[Federal Register Volume 86, Number 227 (Tuesday, November 30, 2021)]
[Notices]
[Pages 67933-67942]
[FR Doc No: 2021-26032]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RM22-2-000]

Reactive Power Capability Compensation

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Notice of inquiry.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
inviting comments on reactive power

capability compensation and market design.

DATES: Initial Comments are due January 31, 2022, and Reply Comments
are due February 28, 2022.

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 comments via the U.S. Postal Service to: Federal Energy
Regulatory Commission, Secretary of the Commission, 888 First Street
NE, Washington, DC 20426. Hand-delivered comments or comments sent via
any other carrier should be delivered to: Federal Energy Regulatory
Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
    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:
Noah Schlosser (Technical Information), Federal Energy Regulatory
Commission, 888 First Street NE, Washington, DC 20426,<PHONE_NUMBER>,
[email protected]
Neil Yallabandi (Legal Information), Federal Energy Regulatory
Commission, 888 First Street NE, Washington, DC 20426,<PHONE_NUMBER>,
[email protected]

SUPPLEMENTARY INFORMATION:
    1. The Federal Energy Regulatory Commission (Commission) is issuing
this Notice of Inquiry (NOI) to seek comments on reactive power
capability compensation and market design.
    2. In an order issued in 2002,\1\ the Commission recommended that
all resources that have actual cost data and support documentation use
the method employed in American Electric Power Service Corporation to
establish a rate for the provision of reactive power.\2\ Since the
issuance of AEP, the electric markets and the generation resource mix
have undergone significant change. For example, in 1999, when AEP
issued, the majority of reactive power filings were made by synchronous
resources that were owned by public utilities subject to the Uniform
System of Accounts (USofA) and who annually submitted a FERC Form No.
1.\3\ Today, the majority of the filings by entities seeking to
establish a rate for reactive power capability compensation received at
the Commission are made by owners of non-synchronous resources that
produce reactive power using different types of equipment than used by
synchronous resources. In addition, most filing entities (both
synchronous and non-synchronous) received waivers of the requirement to
maintain their accounts under the USofA rules and to file FERC Form No.
1 when they were granted market-based rate (MBR) authority under Order
No. 697.\4\ These changes have contributed, at least in part, to many
such filings being set for hearing and settlement judge procedures.
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    \1\ WPS Westwood Generation, LLC, 101 FERC ] 61,290, at P 14
(2002).
    \2\ Am. Elec. Power Serv. Corp., Opinion No. 440, 88 FERC ]
61,141 (1999) (Opinion No. 440).
    \3\ The FERC Form No. 1 is a comprehensive financial and
operating report submitted annually by Major electric utilities,
licensees and others and used for electric accounting regulation,
rate regulation, market oversight analysis, and planning audits. 18
CFR 141.1.
    \4\ Market-Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities, Order No. 697,
119 FERC ] 61,295, clarified, 121 FERC ] 61,260 (2007), order on
reh'g, Order No. 697-A, 123 FERC ] 61,055, clarified, 124 FERC ]
61,055, order on reh'g, Order No. 697-B, 125 FERC ] 61,326 (2008),
order on reh'g, Order No. 697-C, 127 FERC ] 61,284 (2009), order on
reh'g, Order No. 697-D, 130 FERC ] 61,206 (2010), aff'd sub nom.
Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011).
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    3. In light of these developments, we seek comment on various
issues that have arisen regarding reactive power capability
compensation and market design.

I. Background

A. Reactive Power and Regulation

    4. Almost all bulk electric power is generated, transported, and
consumed in alternating current (AC) networks. Elements of AC systems
supply and consume two kinds of power: Real power and reactive power.
Real power accomplishes useful work (e.g., runs motors and lights
lamps). Reactive power supports the voltages that must be controlled
for system reliability. At times, resources must either supply or
consume reactive power for the transmission system to maintain voltage
levels required to reliably supply real power from generation to load.
Inadequate reactive power supply lowers voltage; as voltage drops,
current must increase to maintain the power supplied, causing the lines
to consume more reactive power and the voltage to drop further,
eventually leading to reliability problems such as loss of transmission
system stability and voltage collapse.\5\
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    \5\ Payment for Reactive Power, Commission Staff Report, Docket
No. AD14-7-000, at 4-6 (Apr. 22, 2014), https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf.
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    5. In the Commission's pro forma LGIA, the power factor design
criteria specify that, for synchronous resources, the ``Interconnection
Customer shall design the Large Generating Facility to maintain a
composite power delivery at continuous rated power output at the Point
of Interconnection.'' \6\ For non-synchronous resources, the
``Interconnection Customer shall design the Large Generating Facility
to maintain a composite power delivery at continuous rated power output
at the high side of the generator substation.'' \7\
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    \6\ See Pro Forma LGIA, Sec.  <IP_ADDRESS>.
    \7\ Id., Sec.  <IP_ADDRESS>.
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    6. Not only is reactive power necessary to operate the transmission
system reliably, but it can also substantially improve the efficiency
with which real power is delivered to customers. Increasing reactive
power production at certain locations (usually near a load center) can
sometimes alleviate transmission constraints and allow cheaper real
power to be delivered into a load pocket.\8\
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    \8\ Id. at 7-8.
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    7. The rules for procuring reactive power can affect whether
adequate reactive power supply is available, as well as whether the
supply is procured efficiently from the most reliable and lowest-cost
resources. This is readily apparent in the large portions of the United
States where the transmission system is operated by regional
transmission organizations (RTO) and independent system operators
(ISO); these operators do not own generation and transmission
facilities for producing and consuming reactive power and therefore
must procure reactive power from others. But procurement rules also
affect other parts of the United States where vertically integrated
utilities operate the transmission system because reactive power
capability is also available from independent companies.\9\ Therefore,
it is necessary to ensure that system operators, whether they are
independent or vertically integrated, have adequate reactive power
supplies at a just and reasonable rate.
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    \9\ Id. at 11-13.
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    8. The modern history of compensation for reactive power begins
with the Commission's Order No. 888, its Open Access Rule, issued in
April 1996.\10\ In that order, the Commission

