HomeMy WebLinkAboutMemo - Mail Packet - 12/6/2016 - Memorandum From Tim Mccollough Re: Prpa Presentation Materials On Energy Markets At The November Energy BoardUtilities
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M E M O R A N D U M
DATE: November 30, 2016
TO: Mayor Troxell and Councilmembers
FROM: Tim McCollough, Utilities Light and Power Operations Manager
THROUGH: Darin Atteberry, City Manager
Kevin R. Gertig, Utilities Executive Director
RE: PRPA Presentation Materials on Energy Markets at the November Energy Board
This memo is in response to City Manager Darin Atteberry’s request at the November 28
Leadership Planning Team meeting for staff to provide a copy to Council of Platte River Power
Authority’s (PRPA) Energy Markets presentation at the November 3 Energy Board meeting.
Bottom Line
There is the potential for the formation of a regional power market in the Rocky Mountain
region. There are benefits and risks in entering an energy market, both to PRPA and the member
City owners of PRPA. These risks and benefits vary according to the structure of the chosen
energy market, and it is premature to quantify the risk until a market formation agreement is
reached.
Background
PRPA is one of seven regional utilities considering membership in an organized power market.
The group has been in discussions over the past twelve months and appears to be close to making
a decision. While membership in the market may allow PRPA (and its wholesale customers) to
avoid some power transmission fees, it may also obligate PRPA to pay other market costs and
affect the rate controls currently exercised by Fort Collins as a municipal electric utility. Further
discussion and materials will be provided to Council by staff and PRPA as the formation of the
market progresses.
Attached with this memo you will find:
• PRPA’s Energy Markets presentation slide set to Energy Board
• The Energy Board draft minutes (abridged) that summarize the discussion
• A white paper on Energy Markets from PRPA’s staff to the PRPA Board of Directors
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Regional
Energy
Markets
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• Each Transmission Owner has its own tariff for its system
• Network service for serving load
• Point-to-Point service for moving power through a system at specific
points of receipt and delivery
• Transmission customers pay a tariff for each transmission
system used to deliver power. (Pancaked Rates)
• Pancaked Rates
• Add to cost of serving load and selling surplus power
• Hinder access to remote generation
• Could incentivize construction of duplicate “bypass” transmission
How Transmission Tariffs Work Today
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• An Independent Transmission Service Provider manages
a tariff for the Footprint.
• Benefits to PRPA and Owner Municipalities:
• Stop paying for pancaked rate to deliver wind energy to our
load
• Reduce ancillary service fees
• PRPA could exchange power to Utilities in parts of Wyoming,
South Dakota, and all of Colorado without additional
transmission cost
• PRPA could build or contract for new generation anywhere in the
footprint and bring it home under one tariff
• Common Tariff creates a foundation for organized energy
markets
How a Regional Tariff Would Work
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What is an Organized Energy
Market ? RTO/ISO?
RTO—Regional transmission organization
ISO—Independent system operator
Both types of entities are functionally the same—they operate and
manage the interstate electricity grid over a large region, dispatch
the system by means of auction/bid-based energy markets, and
provide market monitoring oversight.
A key characteristic of both ISOs and RTOs is that, in contrast with
grid operators in utility operated systems, they are not affiliated with
any market participant and thus provide the fair access to grid
services needed for a level playing field.
RTOs and ISOs dispatch the system by means of competitive
auction/bid-based energy markets, in contrast to the purely bilateral
markets in single utility operated systems.
