[Federal Register Volume 82, Number 24 (Tuesday, February 7, 2017)]
[Proposed Rules]
[Pages 9539-9555]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-02332]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM17-2-000]
Uplift Cost Allocation and Transparency in Markets Operated by
Regional Transmission Organizations and Independent System Operators
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
proposing to revise its regulations to require that each regional
transmission organization (RTO) and independent system operator (ISO)
that currently allocates the costs of real-time uplift due to
deviations should allocate such real-time uplift costs only to those
market participants whose transactions are reasonably expected to have
caused the real-time uplift costs. The Commission also proposes to
revise its regulations to enhance transparency by requiring that each
RTO/ISO post uplift costs paid (dollars) and operator-initiated
commitments (megawatts) on its Web site; and define in its tariff its
transmission constraint penalty factors, as well as the circumstances
under which those penalty factors can set locational marginal prices,
and any procedure for changing those factors.
DATES: Comments are due April 10, 2017.
ADDRESSES: Comments, identified by docket number, may be filed in the
following ways:
Electronic Filing through http://www.ferc.gov. Documents
created electronically using word processing software should be filed
in native applications or print-to-PDF format and not in a scanned
format.
Mail/Hand Delivery: Those unable to file electronically
may mail or hand-deliver comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE.,
Washington, DC 20426.
Instructions: For detailed instructions on submitting comments and
additional information on the rulemaking process, see the Comment
Procedures Section of this document.
FOR FURTHER INFORMATION CONTACT:
Stanley Wolf (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-6841, [email protected]
Keatley Adams (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-8678, [email protected]
Colin Beckman (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, (202) 502-8049, [email protected]
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
I. Background............................................... 9
II. Discussion.............................................. 12
A. Uplift Cost Allocation............................... 12
[[Page 9540]]
1. Uplift Cost Allocation Background................ 13
2. Current RTO/ISO Practices........................ 16
3. Comments......................................... 23
a. Practices for Allocating Uplift Costs to 23
Deviations.....................................
b. Virtual Transactions and Uplift.............. 27
c. Coordinated Transaction Scheduling........... 29
d. Additional Comments.......................... 30
4. Need for Reform.................................. 31
5. Proposal......................................... 35
a. Real-Time Uplift Categories.................. 40
b. Netting...................................... 45
c. Deviations That Result From Following 51
Dispatch.......................................
d. Settlement................................... 55
e. Other Comments Sought........................ 56
B. Transparency......................................... 57
1. Background....................................... 58
2. Current RTO/ISO Practices........................ 59
a. Reporting Uplift............................. 59
b. Reporting Operator-Initiated Commitments..... 63
c. Transmission Constraint Penalty Factors...... 66
3. Comments......................................... 67
a. General Comments............................. 67
b. Comments on Uplift Reporting................. 68
c. Comments on Reporting Operator-Initiated 72
Commitments....................................
d. Comments on Transmission Constraint Penalty 75
Factors........................................
4. Need for Reform.................................. 77
5. Proposal......................................... 82
a. Uplift Reporting............................. 83
b. Reporting Operator-Initiated Commitments..... 90
c. Transmission Constraint Penalty Factors...... 96
d. Comment Sought on Transmission Outages....... 100
e. Comment Sought on Availability of Market 101
Models.........................................
III. Compliance............................................. 102
IV. Information Collection Statement........................ 105
V. Environmental Analysis................................... 110
VI. Regulatory Flexibility Act.............................. 111
VII. Comment Procedures..................................... 113
VIII. Document Availability................................. 117
1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy
Regulatory Commission (Commission) proposes to revise its regulations
to address potentially unjust and unreasonable approaches to real-time
uplift cost allocation and transparency practices by regional
transmission organizations (RTOs) and independent system operators
(ISOs).
2. While the Commission and RTOs/ISOs have taken steps to reduce
the amount of uplift in the energy and ancillary services markets, the
complexity inherent in the electric system and limitations in the tools
available to maintain reliable operations can lead to system operators
taking out-of-market actions to manage reliability. When they do so,
energy and ancillary service prices may not reflect the marginal cost
of production and some resources may therefore need make-whole payments
to ensure recovery of operating costs. Since the limitations in
representing the complexity of the electric system in market models are
unlikely to ever be fully resolved, uplift costs are also unlikely to
be completely eliminated. As a result, RTOs/ISOs need to have a method
for allocating these costs to market participants. At the highest
level, the allocation of uplift costs should, to the extent possible,
encourage behavior that will reduce the need for uplift-creating
actions and avoid discouraging market participant behavior that lowers
total production costs (i.e., enhances efficiency). The reforms
proposed in this NOPR are designed to achieve these objectives.
3. Given that RTOs/ISOs are likely going to need to take some out-
of-market actions, there is a need to provide transparency regarding
those actions and the associated uplift costs. The lack of transparency
regarding uplift and operator-initiated commitments,\1\ which can cause
uplift, hinders a market participant's ability to plan and efficiently
respond to system needs. Market participants may lack the information
necessary to evaluate the need for and value of additional investment,
such as transmission upgrades or new generation. Also, without
sufficient transparency, market participants may not be able to assess
each RTO's/ISO's operator-initiated commitment practices and raise any
issues of concern through the stakeholder process. The transparency
reforms proposed in this NOPR are designed to allow market participants
to understand the actions RTOs/ISOs are taking and respond accordingly.
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\1\ An operator-initiated commitment is a commitment that is not
associated with a resource clearing the day-ahead or real-time
market on the basis of economics and that is not self-scheduled. See
FERC, Operator Initiated Commitments in RTO and ISO Markets, Docket
No. AD14-14-000 at 8-20 (Dec. 2014), http://www.ferc.gov/legal/staff-reports/2014/AD14-14-operator-actions.pdf.
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4. First, we preliminarily find that certain practices of
allocating the cost of real-time uplift \2\ to market participants who
deviate from day-ahead market schedules (deviations) are inconsistent
with cost causation, which may distort market outcomes, potentially
resulting in unjust and unreasonable rates.
[[Page 9541]]
Specifically, some RTO/ISO practices of allocating real-time uplift
costs to deviations that could not reasonably be expected to have
caused those uplift costs can distort market outcomes by
inappropriately penalizing behavior that can improve price formation.
Therefore, we propose to require that, if an RTO/ISO allocates real-
time uplift costs to deviations, it must do so based on cost causation,
as further discussed below. For the purposes of allocating uplift costs
to deviations, we propose that deviations are megawatt hour differences
between a market participant's scheduled deliveries or receipts at
particular points--as determined by the day-ahead market clearing
process--and those amounts actually delivered or received in real-time
that are not related to real-time economic or reliability-related
operator dispatch instructions. This proposal would apply only to real-
time uplift cost allocation to deviations. This NOPR does not apply to
other methods used by RTOs/ISOs to allocate uplift costs. If an RTO/ISO
does not currently allocate real-time uplift costs to deviations, this
NOPR does not impose a requirement on those RTOs/ISOs to allocate real-
time uplift costs to deviations.
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\2\ Real-time uplift refers to uplift payments to resources
committed after the close of the day-ahead market, including any
uplift associated with reliability commitments, whether or not the
RTO/ISO considers such commitments outside of the day-ahead market,
e.g., the Reliability Unit Commitment or RUC process. As such,
uplift payments to resources committed in a reliability unit
commitment process would be considered real-time uplift for the
purposes of this NOPR).
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5. Second, we preliminarily find that current practices with
respect to reporting uplift payments, operator-initiated commitments,
and transmission constraint penalty factors \3\ are unjust and
unreasonable. The lack of transparency into the costs allocated to
market participants, and into the causes of such costs, hinders the
ability of market participants to assess the effectiveness of current
operational practices or to evaluate the need for additional
investment, such as transmission upgrades or new generation. Similarly,
the lack of transparency with respect to transmission constraint
penalty factors may hinder a market participant's ability to
effectively understand how an RTO's/ISO's actions affect energy prices
and thus, hinder its ability to hedge energy market transactions. As
discussed further below, for these reasons we preliminarily find that
these practices may result in rates that are unjust and unreasonable.
We therefore propose to require that each RTO/ISO: (1) Report total
uplift payments for each transmission zone, broken out by day and
uplift category; (2) report total uplift payments for each resource on
a monthly basis; (3) report megawatts (MW) of operator-initiated
commitments in or near real-time and after the close of the day-ahead
market, broken out by transmission zone and commitment reason; and (4)
define in its tariff the transmission constraint penalty factors, as
well as the circumstances under which those factors can set locational
marginal prices (LMPs), and the process by which they can be changed.
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\3\ Transmission constraint penalty factors are the values at
which an RTO's/ISO's market software will relax the limit on a
transmission constraint rather than continue to re-dispatch
resources to relieve congestion associated with that constraint.
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6. The goals of the price formation proceeding are to: (1) Maximize
market surplus for consumers and suppliers; (2) provide correct
incentives for market participants to follow commitment and dispatch
instructions, make efficient investments in facilities and equipment,
and maintain reliability; (3) provide transparency so that market
participants understand how prices reflect the actual marginal cost of
serving load and the operational constraints of reliably operating the
system; and (4) ensure that all suppliers have an opportunity to
recover their costs.\4\
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\4\ See Price Formation in Energy and Ancillary Services Markets
Operated by Regional Transmission Organizations and Independent
System Operators, Notice Inviting Post-Technical Workshop Comments,
Docket No. AD14-14-000, at 1 (Jan. 16, 2015) (Notice Inviting
Comments); Price Formation in Energy and Ancillary Services Markets
Operated by Regional Transmission Organizations and Independent
System Operators, Notice, Docket No. AD14-14-000 (June 19, 2014)
(Price Formation Notice).
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7. The reforms proposed in this NOPR address two of the
Commission's price formation goals. First, the proposed reforms to
uplift costs allocated to deviations should improve market
participants' incentives to perform in real-time consistent with
operator instructions and bid into the day-ahead market and submit day-
ahead schedules consistent with expected real-time system conditions.
Second, the proposed transparency reforms will help market participants
understand how prices reflect the actual marginal cost of serving load
and the operational constraints of reliably operating the system.
8. We seek comment on these proposed reforms 60 days after
publication of this NOPR in the Federal Register.
I. Background
9. In June 2014, the Commission initiated a proceeding, in Docket
No. AD14-14-000, Price Formation in Energy and Ancillary Services
Markets in Regional Transmission Organizations and Independent System
Operators, to evaluate issues regarding price formation in the energy
and ancillary services markets operated by RTOs/ISOs (Price Formation
Proceeding). The notice initiating that proceeding stated that there
may be opportunities for the RTOs/ISOs to improve the price formation
process in the energy and ancillary services markets. As set forth in
the notice, prices used in energy and ancillary services markets
ideally ``would reflect the true marginal cost of production, taking
into account all physical system constraints, and these prices would
fully compensate all resources for the variable cost of providing
service.'' \5\ Pursuant to the notice, staff conducted outreach and
convened technical workshops on the following four general issues: (1)
Use of uplift payments; (2) offer price mitigation and offer price
caps; (3) scarcity and shortage pricing; and (4) operator actions that
affect prices.\6\
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\5\ Price Formation Notice, Docket No. AD14-14-000, at 2 (June
19, 2014).
\6\ Id. at 1, 3-4.
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10. In January 2015, the Commission requested comments on questions
that arose from the price formation technical workshops.\7\ As a result
of these comments, the Commission identified, among other things, five
topics with potential for reform to improve price formation, but for
which further information was needed.
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\7\ Notice Inviting Comments, Docket No. AD14-14-000 (Jan. 16,
2015).