concluded that ``reactive supply and voltage control from generation
sources'' is one of six ancillary services that transmission providers
must include in an open access transmission tariff.\11\ The Commission
noted that there are two approaches for supplying reactive power to
control voltage: (1) Installing facilities as part of the transmission
system and (2) using generation resources. The Commission concluded
that the costs associated with the first approach would be recovered as
part of the cost of basic transmission service and, thus, would not be
a separate ancillary service. The second (using generation resources)
would be considered a separate ancillary service and must be unbundled
from basic transmission service. The Commission stated that, in the
absence of proof that the generation seller lacks market power in
providing reactive power, rates for this ancillary service should be
cost-based and established as price caps, from which transmission
providers may offer a discount.
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    \10\ Promoting Wholesale Competition Through Open Access
Nondiscriminatory Transmission Services by Public Utilities;
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,705-06
and 31,716-17 (1996) (cross-referenced at 75 FERC ] 61,080), Order
No. 888-A, FERC Stats. & Regs. ] 31,048 (cross-referenced at 78 FERC
] 61,220), order on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997),
order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in
relevant part sub nom. Transmission Access Policy Study Group v.
FERC, 225 F.3d 667 (DC Cir. 2000), aff'd sub nom. New York v. FERC,
535 U.S. 1 (2002).
    \11\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,705. The
pro forma open access transmission tariff (OATT) includes six
schedules that set forth the details pertaining to each ancillary
service. The details concerning reactive power are included in
Schedule 2 of the pro forma OATT. Id. at 31,960.
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    9. In Opinion No. 440,\12\ the Commission approved a method
presented by American Electric Power Service Corp. (AEP), a vertically
integrated utility, for allocating the costs of generator equipment
between real power capability and reactive power capability, as well as
the related operations and maintenance costs. AEP identified four
components of a generation plant related to the production of reactive
power: (1) The generator and its exciter, (2) the generator step-up
transformer, (3) accessory electric equipment that supports the
operation of the generator-exciter, and (4) the remaining total
production investment required to provide real power and operate the
exciter. Because these plant items produce both real and reactive
power, AEP developed an allocation factor to sort the annual revenue
requirements of these components between real and reactive power
production. The factor for allocating to reactive power, developed by
AEP, is MVAR\2\/MVA\2\, where MVAR is megavolt amperes reactive
capability and MVA is megavolt amperes capability at a power factor of
1. Subsequently, the Commission indicated that all resources that have
actual cost data and support should use AEP's methodology in seeking to
recover reactive power capability costs pursuant to individual cost-
based revenue requirements (hereinafter, the AEP Methodology).\13\
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    \12\ AEP, Opinion No. 440, 88 FERC ] 61,141.
    \13\ WPS Westwood Generation, LLC, 101 FERC ] 61,290 at P 14;
FPL Energy Marcus Hook, L.P., 110 FERC ] 61,087, at P 16, order on
reh'g, 111 FERC ] 61,168 (2005).
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    10. In Order No. 2003,\14\ the Commission adopted standard large
generator interconnection procedures and a standard agreement for the
interconnection of large generation facilities (the pro forma Large
Generator Interconnection Agreement (LGIA)), which included the
requirement that interconnection customers maintain a power factor
range of 0.95 leading to 0.95 lagging, unless the transmission provider
has established a different power factor range.\15\ Order No. 2003
required payment for reactive power to an interconnection customer only
when the transmission provider requests the interconnection customer to
operate its generating facility outside the established power factor
range.\16\ With respect to reactive power within the established power
factor range, the Commission initially concluded that an
interconnection customer ``should not be compensated for reactive power
when operating its Generating Facility within the established power
factor range, since it is only meeting its obligation.'' \17\ In Order
No. 2003-A, however, the Commission clarified that ``if the
Transmission Provider pays its own or its affiliated generators for
reactive power within the established range, it must also pay the
Interconnection Customer.'' \18\ Subsequently, in Order No. 2003-C, the
Commission disagreed with commenters that reactive power capability
compensation would result in a windfall to generators, explaining that
reactive power is an important service.\19\ Order No. 2003-A also
exempted wind generators from maintaining the established power factor
range.\20\
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    \14\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, 104 FERC ] 61,103 (2003), order on
reh'g, Order No. 2003-A, 106 FERC ] 61,220, order on reh'g, Order
No. 2003-B, 109 FERC ] 61,287 (2004), order on reh'g, Order No.
2003-C, 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of
Regulatory Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).
    \15\ Id. P 542.
    \16\ Id. P 546.
    \17\ Id.
    \18\ Order No. 2003-A, 106 FERC ] 61,220 at P 416.
    \19\ Order No. 2003-C, 111 FERC ] 61,401 at P 42.
    \20\ Order No. 2003-A, 106 FERC ] 61,220 at P 34.
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    11. Order No. 661 established technical requirements for
interconnecting large wind resources and maintained the exemption from
providing reactive power, except where the transmission provider
showed, through a system impact study, that reactive power capability
was required to ensure safety or reliability.\21\ In Order No.
2006,\22\ the Commission adopted identical power factor and
compensation requirements for small generating facilities (facilities
having a capacity of no more than 20 MW) but exempted small wind
generators from the reactive power requirement. In Order No. 827,\23\
the Commission eliminated the exemptions for wind resources from the
requirement to provide reactive power. As a result, all newly
interconnecting non-synchronous generators were required to provide
reactive power within the range of 0.95 leading to 0.95 lagging at the
high-side of the generator substation as a condition of
interconnection. Order No. 827 also clarified that the amount of
reactive power required from non-synchronous resources should be
proportionate to the actual (real) power output.\24\ With respect to
compensation, the Commission concluded that it did not have a
sufficient record for determining a new methodology for non-synchronous
generation reactive power compensation and stated that any non-
synchronous resource seeking reactive power compensation would need to
propose a method for calculating that compensation as part of its
filing.\25\
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    \21\ Interconnection for Wind Energy, Order No. 661, 111 FERC ]
61,353, order on reh'g, Order No. 661-A, 113 FERC ] 61,254 (2005).
    \22\ Standardization of Small Generator Interconnection
Agreements and Procedures, Order No. 2006, 111 FERC ] 61,220, order
on reh'g, Order No. 2006-A, 113 FERC ] 61,195 (2005), order granting
clarification, Order No. 2006-B, 116 FERC ] 61,046 (2006).
    \23\ Reactive Power Requirements for Non-Synchronous Generation,
Order No. 827, 155 FERC ] 61,277, order on clarification and reh'g,
157 FERC ] 61,003 (2016).
    \24\ Id. P 49.
    \25\ Id. PP 47, 52.
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B. Approaches to Reactive Power Capability Compensation

    12. In RTOs/ISOs where transmission providers compensate for
reactive power capability, the compensation is either (1) based on
individual reactive power revenue requirements determined in cases for
individual resources (or fleets \26\ of resources) established pursuant
to a cost-based methodology (e.g., the AEP