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Organized Energy Markets, PJM
Example (Day 2 Market)
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RTO/ISO Map
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Possible Areas of Value
1. Reduced cost of third-party transmission
2. Operating reserves and services managed on a larger
footprint with market based tools
3. Transparent and open markets creating more efficient
day-ahead and hourly dispatch and marketing
4. Ability to interconnect new generation resources
anywhere in footprint
5. Reduced system-wide planning reserves
6. Improved reliability
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Transmission Owners
• Basin Electric
• Black Hills
(BHP,CLFP,BHCE)
• Colorado Springs
• Platte River
• PSCo
• Tri-State
• WAPA (LAP and CRSP)
MWTG Footprint for the Regional
Joint Tariff
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DRAFT: Energy Board Minutes
November 3, 2016
DRAFT: Fort Collins Utilities Energy Board Minutes (ABRIDGED)
Thursday, November 3, 2016
Energy Board Chairperson City Council Liaison
Pete O’Neill, 970-223-8703 Ross Cunniff, 970-420-7398
Energy Board Vice Chairperson Staff Liaison
Nick Michell, 970-215-9235 Tim McCollough, 970-305-1069
Roll Call
Board Present: Chairperson Pete O’Neill, Vice Chairperson Nick Michell, Board Members Alan Braslau,
Greg Behm, Margaret Moore, Phil Friedman
Late Arrivals: Stacey Baumgarn, Lori Nitzel
Board Absent: Mohit Chhabra
Others Present
Staff: Cyril Vidergar, Tim McCollough, Christie Fredrickson, Dan Hodges (CAMU), Tyler Marr, Ginny
Sawyer, Jen Barna, Bob Hover, Lisa Rosintoski
PRPA: Paul Davis, Andy Butcher
Members of the Public: None
Meeting Convened
Chairperson Pete O’Neill called the meeting to order at 5:30 p.m.
Announcements and Agenda Changes
The Board would like to have all memos or future correspondence distributed and posted to the
SharePoint.
The board would like to discuss of the Joint Meeting with the LUC to the end of tonight’s meeting.
Public Comment
None
Approval of October 6, 2016 Board Meeting Minutes
Amendments to the October 6, 2016 minutes were made by the Board Members and the minutes were
accepted as amended.
Intro to Energy Markets
Andy Butcher, Vice President of Power Delivery, Platte River Power Authority
(attachments available upon request)
Mr. Butcher described Colorado’s current energy market, which he believes is archaic, and explained that
it can be broken down into two markets: a transmission system market and an energy market. Currently,
each transmission owner has its own tariff for its system, and transmission customers pay a tariff for each
transmission system used to deliver power—this is also called “pancaked rates.” There are five separate
companies that have a transmission tariffs in Colorado alone. Mr. Butcher likened the markets to
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November 3, 2016
plumbing; the transmission market is similar to the pipes to your home, and water in the pipes is similar
to the energy market—someone has to put energy in them. PRPA has its own energy system (or market),
but at times it is necessary to use energy from other systems in Colorado or neighboring states. If that
happens, the way energy is currently acquired is by picking up the phone and calling someone.
Mr. Butcher’s goal is to explain that there could be a better market structure through a regional tariff. An
independent transmission service provider manages a tariff for the footprint, which eliminates pancakes.
The benefits to PRPA and owner municipalities are: no pancaked rates to deliver energy, reduced
ancillary service fees, and the ability to exchange power to utilities in parts of Wyoming, South Dakota
and all of Colorado without additional cost. PRPA could also build or contract for new generation
anywhere within the footprint and bring it home under one tariff. Overall, there could be large savings for
Platte River under this market structure. Board member Braslau pointed out that PRPA will no longer be
paying those charges, but they also will no longer receive that revenue either. Mr. Butcher said that the
amount of revenue Platte River receives for third party usage of its transmission is much smaller than the
amount it spends on purchasing transmission, so a change to a single transmission tariff is likely to be
beneficial to Platte River.
Mr. Butcher explained what organized energy markets are, including RTO (Regional Transmission
Organization) and ISO (Independent System Operator). Both entities are functionally the same in that
they operate and manage the electricity grid over a large region. Under this organized energy market,
dispatch systems exist that would allow PRPA to serve their load from any available resource within the
footprint. Cheaper resources can now serve the load, and Fort Collins’ cost of serving energy is now
reduced. Market studies show that regionally, everyone will save something and those who were losing
on the transmission market side are now kept whole. Additionally, there are lower balancing costs. Mr.
McCollough asked if there is a cost of carbon in any existing market and Mr. Butcher said that the
concept has been discussed, but at this time there’s no need to change anything, but rather just add the
cost of carbon to the unit.
In the new system, there are four electronically-driven markets: the Day-Ahead Market (next day
operations plan), Real-Time Market (5 minute dispatch signals to balance load/generation), Financial
Transmission Rights Market (hedging cost of transmission congestion) and Resource Adequacy (year-
ahead forward planning reserves). Vice Chair Michell asked about the day-ahead market versus the real-
time market forecasting and Mr. Butcher said the Real Time market is typically more volatile because its
making up for any missed forecasting from the Day-Ahead market.
