PRELIMINARY
ENTERGY NEW ORLEANS, INC.
CITY OF NEW ORLEANS DOCKET NO. UD-08-02
2015 IRP Technical Conference #1
IRP Overview including Plans for DSM Potential Study & DSM Avoided Cost Inputs
JUNE 27, 2014
Note: All IRP materials presented here are marked “preliminary”. This is because the material is
subject to change prior to ENO’s filing of its final IRP report scheduled for October 2015.
1
PRELIMINARY
ORGANIZATION OF MATERIALS*
I.
II.
III.
IV.
Overview of IRP
Process
Impact From Joining
MISO
DSM Potential Study
DSM Avoided Cost
Inputs
• IRP Objectives &
Framework
• Energy Market
• Load Forecast
• Portfolio Design
Analytics
• Load Modifying
Resources
• Demand Side
Management
Potential Study
Process
• Benefits of ICF
• Next steps
• Capacity Market
• Avoided Energy
• Avoided Capacity
*All material presented is informational and subject to change based on
additional analysis, new information or stakeholder feedback.
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PRELIMINARY
OVERVIEW OF IRP PROCESS
IRP PLANNING OBJECTIVES
The process will seek to balance three
objectives . . .
• Consider the effects of environmental
compliance regulation on customer costs.
Reliability
Cost
While considering utilization of
natural resources and effects on the
environment . . .
• Assess risk to reliability and cost
associated with environmental concerns.
Risk Mitigation
• Assess the implications of proposed
portfolios (which include both supply-side
and demand-side resources) on the use of
natural resources and the effect on the
environment by measuring key parameters
such as:
– CO emissions, and
These objectives will be measured from a
customer perspective. That is, the IRP process
seeks to design a portfolio of resources that
meets customer power needs at the lowest
reasonable cost while considering risk.
– Natural gas use
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PRELIMINARY
OVERVIEW OF IRP PROCESS
CONCEPTUAL REQUIREMENTS OF AN IRP
The IRP considers the range of alternatives available to meet customer needs in order to develop
a preferred resource portfolio.
Requirements
Reliability
Reliability
Peaks
Cost
Stewardship
Peaks
Cost
Stewardship
Shape
Risk
Compliance
Shape
Risk
Compliance
Planning
Objectives
Load
Environmental
Projected
Load
Assess Current
Resource Position
Existing
DSM
Planning
Objectives
Environmental
Identify Future Resource
Needs & Alternatives
Existing
Existing
Generation
Transmission
(including
purchased power)
New
DSM
Alternatives
*MISO Transmission Expansion Plan
New
MISO MTEP* Changes/
Generation
Deactivations
to Existing
Units
Assess Cost
& Risk
IRP
Two Key outputs:
1) “Preferred Resource Portfolio” that
is intended to guide planning and
procurement activities.
2) “Action Pan” which creates a link
between ENO’s preferred portfolio
and the specific implementation
actions that need to be performed
during the first five years of the
planning period.
Note – The IRP guides future planning and procurement activities. However specific resource decisions
are not made during the planning process.
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PRELIMINARY
OVERVIEW OF PROCESS
PREFERRED PORTFOLIO DESIGN ANALYTICS
The Goal of the IRP is develop Preferred Portfolio that meets the IRP objective to maintain
reliability at the lowest reasonable cost recognizing the need to mitigate future risk events which
are beyond the control of ENO or its customers.
Gather Inputs;
Develop
Scenario &
Sensitivity
Cases
Run Capacity
Expansion in
AURORA1
Footprint
Run
Sensitivity
Analysis
Select
Preferred
Portfolio
Detailed MISO
South Modeling
with DSM
Optimization
Develop ENO
Portfolio Plan
For Each
Scenario
Validate
Preferred
Portfolio
The IRP is dynamic process for long-range planning that provides for flexible approach to resource
selection. The Preferred Portfolio resulting from the IRP planning process provides guidance regarding
long-term resource additions, but is not intended as static plan or pre-determined schedule for resource
additions. Actual portfolio decisions are made at the time of execution.
1AURORAxmp is
the name of an electric market simulation model which among other uses forecasts the economic commitment and
dispatch of supply side and demand side resources on an hourly basis over many years. AURORA is product of EPIS (www.epis.com). SPO under
the guidance of EPIS has customized AUROA to better simulate ENO’s participation in MISO.