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11. In November 2015, the Commission issued an order that directed
each RTO/ISO to report on these five price formation topics: Fast-start
pricing; managing multiple contingencies; look-ahead modeling; uplift
allocation; and transparency.\8\ Specifically, the order directed each
RTO/ISO to file a report providing an update on its current practices
in the five topic areas, outlining the status of its efforts (if any)
to address issues in each of the five topic areas, and responding to
specific questions contained in the order. In the reports filed and the
subsequent comments, RTOs/ISOs and other commenters addressed the
issues of uplift cost allocation and transparency,\9\ which are the
subject of this NOPR.
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\8\ Price Formation in Energy and Ancillary Services Markets
Operated by Regional Transmission Organizations and Independent
System Operators, 153 FERC ] 61,221 (2015) (Order Directing
Reports).
\9\ A list of commenters and the abbreviated names used in this
NOPR appears in the Appendix.
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II. Discussion
A. Uplift Cost Allocation
12. In this section, we first provide a brief background on uplift
payments and deviations between day-ahead and real-time schedules as a
way to determine uplift cost allocation. We
[[Page 9542]]
then review current RTO/ISO practices and comments regarding these
practices submitted prior to and after the issuance of the Order
Directing Reports. Finally, we explain the need for reform and set
forth the proposal in detail.
1. Uplift Cost Allocation Background
13. Uplift generally refers to payments that RTOs/ISOs make to a
resource whose commitment and dispatch result in a shortfall between
the costs in a resource's offer and the revenue earned through market
clearing prices.\10\ For example, if a resource is committed and is not
able to fully recover its costs from the energy and ancillary services
markets, it would receive an uplift payment. As noted in the Staff
Analysis of Uplift, modeling, software, and certain other limitations
are inherent in the complexity of the electric system and the tools
available to maintain reliable operations. As a result, system
operators may have to take out-of-market actions to manage reliability,
with resulting energy and ancillary service prices not reflecting the
marginal cost of production. Uplift, or make-whole, payments may
therefore be needed to ensure that resources committed and dispatched
out-of-market are able to recover their operating costs. These
modeling, software, and other limitations will likely persist, making
uplift an inherent element of centralized wholesale energy and
ancillary services markets that may not be completely eliminated.
Therefore, RTOs/ISOs must have a method to allocate these costs to
market participants. Generally, RTOs/ISOs allocate uplift costs either
directly to market participants who caused the uplift or to load.
Allocation of uplift costs to load is motivated by several
considerations. Load can be viewed as the ultimate beneficiary of the
actions the system operator takes to maintain reliability. Further, one
principle of cost allocation is to allocate costs in a way that is
least likely to distort market participant behavior. In electricity
markets, load is the class of market participants that is currently the
least sensitive to price and for whom an allocation of uplift costs is
arguably least likely to distort behavior. For shorthand, allocating
uplift costs to load is referred to as ``beneficiary pays.'' In
practice, RTOs/ISOs often use a combination of the two approaches, with
load receiving all of the uplift costs that are not allocated through
cost-causation methods, such as a deviations-based approach.
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\10\ FERC, Staff Analysis of Uplift in RTO and ISO Markets,
Docket No. AD14-14-000, at 1-2 (Aug. 2014), https://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf.
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14. In its Order Directing Reports, the Commission asked the RTOs/
ISOs to explain whether and how the RTO/ISO allocates real-time energy
and ancillary services market uplift costs based on deviations from
market participants' day-ahead schedules, and whether deviations that
increase the need for actions that cause real-time uplift payments
(harming deviations) are netted against deviations that reduce the need
for actions that cause real-time uplift payments (helping
deviations).\11\
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\11\ Order Directing Reports, 153 FERC ] 61,221 at P 64,
question 3.b.
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15. In response, most RTOs/ISOs state that they classify certain
schedule differences between the day-ahead and real-time markets as
deviations and allocate at least some portion of real-time uplift costs
to those deviations. Allocation of real-time uplift costs to deviations
is the focus of this NOPR because deviations may increase the need for
operator actions that cause real-time uplift, such as additional unit
commitments in real-time to replace a shortfall in generation or an
increase in load compared to the day-ahead market solution. This NOPR
does not address other methods of uplift cost allocation, such as
allocation to load obligations, and does not propose to require RTOs/
ISOs to allocate real-time uplift costs to deviations.
2. Current RTO/ISO Practices
16. All of the RTOs/ISOs state that they use some form of
beneficiary pays or cost-causation principles to allocate uplift
costs.\12\ However, the current uplift cost allocation methods of the
RTOs/ISOs vary significantly, both in terms of granularity and the
exemption of certain types of transactions. The definition of what
precisely constitutes a deviation also varies across RTOs/ISOs.
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\12\ NYISO Report at 45; PJM Report at 28; SPP Report at 19;
MISO Report at 42; ISO-NE Report at 43; CAISO Report at 35.
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17. NYISO generally allocates uplift costs based on the beneficiary
pays principle.\13\ NYISO allocates uplift costs associated with state-
wide reliability to all loads in the New York Control Area, and
allocates uplift costs associated with local reliability to load within
the transmission district where the reliability actions were taken.
NYISO allocates real-time uplift costs on a beneficiary pays basis to
load obligations, using real-time metered load during the hours in
which uplift costs were incurred.\14\ NYISO also explains that it
eliminated all uplift costs associated with Coordinated Transaction
Scheduling (CTS) \15\ in a reciprocal fashion with ISO-NE, and that it
supports the elimination of all uplift cost allocation and fees on
exports because these fees reduce trade between regions and adversely
impact total production costs.\16\
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\13\ NYISO Report at 46.
\14\ Id. at 40.
\15\ CTS is a set of real-time market rules that allow imports
and exports to be scheduled based on a bidder's willingness to
purchase energy sourced from one RTO/ISO and sell the energy at a
sink in another, adjacent RTO/ISO, if the difference between the
forecasted prices at the sink and source is greater than or equal to
the dollar value specified in the CTS Interface Bid (spread bid).
\16\ NYISO Report at 45-46.
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18. CAISO explains that it has many categories of uplift, and that
it allocates uplift costs to transmission owners (who pass uplift costs
to transmission customers), loads, and exports, depending on whether
the system operator made the dispatch decision to address transmission
constraints, energy imbalance, real-time congestion, or bid cost
recovery.\17\ CAISO asserts that any allocation based on deviations
should consider the wide variability in scheduling and metering
granularity for different resources and that there might be
implementation challenges in a more granular cost allocation.\18\
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\17\ CAISO Report at 40-45.
\18\ Id. at 37.
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19. ISO-NE states that roughly half of its uplift costs are
allocated to deviations, which include generator deviations, load
deviations, increment (virtual) deviations, and import deviations.\19\
ISO-NE calculates each market participant's deviations hourly, netting
virtual demand bids and deviations from day-ahead load across all
locations.\20\ However, hourly generator and virtual supply deviations
are not subject to netting in ISO-NE.\21\ ISO-NE does not allocate
uplift costs to CTS transactions.\22\
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\19\ ISO-NE Report at 54-55.
\20\ Id. at 50.
\21\ Id.
\22\ ISO-NE Report at 53.
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20. PJM allocates uplift costs incurred for reasons other than
reliability to deviations, including cleared virtual bids, transaction
deviations, and load deviations.\23\ PJM states that it assesses
deviations daily by netting deviations separately within three
different categories (demand, supply, and generation) at a single
transmission zone, hub, or interface.\24\ PJM explains that its current
netting rule allows a supply or demand deviation from a virtual
transaction in the day-ahead energy market to be netted against
[[Page 9543]]
internal bilateral transactions \25\ occurring at the same
location.\26\ PJM does not consider up-to-congestion transactions \27\
to be deviations and does not allocate uplift to them.\28\ PJM
considers CTS transactions (and other imports and exports) to be
deviations, and allocates uplift to them.
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\23\ PJM Report at 30-31.
\24\ Id. at 31.
\25\ Internal bilateral transactions are a type of bilateral
transaction used to purchase or sell one or more electricity market
product(s) within a region. In all of the RTOs/ISOs, internal
bilateral transactions are financial agreements that the two parties
report to the RTO/ISO to streamline accounting and settlement. None
of the RTOs/ISOs model internal bilateral transactions in the real-
time or day-ahead market, and internal bilateral transactions do not
affect market dispatch or power flows.
\26\ PJM Report at 33.
\27\ An up-to-congestion transaction is a form of virtual
transaction that combines an offer to sell energy at a source, with
a bid to buy the same MW quantity of energy at a sink where such
transaction specifies the maximum difference between the LMP at the
source and sink.
\28\ PJM Report at 33.
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21. SPP states that it allocates uplift costs based on causation
when the cause is identifiable and the cost of doing so does not
outweigh the benefit.\29\ For example, real-time uplift costs are
allocated to deviations from day-ahead schedules and SPP dispatch
instructions.\30\ SPP states that virtual transactions are considered
deviations, but virtual supply offers are netted against a
countervailing deviation between day-ahead and real-time schedules
(i.e., a load or export decrease, or import increase, relative to its
day-ahead schedule) at the same settlement location.\31\
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\29\ SPP Report at 20.
\30\ Id. at 22.
\31\ Id. at 38.
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22. MISO has a granular approach to allocating uplift costs that it
states is based on determining cost-causation where possible. MISO has
several categories of uplift, but, for example, MISO's Revenue
Sufficiency Guarantee uplift category has six different methodologies
for distributing costs based on the reason a resource was
committed.\32\ MISO also allocates uplift costs according to a set of
defined categories based on what MISO determines to be the cause of the
uplift. Uplift costs resulting from real-time capacity commitments are
largely allocated to deviations, including physical supply and demand
deviations, virtual transactions, and import and export physical
schedules.\33\ A portion of uplift resulting from transmission
constraint relief is assigned to the deviations that caused the
congestion.\34\ MISO has also noted that it will not allocate uplift
costs to CTS between itself and PJM, which is expected to be
implemented in the spring of 2017.\35\
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\32\ MISO Report at 42-43.
\33\ Id. at 44.
\34\ Id.
\35\ Midcontinent Indep. Sys. Operator, Inc., 155 FERC ] 61,038,
at P 3 (2016).
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3. Comments
a. Practices for Allocating Uplift Costs to Deviations
23. Some commenters criticize the practice of allocating uplift
costs to real-time deviations from day-ahead schedules. For example,
Appian Way asserts that deviations-based approaches to uplift cost
allocation create market inefficiencies in the form of unnecessary and
inappropriate barriers to market participants accessing the spot
market, and also shift the cost responsibility for uplift from load to
other market participants.\36\
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\36\ Appian Way Comments at 1, 7.
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24. Others, however, support allocating uplift costs to deviations
from day-ahead schedules, but argue that such deviations should be
netted based on whether they contribute to or alleviate the condition
causing uplift.\37\ Some commenters contend, for example, that netting
such deviations is consistent with cost causation principles because it
ensures that only market participants deviating from their day-ahead
schedules in a manner that increases uplift payments will incur those
costs.\38\
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\37\ Financial Marketers Coalition Comments at 31.
\38\ Id. at 14, 31.
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25. Multiple commenters also recommend the creation of more
specific uplift cost allocation categories that are better aligned with
cost causation. To this end, some commenters suggest creating a
congestion management category that would distinguish uplift incurred
for congestion management from uplift incurred for capacity needs or
voltage and local reliability and allocate uplift costs
accordingly.\39\
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\39\ Id. at 14; XO Energy Comments at 24.
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26. MISO Market Monitor asserts that uplift costs should be
minimized to the extent possible by incorporating reliability
requirements into market-based products, but any remaining uplift costs
should then be allocated based on cost causation. MISO Market Monitor
believes that allocating uplift costs to those that cause it or benefit
from it gives market participants an incentive to act to minimize it.