Mr. Butcher displayed a slide showing a map of the current RTO/ISO markets in North America and
pointed out that the west does not have any organized markets with the exception of the California ISO,
but they have unique rules. Ultimately, the Mountain West group (including Basin Electric, Black Hills,
Colorado Springs, PRPA, PSCo, Tri-State and WAPA) would like select one of the existing entities to
help set up its regional market. They’ve spoken to four of them on the map, and hope to announce by the
end of the year what direction the group has decided to move in. Board Members wondered if it’s
possible to predict the future now, but Mr. Butcher said he’s still bound by confidentiality at this time.
Mr. Butcher summarized potential areas of value, including reduced cost of third party transmission,
improved reliability and the ability to interconnect new generation resources anywhere within the
footprint. In this scenario, there is one question: how will the future cost of new transmission be
allocated? He advised that right now they are still working through the nuances of cost allocation.
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Board member Baumgarn asked what the future looks like as far as energy generation mix, since PRPA is
currently very coal heavy (~65%), because his vision would include more wind energy. Mr. Butcher said
that’s something PRPA would deal with through resource planning, but a regionalized market is a vehicle
to get to that vision.
Adjournment
The meeting adjourned at 8:39 p.m.
Approved by the Energy Board on December 1, 2016
________________________________ ______________
Board Secretary, Christie Fredrickson Date
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Memorandum
Date: October 19, 2016
To: Board of Directors
From: Jason Frisbie, General Manager/CEO
Andy Butcher, Director, Generation Dispatch and Power Markets
Subject: Whitepaper on Organized Power Markets—RTOs and ISOs
Attached to this memo is a whitepaper discussing the potential formation of a regional power market in
the Rocky Mountain region. Platte River is one of seven regional utilities considering membership in an
organized power market.
This report summarizes the process underway to evaluate the benefits and organizational structure of a
regional power market, and also discusses the typical characteristics and operations of regional power
markets. The report is based on currently available information. Discussions are ongoing about
the market’s structure and membership, so the contents of this document are subject to
revision as the effort progresses.
Attachment
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Draft Whitepaper to Platte River Board of Directors
Report on Organized Power Markets—RTOs and ISOs
Presented for the October 2016 Board Meeting
Overview
This report on the potential formation of a regional power market in the Mountain West is based on
currently available information. Discussions are ongoing about the market’s structure and
membership, so the contents of this document are subject to revision as the effort progresses.
Platte River is currently engaged in
discussions with six other regional
utilities to consider joining a regional
wholesale market in the Rocky
Mountain West under a common
transmission tariff. The area under
consideration would reach from South
Dakota to Arizona. In addition to Platte
River, the Mountain West
Transmission Group (MWTG) includes
Basin Electric Power Cooperative,
Black Hills Power, Colorado Springs
Utilities, Public Service Company of
Colorado, Tri-State Generation and
Transmission Assoc., and Western
Area Power Administration.
MWTG has been evaluating potential
options for an independent market
operator, including PJM Interconnect
(PJM), Midcontinent Independent
System Operator, Inc. (MISO),
California Independent System
Operator (CAISO), and Southwest
Power Pool (SPP). The Brattle Group
was hired by MWTG to analyze the
operating benefits of joining a regional
power market.
Figure 1 – Proposed MWTG Region
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History
Prior to joining the MWTG, Platte River participated in two previous attempts with other Rocky
Mountain area utilities to develop a regional transmission tariff with the primary focus of eliminating
pancaked transmission rates. First, in the mid-1990s, Platte River was involved in the Joint
Transmission System (JTS) initiative. The JTS-involved utilities collaborated on a regional postage
stamp rate design and MW-mile powerflow studies. The transmission cost shifts were large and the
JTS effort ceased for lack of agreement on cost shift mitigation. Second, in the early 2000s, there
was an effort in the southwest area of the Western Interconnection to form an RTO called Desert
Star, which transformed into a larger footprint called WestConnectRTO. Platte River participated in
WestConnectRTO which wanted to create a regional transmission tariff along with an RTO, a larger
initiative than the JTS. In 2005 Platte River shared in a WestConnectRTO Cost-Benefit study which
determined that the RTO costs exceeded its benefits. Consequently, “RTO” was dropped from the
WestConnect name. Platte River continues to participate as a member in the WestConnect regional
transmission planning processes.
