version and the prior quarterly release. More comparison features will be added as we have more versions to compare.
No prior version found.