MISO Market Monitor also asserts that MISO's uplift cost allocation
approach is the best practice in the industry because it determines why
the uplift was incurred and allocates the costs accordingly.\40\ MISO
Market Monitor also argues that for both capacity-related and
congestion-related uplift, cost allocations should be based on
deviations from the market participants' day-ahead schedules.\41\
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\40\ MISO Market Monitor Feb. 24, 2015 Comments at 16-17.
\41\ Id. at 17.
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b. Virtual Transactions and Uplift
27. Allocation of uplift costs to virtual transactions is a
contentious issue, and commenters hold disparate opinions. Some
commenters argue that virtual transactions contribute to price
convergence between the day-ahead and real-time markets, thus reducing,
rather than increasing, uplift. They also argue that virtual
transactions are easily forced out of the market by added fees, such as
uplift. These commenters support either reducing or eliminating the
allocation of uplift costs to virtual transactions.\42\ For example, XO
Energy argues that it is unjust and unreasonable to allocate energy
deviation-related uplift costs to virtual transactions as XO Energy
asserts these transactions do not impact unit commitment because the
energy impacts ``net out'' and do not affect the system's power
balance.\43\
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\42\ Appian Way Comments at 10; Financial Marketers Coalition
Comments at 14-15; XO Energy Comments at 21.
\43\ XO Energy Comments at 19-21.
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28. Other commenters disagree, arguing that virtual transactions
should be allocated uplift costs because they affect day-ahead
commitment and dispatch, and thus can impact uplift.\44\ For example,
PJM states that allocating uplift costs to virtual transactions is
consistent with cost causation, and that up-to-congestion transactions
should be allocated uplift costs similar to other virtual transactions,
although they are not currently allocated such costs.\45\ Several
commenters also contend that cost allocation rules for virtual
transactions may need to be revised.\46\ For example, EEI notes that in
PJM, virtual transactions, including increment offers and decrement
bids, are allocated uplift costs, while up-to-congestion transactions
are not. EEI asserts that up-to-congestion transactions should not be
given preferential treatment and should instead be allocated a share of
uplift costs.\47\
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\44\ PSEG Companies Comments at 10; EEI Comments at 4.
\45\ PJM Report at 33.
\46\ EPSA/P3 Comments at 12; DC Energy, Inertia Power, and Vitol
Comments at 4-5.
\47\ EEI Comments at 4.
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[[Page 9544]]
c. Coordinated Transaction Scheduling
29. CTS transactions are scheduled in real-time by the
participating RTO/ISOs \48\ based on forecasted prices. CTS is not used
in all RTO/ISO markets and the allocation of uplift costs to CTS varies
by market, as described herein. Some RTOs/ISOs, such as MISO, view CTS
transactions as economically dispatched, similar to the economic
dispatch of a generator, and therefore do not consider them to be
deviations for the purpose of allocating uplift costs. NYISO and ISO-NE
do not allocate uplift costs to CTS transactions between their markets.
PJM, however, views CTS transactions as deviations, indistinguishable
in effect from other deviations that cause uplift.
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\48\ Currently, CTS is effective between NYISO and ISO-NE and
NYISO and PJM. MISO and PJM expect to implement CTS in 2017.
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d. Additional Comments
30. Commenters also provide feedback on several other market design
mechanisms related to uplift. For example, several commenters discuss
the netting of internal bilateral transactions against other deviations
when allocating uplift costs in PJM. While some advocate eliminating
this market rule,\49\ others support it, contending that internal
bilateral transactions are valuable hedging tools which allow market
participants to counteract a deviation from a virtual transaction in
the day-ahead market and promote convergence between day-ahead and
real-time prices.\50\
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\49\ PJM Market Monitor Comments at 13; PJM Report at 33; Appian
Way Comments at 8.
\50\ EPSA/P3 Comments at 12-13.
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4. Need for Reform
31. We preliminarily find that some existing RTO/ISO practices of
real-time uplift cost allocation to deviations may be unjust and
unreasonable. Specifically, these real-time uplift cost allocation
practices may result in unjust and unreasonable rates by allocating
costs to deviations that could not reasonably be expected to have
caused those costs. Allocating costs to deviations that did not cause
these costs can inappropriately penalize certain types of transactions
that may be beneficial to price formation. We note that the Commission
is not proposing to require RTOs/ISOs to allocate any amount of uplift
costs to deviations, rather we are simply proposing reforms to uplift
cost allocation to deviations to the extent an RTO/ISO chooses to
allocate some uplift costs to deviations.
32. While there are several approaches to allocating uplift costs,
most RTOs/ISOs allocate at least a portion of real-time uplift costs to
market participants that deviate from their day-ahead market schedules.
When market participants deviate from their day-ahead schedule, RTOs/
ISOs may have to take actions in real-time to address differences
between the day-ahead market solution and real-time system conditions.
These actions, such as committing additional resources, can result in
real-time uplift costs.
33. However, RTOs/ISOs do not always consider whether a deviation
likely contributed to increasing or decreasing real-time uplift costs
when allocating real-time uplift costs. Deviations from day-ahead
market schedules that create the need for additional resource
commitments in real-time tend to increase real-time uplift costs. On
the other hand, deviations can also contribute to the convergence of
the day-ahead and real-time markets by helping to ensure that the day-
ahead market solution and the attendant day-ahead schedule reduces the
need for system operator actions in real-time. If real-time uplift
costs are assigned improperly, such costs may impact market behavior in
a manner that limits otherwise beneficial transactions, which in turn
may distort prices and market outcomes. This distortion can lead to
increased real-time uplift payments, higher overall costs to consumers,
and potentially unjust and unreasonable rates.\51\
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\51\ FERC, Staff Analysis of Uplift in RTO and ISO Markets,
Docket No. AD14-14-000, at 5-7 (Aug. 2014), https://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf.
---------------------------------------------------------------------------
34. Therefore, we preliminarily find unjust and unreasonable real-
time uplift cost allocation rules that fail to distinguish between
deviations that help converge day-ahead and real-time markets \52\ and
those that harm efforts to address system needs. Such rules fail to
appropriately assign real-time uplift costs to market participants that
are likely to cause such costs and inappropriately deter transactions
that are likely to minimize these costs.
---------------------------------------------------------------------------
\52\ Deviations that help converge day-ahead and real-time
markets are deviations that bring day-ahead and real-time prices,
commitments, and dispatch closer together.
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5. Proposal
35. To remedy the potentially unjust and unreasonable rates
resulting from allocating real-time uplift costs to deviations in a
manner inconsistent with cost causation, we propose that, pursuant to
section 206 of the Federal Power Act,\53\ each RTO/ISO that currently
allocates real-item uplift costs to deviations must follow the
practices described below when allocating such costs. Specifically, the
following practices ensure that if an RTO/ISO chooses to allocate real-
time uplift costs to deviations, it must do so consistent with cost
causation. Accordingly, we first propose that RTOs/ISOs categorize
real-time uplift costs allocated to deviations into at least two
categories based on the reason uplift costs were incurred, a system-
wide capacity category and a congestion management category as
discussed in more detail below. Second, we propose to require each RTO/
ISO to distinguish between deviations that are ``helping'' to address
system needs and those that are ``harming'' efforts to address system
needs. Further, within each uplift category, uplift costs must be
allocated to a market participant's net ``harming'' deviations, i.e.,
relevant ``harming'' deviations net of relevant ``helping'' deviations.
Third, we propose to clarify that a resource responding to an RTO/ISO-
initiated real-time dispatch instruction should not be allocated
deviations-related real-time uplift costs. Finally, we propose that
real-time uplift costs allocated to deviations must be settled using
hourly uplift rate calculations. Each proposed practice is described in
detail below.
---------------------------------------------------------------------------
\53\ 16 U.S.C. 824e.
---------------------------------------------------------------------------
36. This proposal would apply only to real-time uplift costs
allocated to deviations. The NOPR does not propose to require that
RTOs/ISOs allocate uplift costs to deviations, and we recognize that
there are other methods for allocating uplift costs that are not based
on deviations, such as allocations based on load obligation. Further,
we recognize that there are many causes of uplift and this NOPR does
not propose to address the allocation of all uplift costs. Rather, to
improve upon existing RTO/ISO cost allocation practices, this NOPR
addresses the allocation of uplift costs caused by market participants
that deviate from their day-ahead market schedules.
37. Most RTOs/ISOs allocate some real-time uplift costs to
deviations, although their methods for doing so vary. We set forth here
a definition of deviations to delineate what type of real-time uplift
cost allocation is the subject of this NOPR. We propose that deviations
are megawatt hour differences between a market participant's scheduled
deliveries or receipts at particular points cleared in the day-ahead
market and those amounts actually delivered or received at those points
in real-time that are not related to real-time economic or reliability-
related operator dispatch instructions. We propose that, to the
[[Page 9545]]
extent an RTO/ISO allocates real-time uplift costs to deviations, it
must do so consistent with this proposed definition. We seek comment on
the proposed definition of deviations.
38. We propose that if an RTO/ISO allocates real-time uplift costs
to deviations, it must allocate such costs only to deviations that can
reasonably be expected to have caused those costs. Real-time uplift
costs are most likely to be incurred when, for various reasons, the
day-ahead market clearing process does not schedule sufficient
resources to satisfy the system's real-time needs, and instead, RTOs/
ISOs must procure additional resources after the day-ahead market has
cleared. Market participants that deviate from their day-ahead
schedules will either more closely align the day-ahead market solution
with actual real-time system needs or contribute to a divergence from
the day-ahead solution. Scheduling practices that contribute to these
divergences may require operator actions, such as operator-initiated
commitments, in real-time.
39. RTO/ISO day-ahead and real-time price signals provide economic
incentives to respond to system needs. Allocating real-time uplift
costs to deviations consistent with cost causation would help ensure
that real-time uplift cost allocation does not discourage or deter
behavior that may converge day-ahead and real-time market solutions. By
eliminating the allocation of real-time uplift costs to transactions
that are beneficial to meeting system needs, this proposal strengthens
the economic incentives for market participants to respond to system
needs. Further, allocating real-time uplift costs consistent with cost
causation rewards the ability to perform in real-time consistent with
operator instructions and disciplines forward scheduling practices by
encouraging market participants to bid into the day-ahead market and
submit day-ahead schedules consistent with expected real-time system
conditions.
a. Real-Time Uplift Categories
40. We propose to require each RTO/ISO to categorize real-time
uplift costs allocated to deviations into at least two categories based
on the reason the uplift cost was incurred: (1) A system-wide capacity
category and (2) a congestion management category. The system-wide
capacity category would include real-time uplift related to resource
commitments made to ensure sufficient system-wide online capacity to
meet energy and operating reserve requirements. The congestion
management category would include real-time uplift related to resource
commitments to manage transmission congestion on specific constraints.
Under this proposal, we require that an RTO/ISO establish at least
these two categories for real-time uplift cost allocation to
deviations, but propose to provide flexibility to an RTO/ISO to
establish additional categories.
41. We propose distinguishing the two categories, system-wide
capacity and congestion management. The distinction ensures real-time
uplift costs are allocated more specifically to the market participant
that caused the uplift. Two examples illustrate how delineating these
two categories is consistent with cost causation.
42. As a first example, consider a market participant that owns a
generator that in real-time produces less than the output set forth in
its day-ahead schedule when it did not receive dispatch instructions to
do so. That generator's deviation impacted the RTO's/ISO's ability to
maintain real-time energy and operating reserve requirements and
required a new commitment to make up for the generator's deviation.