Methodology) using the resource's MVAR capability or (2) paid on a flat
per-MVAR region-wide basis based on testing for the maximum MVAR
capability of the resource. Resources in PJM Interconnection, Inc.
(PJM) and Midcontinent Independent System Operator, Inc. (MISO)
generally use the AEP Methodology to set reactive power compensation on
an individual resource basis, whereas resources in ISO New England Inc.
(ISO-NE) and New York Independent System Operator, Inc. (NYISO) are
compensated for reactive power under a flat rate described further
below. Outside of these RTOs/ISOs, when transmission providers pay for
the capability to provide reactive power within the standard power
factor range, resources generally propose to use the AEP Methodology to
set reactive power compensation on an individual resource basis.\27\
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    \26\ Fleet-based rate schedules consist of a single rate for
multiple resources, sometimes developed over an extended period of
time, which do not specify which resources are being compensated
under the rate schedule.
    \27\ In addition, California Independent System Operator
Corporation (CAISO); Southwest Power Pool, Inc. (SPP); and some non-
RTO/ISO transmission operators (e.g., Bonneville Power
Administration, Arizona Public Service Company, Southern Companies)
do not pay for reactive power capability.
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    13. PJM and MISO compensate each resource owner with an amount
equal to the resource owner's monthly reactive power capability service
revenue requirement for reactive power capability, as accepted by the
Commission. Although PJM and MISO both conduct regular reactive power
capability testing,\28\ because they compensate based on the reactive
power revenue requirements on file with the Commission, they do not
link the tested capability to compensation, and neither PJM nor MISO is
required to notify the Commission when a resource fails to achieve its
nameplate MVAR capability when tested.
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    \28\ Under Schedule 2 of MISO's tariff, MISO's technical
requirements dictate that within the past five years the generation
resource meets the testing requirements for voltage control
capability required by the Regional Reliability Council where the
generation resource is located. See MISO, FERC Electric Tariff,
Sched. 2, Sec.  II.B.3 (38.0.0). In PJM, resource owners are
required to test 20% of their resources that receive reactive power
capability compensation for reactive power capability annually,
totaling 100% of such facilities over a 66 month period. However,
individual resources that (1) have nameplate ratings below 20 MVA,
(2) form part of aggregate generating facilities with nameplate
ratings below 75 MVA, or (3) are not directly connected to the Bulk
Electric System are exempt from these testing requirements. See PJM
Manual 14D (Generator Operational Requirements), attach. E Sec.
E.2.
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    14. ISO-NE and NYISO compensate resources for reactive power
capability using a flat rate representing dollars per MVAR-year,\29\
which is multiplied by the resource's tested reactive power
capability.\30\
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    \29\ Both ISO-NE and NYISO proposed their respective reactive
power capability compensation mechanisms pursuant to section 205
filings. See ISO New England Inc., 122 FERC ] 61,056, at P 1 (2008)
(settling, in part, for a new flat rate in $/kVAR-yr). Note that,
although NYISO also has a fixed rate for reactive power capability
compensation, NYISO proposed the approach pursuant to an FPA section
205 filing, with stakeholder support. N.Y. Indep. Sys. Operator,
Inc., Docket No. ER02-617-000 (Feb. 5, 2002) (delegated order
accepting NYISO's amended Rate Schedule 2 of the Market
Administration and Control Area Services Tariff).
    \30\ ISO-NE, Transmission, Markets and Services Tariff, Schedule
2--Reactive Supply and Voltage Control Service (10.0.0); NYISO,
NYISO Market Administration and Control Area Services Tariff (MST),
Section 15.2, Rate Schedule 2--Payments for Supplying Voltage Supply
(11.0.0). ISO-NE and NYISO conduct reactive power capability testing
at least once every five years and annually, respectively. See ISO-
NE, Transmission, Markets and Services Tariff, Schedule 2, Sec.
IV.A.12(a); NYISO, NYISO MST, Section <IP_ADDRESS>, Annual Payment for
Voltage Support Service; NYISO, Ancillary Services Manual, Sec.  3.6
(Oct. 2021).
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    15. In ISO-NE, reactive power compensation is established by
adding: (a) A flat rate for capacity costs designed to compensate for
fixed capital costs related to providing reactive power; (b) a variable
rate for lost opportunity costs; (c) a variable rate for energy
consumed to produce reactive power; and (d) a variable rate for costs
for the resource to come online or to increase its output above its
economic loading point.\31\ ISO-NE periodically adjusts the base flat
rates for inflation.
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    \31\ See, e.g., Me. Pub. Utils. Comm'n v. ISO New England Inc.,
126 FERC ] 61,090, at P 6 (2009).
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    16. The NYISO flat rate is based on the average cost-of-service in
NYISO for providing leading and lagging reactive power.\32\ In NYISO,
the annual payment to qualified reactive power suppliers equals the
product of the compensation rate and the sum of the lagging and the
absolute value of the leading MVAR capacity \33\ of the resource, as
evidenced by the resource's tested reactive power capability. NYISO
adjusts the base flat rates annually for inflation. In NYISO, only the
flat rate portion is paid.\34\
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    \32\ NYISO, Deficiency Letter Response, Docket No. ER15-1042-
001, at 1 (filed Apr. 30, 2015). NYISO explained that the $2,592/
MVAR flat rate was calculated ``by dividing the total VSS [Voltage
Support Service] program compensation paid to qualified VSS
Suppliers in 2012 by the total lagging and leading reactive power
capability of all qualified VSS Suppliers in 2012.'' Voltage Support
Service is the ability to produce or absorb reactive power and the
ability to maintain a specific voltage level under both steady-state
and post-contingency operating conditions subject to the limitations
of the resource's stated reactive capability.
    \33\ Reactive power capability is measured in MVAR. A resource's
lagging reactive power capability indicates its ability to produce
reactive power, and its leading reactive power capability indicates
its ability to consume reactive power.
    \34\ Like the AEP Methodology, these flat rates are intended to
compensate resources for the costs of reactive power capability.
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II. Discussion