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OVERVIEW OF PROCESS
PRELIMINARY
IRP OUTPUT METRICS
Portfolios will be designed to provide
reliable power . . .
All portfolios must include sufficient
capacity to meet peak load plus
contingencies.
Metric
• Planning Reserve Margin
While Considering Risks . . .
Portfolio design will consider risks relating to
total supply cost and reliability. Risks
include exposure to power price volatility
and fuel cost uncertainty.
Metrics
• Variability in Total Supply
Cost across scenarios
• Change in portfolio
rankings
Objective function is to minimize
customer cost . . .
Analysis measures total supply costs, which
include variable production cost and fixed
supply costs. In other words, all supply costs
that ultimately affect customer bills.
Metric
• Present Value of Total Supply Cost
Other Considerations & Metrics
Analysis will produce a variety of other
metrics.
Metrics
• Emissions
• Natural Gas Consumption
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PRELIMINARY
ORGANIZATION OF MATERIALS*
I.
II.
III.
IV.
Overview of IRP
Process
Impact From Joining
MISO
DSM Potential Study
DSM Avoided Cost
Inputs
• IRP Objectives &
Framework
• Energy Market
• Load Forecast
• Portfolio Design
Analytics
• Load Modifying
Resources
• Demand Side
Management
Potential Study
Process
• Benefits of ICF
• Next steps
• Capacity Market
• Avoided Energy
• Avoided Capacity
*All material presented is informational and subject to change based on
additional analysis, new information or stakeholder feedback.
7
IMPACT FROM JOINING MISO
PRELIMINARY
SUMMARY OF MISO ENERGY MARKET
ENO pays MISO to serve its load and is paid to supply energy. A locational marginal
price (“LMP”) mechanism is used which considers three components: energy,
congestion and line losses. The LMP price differs at each generation and load point
along the MISO network. The concept behind LMP is that the market price of
electricity should be the cost of supplying the next unit when supply and demand are
in balance.
The energy cost includes the cost of supplying operating reserves.
The diagram below is a simplified version of how the LMP methodology works. The
cost to serve load in the West is $30/MWh and $40/MWh in the East. If there was no
congestion the cost to serve load across both the West and the East would be
$30/MW. Note, in this simplified example line losses are assumed to be zero.
Source: Illustrative training materials
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IMPACT FROM JOINING MISO
PRELIMINARY
SUMMARY OF MISO ENERGY MARKET (CONTINUED)
MISO Operates what is commonly known as a Day Two Market:
Day ahead market (hourly energy prices for a 24 hour period)
Real Time Market (energy prices change every five minutes)
Both load and energy generated clear at locational marginal prices (“LMPs”): generally
about 95% or more in day ahead market, about 5% or less in real time market.
Although the MISO market and SPO’s generation offers determine operation of ENO’s
resources, physical control remains with SPO which provides the service to ENO and
the other Entergy operating companies.
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PRELIMINARY
IMPACT FROM JOINING MISO
MISO RULES CREATE A MARKET FOR CAPACITY
•
MISO is a “two-part” market in which capacity and energy transact and are valued
separately.
•
The existence of an annual capacity market coupled with Resource Adequacy rules
requiring load serving entities (“LSE”) to meet prescribed levels of capacity creates a
value (or opportunity cost) for capacity.
•
The objective of meeting customers power needs at the lowest reasonable cost
requires that the Capacity Value be considered in the System’s resource planning and
investment decisions.
•
Capacity Prices are determined by supply / demand conditions in MISO overall as
well as in each of the MISO Local Resource Zone (“LRZ”). ENO is in LRZ 9. Prices
are the same throughout each LRZ and can be the same or different across LRZs.
MISO North LRZs
MISO South LRZs
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9
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PRELIMINARY
IMPACT FROM JOINING MISO
SUMMARY OF MISO CAPACITY MARKET
MISO conducts an annual auction each year and each load serving entity must provide
physical capacity or capacity credits to meet its projected peak load plus reserves referred
to as a planning reserve margin requirement in MISO.
MISO South is currently oversupplied. SPO estimates the 2013 reserve margin was 39%
based on an SPO assessment of installed capacity and load.