However, absent impacting the power flows on a system constraint, the
generator did not contribute to congestion on any constraint. Such a
generator should be allocated real-time uplift costs for capacity but
not congestion management. The generator caused a need for more
capacity to come online, but did not cause a need to relieve congestion
on a constraint.
43. As a second example, suppose that the same generator is owned
by a market participant that also serves real-time load. If the market
participant reduces its real-time load in an amount that equals the
generator's deviation (i.e., its reduced supply), the market
participant's behavior on net did not impact the RTO's/ISO's ability to
maintain real-time energy and operating reserve requirements. However,
if this behavior--on net--impacts congestion on the system, the market
participant should be allocated real-time uplift costs related to
congestion management.
44. We request comments on whether the proposed reforms should
recognize the need for regional flexibility with regard to the uplift
categories. We also request comment on whether other categories should
be required.
b. Netting
45. In allocating uplift costs to deviations, we propose to require
each RTO/ISO to distinguish between deviations that are ``helping''
efforts to address system needs and those that are ``harming'' efforts
to address system needs. The particular system need of relevance will
depend on the category of uplift costs at issue, as discussed further
below. Within each uplift category, uplift costs must be allocated to a
market participant's net ``harming'' deviations, i.e., relevant
``harming'' deviations net of relevant ``helping'' deviations. Such
allocation should be commensurate with a market participant's share of
total net ``harming'' deviations.
46. Under the proposed system-wide capacity category, a market
participant would be allocated a portion of the total real-time uplift
costs incurred to maintain energy and operating reserve requirements in
the real-time market based on the net contributions of its deviations
to those costs. This method would require an RTO/ISO to determine if
each market participant's deviations are, on net, ``helping'', by
converging the day-ahead scheduled unit commitment and dispatch to the
unit commitment and dispatch needed to meet real-time energy and
operating reserve requirements, or if they are ``harming'', by
exacerbating the difference between the day-ahead scheduled unit
commitment and dispatch and the unit commitment and dispatch needed to
meet real-time energy and operating reserve requirements. For example,
if the system operator committed an additional resource to maintain
energy and operating reserve requirements in the real-time market, a
market participant with net deviations that increased demand (or
decreased supply) would be allocated a portion of real-time uplift
costs in the system-wide category, while a market participant with net
deviations that increased supply (or decreased demand) would not.
47. Under the proposed congestion management category, a market
participant would be allocated real-time uplift costs if its net
deviations contributed to a difference between the congestion on a
specific constraint in the day-ahead market and the real-time
congestion on that constraint. This method would require an RTO/ISO to
determine if each market participant's deviations are, on net,
``helping'', by converging day-ahead and real-time congestion patterns,
or if they are ``harming'', by exacerbating the difference between day-
ahead and real-time congestion on a constraint. Market participants
would be allocated real-time uplift costs in this category only if
their net deviations are harming by contributing to differences between
day-ahead and real-time congestion on a constraint.
[[Page 9546]]
48. For netting within this congestion management category, we
propose to require each RTO/ISO to determine real-time uplift cost
allocation based on the net impact of a market participant's deviations
on a constraint. To make this determination, an RTO/ISO should net the
deviations that relieve real-time congestion on the constraint with
those that contribute to it.
49. Deviations caused by non-market transactions (such as internal
bilateral transactions) would not be netted in either the proposed
system-wide capacity category or the proposed congestion management
category because they take place outside of the day-ahead and real-time
markets. Transactions that take place outside of the markets do not
affect real-time scheduling or dispatch and therefore should not offset
transactions that do affect real-time scheduling or dispatch.
50. We seek comment on whether there should be advanced
notification requirements in determining helpful deviations. That is,
is there a period of time prior to the operating hour at which a
deviation should no longer be considered helpful because notification
of the deviation was provided to the RTO/ISO too close to the operating
hour? If so, we seek comment on what the advanced notification
requirement should be.\54\ Under the proposed definition of deviations,
transactions related to real-time economic or reliability-related
operator dispatch instructions would not be used in determining a
market participant's net deviations for both the system-wide capacity
and congestion management categories. We also request comment on
whether and how such transactions should be used to determine a market
participant's net deviations.
---------------------------------------------------------------------------
\54\ For example, MISO determines whether a deviation is helpful
based on whether it occurred before or after a notification deadline
which is four hours prior to the operating hour. See generally MISO,
FERC Electric Tariff, Definitions, ``Notification Deadline'', 1.N &
Real-Time Energy and Operating Reserve Market Settlement Cal,
40.3.3.
---------------------------------------------------------------------------
c. Deviations That Result From Following Dispatch
51. Based on the discussion above and consistent with the proposed
definition of deviations, we clarify that if the RTO/ISO instructs a
resource to deviate from its day-ahead schedule, be that a market-based
or out-of-market instruction, that resource would not be regarded as
deviating for purposes of this NOPR, and should not be allocated real-
time deviation-related uplift costs, because it is helping to address
differences between the day-ahead market solution and real-time system
needs.
52. Consistent with this clarification, first, we propose that an
RTO/ISO may not allocate deviation-related real-time uplift costs to a
transaction that is economically evaluated by the RTO/ISO in the real-
time market. Such transactions include real-time energy transactions
and CTS transactions. Such real-time transactions are responding to
real-time market price signals and are not deviations for the purposes
of this NOPR. These transactions are helping to address real-time
system needs and allocating real-time deviation-related uplift costs to
such transactions could distort incentives to respond to these signals.
Conversely, transactions that are not economically evaluated in the
real-time market and do not have day-ahead schedules, such as self-
scheduled real-time transactions, should be treated as deviations for
the purposes of allocating real-time deviation-related uplift costs.
53. Second, consistent with this clarification, we further propose
that instructed deviations (those initiated by the RTO/ISO) are not
deviations for the purposes of allocating real-time uplift costs, and
therefore, an RTO/ISO may not allocate real-time uplift costs based on
deviations that result from a market participant following a
reliability- related dispatch instruction. Following such a dispatch
instruction, by definition, helps the system. Allocating real-time
uplift costs to market participants who follow dispatch instructions
unfairly penalizes market participants that are responding to system
needs in real-time. Further, assessing real-time uplift costs to such
deviations could discourage a market participant from following
dispatch instructions. At times of system stress, it is essential that
resources follow dispatch instructions. For instance, an RTO/ISO may
issue out-of-market dispatch instructions or deploy reserves to address
immediate reliability issues. A resource that responds to such an RTO/
ISO instruction performs an essential reliability function and should
not be allocated real-time deviation-related uplift costs for following
the dispatch instruction.
54. By excluding instructed deviations from the definition of a
deviation, the Commission is also proposing that instructed deviations
would not be used in any `helping' and `harming' netting process. We
seek comment on whether instructed deviations should be included in any
netting calculations.
d. Settlement
55. Regarding settlement of uplift costs, under both the system-
wide capacity category and the congestion management category, we
propose to require RTOs/ISOs to allocate and net real-time uplift costs
on an hourly basis. RTOs/ISOs typically allocate uplift costs either
hourly or daily. Hourly allocation would most closely align the
imposition of costs with the incentives to behave efficiently in the
market, since the costs of real-time uplift and the actions that cause
that real-time uplift can and usually do change from hour to hour.
Under hourly cost allocation, the costs for real-time uplift during a
particular hour are allocated only to those market participants that
contribute to the need for that uplift in that hour.
e. Other Comments Sought
56. We recognize that considering real-time uplift cost allocation
to deviations for system-wide capacity and congestion management
separately may require a method for dividing costs between the two
categories for circumstances in which real-time uplift is incurred for
the benefit of both categories (e.g., committing a unit to relieve
transmission congestion will also impact system-wide capacity
requirements). We seek comment on the best methods to quantify this
impact and to perform the appropriate cost allocation. We also seek
comment on the process for netting of transactions and deviations set
forth in the proposal for each category. Finally, we seek comment on
the clarifications provided herein regarding those transactions that
should not be considered deviations for the purpose of real-time uplift
cost allocation and whether there are additional transactions that
should be included in this category.
B. Transparency
57. In this section, we first provide a brief background on the
benefits of transparency in the wholesale electric power markets
operated by RTOs/ISOs with respect to reporting uplift, operator-
initiated commitments, and transmission constraint penalty factors. We
then review current RTO/ISO practices with regard to reporting uplift
and operator-initiated commitments, and summarize comments on
transparency requirements, frequency of reporting, type of uplift
information to be reported, inclusion of reasons for uplift or
operator-initiated commitments, granularity with respect to location,
and the inclusion of transmission constraint penalty factors in RTO/ISO
tariffs. Then, we explain the
[[Page 9547]]
need for the reform regarding reporting of uplift, operator-initiated
commitments, and transmission constraint penalty factors. Finally, we
request comment on two additional topics: Reporting of transmission
outages and availability of network models.
1. Background
58. Visibility into the process by which prices are developed in
energy and ancillary services markets supports the functioning of
efficient markets by enhancing predictability, identifying system
needs, and facilitating investment decisions. Moreover, understanding
how RTOs/ISOs calculate prices and how events impact those prices is
critical to hedging, investment, and resource entry and exit decisions.
While all RTOs/ISOs release some information, either through periodic
reports or making data available on their Web sites, as discussed
below, there is significant variation in the timing, granularity, and
types of data released.
2. Current RTO/ISO Practices
a. Reporting Uplift
59. All RTOs/ISOs report information about uplift payments.
However, the extent of the information reported varies widely. For
example, ISO-NE and NYISO provide monthly reports of uplift that
generally provide information that is aggregated across zones and over
the month.\55\ NYISO also makes aggregated uplift costs (in dollars)
available to stakeholders on a daily basis through its daily
reconciliation reports.\56\ MISO provides a number of monthly reports
to market participants on categories of uplift costs; the reports
aggregate the uplift data by category by month and provide historical
monthly data for comparison.\57\ CAISO aggregates uplift data to its 10
existing local capacity requirement areas and reports daily total
uplift costs for each month by the market in which the uplift is
incurred (e.g., day-ahead or real-time), and by the type of costs
incurred, i.e., start-up costs, minimum load costs or energy bid
costs.\58\ PJM has recently adopted new rules to allow the reporting of
daily uplift information by transmission zone, with certain exceptions
for confidentiality reasons.\59\ SPP provides uplift information in a
report that divides uplift costs into seven categories.\60\
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\55\ ISO-NE Report at 60; NYISO Report at 56-57.
\56\ NYISO Report at 59.
\57\ MISO Report at 60.
\58\ CAISO Report at 56.
\59\ PJM, Business Practice Manual 33: Administrative Services
for the PJM Interconnection Operating Agreement at 23-24.
\60\ SPP Report at 40.
---------------------------------------------------------------------------
60. RTO/ISO reporting practices are driven, in part, by the time
needed to complete the settlement process. Some settlement periods last
three to five business days and CAISO provides uplift cost information
based on its 12-business day recalculation statement, although the
settlement period is shorter.\61\ Because of this lag, RTOs/ISOs
typically report uplift on a monthly basis, with the information
aggregated to a zonal or settlement area level.
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\61\ ISO-NE Report at 64-65; PJM Report at 51; CAISO Report at
58.
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61. Most RTOs/ISOs cite confidentiality issues as an additional
reason for their current reporting practices, particularly in regions
with few market participants.\62\ Uplift information is typically
aggregated to avoid publishing information for individual resources.
All RTOs/ISOs assert that they are prohibited from publicly revealing
resource-specific data, as specified in their confidentiality
rules.\63\ Some RTOs/ISOs note that they cannot provide information on
a more granular basis without changes to their confidentiality rules or
information policies.\64\
---------------------------------------------------------------------------
\62\ PJM Report at 48, 54-55; SPP Report at 41, 44; ISO-NE
Report at 61, 67; NYISO Report at 60.