    17. Generation owners seeking compensation for reactive power
capability in PJM, MISO, and non-RTO/ISO regions that compensate for
reactive power capability based on the costs of individual resources or
on a fleet-wide basis generally submit individual cost-of-service
filings based on the AEP Methodology.\35\ As explained above, the AEP
Methodology was designed based on the physical attributes of
synchronous resources owned by a public utility that utilized the USofA
and annually submitted a FERC Form No. 1. Since the AEP Methodology was
established in 1999, the electric industry has undergone significant
changes, both in the generation resource mix and a general shift away
from cost-of-service rates for generators selling into Commission-
jurisdictional markets. Now, the majority of the reactive power filings
submitted to the Commission are made by owners of non-synchronous
resources that, relying on waivers granted by the Commission in
conjunction with sellers obtaining MBR authority under Order No. 697,
neither use the USofA nor file FERC Form No. 1. Because the AEP
Methodology was designed based on the physical attributes of a
synchronous resource and because of this lack of FERC Form No. 1
information for independent power producers (synchronous and non-
synchronous alike), customers and the Commission have faced challenges
in evaluating proposed reactive power rate schedules submitted pursuant
to section 205 of the Federal Power Act (FPA), resulting in the
majority of the filings being set for hearing and settlement
procedures.
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    \35\ Am. Elec. Power Serv. Corp., 80 FERC ] 63,006, at 65,071
(1997), aff'd in part, rev'd in part, Opinion No. 440, 88 FERC ]
61,141 at 61,437 (establishing the AEP Methodology); see also WPS
Westwood Generation, L.L.C., 101 FERC ] 61,290 at P 14 (recommending
that all resources seeking to recover reactive power capability
costs pursuant to individual cost-based revenue requirements use the
AEP Methodology); Dynegy Midwest Generation, Inc., Opinion No. 498,
121 FERC ] 61,025, at P 71 (2007), order on reh'g, 125 FERC ] 61,280
(2008) (discussing the AEP Methodology and recovery of heating
losses).
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    18. Furthermore, in PJM, several resources that have interconnected
to the distribution system rather than the transmission system have
still sought compensation from transmission operators for their
reactive power capabilities.\36\ Monitoring Analytics, LLC, the
Independent Market Monitor

for PJM (PJM Market Monitor), has argued that these resources are not
technically capable of providing reactive power capability service
consistent with Schedule 2 of PJM's tariff. Furthermore, it is unclear
whether all such distribution-connected resources are technically
capable of providing their full reactive power capability to the
transmission system such that they are properly compensated through the
applicable transmission rate schedules.\37\
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    \36\ See, e.g., Ingenco Wholesale Power, LLC, 173 FERC ] 61,247
(2020) (Ingenco); Whitetail Solar 3, LLC, 173 FERC ] 61,288 (2020);
Whitetail Solar 2, LLC, 174 FERC ] 61,238 (2021); Elk Hill Solar 2,
LLC, 175 FERC ] 61,188 (2021); Mechanicsville Solar, LLC, 176 FERC ]
61,076 (2021).
    \37\ See infra Section II.C.
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    19. Due to the aforementioned differences in the generation
resource mix and divergent reporting requirements between market-based
and cost-based sellers since the time when the AEP Methodology was
established, the Commission seeks to examine whether the current regime
for reactive power capability compensation requires revisions to ensure
that payments for reactive power capability accurately reflect the
costs associated with reactive power capability.

A. Issues With AEP Methodology-Based Reactive Power Compensation

    20. We wish to explore several potential issues with reactive power
capability compensation based on the AEP Methodology. These include the
failure to account for the degradation of a resource's reactive power
capability over time, any difficulties associated with applying the AEP
Methodology to non-synchronous resources, any difficulty in verifying
the revenue requirements proposed by owners of resources that have been
granted waiver of certain accounting and reporting requirements, and
any potential overcompensation in PJM stemming from the reactive power
offset used in the PJM capacity market.\38\
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    \38\ See infra notes 40-41, 47.
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1. Degradation
    21. Although the Commission has established that resources that
seek reactive power capability compensation under the AEP Methodology
are required to submit test reports of their reactive power capability
that support the company's proposed level of reactive power capability
for which the company is seeking a proposed reactive power revenue
requirement,\39\ the AEP Methodology does not account for the fact that
a resource's reactive power capability may degrade. As a result, over
time the reactive power revenue requirement originally established
under the AEP Methodology may no longer reflect the actual reactive
power capability of the associated resource(s). However, unless a
resource voluntarily files to revise its Commission-accepted revenue
requirement or is otherwise required to do so under an applicable
tariff, it will receive the same revenue over the course of its life,
regardless of whether it maintains the capability to produce its stated
power factor at its full real power capacity, which it supported with
test reports at the time of its filing before the Commission.
Furthermore, it can be difficult for the Commission to determine if the
test reports accurately reflect the reactive power capability of the
resource, particularly when the data the resource submits may be
incomplete.\40\
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    \39\ The Commission required all resources to submit test
reports when seeking a reactive power revenue requirement in Wabash
Valley Power Ass'n, Inc., 154 FERC ] 61,245, at P 29 (2016); Wabash
Valley Power Ass'n, Inc., 154 FERC ] 61,246, at P 28 (2016)
(together, Wabash). The Commission also reiterated ``that revenue
requirements established pursuant to Schedule 2 of the pro forma
Open Access Transmission Tariff . . . are based on a particular
level of reactive power capability for a particular generating unit
or group of units'' and ``should reflect'' the present circumstances
of the unit. See Wabash, 154 FERC ] 61,245 at P 28; 154 FERC ]
61,246 at P 27.
    \40\ The test report data does not always support the revenue
requirement, and a resource's test reports are one of the issues
often set for hearing and settlement procedures. See, e.g., Talen
Energy Mktg., LLC, 155 FERC ] 61,297, at P 9 (2016); Dynegy Lee II,
LLC, 161 FERC ] 61,016, at P 16 (2017); Buckeye Power, Inc., 162
FERC ] 61,145, at P 10 (2018); Ingenco, 173 FERC ] 61,247 at P 30.
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2. Accounting and Ratemaking Issues Related to Non-Synchronous
Resources
    22. A lack of accounting and ratemaking guidance for non-
synchronous resources under the AEP Methodology has contributed to
litigation over reactive power compensation.\41\ As noted above, the
AEP Methodology was originally developed to determine the cost-of-
service for reactive power production equipment owned by cost-of-
service-regulated sellers and intended solely for synchronous
resources. When compared to synchronous resources, non-synchronous
resources have different physical processes and electric plant that is
utilized in reactive power production. For example, relevant components
of producing and controlling reactive power for synchronous resources
include generator-exciters, step-up transformers, and accessory
electric equipment. In contrast, non-synchronous resources may be
capable of producing reactive power using only inverters.\42\ As a
result, when non-synchronous resources propose reactive power revenue
requirements based on the AEP Methodology, they generally propose to
populate AEP Methodology cost categories with equipment different from
those used by synchronous resources.
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    \41\ See Locke Lord LLP, 174 FERC ] 61,033 (2021).
    \42\ Typically, inverter-based resources will shut down without
sufficient power supply; however, if configured to do so, some
inverter-based resources can produce reactive power without real
power. E.g., North American Electric Reliability Corporation,
Reliability Guideline--BPS-Connected Inverter-Based Resource
Performance at 34 (Sept. 2018), https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Inverter-Based_Resource_Performance_Guideline.pdf.
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    23. For example, although the original AEP Methodology did not
contemplate inclusion of a collection system as equipment necessary for
production of reactive power, applicants have claimed that the
collection system is comparable to the isolated phase bus of a
synchronous facility, which is considered part of accessory electric
equipment costs for synchronous resources. The isolated phase bus of a
synchronous resource carries current between a synchronous resource and
its step-up transformer. An isolated phase bus may be several feet in
length, whereas a collection system for a non-synchronous resource may
exceed a mile in length. The typical collection system in a non-
synchronous resource uses multiple distribution voltage lines in a
radial configuration to connect the power from the wind turbines or
solar panels back to a central point, and the long length of the
collector system lines causes reactive power losses. In comparison, the
enclosed conductors of an isolated phase bus are short in length, thus
causing much smaller reactive power losses, and provide fault
protection between the synchronous resource and the step-up
transformer. Due to these differences, the collection system of a non-
synchronous resource generally represents a significantly higher
proportion of the resource's total investment cost than the isolated
phase bus represents for synchronous resources. Thus, non-synchronous
resources' interpretation of the AEP Methodology under this approach
increases the annual revenue requirement for those resources on a
relative basis as compared to the annual revenue requirements for
synchronous resources. The Commission has yet to formally address any
difference in cost structures across generation types for reactive
power compensation under the AEP Methodology.
    24. Furthermore, the Commission's USofA does not include accounts
that clearly accommodate non-hydro non-synchronous resources and
associated operation and maintenance expenses. The Commission recently
issued a separate NOI seeking input on whether