Then, in April 2014 Platte River was invited to participate in the MWTG effort. Subsequently, MWTG
participants have reached the following significant milestones:
x Retained an experienced consultant well known for transmission rate designs in various
x RTO/Decided ISO on regions an 8-Zone and presenting License Plate before rate FERC for serving on related load and tariff a matters. Postage Stamp rate for
x transmission Signed a Memorandum service through of Understanding or out of the acknowledging MWTG footprint. decisions reached, including the
x pivotal Issued mitigation requests for plan information for addressing to four transmission regional operators cost shifts. for an Independent Transmission
Tariff Administrator and a Market Operator.
Process and Timeline
x The MWTG participants are reviewing results and recommendations from the production cost
x x x impact The The Development market choice analysis of study of a performed preferred a is common separated market by regional the into operator Brattle two tariff phases Group and
is expected market with the rules by final the would report end follow of due 2016 in the mid-selection November of an
x independent The goal for a operator market start-up is fourth quarter of 2018 or first quarter of 2019
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How Wholesale Energy and Transmission Markets Operate Today
Currently, utilities in the Mountain States Rocky Mountain region operate under a traditional
jurisdictional market model, known as a “bilateral trading market”. Wholesale power is typically
sourced directly from owned generation facilities or procured through third-party contracts—bilateral
agreements—where buyers and sellers negotiate with each other directly and execute a contract to
trade power. Bilateral contracts are crucial to the effective operation of power systems, and can help
utilities optimize generation and reliability services for their customers, as well as mitigate risks
associated with fuel, construction, and other economic factors.
Similarly, these utilities operate their own transmission systems under individual tariffs, mostly
independent of other utilities. The individual tariff format means that moving power could result in
“pancaking” where multiple delivery charges are incurred as power is scheduled through multiple
utility systems. Pancaking may inhibit access to more favorable generation when delivery charges
become burdensome. In this situation, utilities will look to alternatives for connecting new generation
to their system or building a line to extend their system to the new generation.
Organized Markets—RTOs and ISOs
Created as part of electricity restructuring in the US in the 1990s, regional transmission
organizations (RTOs) and independent system operators (ISOs) are generally not-for-profit
organizations that serve as third-party operators of a pooled transmission system under a common
tariff (sometimes referred to as “power pools”).
RTOs/ISOs were first proposed by FERC under Orders 888 and 889, to facilitate competition
through non-discriminatory access to transmission systems. RTOs/ISOs consolidate transmission
operations over wide areas, often spanning multiple states. Almost two-thirds of the US power
network is operated under an RTO/ISO structure, with the exception of the Rocky Mountain region,
the Pacific Northwest, and the Southeast. Current organized markets in the continental US include:
• ISO New England
• New York ISO
• PJM
• Micontinent ISO
• Southwest Power Pool
• ERCOT
• California ISO
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Figure 2 -- Organized Wholesale Power Markets in North America
Source: pjm.com
RTOs/ISOs perform many of the same functions as vertically integrated utilities, but operate using
different market incentives and cost recovery mechanisms. RTOs/ISO do not own physical assets,
and do not sell electricity to retail customers. Their primary functions are to manage the flow of
energy across the grid, manage the flow of market information and money between participants, and
conduct regional system planning.
Generally, RTOs/ISOs can run three types of markets that enable them to manage the power grid:
Energy Markets are forward power markets operated by all RTOs/ISOs, and include day-ahead and
real-time formats. Based on projections of loads provided by utilities, the day-ahead market is used
to determine which generators will be scheduled to operate over the course of the next day. Real-
time markets are managed by RTOs/ISOs to balance the operation of these scheduled generators
on an hour-ahead basis, dependent on prevailing same-day demand conditions.