\63\ CAISO Report at 59; NYISO Report at 58; PJM Report at 50-
51; SPP Report at 42; ISO-NE Report at 63-64; MISO Report at 58-59.
\64\ PJM Report at 48; ISO-NE Report at 61.
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62. It is worth noting that market participants with market-based
and traditional cost of service rate authority are required to report
uplift payments in the Electric Quarterly Report (EQR). Pursuant to EQR
reporting requirements, uplift payments are required to be reported at
a granular level. Those reporting requirements require market
participants to report when the uplift payment changes. Because many
resources are commercially organized as stand-alone limited liability
corporations, many individual resources report uplift payments to EQR
within 30 days following the end of a quarter. While EQR provides a
significant amount of information, it does not provide detailed
information regarding uplift. For example, EQR contains only a single
``uplift'' category which does not differentiate between different
types of uplift (e.g., day-ahead, voltage and local reliability).
b. Reporting Operator-Initiated Commitments
63. RTOs/ISOs also vary in the amount, granularity, and timing of
information that is reported on operator-initiated commitments. For
example, CAISO, MISO, and NYISO provide information regarding operator-
initiated commitments either shortly after the operating day or in near
real-time. CAISO and MISO both report total operator-initiated
commitments aggregated across the RTO/ISO, including the reasons for
the commitments.\65\ MISO provides its reports in near real-time, while
CAISO releases its report several days after the operating day.
Throughout the operating day, NYISO posts operational announcements
providing information about individual operator-initiated commitments,
including the units involved, level of unit commitment, and the reason
for the commitment, with a reference to the relevant reliability rule,
if applicable.\66\
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\65\ MISO Report at 60; CAISO, Daily Exceptional Dispatch
Report, http://www.caiso.com/market/Pages/DailyExceptionalDispatch/Default.aspx.
\66\ NYISO Report at 56-57 and n.32.
---------------------------------------------------------------------------
64. In addition, all RTOs/ISOs provide summary reports of operator-
initiated commitments over longer time periods. CAISO's monthly
performance report provides metrics on exceptional dispatch \67\ and
operator-initiated commitments organized by market (i.e., day-ahead or
real-time), trade date, reason, or local area.\68\ CAISO also files a
monthly report on the frequency and volume of exceptional dispatch,
pursuant to directives in previous Commission orders.\69\ ISO-NE
publishes weekly, monthly, and quarterly reports that describe notable
operational events, but it does not provide any information regarding
the location or capacity of committed units.\70\ ISO-NE also reports
the number of units committed after the close of the day-ahead market
(but not including real-time commitments) each day.\71\ SPP reports
monthly the MW of operator-initiated commitments.\72\
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\67\ CAISO states that its system operator issues exceptional
dispatches to resources to address system issues that cannot be
addressed by the constraints modeled within the market. CAISO Report
at 41.
\68\ Id. at 56.
\69\ Id. See also Cal. Indep. Sys. Operator Corp., 131 FERC ]
61,100 (2010) (clarifying the reporting timeline for reporting
exceptional dispatches).
\70\ ISO-NE Report at 60.
\71\ Id. at 61-62.
\72\ SPP Report at 40.
---------------------------------------------------------------------------
65. PJM states that, although its confidentiality provisions
prevent it from reporting individual operator-initiated commitments in
real-time, it
[[Page 9548]]
does provide regionally aggregated information on uneconomic
commitments in the day-ahead market at the end of the business day. In
addition, PJM posts total capacity committed during the Reliability
Assessment and Commitment period to meet forecasted load and reserves,
as well as resources committed for transmission constraints, voltage/
reactive constraints, or conservative operations.\73\ ISO-NE also
states its confidentiality provisions prohibit reporting of operator-
initiated commitments in real-time, while CAISO states providing
information about exceptional dispatches more frequently than monthly
would require significant changes to its systems.\74\ SPP states it is
technically feasible to report commitments resulting from operator
actions in real-time, but notes such reporting could disclose sensitive
reliability information.\75\
---------------------------------------------------------------------------
\73\ PJM Report at 49-50.
\74\ ISO-NE Report at 65; CAISO Report at 58, 62.
\75\ SPP Report at 41.
---------------------------------------------------------------------------
c. Transmission Constraint Penalty Factors
66. Transmission constraint penalty factors are the values at which
an RTO's/ISO's market software will relax the flow-based limit on a
transmission element to relieve a constraint caused by that limit
rather than re-dispatch resources to relieve the constraint. The cost
of re-dispatching resources can be regarded as the re-dispatch price.
Transmission constraint penalty factors represent the maximum re-
dispatch price that the system will pay before allowing flows to exceed
a given transmission element's limit.\76\ The penalty factors should be
set at levels that are high enough to avoid relaxing constraints too
frequently, but low enough to avoid extremely expensive re-dispatch
solutions that are more expensive than the expected cost of exceeding a
given transmission element's limit. While these penalty factors can
have significant impacts on prices, changes are not always made public
nor do all RTOs/ISOs file them with the Commission. Specifically, PJM
and ISO-NE do not include transmission constraint penalty factors in
their respective tariffs.\77\ Further, MISO is the only RTO/ISO that
details in its tariff how transmission constraint penalty factors are
temporarily changed.\78\
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\76\ Transmission constraint penalty factors create a cap on the
shadow price of a transmission constraint. See MISO Market Monitor
Comments, Docket No. AD14-14-000, at 20-21 (Feb. 24, 2015).
\77\ CAISO, MRTU Tariff 27.4.3.1-27.4.3.3; SPP, OATT, Sixth
Revised Volume No. 1, Attachment AE, 8.3.2, Addendum 1; NYISO
Tariffs, NYISO Markets and Services Tariff 1.20; MISO, FERC Electric
Tariff, Schedule 28A.
\78\ MISO, FERC Electric Tariff, Schedule 28A.
---------------------------------------------------------------------------
3. Comments
a. General Comments
67. Various commenters recommend reporting of uplift and operator-
initiated commitments that is more regular, more geographically
granular, more specific about the size of the action (in MW), and/or
more informative of the reason for uplift or operator action. Numerous
commenters argue that such reporting about uplift and operator-
initiated commitments should be mandatory.\79\ Exelon urges the
Commission to require RTOs/ISOs to identify out-of-market actions and
the resulting uplift in regular reports.\80\ Several commenters propose
that RTOs/ISOs be required to post information in a way that is
uniform, consistent, and comparable across RTOs/ISOs.\81\
---------------------------------------------------------------------------
\79\ DC Energy, Inertia Power, and Vitol Comments at 18; EPSA
Comments (on MISO Report) at 22; EPSA/NEPGA Comments at 14; Energy
Storage Association Comments at 2-3; Exelon Comments at 17-18; PSEG
Companies Comments at 16.
\80\ Exelon Comments at 17-18.
\81\ DC Energy, Inertia Power, and Vitol Comments at 18; EPSA
Comments (on price formation) at 22; EPSA Comments (on MISO Report)
at 22; EPSA/IPPNY Comments at 13; EPSA Comments (on SPP Report) at
10; EPSA/NEPGA Comments at 14-15; EPSA/P3 Comments at 15; EPSA/WPTF
Comments at 10.
---------------------------------------------------------------------------
b. Comments on Uplift Reporting
68. In terms of frequency, some commenters recommend monthly
reporting of uplift to improve transparency.\82\ Energy Storage
Association requests that RTOs/ISOs provide daily summary data on
uplift credits. Energy Storage Association asserts that such
information should, at a minimum, be at a zonal level and should be
made available by all RTOs/ISOs several days after the operating
day.\83\
---------------------------------------------------------------------------
\82\ EPSA Comments (on MISO Report) at 21-22; EPSA/NEPGA
Comments at 13.
\83\ Energy Storage Association Comments at 2-3.
---------------------------------------------------------------------------
Several commenters request more granular locational information
regarding uplift.\84\ These commenters argue that it is difficult to
reduce or eliminate uplift when market participants do not know where
it originates. To address this request, many commenters, including
CAISO, ISO-NE, and PJM, support reporting uplift on a zonal basis.\85\
CAISO, ISO-NE, and PJM state that zonal reporting strikes a balance
between granularity and confidentiality.\86\ In contrast, SPP and MISO
caution that reporting uplift on a zonal basis could reveal sensitive
market participant information.\87\
---------------------------------------------------------------------------
\84\ Financial Marketers Coalition Comments at 45; Energy
Storage Association Comments at 6; Golden Spread Comments at 8-9.
\85\ Financial Marketers Coalition Comments at 45; Energy
Storage Association Comments at 6; PJM Market Monitor Comments at
20; CAISO Report at 61; PJM Report at 52; ISO-NE Report at 64, 66.
\86\ PJM Report at 53; ISO-NE Report at 66; CAISO Report at 61.
\87\ MISO Report at 60-61; SPP Report at 43.
---------------------------------------------------------------------------
69. Commenters have differing views on what uplift information
should be reported. PSEG Companies argue that uplift can be effectively
reported on a dollar basis.\88\ Energy Storage Association states that
RTOs/ISOs should share daily summary data on uplift in dollars,
including the reasons for the uplift and the location (at a minimum at
a zonal level) of the resources that receive it.\89\ The PJM Market
Monitor recommends reporting uplift charges by resource as well as
detailed reasons for incurring uplift.\90\ EPSA and EPSA/NEPGA
recommend reporting the settled uplift dollar impact on a MW basis, as
well as the reasons for out-of-market commitments every month.\91\ EPSA
asserts that reporting additional information on the drivers of uplift
and out-of-market dispatch can be made public without compromising
sensitive information, because NYISO currently does so in monthly
reports.\92\
---------------------------------------------------------------------------
\88\ PSEG Companies Comments at 12, 15-16.
\89\ Energy Storage Association Comments at 2.
\90\ PJM Market Monitor Comments at 20-21.
\91\ EPSA and its joint commenters support several variations of
``reporting actual settled uplift dollar impacts, on a Megawatt (MW)
basis.'' It is unclear whether this is referring to reporting uplift
dollars divided by the total capacity of resources that receive
uplift payments, or reporting the total capacity of committed
resources in lieu of identifying specific units. EPSA Comments (on
price formation) at 23; EPSA Comments (on MISO Report) at 21-22;
EPSA/NEPGA Comments at 13.
\92\ EPSA Comments (on price formation) at 23.
---------------------------------------------------------------------------
70. EPSA/IPPNY warns that reporting uplift more frequently than
daily could potentially reveal confidential information.\93\ Energy
Storage Association suggests that, given confidentiality concerns, the
Commission could allow an RTO/ISO to request an exemption from
reporting zonal or locational information in certain situations where
there are few participants in a zone or location.\94\ ISO-NE and MISO
suggest that the level of aggregation be adjusted to ensure that
confidentiality is maintained.\95\
---------------------------------------------------------------------------
\93\ EPSA/IPPNY Comments at 12-13.
\94\ Energy Storage Association Comments at 3.
\95\ ISO-NE Report at 66; MISO Report at 61.
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c. Comments on Reporting Operator-Initiated Commitments
71. Several commenters recommend monthly reporting of operator-
initiated actions, including the reasons for out-of-market actions, to
improve
[[Page 9549]]
transparency.\96\ Commenters argue that understanding the reasons for
out-of-market commitments will help market participants discern what
types of investments are needed to meet system needs.\97\ Moreover, the
Financial Marketers Coalition states that, when out-of-market
commitments are identified by location and explained, financial
participants will refrain from bidding because they know that prices
will not converge and uplift is likely.\98\
---------------------------------------------------------------------------
\96\ EPSA Comments (on MISO Report) at 21-22; EPSA/NEPGA
Comments at 13; Exelon Comments at 18; EPSA Comments (on price
formation) at 23 EPSA/IPPNY Comments at 13; EPSA/P3 Comments at 15-
16.