to create new accounts to accommodate these resources, how to modify
FERC Form No. 1 to reflect any new accounts, and the rate setting
implications, including for reactive power, of these potential
accounting and reporting changes.\43\
---------------------------------------------------------------------------

    \43\ See Accounting and Reporting Treatment of Certain Renewable
Energy Assets, 174 FERC ] 61,032, at P 3 (2021) (citations omitted)
(``Recently, parties have expressed disagreement regarding which
Other Production accounts should be used to book non-hydro renewable
assets. In Docket No. AC20-103, the Commission received a request
for confirmation that the costs of certain wind and solar generating
equipment are properly booked to the Other Production Accounts 343
(Prime Movers), 344 (Generators), and 345 (Accessory Electric
Equipment). In that proceeding, commenters argued that the proposal
booked an inappropriate amount of costs to Account 345, which are
included in reactive power rates pursuant to the AEP Methodology.
Commenters, including the Edison Electric Institute, suggested that
the Commission consider creating new accounts for wind, solar, and
other non-hydro renewables to resolve this issue.'').
---------------------------------------------------------------------------

3. Evidentiary Support
    25. The AEP Methodology originally contemplated the use of USofA
accounting structures and the sworn and attested-to accounting entries
in the FERC Form No. 1 to support the proposed reactive power rates.
This reliance enables resources to develop a cost-of-service rate that
is verifiable by Commission staff and parties. However, the vast
majority of resource owners currently applying for reactive power
compensation reflecting the AEP Methodology received waivers of the
Commission's accounting and reporting requirements when they were
granted MBR authority under Order No. 697, meaning they do not submit
the FERC Form No. 1, nor are they required to track their costs
consistent with USofA accounting.\44\ Thus, when resources that have
been granted these waivers propose revenue requirements using the AEP
Methodology, it is difficult for the Commission and affected customers
to easily verify that the proposed rates accurately reflect the AEP
Methodology.
---------------------------------------------------------------------------

    \44\ Per Order No. 697, the Commission grants MBR sellers waiver
of the accounting and reporting requirements in its approval of
initial applications for MBR authority.
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4. Market-Based Compensation and Potential Overcompensation in PJM
    26. The PJM Market Monitor has argued for some time that the best
approach to reactive power compensation in PJM is through the capacity
market rather than compensation through a separate cost-of-service
construct as currently provided for under Schedule 2 of the PJM
Tariff.\45\ The PJM Market Monitor contends that cost-of-service
compensation for reactive power capability is an anachronistic approach
that predates the introduction of wholesale power markets and is
unnecessary in light of potential compensation through the PJM markets.
The PJM Market Monitor states that generating resources are required to
have reactive capability to receive interconnection service. The PJM
Market Monitor argues that Schedule 2 should be eliminated from the PJM
tariff and PJM should rely on the capacity markets to ensure resource
adequacy, including the capability to provide real power and reactive
power at the lowest possible cost. More specifically, under the PJM
Market Monitor's approach, if PJM's Schedule 2 were eliminated
entirely, the gross costs of the entire plant, including any costs
associated with the production of reactive power, would be included in
the gross Cost of New Entry (CONE) and the generic offset for reactive
power capability service compensation \46\ would no longer be used to
calculate Net CONE.
---------------------------------------------------------------------------

    \45\ See, e.g., PJM Market Monitor, Comments, Docket No. AD16-
17-000, at 1, 6-10 (filed Aug. 1, 2016) (detailing the PJM Market
Monitor's view that reactive capability costs can--and should--be
recovered through PJM's capacity market instead of under a cost-of-
service paradigm); Monitoring Analytics, 2020 State of the Market
Report for PJM at 523, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020.shtml (describing the PJM Market
Monitor's position and recommended improvements).
    \46\ The Energy and Ancillary Services Offset (E&AS Offset) is
used to calculate Net CONE in the PJM capacity market and it
includes a revenue offset of $2,199/MW-year to reflect the average
annual reactive power revenue for combustion turbines from 2005
through 2007, based on the actual costs reported to the Commission
in reactive power capability service filings of combustion turbines.
The result of this offset is that, conceptually, the cost of
reactive capability is not part of Net CONE.
---------------------------------------------------------------------------

    27. The PJM Market Monitor alternatively argues that, if PJM
retains Schedule 2, Schedule 2 should be revised to avoid the potential
overpayment for reactive power capability.\47\ The PJM Market Monitor
explains that the E&AS Offset associated with the reference resource in
the capacity market is assumed to recover $2,199/MW-year in reactive
power payments. The PJM Market Monitor states that, as a result of the
offset rules, reactive power capability rates of up to $2,199/MW-year,
do not result in double recovery for reactive power capability. On the
other hand, the PJM Market Monitor contends that any separate reactive
power capability payments through Schedule 2 that exceed $2,199/MW-year
result in overcompensation as such costs can and should be recovered
through the capacity market. In short, the PJM Market Monitor contends
that when the market design allows for the recovery of specific costs
for reactive power capability, it is inappropriate to also include
those costs in a separate cost-of-service rate.
---------------------------------------------------------------------------