Capacity Markets help ensure that the power system has adequate resources to meet the needs of
customers. These markets are intended to provide price signals that can induce new investment in
generation, or ensure that existing generators are available when needed. Not all RTOs/ISOs
sponsor capacity markets.
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Ancillary Services Markets ensure the hour-to-hour reliability of the power system. They allow
RTOs/ISOs to maintain a portfolio of backup generation in case of unexpectedly high demand or if
contingencies, such as generator outages, arise on the system.
Market Fundamentals—Locational Marginal Pricing (LMP)
RTO/ISO markets are operated using uniform price auctions, where the price and quantity of
generation are bid on a day-ahead basis to the independent operator. In much the same fashion that
utilities dispatch their own resources to meet load, the RTO/ISO will consolidate supply offers for
generation and match them to predicted demand for power—in an incremental fashion—up to the
point where total system-wide demand is satisfied. The cost of the last generator required to satisfy
demand sets the incremental price or “market clearing price” of power. The chart below
demonstrates market clearing prices at different hours during a calendar day.
What to Expect in an RTO/ISO
x Utilities will operate under a common transmission tariff administered by the RTO/ISO,
xefficiency eliminating Transmission “pancakes” rate design – a in potential an RTO/source ISO can of follow added “postage stamp” or “license plate”
x x x x x Available approaches, Loads RTO/Markets More ISO complicated and are transmission publishes resources optimized or both market market are through capacity scheduled/settlements—will
clearing location-to deliver prices bid specific on power for a require day-market markets, is ahead based enhanced participants basis with on flows systems location-into (rather LSEs)
common specific and than at staff specific markets physical prices skill LMPs sets (LMPs) contracts
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Figure 3 – Market Clearing Prices
Within an RTO/ISO, there are many points (nodes) where market clearing prices exist. This gives
rise to “locational marginal prices” (LMPs), which are the basis for wholesale market design. LMPs
can vary across an entire RTO/ISO, primarily due to constraints presented by transmission
limitations. These differences in LMPs act as price signals for participants in an RTO/ISO to procure
generation for retail customers, as well as make decisions for future resource additions for
generation and transmission.
Any price difference between LMPs is called “congestion”, and represents the value of transmission
between two pricing nodes. Transmission lines have physical limits, and represent a potential
constraint in an RTO/ISO. If demand for power exceeds the physical limits of a transmission line
carrying low-cost power, another route must be used, with “out-of-merit”, higher cost generation
driving up the LMP. The uncertainty associated with LMPs can lead power generators to look for
methods that ensure their customers’ delivered price of power is representative of their cost to
generate power.
In Figure 4, a simple example of LMPs is shown. Two generators and two loads reside on the
hypothetical grid. NodeA and NodeB are connected by a transmission line with capacity limited to 50
MW (either due to physical limits or a system constraint). GenA is able to supply all 50 MW of
NodeA’s load at $20/MWh, so NodeA’s LMP ultimately settles at $20/MWh. While GenA has sufficient
capacity to also supply the demand at NodeB, the transmission capacity limit between NodeA and
NodeB prohibits the low-cost resource at NodeA from satisfying the full amount of the load at NodeB.
Instead, the higher-priced generator at NodeB operates to meet the reminder of the load needs, and
NodeB’s LMP is $40. Had there been no transmission constraint between NodeA and NodeB, the
whole system would settle at an LMP of $20.
Supply
Renewables Hydro
Base Coal
Mid
Coal
Base
Gas
Peak
Gas
DSM
Generation (GW)
Price
($/MWh)
Demand at
hour 1700
Demand at
hour 1200
Demand at
hour 0800
$25 Oil
$35
$50
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Figure 4 – Locational Marginal Pricing Example
Any participant bidding generation into the market at the LMP or lower will receive the full value of
the LMP (provided their generation is scheduled for delivery). For low-cost generators, LMP
structures imply greater short-run profits that can offset capital costs. Generators with costs
consistently higher than LMPs may find themselves idle to an extent that they consider retirement in
an RTO/ISO.
Hedging and Financial Transmission Rights
As mentioned earlier, new exposure to potential market volatility at LMPs may require further risk
management methods that were unnecessary in a traditional jurisdictional market. To make the LMP
structure viable, a method of hedging the transmission risk is necessary. Hedges are financial
instruments or techniques (like insurance) that can protect against an adverse financial outcome.