\97\ EPSA Comments (on price formation) at 23; EPSA/P3 Comments
at 15-16.
\98\ Financial Marketers Coalition Comments at 42.
---------------------------------------------------------------------------
72. Some commenters also suggest that RTOs/ISOs report operator-
initiated commitments closer to real-time. In particular, PSEG
Companies suggest that NYISO's approach to disclosing out-of-market
commitment and dispatch decisions should be considered a best
practice.\99\
---------------------------------------------------------------------------
\99\ PSEG Companies Comments at 11.
---------------------------------------------------------------------------
74. Several commenters request more granular locational information
regarding out-of-market operator actions.\100\ PSEG Companies note that
when RTOs/ISOs provide only aggregated data, it is not possible to
discern whether the RTO/ISO needed those units or how many MW were
actually required.\101\
---------------------------------------------------------------------------
\100\ Financial Marketers Coalition Comments at 45 (referring to
SPP); Energy Storage Association Comments at 6 (referring to MISO
and SPP); Golden Spread Comments at 8-9.
\101\ PSEG Companies Comment at 14.
---------------------------------------------------------------------------
d. Comments on Transmission Constraint Penalty Factors
75. The MISO Market Monitor asserts that transmission constraint
penalty factors substantially affect market outcomes but are not filed
with or approved by the Commission for some RTOs/ISOs. MISO Market
Monitor adds that increasing transmission constraint penalty factors
during real-time operations to relieve constraints may indicate that
constraints were undervalued previously, and lowering transmission
constraint penalty factors during real-time operations may indicate
that the RTO/ISO is attempting to manually reduce congestion costs.
MISO Market Monitor contends that these concerns can be addressed by:
(1) Establishing parameters that reflect the reliability value of
managing the constraints, which likely varies by constraint; (2) filing
these values in the RTO's/ISO's tariffs so they are known and approved
by the Commission; and (3) filing tariff provisions that specify the
procedures and authority for RTOs/ISOs to modify transmission
constraint penalty factors.\102\
---------------------------------------------------------------------------
\102\ Comments of MISO Market Monitor, Docket No. AD14-14-000,
at 20-21 (Feb. 24, 2015).
---------------------------------------------------------------------------
76. XO Energy states that transmission constraint penalty factors
can have a significant impact on prices; however, there is not
necessarily clear insight as to how transmission constraint penalty
factors are determined or calculated in the pricing and dispatch
algorithms.\103\ XO Energy contends that, in some cases, the default
transmission constraint penalty factors can be arbitrarily assigned and
modified on a case-by-case basis.\104\
---------------------------------------------------------------------------
\103\ XO Energy Comments at 67-68.
\104\ Id. at 68.
---------------------------------------------------------------------------
4. Need for Reform
77. We preliminarily find that some existing RTO/ISO practices of
reporting uplift, operator-initiated commitments, and transmission
constraint penalty factors may result in unjust and unreasonable rates.
The lack of transparency regarding uplift and operator-initiated
commitments, which can cause uplift, hinders market participants'
ability to plan and efficiently respond to system needs. Market
participants may lack the information necessary to evaluate the need
for and value of additional investment, such as transmission upgrades
or new generation. Also, without sufficient transparency, market
participants may not be able to assess each RTO's/ISO's operator-
initiated commitment practices and raise any issues of concern through
the stakeholder process.
78. Reporting that specifies the location and causes of uplift and
operator-initiated commitments will help incent appropriate market
responses to system needs. For example, if resources are routinely
committed out-of-market to resolve a local voltage issue and require
uplift payments as a result, it may be beneficial to release
information on the uplift associated with using such resources to alert
market participants about the problem. Providing more detailed
information about the uplift incurred to address a local reliability
issue could potentially incent market participants to advocate for
changes to the RTO/ISO's operational procedures or to undertake
investments that could resolve the local reliability issue more
efficiently (e.g., install additional capacitors).
79. While all RTOs/ISOs provide some information regarding the
locations and causes of uplift and operator-initiated commitments, the
information is often highly aggregated or lacks detail, limiting its
usefulness. Information about the location and causes of uplift and
operator-initiated commitments that is overly aggregated or lacks
detail hinders the ability of a market participation to evaluate RTO/
ISO operating practices and potentially respond to system needs by
undertaking new investments. For example, reports that aggregate uplift
payments over the month may not provide sufficient information, since
monthly reports can obscure daily trends, which may be more relevant to
those evaluating operating practices or potential investments.
Therefore, increasing transparency with respect to the location and
cause of uplift can provide market participants additional information
to evaluate the effectiveness of current operating practices. Without
sufficient information to evaluate existing operating practices or the
need for additional investment, market efficiency may be reduced,
resulting in unjust and unreasonable rates. Allowing market
participants to better evaluate the need for changes in operating
practices or additional investment could ultimately reduce the level of
uplift, thereby resulting in rates that are just and reasonable.
80. Similarly, the lack of transparency with respect to
transmission constraint penalty factors may hinder the ability of
market participants to undertake efficient transactions. For example,
if market participants are unaware of what transmission constraint
penalty factors are used and whether they will be used to set LMPs,
market participants may not be able to adequately understand how an
RTO's/ISO's actions affect clearing prices and thus may not be able to
hedge transactions appropriately or effectively assess the RTO's/ISO's
actions and raise concerns through the stakeholder process. Without the
ability to appropriately hedge transactions, market participants may
either over-hedge or under-hedge their positions, reducing market
efficiency. Also, if market participants are not able to raise concerns
about changes in transmission constraint penalty factors, RTOs/ISOs may
alter transmission constraint penalty factors more often than
necessary, which impacts market clearing prices. Therefore, the
resulting rates may be unjust and unreasonable.
81. Some RTOs/ISOs report that there are a variety of stakeholder
initiatives and discussions underway to improve transparency,\105\
while others do not
[[Page 9550]]
mention any specific plans.\106\ Despite these efforts, it is not clear
that the transparency concerns discussed in this NOPR will be addressed
through existing stakeholder initiatives. Accordingly, we preliminarily
find that some existing RTO/ISO practices with respect to reporting
uplift, operator-initiated commitments, and transmission constraint
penalty factors may be unjust and unreasonable.
---------------------------------------------------------------------------
\105\ CAISO Report at 55; MISO Report at 56; NYISO Report at 55;
PJM Report at 47.
\106\ ISO-NE Report at 59; SPP Report at 39.
---------------------------------------------------------------------------
5. Proposal
82. To remedy these potentially unjust and unreasonable reporting
practices, we propose, pursuant to section 206 of the Federal Power
Act, to require that each RTO/ISO: (1) Report total uplift payments for
each transmission zone on a monthly basis, broken out by day and uplift
category; (2) report total uplift payments for each resource on a
monthly basis; (3) report the MW of operator-initiated commitments in
or near real-time and after the close of the day-ahead market, broken
out by zone and commitment reason; and (4) list in its tariff the
transmission constraint penalty factors, the circumstances under which
they can set LMPs, and the procedure by which they can be temporarily
changed.
a. Uplift Reporting
83. We propose to require that, within 20 days of the end of each
month, each RTO/ISO post on its Web site two reports, at minimum,
regarding uplift payments. First, the RTO/ISO should report the total
uplift payments in dollars paid daily to the resources in each
transmission zone, subject to certain exceptions described below. Each
RTO/ISO must post the total amount of uplift in dollars in each
category (e.g., day-ahead, real-time, voltage and local reliability)
paid to resources in each transmission zone for each day within the
calendar month. We propose to require that each RTO/ISO post uplift
payment amounts based on its specific uplift categories to allow market
participants to distinguish between different types of uplift. Second,
each RTO/ISO must post the resource name and the total amount of uplift
paid in dollars aggregated across the month to each resource that
received uplift payments within the calendar month. We seek comment on
whether these resource-specific reports should also be broken out by
uplift category, be reported using a different time duration, or
contain other additional details.
84. Information on uplift payments should be posted in a machine
readable format on a publicly accessible portion of the RTO's/ISO's Web
site. With this information, market participants may be able to
evaluate possible solutions to reduce the incurrence of uplift. For
example, with more granular information on the location, amounts, and
types of uplift, market participants can better evaluate the benefits
of additional transmission upgrades that could reduce the need for unit
commitments.
85. We also propose to define ``transmission zone'' as a geographic
area that is used for the local allocation of charges. For example,
this could include a load zone that is used to settle charges for
energy. We request comments on this proposed definition of transmission
zone, including the appropriate level of geographic granularity.
86. Regarding the timeliness of posting this information, we
recognize that each RTO/ISO has a different settlement window and
uplift is finalized during the settlement process. As such, it is not
possible for an RTO/ISO to release information immediately at the end
of the month. In order to account for differences in settlement periods
and the time necessary to prepare the uplift data for publication, we
propose to require that both reports described above be released no
later than 20 calendar days following the end of the month. While we
believe this is a reasonable timeframe for release, we seek comment on
the timeframe for releasing the information after the end of each
month. In addition, we seek comment on the proposed requirement for a
daily breakdown of uplift categories by charge code, including any
obstacles or difficulties related to such reporting and whether
different categorizations would be more useful.
87. Many commenters express concern that greater transparency in
uplift reporting could unintentionally disclose a resource's uplift
payments or energy offers, which some characterize as confidential or
commercially-sensitive information. Commenters' core concerns appear to
relate to two issues: first, that disclosing a resource's uplift
payments will allow other market participants to calculate energy
offers and may result in collusion between market participants.\107\
Second, commenters appear to be concerned that revealing uplift
payments may put a resource at a competitive disadvantage by disclosing
commercially sensitive information like fuel procurement strategies.
---------------------------------------------------------------------------
\107\ In conjunction with other information, uplift payments
could potentially be used to determine a resource's energy offers.
For example, if a market participant knew a resource's output, LMP,
and uplift payments, it could potentially calculate the resource's
energy offer because the uplift would make the resource whole up to
its offer costs.
---------------------------------------------------------------------------
88. While we understand the need to protect certain types of
information, we are not persuaded that revealing a resource's daily
uplift payments or energy offer, after some minimal time lag, would
result in any significant harm to competition or individual market
participants. First, many individual resources already publicly report
their uplift payments pursuant to Electric Quarterly Reporting
requirements (with a 90-day lag). Second, RTO/ISO energy markets are
mitigated, so concerns about the potential for collusion can be
addressed through must offer requirements and market power mitigation
rules. Third, after the 20-day lag for reporting following the end of
the month, fuel costs and other conditions have often changed,
diminishing the potential usefulness of any resource offer information.
These three factors limit the potential for anti-competitive behavior
and any harm to market participants.