    \47\ See, e.g., PJM Market Monitor, Comments, Docket No. AD16-
17-000, at 8, 10 (filed Aug. 1, 2016) (explaining that ``[i]f
revenues for reactive capacity were removed from the Net Energy and
Ancillary Services Revenue Offset, then the fixed costs for
investment in reactive capability would be recoverable through the
capacity market,'' obviating the need for separate cost-of-service
reactive power rates); PJM Market Monitor, Brief on Exceptions,
Docket No. ER17-1821-002, at 3-16 (filed June 12, 2019) (discussing
the PJM Market Monitor's concerns about what it termed a ``hybrid of
market-based rates and cost of service rates''); PJM Market Monitor,
Rehearing Request, Docket No. ER17-1821-005, at 3-5 (filed Apr. 30,
2021) (addressing issues regarding the E&AS Offset and a generator's
proposed reactive power rates).
---------------------------------------------------------------------------

5. Questions Regarding AEP Methodology-Based Compensation
    28. Given the backdrop of the issues discussed herein, we wish to
explore in this NOI, whether the AEP Methodology remains a just and
reasonable approach to determining reactive power revenue requirements
in all circumstances. We encourage comments regarding the topics
broadly discussed above. The following questions are designed to
identify potential modifications to the AEP Methodology and related
market designs and reporting requirements necessary to ensure just and
reasonable rates for reactive power capability compensation. Commenters
need not answer every question enumerated below.
    a. Does compensating resources based on their costs of investment
in reactive power capability continue to be the appropriate basis for
reactive power capability compensation? Why or why not?
    i. If so, does the AEP Methodology accurately reflect a resource's
investment costs? Why or why not? To the extent your answer depends on
the type of resource, please be specific.
    b. What is the appropriate time period for compensation from a rate
developed under the AEP Methodology? Should payments be limited based
on the useful lives of the plant at issue? Why or why not?
    c. As noted earlier, the power factor design criteria in the
Commission's pro forma LGIA specify that the Large Generating Facility
should be designed to maintain a composite power delivery at continuous
rated power output, either at the Point of Interconnection for
synchronous resources or at the high side of the generator substation
for non-synchronous resources. Given this, when a resource conducts
testing to demonstrate its reactive power capability, over what minimum
amount

of time should a resource be required to maintain its maximum real
power output while operating across its claimed reactive power factor
range? Please specify to which type(s) of resource your proposed
minimum time period corresponds.
    i. The Commission has found that, to the extent the resource has
established that it is able to produce reactive power up to its
nameplate capability, a resource may use up to its nameplate power
factor in calculating its reactive power revenue requirements.\48\ Is
there any reason for the Commission to believe that the nameplate
capability aspect of calculating reactive power revenue requirements
should be revised in order to produce a more accurate result? Why or
why not? If so, in what manner (for example, should the power factor
range identified in the interconnection agreement be considered)?
---------------------------------------------------------------------------

    \48\ See, e.g., Panda Stonewall LLC, 174 FERC ] 61,266, at PP
99, 107-109 (2021) (finding that a reactive power supplier was
entitled to use its nameplate power factor in calculating its
reactive power revenue requirement, rather than being limited to the
power factor specified in its interconnection agreement, since the
facility was a new synchronous generator facility and degradation of
its reactive power output was not an issue).
---------------------------------------------------------------------------

    d. Many resources have an interconnection agreement in which
reactive power requirements are addressed; however, to the extent that
reactive power capability requirements are not addressed in a
resource's interconnection agreement and a resource seeks compensation
for supplying reactive power capability, how should the Commission
address this? For example, should the Commission require that the
resource and its transmission provider propose updates or additions to
the interconnection agreement to specify the resource's reactive power
capability requirements as a condition of establishing or maintaining a
reactive power revenue requirement or should other methods be used in
this regard?
    e. Reactive power filings set for hearing and settlement judge
procedures often do not have active intervening parties other than the
market monitor and RTO/ISO. Why do other parties not participate more
in these proceedings?
a. Degradation
    f. How does a resource's reactive power capability degrade over
time? Does the degradation follow a predictable pattern over a certain
period of time? Does this answer vary depending on the generation type,
real power capacity, and/or other aspects of a particular resource? If
so, how?
    i. Should resources receiving reactive power capability
compensation undergo periodic reactive power capability testing to
demonstrate that their reactive power capability compensation remains
accurate?
    1. If so, how frequently should this testing be performed?
    2. Should the frequency of testing be influenced by other factors,
including the generation type, real power capacity, and/or other
aspects of a particular resource?
    3. Is there a period after a new resource begins operating during
which testing is unnecessary? If so, what is the appropriate length of
this period and why? Please clarify which type of resource(s) this
period should apply to and why.
    4. Should reactive power capability compensation in all cases be
linked to tested capability? If not, why not? If so, how? And, if so,
should test results be updated and how frequently?
    g. Should the AEP Methodology be modified to account for reactive
power capability degradation over the lifetime of the resource and, if
so, how?
    i. If the Commission makes such a modification, should the revised
methodology only consider the resource's most recent reactive power
capability testing results, or should the Commission incorporate
degradation curves or other processes to estimate continued degradation
between tests? If using degradation curves, should this methodology
vary by resource type? If so, how? Should a resource have the
opportunity to rebut the application of a degradation curve if it can
demonstrate that its test results exceed the estimate derived from a
degradation curve?
    ii. Should the Commission adopt a standard minimum testing
frequency for resources that receive reactive power capability
compensation? If not, why not? If so, what time period should the
minimum frequency be (e.g., testing required annually, biannually,
every five years, etc.)? Please indicate to which type(s) of resources
your proposed minimum frequency corresponds.
    h. Over what time period does the NERC MOD-25-2 Reliability
Standard \49\ accurately represent a resource's capability to provide
reactive power?
---------------------------------------------------------------------------

    \49\ The NERC MOD-25-2 standard refers to verification and data
reporting of generator real and reactive power capability as well as
synchronous condenser reactive power capability. Under this
standard, each Generator Owner shall provide its Transmission
Planner with verification of the Reactive Power capability of its
applicable facilities within 90 calendar days of the date the data
is recorded for a staged test or the date the data is selected for
verification using historical operating data. Reliability Standard
MOD-25-2 (Verification and Data Reporting of Generator Real and
Reactive Power Capability and Synchronous Condenser Reactive Power
Capability), at Requirement R2.
---------------------------------------------------------------------------

    i. For how long is this data valid? Please explain.
    ii. If these standards do not accurately represent a resource's
reactive power capability, what additional data should resources
provide to verify their reactive power capability? Should this data
vary by resource type? If so, how and why?
    i. Are there maintenance activities needed to maintain reactive
power capability that do not also contribute to real power capability?
    i. If so, what percentage of a generating facility's operating and
maintenance budget is necessary to maintain reactive power capability?
    ii. Does this differ by type of generating resource? If so, how?
b. Non-Synchronous Resources
    j. Is the existing AEP Methodology appropriate to allocate the
costs associated with reactive power revenue requirements of non-
synchronous resources? If not, why and can changes be made to the
existing AEP Methodology to establish just and reasonable reactive
power revenue requirements for non-synchronous resources? If so, please
provide detailed descriptions of any potential changes and explain why
they are necessary.
    k. As discussed above,\50\ the AEP Methodology determines a
resource's cost of reactive power capability by applying an allocation
factor to four groups of costs that are involved in the production or
consumption of reactive power for a synchronous resource: (1) The
generator and exciter, (2) the step-up transformer, (3) accessory
electric equipment used to support the operation of the generator and
exciter, and (4) the remaining production plant investment. For each of
these groups of costs, assuming that the non-synchronous resource type
can provide reactive power capability, please identify what non-
synchronous resource equipment corresponds to the synchronous resource
equipment used in the AEP Methodology and how that equipment is related
to the production of reactive power. Please explain if that equipment
is also related to the production of real power. Please specify if the
equipment identified is specific to a type of non-synchronous resource
(e.g., wind, solar, battery).
---------------------------------------------------------------------------