Consequently, capacity prices have been low and are expected to be low in the near-term
reflecting the excess capacity in MISO South.
As measured by MISO for the planning year started June 1, 2014, ENO had 140 MW of
extra generating capacity meaning it did not have to purchase capacity in the MISO annual
capacity auction. The clearing price for capacity in the auction was 16.44/MW-day (can be
expressed as $6.00 per KW year).
Overtime, however, capacity prices are expected to increase as the market tightens due to
load growth, unit deactivation, etc.
When valuing DSM the current and projected cost of capacity credits or the lowest cost of
physical capacity (whichever is lower) represents the avoided cost of generating capacity
which is the primary basis for the DSM avoided capacity cost benefit.
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PRELIMINARY
IMPACT FROM JOINING MISO
LOAD MODIFYING RESOURCES
•
MISO values load modifying resources (“LMR”) on equal footing with generation resources
(supply side resources). LMR resources are any resource that can reduce demand at the
time of peak or at other times when MISO needs to reduce demand.
•
LMRs reduce a load serving entities peak load and the associated requirement to carry
reserves. For long-term planning purposes ENO assumes reserves need to equal 12% of
peak load.
•
LMRs recognized by MISO include:
•
•
•
Traditional interruptible tariffs registered with MISO.
Demand respond resources under the control of the local balancing authority (“LBA”).
Entergy operates the LBA for zone 9 which includes ENO.
LMRs lower the amount of generating capacity credits needed in MISO’s annual capacity
auction.
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IMPACT FROM JOINING MISO
Preliminary
MISO MARKET CONSTRUCT SUMMARY
ENO used to operate in a bilateral market, now it operates in an organized market
ENO serves
customer load
through energy
purchased from
MISO.
ENO
MISO
“Generators” sells output to MISO.
$
MWh
Load Serving
Entity
$
MWh
ENO receives payments from MISO for its
generation both owned and contracted
which revenues are used to offset the cost
of energy purchased to serve ENO load.
Generation (Owned & Contracts)
MISO market participation does not
change the objective that ENO is
trying to minimize customer
revenue requirements.
Customer
Cost
Load
Settlement
Cost
Base Rate
Components
of generation
costs (“NonFuel”)
Generation
Variable
Production
Cost (“Fuel &
Emissions”)
Generation
Revenues
Total Supply
Cost
Legend
Effects (cost or benefit) of
transaction flow to customer
Denotes transaction between
Utility (“LSE”) and MISO
13
PRELIMINARY
ORGANIZATION OF MATERIALS*
I.
II.
III.
Overview of IRP
Process
Impact From Joining
MISO
DSM Potential Study
DSM Avoided Cost
Inputs
• IRP Objectives &
Framework
• Energy Market
• Load Forecast
• Portfolio Design
Analytics
• Load Modifying
Resources
• Demand Side
Management
Potential Study
Process
• Benefits of ICF
• Next steps
• Capacity Market
IV.
• Avoided Energy
• Avoided Capacity
*All material presented is informational and subject to change based on
additional analysis, new information or stakeholder feedback.
14
PRELIMINARY
DSM PROCESS
DSM RESOURCES
There are two basic types of utility-sponsored DSM. Demand Response, which lowers capacity
requirements, and Energy Efficiency, which lowers both capacity and energy requirements.
Demand Response
Energy Efficiency
Load management program
that have the intended goal
of reducing or shifting load
from hours with high
electricity cost and/or
reliability problems.
Permanent changes to
electricity use through
replacement of end-use
devices with more efficient
equipment or more effective
operation of existing devices,
and any program or resource
defined as an Energy Efficiency
resource in any Energy
Efficiency rule(s) issued by the
New Orleans City Council.
Demand Response programs
may include direct load
control (such as air
conditioners and water
heaters), and interruptible
rates which include incentive
payments designed to induce
lower electricity use at times
of high wholesale market
prices or when system
reliability is jeopardized.
Generally, this type of resource
results in reduced energy
consumption across all hours
rather than just event-driven
targeted load reductions in
specific hours.
ICF International will produce a detailed DSM Potential Study For ENO and this will be
reviewed with parties to this docket and the public at the 2nd Technical Conference scheduled for October 2014
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PRELIMINARY
DSM PROCESS
TYPES OF DSM POTENTIAL
Technically
Achievable
The estimated level of energy and capacity savings that could be
achieved without consideration of cost, customer behavior or
other barriers. Assumes customers adopt 100% of what is
feasible.