89. Nevertheless, to address commenters' concerns, we seek to
balance the benefits of greater transparency with the desire to
preserve a reasonable level of confidentiality. Specifically, for the
reporting requirements aggregated by transmission zone, we propose that
transmission zones with fewer than four resources need not be reported
individually; rather, transmission zones with fewer than four resources
may be aggregated with a neighboring transmission zone and reported
collectively. If only one transmission zone exists and it has fewer
than four resources or, if when combined with a neighboring
transmission zone the combined transmission zone still has fewer than
four resources, then these transmission zones would be exempted from
reporting the uplift information described above. Similarly, for the
resource-specific reporting requirements proposed above, we will
require that uplift payment data for each resource be aggregated across
the month, rather than reporting daily uplift payments to each
resource. We expect that this temporal aggregation should mask daily
behavior that some commenters have expressed concerns over revealing.
b. Reporting Operator-Initiated Commitments
90. We also propose to require that each RTO/ISO post all operator-
initiated commitments on its Web site. For the purposes of this NOPR,
we propose to define operator-initiated commitments as a commitment
that is not associated
[[Page 9551]]
with a resource clearing the day-ahead or real-time market on the basis
of economics and that is not self-scheduled.\108\ This definition would
include any commitment, whether manual or automated, made after the
execution of the day-ahead market that is made outside of the real-time
market. Such commitments include commitments made through a residual
unit commitment processes after the execution of the day-ahead market,
commitments made through look-ahead commitment processes, and manual
commitments made in real-time. We acknowledge that this definition of
operator-initiated actions could result in reporting most commitments
that occur after the day-ahead market. Moreover, we understand that
whether a commitment cleared the market on the basis of economics could
be a point of confusion, particularly with respect to look-ahead
commitment processes. Therefore, we request comment on this aspect of
the definition of operator-initiated actions.
---------------------------------------------------------------------------
\108\ See supra text accompanying note 1.
---------------------------------------------------------------------------
91. The report posted on each RTO's/ISO's Web site would include
the following: (1) The upper economic operating limit of the committed
resource in MW (i.e., its economic maximum); (2) the transmission zone
in which the resource is located; and (3) the reason for
commitment.\109\ We propose that each RTO/ISO post this information on
a publicly accessible portion of its Web site in machine-readable
format as soon as practicable after the resource has been committed
(i.e., directed to start up by the RTO/ISO). As above, we propose to
define ``transmission zone'' as a geographic area that is used for the
local allocation of charges. We request comments on this proposed
definition, including the appropriate level of geographic granularity.
Also, as discussed further below, we propose that real-time commitments
be posted as soon as practicable after they occur, but no later than
four hours after the commitment.
---------------------------------------------------------------------------
\109\ For example, if a resource with two combustion turbines
with a capacity of 50 MW each was committed to manage congestion on
a transmission facility, the RTO/ISO would be required to report the
committed capacity (100 MW) and the reason (e.g., constraint
management).
---------------------------------------------------------------------------
92. Many commenters express concern about the lack of transparency
surrounding operator-initiated commitments and request that the
Commission require RTOs/ISOs to provide more information.\110\ We agree
that current RTO/ISO practices may not provide sufficient transparency
regarding operator-initiated commitments and that a minimum level of
transparency is necessary as operator-initiated commitments can affect
rates. In particular, operator-initiated commitments can affect energy
and ancillary service prices and can result in uplift. In addition,
greater transparency will allow stakeholders to better assess the
RTO's/ISO's operator-initiated commitment practices and raise any
issues of concern through the stakeholder process.
---------------------------------------------------------------------------
\110\ E.g., EPSA Comments at 22-23; Exelon Comments at 17-18;
Financial Marketers Coalition Comments at 42; PSEG Comments at 12.
---------------------------------------------------------------------------
93. While most commenters focus on reporting of manual operator-
initiated commitments (i.e. not through automated software),\111\
operator-initiated commitments made through automated processes like
look-ahead commitment can also have a significant impact on uplift. In
addition, as noted by several RTOs/ISOs, manual operator-initiated
commitments are generally infrequent. Because posting all operator-
initiated commitments, whether manual or automated, would help market
participants to better understand the drivers behind the incurrence of
uplift in each zone and the impact of such commitments on rates, we
propose that all operator-initiated commitments be posted, whether
manual or automated. We also seek comment on the types of unit
commitments that should be reported as operator-initiated commitments.
---------------------------------------------------------------------------
\111\ CAISO Report at 60; ISO-NE Report at 65; SPP Report at 42;
PSEG Companies Comments at 12, 14-16, 21.
---------------------------------------------------------------------------
94. In addition, we propose that real-time commitments be posted as
soon as practicable after they occur, but no later than four hours
after the commitment. We understand that this type of reporting could
require significant changes to current RTO/ISO systems and processes.
Accordingly, we seek comment on the proposed reporting timeframe,
including the potential software upgrades necessary to facilitate
reporting in near real-time and other potential implementation
challenges. We also seek comment on whether a different reporting
timeframe (e.g., reporting once daily or monthly) would provide
sufficient transparency.
95. We also understand that reporting the reason for an operator-
initiated commitment may require the development of new internal
processes. In particular, we understand that the reasons for operator-
initiated commitments can vary based on the particular situation.
Therefore, our proposal would only require RTOs/ISOs to report the
commitment reason within broad categories (e.g., voltage support,
capacity-related). We seek comment on whether the Commission should
define a common set of categories for use across all RTOs/ISOs and, if
so, what categories should be included, or whether it is more
appropriate to allow each RTO/ISO to establish a set of appropriate
operator-initiated commitment reasons on compliance. In addition, we
note that some RTOs/ISOs currently provide more granular or detailed
information about the reason for operator-initiated commitments.\112\
Therefore, we seek comment on whether the proposal provides sufficient
transparency, or if more information is needed (e.g., specific
constraint name), as well as any potential concerns with requiring
additional information (e.g., required software upgrades or impact on
operational processes).
---------------------------------------------------------------------------
\112\ For example, for real-time commitments made to manage
congestion, MISO identifies the specific constraint that prompted
the commitment. MISO Report at 60.
---------------------------------------------------------------------------
c. Transmission Constraint Penalty Factors
96. We propose to require that all RTOs/ISOs include certain
provisions related to transmission constraint penalty factors in their
tariffs because transmission constraint penalty factors can
significantly impact market clearing prices.
97. First, we propose to require that all RTOs/ISOs include their
transmission constraint penalty factor values in their tariffs. This
requirement would only apply to penalty factors used for transmission
constraints and would not include other penalty factors used in
commitment and dispatch algorithms. If the RTO/ISO uses different
transmission constraint penalty factors for different processes, we
propose to require that all sets of transmission constraint penalty
factors be included in the tariff. For example, if an RTO/ISO uses
different transmission constraint penalty factors in its security
constrained unit commitment and its security constrained economic
dispatch, it should include both sets of transmission constraint
penalty factors in its tariff.
98. Second, we propose to require that RTOs/ISOs include in their
tariffs an explanation as to if and when transmission constraint
penalty factors may be used to set LMPs. If the RTO/ISO has different
processes for allowing transmission constraint penalty factors to set
LMPs in different circumstances, this should be explained in the
tariff. As part of its explanation, the RTO/ISO should also make clear
whether there are any specific restrictions or
[[Page 9552]]
conditions under which transmission constraint penalty factors are
allowed to set LMPs, such as a minimum duration for transmission
constraint violations.
99. Finally, if RTOs/ISOs wish to have the flexibility to
temporarily change transmission constraint penalty factors to account
for changes in system conditions, they must include the procedures for
doing so in their tariffs. We also propose to require these procedures
to include a requirement that notice of the temporary change be
provided to market participants. For example, an RTO/ISO could notify
market participants of the temporary change by posting on its Web site.
d. Comment Sought on Transmission Outages
100. We seek comment on whether additional reporting of
transmission outages should be required. Transmission outages can
affect RTO/ISO commitment and dispatch decisions and resulting market
clearing prices, and thus are an important facet of price formation.
Though the current record on this issue is limited, we seek comment as
to whether additional transparency in this regard would be beneficial
to stakeholders and if RTOs/ISOs have any limitations in providing more
detailed data in this regard, including any appropriate time lag for
reporting.
e. Comment Sought on Availability of Market Models
101. Some commenters indicate that distribution of the network
model may be limited to certain market participants.\113\ For the
purposes of this NOPR we define network model as the RTO's/ISO's model
used in its energy management system for the real-time operation of the
transmission system (e.g., state-estimation, contingency analysis). We
seek comment on whether certain classes of market participants are
prohibited from obtaining the network model in certain RTOs/ISOs.
Moreover, if there are limitations to which market participants are
able to obtain the model, we seek comment on the justification for any
such limitations.
---------------------------------------------------------------------------
\113\ DC Energy, Inertia Power, and Vitol Comments at 21, 26;
Financial Marketers Coalition Comments at 43.
---------------------------------------------------------------------------
III. Compliance
102. We propose to require that each RTO/ISO submit a compliance
filing within 90 days of the effective date of any eventual Final Rule
in this proceeding to demonstrate that it meets the proposed
requirements set forth in the Final Rule. We note that this compliance
deadline is for RTOs/ISOs to submit proposed tariff changes or
otherwise demonstrate compliance with the Final Rule. We understand
that implementing the reforms required by any Final Rule in this
proceeding may be a complex endeavor. However, we preliminarily find
that implementation of these reforms is important to ensure rates are
just and reasonable. Therefore, we propose that tariff changes filed in
response to a Final Rule in this proceeding must become effective no
more than six months after compliance filings are due.
103. We seek comment on whether 90 days is sufficient time for
RTOs/ISOs to develop new tariff language in response to the Final Rule.
104. To the extent that any RTO/ISO believes that it already
complies with the reforms proposed in this NOPR, the RTO/ISO would be
required to demonstrate how it complies in the compliance filing
required 90 days after the effective date of any Final Rule in this
proceeding. To the extent that any RTO/ISO believes that its existing
market rules are consistent with or superior to the reforms adopted in
any Final Rule, the Commission will entertain those at that time.\114\
---------------------------------------------------------------------------
\114\ See, e.g., Settlement Intervals and Shortage Pricing in
Markets Operated by Regional Transmission Organizations and
Independent System Operators, Order No. 825, FERC Stats. & Regs. ]
31,384, at P 72 (2016); Demand Response Compensation in Organized
Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ]
31,322, at P 4 & n.7, order on reh'g and clarification, Order No.
745-A, 137 FERC ] 61,215 (2011), reh'g denied, Order No. 745-B, 138
FERC ] 61,148 (2012), vacated sub nom. Elec. Power Supply Ass'n v.
FERC, 753 F.3d 216 (D.C. Cir. 2014), rev'd & remanded sub nom. FERC
v. Elec. Power Supply Ass'n, 136 S. Ct. 760 (2016).
---------------------------------------------------------------------------
IV. Information Collection Statement
105. The Paperwork Reduction Act (PRA) \115\ requires each federal
agency to seek and obtain Office of Management and Budget (OMB)
approval before undertaking a collection of information directed to ten
or more persons or contained in a rule of general applicability. OMB's
regulations \116\ require approval of certain information collection
requirements imposed by agency rules. Upon approval of a collection of
information, OMB will assign an OMB control number and an expiration
date. Respondents subject to the filing requirements of an agency rule
will not be penalized for failing to respond to the collection of
information unless the collection of information displays a valid OMB
control number.
---------------------------------------------------------------------------
\115\ 44 U.S.C. 3507 (2012).
\116\ 5 CFR 1320 (2016).
---------------------------------------------------------------------------
106. The reforms proposed in this NOPR would amend the Commission's
regulations to improve the operation of organized wholesale electric
power markets operated by RTOs/ISOs. The Commission proposes to require
each RTO/ISO that allocates the costs of real-time uplift due to
deviations should allocate such real-time uplift costs to only those
market participants whose transactions are reasonably expected to have
caused the real-time uplift. The Commission also proposes to revise its
regulations to enhance transparency by requiring that each RTO/ISO post
uplift costs paid (dollars) and operator-initiated commitments
(megawatts) on its Web site; and define in its tariff its transmission
constraint penalty factors, as well as the circumstances in which the
penalty factors can set locational marginal prices, and any procedure
for changing the penalty factors. The reforms proposed in this NOPR
would require one-time filings of tariffs with the Commission and
potential software upgrades to implement the reforms proposed in this
NOPR. The Commission anticipates the reforms proposed in this NOPR,
once implemented, would not significantly change currently existing
burdens on an ongoing basis. The Commission will submit the proposed
reporting requirements to OMB for its review and approval under section
3507(d) of the Paperwork Reduction Act.\117\
---------------------------------------------------------------------------
\117\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------
107. While the Commission expects the adoption of the reforms
proposed in this NOPR to provide significant benefits, the Commission
understands implementation can be a complex endeavor. The Commission
solicits public comments on its need for this information, whether the
information will have practical utility, the accuracy of burden and
cost estimates, ways to enhance the quality, utility, and clarity of
the information to be collected or retained, and any suggested methods
for minimizing respondents' burden, including the use of automated
information techniques.