    \50\ See supra Section I.
---------------------------------------------------------------------------

    i. In the alternative, please describe what groups of costs are
involved in the production or consumption of reactive

power for a non-synchronous resource and how a non-synchronous
resource's equipment would be allocated to each of those groups. Please
explain if these groups are involved in the production or consumption
of power other than reactive power.
    l. Which, if any, of the four groups under the AEP Methodology do
costs associated with the collection system of a non-synchronous
resource fall into and why?
    i. If they do not fall into any of those groups, should those costs
related to the collection system be recovered? Why?
    ii. Is the collection system comparable to the isolated phase bus
of a synchronous resource? Why or why not? In what ways are they
similar and in what ways are they different? What other aspects of a
non-synchronous resource does a collection system serve?
    m. Please explain whether it is necessary for a Type 3 wind
turbine,\51\ Type 4 wind turbine,\52\ or solar PV facility to produce
real power at a particular time in order for the resource to provide
reactive power capability at that time.
---------------------------------------------------------------------------

    \51\ Type 3 wind turbines have doubly-fed induction generators
with rotor terminals connected to power converters. The stator
terminals of Type 3 wind turbines are directly connected to the bulk
electric system.
    \52\ Type 4 wind turbines use either synchronous or asynchronous
generators with generator stator terminals connected to a power
converter. The power converters of Type 4 wind turbines are directly
connected to the bulk electric system.
---------------------------------------------------------------------------

    i. If so, what are the implications, if any, for the current
proportionality requirement on reactive power from non-synchronous
resources?
    n. Should the AEP Methodology be altered to account for the
intermittent availability of some non-synchronous resources? Why or why
not?
    o. Solar resources can be designed with power factors much lower
than those of synchronous resources,\53\ which implies a much higher
reactive power capability and results in higher revenue requirements
under current application of the AEP Methodology for solar generating
facilities versus a comparable synchronous resource, all else being
equal. Should the AEP Methodology be altered to account for this
difference? Why or why not?
---------------------------------------------------------------------------

    \53\ See, e.g., Delta's Edge Solar, LLC, Exhibit DES-1, Docket
No. ER21-1452-000, at 8 (filed Mar. 16, 2021); Crossett Solar
Energy, LLC, Exhibit CSE-1, Docket No. ER21-1453-000, at 8 (filed
Mar. 16, 2021).
---------------------------------------------------------------------------

    i. Refer to Section II.A.5, question l.i. Would allocating the
costs of solar generating facilities into cost categories different
from those categories defined under the AEP Methodology, and using a
solar generating facility's power factor, result in a revenue
requirement more or less comparable to that of a synchronous generating
facility, all else being equal?
c. Evidentiary Support
    p. What options are available to collect independently verifiable
cost information from MBR sellers that have received waiver of the
accounting and FERC Form No. 1 requirements to support their reactive
power capability revenue requirements? For example, how should MBR
sellers that receive reactive power capability compensation track their
equipment costs and support their proposed reactive power revenue
requirements?
    q. In order to simplify and provide transparency to proposed
reactive power capability compensation filings, should the Commission
require, in PJM, MISO, and non-RTO/ISO regions that compensate for
reactive power capability based on the costs of individual resources or
on a fleet-wide basis, reactive power filers to include with their
filing a standardized form with recognized schedules and officer and
independent accountant certification requirements? Please explain why
or why not.
    i. Would the standardized form allow for better comparisons between
reactive power rates and/or allow the reactive power rates to be more
easily refreshed to reflect degradation or other changes to reactive
power capability? If not, why not?
    ii. Should the form contain similar information as the relevant
USofA accounts used in the AEP Methodology? If not, why not? If yes,
please specify the types of information that would be necessary to
calculate a reactive power revenue requirement.
    iii. If the Commission pursued a standardized form approach, what
cost support should be included in a standardized form?
d. Potential Overcompensation in PJM
    r. Refer to the PJM Market Monitor's concerns regarding the
potential in PJM of overpayment for reactive power capability.\54\ In
PJM and other RTOs/ISOs with centralized capacity markets, how do
resources typically account for revenues from reactive power
compensation when calculating their capacity offers?
---------------------------------------------------------------------------

    \54\ See supra Section II.A.4.
---------------------------------------------------------------------------

    i. If a resource accounts for revenues from reactive power
compensation when calculating its capacity offers, does that approach
ensure that the resource does not receive double compensation for
providing reactive power capability service? Please explain why or why
not.
    ii. Please explain how the lack of accounting for revenues from
reactive power compensation when calculating resources' capacity offers
does not constitute double compensation.
    s. Do resources in PJM that receive reactive power capability
compensation above $2,199/MW-year effectively receive double-recovery
as alleged by the PJM Market Monitor?
    i. If so, how should such overcompensation be corrected?
    ii. If not, please explain why no double-recovery occurs.