X
Economically
Achievable
Cost effective sub-set of Technically Achievable potential.
Ignores customer financial constraints, behavioral issues or other
market barriers.
X
Achievable
Potential
Sub-set of Economically Achievable potential. In other words,
what is likely to be achieved given customer profile and local
market conditions. ICF Potential Study will solve for this level of
DSM.
Appropriate
For IRP
X
Not Appropriate
For IRP
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PRELIMINARY
DSM PROCESS
2014 DSM POTENTIAL STUDY PROCESS MAP
4 Standard Tests
Total Resource Cost
Program Administrator
Ratepayer Impact
Participant Test
DSM Programs that achieve a TRC
Test of 1.0 or higher are candidates for
more detailed Optimization Modeling.
Bundle Similar Programs If Needed for IRP Modeling Which Compares Supply-Side and
Demand-Side Resource Options to Meet Customers’ Needs at the Lowest Reasonable Cost
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PRELIMINARY
DSM Process
ICF CHOSEN TO CONDUCT DSM POTENTIAL STUDY
•
ENO will use ICF International to conduct the DSM Potential study for the ENO
service territory (i.e. City of New Orleans excluding Algiers*)
•
ICF’s experience producing DSM Potential Studies for ENO, the other Entergy
Operating Companies and other utilities across the U.S. will provide an independent,
unbiased expert point of view:
•
ICF conducted an ENO DSM Potential in 2009 and 2012 for ENO as well as the
other Entergy utility Operating companies.
•
ICF is currently conducting a DSM Potential Study for Entergy Louisiana
(including Algiers), Entergy Gulf States and Entergy Mississippi. The cost of the
current ENO study is modestly lower due to economies of scale.
•
In addition to its expertise pertaining to DSM, ICF can draw upon its deep knowledge
across the energy spectrum, with particular expertise in environmental issues and
environmental compliance modeling in the power sector.
•
ICF is a major contractor for the U.S. Environmental Protection Agency.
* Algiers we be part of a larger study conducted encompassing all of Entergy Louisiana’s service territory
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PRELIMINARY
ORGANIZATION OF MATERIALS*
I.
II.
III.
IV.
Overview of IRP
Process
Impact From Joining
MISO
DSM Potential Study
DSM Avoided Cost
Inputs
• IRP Objectives &
Framework
• Energy Market
• Load Forecast
• Portfolio Design
Analytics
• Load Modifying
Resources
• Demand Side
Management
Potential Study
Process
• Benefits of ICF
• Next steps
• Capacity Market
• Avoided Energy
• Avoided Capacity
*All material presented is informational and subject to change based on
additional analysis, new information or stakeholder feedback.
19
PRELIMINARY
DSM AVOIDED COST INPUTS
ENO LOAD FORECAST FOR DSM POTENTIAL STUDY
1.5
7,000
5,000
1.0
4,000
3,000
0.5
2,000
Net Energy For Load (TWh)
Total Peak Demand (GW)
6,000
1,000
0
WN Peak
10 Year
CAGR
20142024
20242034
Peak:
0.9%
1.3%
Energy:
0.95%
1.0%
Total Peak Forecast
2030
2028
2026
2024
2022
2020
2018
2016
2014
2012
2010
2008
2006
0.0
Total Eenrgy Forecast
WN Peak = Actual peak demand at the generator adjusted to normal weather.
Note: For 2013 it’s the actual peak (has not been weather normalized).
Forecast assumes no DSM spending beyond 2014
Forecast
2014
2015
2020
2025
2030
Peak (MW)
1,014
1,043
1,080
1,117
1,158
Energy (GWh)
5,250
5,461
5,763
6,046
6,359
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PRELIMINARY
DSM Avoided Cost Inputs
AVOIDED ENERGY COST IN DSM POTENTIAL STUDY
The use of avoided energy cost in the DSM Potential Study allows the examination of
hundreds of DSM measures without having to run hundreds of detailed hourly Market
Model simulations to assess which DSM programs are worthy of further study.