108. Public Reporting Burden Estimate and Information Collection
Costs: The Commission believes that the burden estimates that follow
are representative of the average burden on respondents, including
necessary communications with stakeholders.
[[Page 9553]]
FERC-516G, as Modified by the NOPR in Docket RM17-2-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average burden Total annual
Number of Annual number Total number (hours) & cost burden hours & Cost per
respondents of responses of responses per response total annual respondent ($)
\118\ per respondent \119\ cost
(1) (2) (1) x (2) = (4) (3) x (4) = (5) / (1)
(3) (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Uplift Allocation....................................... 6 1 6 500; $36,500 3,000; $36,500
$219,000
Transparency............................................ 6 1 6 500; $36,500 3,000; 36,500
$219,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost to Comply: The Commission has projected the total cost of
compliance, within Year 1 to be $438,000. After Year 1, the reforms
proposed in this NOPR, once implemented, would not significantly change
existing burdens on an ongoing basis.
---------------------------------------------------------------------------
\118\ Respondent entities are either RTOs or ISOs.
\119\ The estimated hourly cost (salary plus benefits) provided
in this section are based on the salary figures for May 2015 posted
by the Bureau of Labor Statistics for the Utilities sector
(available at http://www.bls.gov/oes/current/naics2_22.htm#00-0000)
and scaled to reflect benefits using the relative importance of
employer costs in employee compensation from December 2015
(available at http://www.bls.gov/news.release/ecec.nr0.htm). The
hourly estimates for salary plus benefits are:
Legal (code 23-0000), $129.12
Computer and Mathematical (code 15-0000), $60.63
Information Security Analyst (code 15-1122), $58.08
Accountant and Auditor (code 13-2011), $53.86
Information and Record Clerk (code 43-4199), $37.75
Electrical Engineer (code 17-2071), $64.29
Economist (code 19-3011), $74.53
Computer and Information Systems Manager (code 11-3021), $91.76
Management (code 11-0000), $89.07
The average hourly cost (salary plus benefits), weighting all of
these skill sets evenly, is $73.23. For the calculations here, the
Commission rounds it to $73 per hour.
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Title: FERC-516G, Electric Rate Schedules and Tariff Filings in
Docket RM17-2-000.
Action: Proposed revisions to an existing information collection.
OMB Control No.: TBD.
Respondents for this Rulemaking: RTOs/ISOs.
Frequency of Information: One-time.
Necessity of Information: The Federal Energy Regulatory Commission
implements this rule to improve competitive wholesale electric markets
in the RTO/ISO regions.
Internal Review: The Commission has reviewed the changes and has
determined that such changes are necessary. These requirements conform
to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has specific, objective support for the burden estimates
associated with the information collection requirements.
109. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director], email:
[email protected], Phone: (202) 502-8663, fax: (202) 273-0873.
Comments concerning the collection of information and the associated
burden estimate(s) may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission]. Due to security concerns, comments
should be sent electronically to the following email address:
[email protected]. Comments submitted to OMB should refer to
FERC-516G and OMB Control No TBD.
V. Environmental Analysis
110. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\120\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this NOPR under section 380.4(a)(15)
of the Commission's regulations, which provides a categorical exemption
for approval of actions under sections 205 and 206 of the FPA relating
to the filing of schedules containing all rates and charges for the
transmission or sale of electric energy subject to the Commission's
jurisdiction, plus the classification, practices, contracts and
regulations that affect rates, charges, classifications, and
services.\121\
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\120\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
\121\ 18 CFR 380.4(a)(15) (2016).
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VI. Regulatory Flexibility Act
111. The Regulatory Flexibility Act of 1980 (RFA) \122\ generally
requires a description and analysis of proposed rules that will have
significant economic impact on a substantial number of small entities.
The RFA does not mandate any particular outcome in a rulemaking. It
only requires consideration of alternatives that are less burdensome to
small entities and an agency explanation of why alternatives were
rejected.
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\122\ 5 U.S.C. 601-12 (2012).
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112. This rule would apply to six RTOs/ISOs (all of which are
transmission organizations). The average estimated annual cost to each
of the RTOs/ISOs is $73,000. The RTOs/ISOs are not small entities, as
defined by the RFA.\123\ This is because the relevant threshold between
small and large entities is 500 employees and the Commission
understands that each RTO/ISO has more than 500 employees. Furthermore,
because of their pivotal roles in wholesale electric power markets in
their regions, none of the RTOs/ISOs meet the last criterion of the
two-part RFA definition of a small entity: ``not dominant in its field
of operation.'' As a result, the Commission certifies that the reforms
proposed in this NOPR would not have a significant economic impact on a
substantial number of small entities.
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\123\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
Small Business Administrations' regulations at 13 CFR 121.201 define
the threshold for a small Electric Bulk Power Transmission and
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C.
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C.
632.
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VII. Comment Procedures
113. The Commission invites interested persons to submit comments
on the matters and issues proposed in this document to be adopted,
including any related matters or alternative proposals that commenters
may wish to
[[Page 9554]]
discuss. Comments are due April 10, 2017. Comments must refer to Docket
No. RM17-2-000, and must include the commenter's name, the organization
they represent, if applicable, and their address.
114. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
115. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE.,
Washington, DC 20426.
116. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.
VIII. Document Availability
117. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
118. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
119. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from the Commission's Online
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By direction of the Commission.
Issued: January 19, 2017.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Regulatory Text
In consideration of the foregoing, the Commission proposes to amend
Part 35, Chapter 1, Title 18, Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES AND TARIFFS
0
1. The authority citation for part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
0
2. Amend Sec. 35.28, by adding new paragraph (g)(11) to read as
follows:
Sec. 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(g) * * *
(11) Uplift allocation and transparency--(i) Uplift allocation.
Each Commission-approved independent system operator or regional
transmission organization that allocates the costs of real-time uplift
to deviations must allocate such costs only to those market
participants whose transactions are reasonably expected to cause the
uplift costs. For purposes of this allocation, deviations are megawatt
hour differences between a market participant's scheduled deliveries or
receipts at particular points cleared in the day-ahead market and those
amounts actually delivered or received in real-time that are not
related to real-time economic or reliability-related operator dispatch
instructions. Costs of uplift payments must be allocated to at least
two distinct categories: System-wide capacity and congestion
management. For purposes of this allocation, each Commission-approved
independent system operator or regional transmission organization must
distinguish between deviations that help efforts to address system
needs and those that harm efforts to address system needs. A market
participant's net harmful deviations are its harmful deviations less
its helpful deviations. Within each uplift category, uplift costs must
be allocated to a market participant's net harmful deviations
commensurate with the extent to which those deviations harm efforts to
address system needs. Within the system-wide capacity category, a
market participant shall be allocated a portion of the total real-time
uplift costs incurred to maintain energy and operating reserve
requirements in the real-time market based on the net contributions of
its deviations to those costs. Within the congestion management
category, costs shall be allocated based on whether a market
participant's deviations on net contributed to the real-time congestion
at a given constraint. For the purposes of real-time uplift allocated
to deviations, a market participant's deviations must be netted hourly.
Real-time uplift allocated to deviations must be settled on an hourly
basis.
(ii) Transparency--(A) Uplift reporting. Each Commission-approved
independent system operator or regional transmission organization must
post two reports, at minimum, regarding uplift on a publicly accessible
portion of its Web site. Such postings shall be made within 20 calendar
days of the end of each month. First, each Commission-approved
independent system operator or regional transmission organization must
post uplift, paid in dollars, and categorized by transmission zone,
day, and uplift category. Transmission zone shall be defined as the
geographic area that is used for the local allocation of charges.
Transmission zones with fewer than four resources may be aggregated
with a neighboring transmission zone and reported collectively. If, for
any given monthly report, only one transmission zone exists and it has
fewer than four resources or, if when combined with a neighboring
transmission zone, the combined transmission zones still have fewer
than four resources, these transmission zones may be omitted from the
reporting requirements described in this section. Second, each
Commission-approved independent system operator or regional
transmission organization must post the resource name and the total
amount of uplift paid in dollars aggregated across the month to each
resource that received uplift payments within the calendar month.
(B) Reporting operator-initiated commitments. Each Commission-
approved independent system operator or regional transmission
organization must post operator-initiated commitments in megawatts,
categorized by transmission zone and commitment reason, on a publicly
accessible portion of its Web site as soon as practicable after the
resource has been committed, but no later than four hours after the
commitment. Transmission zone shall be defined as a geographic area
that is used for the local allocation of charges.
(C) Transmission constraint penalty factors. Each Commission-
approved
[[Page 9555]]
independent system operator or regional transmission organization must
include, in its tariff, its transmission constraint penalty factor
values; the circumstances, if any, under which the transmission
constraint penalty factors can set locational marginal prices; and the
procedure, if any, for temporarily changing the transmission constraint
penalty factor values. Any procedure for temporarily changing
transmission constraint penalty factor values must provide for notice
of the change to market participants.
Note: The following appendix will not be published in the Code
of Federal Regulations.
Appendix: List of Short Names/Acronyms of Commenters
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Short name/acronym Commenter
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Appian Way................... Appian Way Energy Partners, LLC.
CAISO........................ California Independent System Operator
Corporation.
DC Energy, Inertia Power, and DC Energy, LLC, Inertia Power, LP, and
Vitol. Vitol Inc.
EEI.......................... Edison Electric Institute.
EPSA......................... Electric Power Supply Association.
EPSA/IPPNY................... Electric Power Supply Association and
Independent Power Producers of New York.
EPSA/NEPGA................... Electric Power Supply Association and New
England Power Generators Association,
Inc.
EPSA/P3...................... Electric Power Supply Association and PJM
Power Providers.
EPSA/Western Power Trading Electric Power Supply Association and
Forum. Western Power Trading Forum.
Energy Storage Association... Energy Storage Association.
Entergy...................... Entergy Services, Inc. commented on
behalf of the Entergy Operating
Companies (Entergy Arkansas, Inc.;
Entergy Louisiana, LLC; Entergy
Mississippi, Inc.; Entergy New Orleans,
Inc.; and Entergy Texas, Inc.).
Exelon....................... Exelon Corporation.
Financial Marketers Coalition Financial Marketers Coalition.
Golden Spread Electric....... Golden Spread Electric Cooperative, Inc.
ISO-NE....................... ISO New England Inc.
MISO......................... Midcontinent Independent System Operator,
Inc.
MISO Market Monitor.......... Potomac Economics, LLC.
PJM Market Monitor........... Monitoring Analytics, LLC.
NYISO........................ New York Independent System Operator,
Inc.
PJM.......................... PJM Interconnection, L.L.C.
PSEG Companies............... PSEG Companies (Public Service Electric
and Gas Company, PSEG Power LLC and PSEG
Energy Resources & Trade LLC).
Public Interest Organizations Public Interest Organizations.
SPP.......................... Southwest Power Pool, Inc.
XO Energy.................... XO Energy, LLC.
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[FR Doc. 2017-02332 Filed 2-6-17; 8:45 am]
BILLING CODE 6717-01-P