To act as a hedge against volatile LMPs, RTOs/ISOs have adopted a structure generally known as
“financial transmission rights” (FTRs), that is vital to ensuring that a transmission owner is
indifferent between the traditional jurisdictional model and the RTO/ISO model. FTRs act to ensure
that the cost at the generator matches the cost at the delivery point, alleviating the impact of
transmission congestion. In RTOs/ISOs, transmission owners are typically allocated FTRs (or rights
to FTRs) based on prior utilization of transmission paths that they owned.
A B
GenA
150 MW
@ $20
GenB
75 MW
@ $40
50 MW
Potential
50 MW
LoadA
100 MW
LoadB
LMPB
=
$40/MWh
LMPA
=
$20/MWh
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Referring again to Figure 4, by virtue of the constrained transmission path, congestion exists
between NodeA and NodeB equal to $20/MWh ($40 LMPA minus $20 LMPB). GenB is the last
incremental unit responsible for satisfying the system load, and sets the LMP at NodeB at $40.
However, GenA has also contributed to the load needs at NodeB, but at a cost of $20/MW. As the
middleman that facilitates transactions, the ISO/RTO bills the load at NodeB $40 for each MW
supplied by GenA, but compensates GenA $20 for each MW generated, a difference of $1,000 in
generation receipts.
This example illustrates the risk confronted by GenA in an organized market, and the need for FTRs
to make GenA whole in the transaction. Assuming that GenA was allocated a minimum of 50 MW on
the transmission path between NodeA and NoteB, the revenue generated from holding those FTRs
amounts to $1,000 ($20/MWh congestion times 50 MW), directly offsetting the cost of congestion
between the two paths. An illustration of this computation is shown in Figure 5.
Figure 5 – FTRs
Planning Considerations
Maintaining a reliable supply of energy requires: 1) the proper amount of generation capacity to meet
the needs of customers, as well as provide backup, and 2) an adequate supply of transmission
infrastructure. Planning around these two needs is a primary function of the RTOs/ISOs.
Resource Adequacy RTOs/ISOs may impose a generation resource adequacy requirement on its
members to ensure a sufficient supply of generation to the grid. Resource adequacy is often
RTO/ISO
Clearinghouse 50 MW from GenA
X $40/MWh
$2,000
RTO/ISO collects
from load:
50 MW from GenA
X $20/MWh
$1,000
RTO/ISO compensates
GenA :
50 MW
X $20/MWh congestion cost
$1,000
FTR revenues:
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expressed in terms of reserve margin1, which is a common metric for utility generation planning.
Reserve margin is the amount of excess generating capacity available beyond the requirements of
projected peak demand.
There is no federal reliability standard for reserve margin, but 15 percent is a generally accepted
level for individual utilities.2 In an RTO/ISO, rigorous analyses are conducted (with participation from
generation owners) to determine the optimal amount of reserves utilities need to carry under
RTO/ISO membership. The sharing of reserves can allow generators to carry fewer total reserves,
which can translate into long-run cost savings.
Transmission expansion planning is also led by the RTO/ISO under a top-down approach. Long-
term economic and public policy transmission needs for the overall region are assessed with
participation from members and stakeholders. The top-down approach seeks to determine the
optimum system configuration where the overall system benefit is measured by the difference
between the cost of grid additions and the associated reduction in transmission congestion costs.
These processes are generally iterative to accommodate changing system needs (such as the
interconnection of new generators).
Platte River and other MWTG transmission owners will continue to conduct reliability planning for
their transmission systems under a bottom-up approach for any projects within a MWTG participant’s
zone needed to meet reliability criteria. These projects are generally ineligible for regional cost
allocation. Transmission owners may also plan and build jointly owned reliability projects. The local
transmission owner retains discretion to self-fund any local reliability project originating from its local
planning processes.
Why Should Platte River Pursue Participation in RTOs/ISOs?