The cost of avoided energy for ENO will be calculated as follows using the AURORA
Market Model Nodal construct:
The AURORA model assumes Reference Case fuel price forecasts, SO2 and
NOx allowance prices and no carbon prices as of January 2014.
AURORA forecasts the Locational Marginal Price (“LMP”) of power to serve load
each hour over the twenty year IRP period for each ENO pricing node. MISO
establishes each pricing node and there are 22 pricing nodes for ENO.
The AURORA Market Model Nodal Construct has the same 22 pricing nodes.
The ENO LMPs are load weighted to come up with a load weighted hourly LMP
for ENO.
The hourly LMPs are averaged into nine time buckets each year for use in the
DSM Potential Study. The buckets are:
Summer Weekday 5X16, Weekend 2X16, and Night 7X8
Winter Weekday 5X16, Weekend 2X16, and Night 7X8
Shoulder Weekend 5X16, Weekend 2X16, Night 7X8
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PRELIMINARY
DSM Avoided Cost Inputs
AVOIDED ENERGY COST FOR DSM POTENTIAL STUDY
ENO Load Zone LMPs
$160
$140
$120
$/MWh
$100
$80
$60
$40
$20
$0
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Summer Weekday 5X16
Winter Weekday 5X16
Shoulder Weekday 5X16
Summer Weekend 2X16
Winter Weekdend 2X16
Shoulder Weekend 2X16
Summer Night 7X8
Winter Night 7X8
Shoulder Night 7X8
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PRELIMINARY
DSM Avoided Cost Inputs
AVOIDED CAPACITY COST IN DSM POTENTIAL STUDY
The cost of avoided capacity will be calculated as follows:
The forecast of the clearing price of the MISO annual capacity auction calculated on a $/kW
Year basis. This price is expected to rise over time as reserve margins tighten.
The result is multiplied by (1+ the average distribution line loss percent for each retail
customer class. The loss %’s are:
4.29% (Residential)
4.17% (Commercial)
3.48% (Government)
1.45% (Industrial)
The result is multiplied by (1+ the average transmission line loss percent) for the resource
zone that ENO is in. This value is set by MISO for the next planning year and is used for
calculating ENO’s planning reserve margin requirement. The value is 2.4% for the planning
year beginning June 2014. For planning purposes the 2.4% is kept constant each year.
The result is multiplied by (1 + a planning reserve margin). ENO uses a 12% planning
reserve margin for long-term planning.
An avoided transmission and distribution cost that comes from investing in utility sponsored
DSM is added to the result above. The avoided transmission and distribution (“T&D”) cost is
grown each year based on a forecast provided by IHS Global Insight of cost increases for
T&D spending. In 2014 avoided T&D cost is estimated to equal $24.87/kW Year.
*See MISO Business Practices Manual 011 (Resource Adequacy) Appendix L for more information
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PRELIMINARY
DSM Avoided Cost inputs
ILLUSTRATIVE AVOIDED CAPACITY COST
The avoided capacity cost from DSM for ENO varies by year. However, to provide an order of
magnitude the levelized cost of capacity over the period 2015-2034 is displayed below. The discount
rate used is ENO’s electric weighted average cost of capital which, as of 12/31/2013, is 6.93%.
Value of Avoided
Capacity Cost
(Nominal $)
Capacity at The
Meter
Residential Commercial Government Industrial
$/KW Year $/KW Year
$/KW Year
$/KW Year
$62.44
$62.44
$62.44
$62.44
Transmission Line
Losses
1.50
1.50
1.50
1.50
Distribution Line
Losses
2.68
2.61
2.17
0.90
Planning Reserves
7.99
7.99
7.93
7.78
T&D Cost
28.62
28.62
28.62
28.62
$103.23
$103.15
$102.66
$101.24
Total
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PRELIMINARY
Next Steps
NEXT STEPS
ICF continues to prepare the New Orleans DSM Potential Study.
ENO continues to prepare IRP inputs:
Define scenarios and sensitivities to be performed.
Prepare IRP input forecasts (e.g. load, fuel prices, emissions
prices and macro economic factors).
Prepares a supply-side resource Technology Assessment
(comparing the cost and performance of various supply-side
options)
Conventional technologies
Utility-scale renewable resources
Next milestone in IRP process to review DSM Potential Study
results and IRP inputs:
Technical Conference to be schedule for October 2014.
25