In the Mountain West, a regional approach to planning can help improve the reliability and
coordination of a highly complex power network. An RTO/ISO can facilitate more efficient use of the
transmission system and reduce the number of resources required to support power needs within a
region. Some of the benefits of participation in an RTO/ISO include:
Enhanced Reliability By pooling resources, utilities can take advantage of improved system
diversity. This can translate into better overall system reliability because of access to additional
generation options, particularly during extreme events. Utilities typically plan for enough reserves to
cover outage risks associated with their largest generator. Within an RTO, the outage risk tied to an
individual generator can be reduced by spreading it among the participants, translating into potential
cost savings to carry generation reserves.
1 Reserve margin = (Net total capacity – Net total load) / Net total load
2 Platte River conducts planning according to a 15% reserve margin.
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Improved Flexibility and Efficiency Wholesale power markets result in economies of scale that
can improve operational efficiency. For example, access to a greater number of competitors can
yield lower power production costs to participants, and improved utilization and profitability for low-
cost generators. In times of surplus or deficit, membership in an RTO/ISO can provide better market
depth in which to operate, and promote higher system efficiency for all participants.
Better Price Transparency The hallmark of RTOs/ISOs is the sharing of near-term market price
information. In traditional markets, the lack of reliable, up-to-date market information can hinder long-
term investment in the power grid, or contribute to suboptimal investment decisions. With readily-
available market data, generation developers can make improved investment choices—promoting
further system efficiency.
Coordinated Planning Joint planning within an RTO/ISO can encourage optimal transmission
investments across a broad region. Rather than focusing primarily on the benefits from lower
production costs, joint planning can also introduce enhanced goal-setting to mitigate interregional
congestion, optimize reserve sharing, and satisfy environmental constraints. By broadening the
planning construct, greater overall system efficiency and reliability can be achieved.
What are the Potential Risks of RTO/ISO Membership for Platte River?
While joining an RTO/ISO has many potential benefits, there are also risks and uncertainties that
arise from membership. Some utilities may be reluctant to transfer planning and operational control
to a third party. Market and cost uncertainties also exist, and participants can be subject to price
volatility during adverse market events. Shown below are some risks associated with participation in
an RTO/ISO:
Cost Allocation for Regional Transmission Projects
Cost allocation pertains to MWTG transmission owners contributing to the cost of future transmission
projects which have regional benefits. Although MWTG has not decided on its methodologies, terms
and conditions for cost allocation, we are discussing the following methodologies which FERC has
approved in other regions. A regional transmission project could be cost allocated to Platte River and
all other MWTG transmission owners on a voltage and transmission line length basis, or on an
adjusted production cost benefit basis. Cost allocation of a regional transmission project could
include a combination of local and regional allocations. A potential risk for Platte River is sharing
costs of a very large transmission project that the RTO plans through its top-down approach.
Challenges of new work processes
Utilities may need to reinvent their operations processes to accommodate structures required within
an RTO/ISO. This may require investment in additional staff and equipment to standup a new
SCADA system and real-time power system contingency analysis tool, conduct market analysis,
manage power transactions, and coordinate system management with the RTO/ISO. The
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administration of new systems may also require more involvement from IT staff. Also, regulatory
requirements could require additional legal support.
Glossary
MWTG Mountain West Transmission Group
RTO Regional Transmission Organization—RTOs were created under FERC Order
2000 to coordinate, control, and monitor an electricity transmission grid. Mostly
synonymous with ISO.
ISO Independent System Operator—an organization authorized by the Federal
Energy Regulatory Commission (FERC) that coordinates, controls, and
monitors the operation of the electrical power system, usually at the state-level,
but sometimes spanning multiple states. Mostly synonymous with RTO.
FERC Federal Energy Regulatory Commission
SCADA Supervisory Control And Data Acquisition—is a system for remote power
system monitoring and control that operates with coded signals over
communication channels.
LMP Locational Marginal Pricing—a pricing approach that addresses congestion
costs, by reflecting the cost of re-dispatch for out-of-merit generation and the
cost of delivering energy to the location.
Node A specific locational marginal pricing point on a power network.
Congestion A condition on a transmission network when all desired transactions cannot be
accommodated due to a system constraint.
FTR Financial Transmission Right—a financial contract entitling the FTR holder to a
stream of revenues (or charges) based on the day-ahead hourly congestion
price difference across an energy path.
Hedge A financial instrument, like insurance, used to reduce risk for an uncertain
event.
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