B. Alternative Methodologies

    29. As noted above, the AEP Methodology is currently used as the
Commission's approach to developing revenue requirements for reactive
power capability in PJM, MISO, and by transmission providers in non-
RTO/ISO regions. The Commission, in this NOI, would like to explore
whether other potential alternative methodologies not based on the
costs of the particular resource(s) at issue in a given proceeding
should be considered or better used to develop reactive power
capability revenue requirements.
    30. One possible alternative approach is a flat rate methodology,
which would be based on the total reactive power payments made by
transmission customers in a region divided by the MVARs consumed in the
region. This ``dollars per MVAR-year'' value may be determined either
for each class of resource (solar, wind turbine, combined-cycle,
combustion turbine, and hydroelectric) or a single value could be paid
to all classes of resources similar to the approach used in ISO-NE and
NYISO. We seek comment on the potential benefits and drawbacks of using
any flat rate methodology for reactive power capability compensation.
    31. Another possible approach to reactive power capability
compensation is replacement cost ratemaking. Under this approach, the
lowest-cost technology capable of providing reactive power capability,
such as a synchronous condenser, is used to establish a per-MVAR-year
rate. Then, all resources would be paid the same amount based upon
their tested MVAR capability. Replacement cost ratemaking derives from
the Supreme Court's decision in Smyth v. Ames,\55\ in which the Court
indicated that appropriate rate base is

based on the replacement cost or fair value of the rate base.\56\ Such
a replacement cost approach could also form a benchmark for evaluating
the justness and reasonableness of proposed reactive power capability
revenue requirements, where any proposed rates above the cost of the
alternative technology would be considered unjust and unreasonable
unless the record demonstrates that the resource's costs of investment
in reactive power capability supports the proposed revenue requirement.
---------------------------------------------------------------------------

    \55\ 169 U.S. 466 (1898). The U.S. Supreme Court permitted the
Commission to use original cost ratemaking in place of replacement
or reproduction cost given the difficulty of determining fair value
in most cases. FPC v. Hope Nat. Gas Co., 320 U.S. 591 (1944).
    \56\ Smyth, 169 U.S. at 544 (``the rights of the public would be
ignored if rates for the transportation of persons or property on a
railroad are exacted without reference to the fair value of the
property used for the public'').
---------------------------------------------------------------------------

1. Questions Regarding Alternative Methodologies
    32. We encourage comments regarding the topics discussed above in
this section. The following questions are designed to explore further
potential alternative methodologies. Commenters need not answer every
question enumerated below.
    a. Should alternative methodologies to the AEP Methodology be
considered for the calculation of reactive power capability revenue
requirements? If not, why not? If so, what alternative methodologies to
the AEP Methodology could be used for calculating reactive power
revenue requirements that would accurately capture the cost of
providing reactive power capability? Please clarify if any methodology
is specific to certain types of resources or not. For example, what
methodology could appropriately account for the technical
characteristics of non-synchronous resources that do not exist in
synchronous resources? How would developing revenue requirements under
such a new methodology compare to developing revenue requirements using
the AEP Methodology?
    b. Should a flat rate approach to reactive power compensation
differ depending on the type of resource, or should one rate be used
for all resource types?
    c. Under a flat rate approach:
    i. How should the rate be initially set, and how would it be
adjusted over time (e.g., for inflation)?
    ii. Should payments to a specific resource be based on the
resource's tested reactive power capability or its actual reactive
power output?
    iii. How often should the resource's reactive power capability be
tested?
    d. Under a replacement cost approach:
    i. What alternative technology should be used to establish the rate
and how should that alternative technology be determined?
    ii. How often should the alternative technology used to establish
the rate be reevaluated?
    e. Would a change to a flat rate or replacement rate approach
require resources to change any of their accounting, record keeping or
any other administrative processes?
    i. Would such a change have an impact on capital investment
decisions? Are there any other effects that such a change would cause?
If possible, please provide numbers to quantify statements.
    f. In regions such as CAISO and SPP, where resources are not
directly compensated for their reactive power capabilities, how do
resources recover the costs of their investment in reactive power
capability?
    g. Refer to the PJM Market Monitor's proposal to provide for
reactive power compensation in PJM through the capacity market rather
than through a separate cost-of-service construct.\57\ In regions with
a centrally-cleared capacity market, would it be preferable for
resources to recover the costs of their investment in reactive power
capability by embedding those costs in their capacity market offers,
rather than using a separate cost-based rate? Please describe any
advantages or disadvantages to this approach and any modifications this
would require in the applicable region's OATT and market rules.
---------------------------------------------------------------------------

    \57\ See supra Section II.A.4.
---------------------------------------------------------------------------

C. Distribution-Connected Resources

    33. The Commission has previously found that a transmission
provider need not provide compensation to resources for reactive power
if the resource is not under the control of the control area
operator.\58\ Schedule 2 of the pro forma OATT similarly requires that
generation facilities and non-generation resources capable of providing
reactive power be ``under the control of the control area operator.''
---------------------------------------------------------------------------

    \58\ Otter Tail Power Co., 99 FERC ] 61,019, at 61,092 (2002).
---------------------------------------------------------------------------

    34. In several recent cases,\59\ the PJM Market Monitor has
challenged the eligibility of distribution-connected resources with
Commission-jurisdictional interconnection agreements to receive
compensation for reactive power capability (within the standard power
factor range) under Schedule 2 of PJM's tariff.\60\ The PJM Market
Monitor has argued in these cases that such resources should not
receive reactive power compensation from PJM because the resources have
not established that they provide reactive power capability service to
the PJM transmission system, as required by Schedule 2.\61\ The PJM
Market Monitor likens such resources to pseudo-tied resources, which
are excluded from eligibility to file for reactive power compensation
under Schedule 2 of PJM's tariff. Other protestors have also argued
that distribution-connected resources are not under the operational
control of the transmission system operator and therefore cannot
provide reactive power capability service consistent with the PJM
tariff.\62\
---------------------------------------------------------------------------

    \59\ See supra note 36.
    \60\ Schedule 2 of PJM's tariff is nearly identical to Schedule
2 of the pro forma OATT. It provides in relevant part as follows
(emphasis added):
    In order to maintain transmission voltages on the Transmission
Provider's transmission facilities within acceptable limits,
generation facilities and non-generation resources capable of
providing this service that are under the control of the control
area operator are operated to produce (or absorb) reactive power.
Thus, Reactive Supply and Voltage Control from Generation or Other
Sources Service must be provided for each transaction on the
Transmission Provider's transmission facilities. The amount of
Reactive Supply and Voltage Control from Generation or Other Sources
Service that must be supplied with respect to the Transmission
Customer's transaction will be determined based on the reactive
power support necessary to maintain transmission voltages within
limits that are generally accepted in the region and consistently
adhered to by the Transmission Provider.
    \61\ See, e.g., Mechanicsville Solar, LLC, Protest of the
Independent Market Monitor for PJM, Docket No. ER21-2091-000 (filed
June 28, 2021).
    \62\ See, e.g., Northern Virginia Electric Cooperative, Inc.,
Old Dominion Electric Cooperative, and Dominion Energy Services,
Inc. on behalf of Virginia Electric and Power Company;
Mechanicsville Solar, LLC, Protest and Comments Monitor for PJM,
Docket No. ER21-2091-000 (filed June 25, 2021).
---------------------------------------------------------------------------

    35. We are interested in exploring the PJM Market Monitor's
concerns further, as well as whether these concerns are relevant for
other regions.
1. Questions Regarding Distribution-Connected Resources
    36. The Commission encourages comments regarding the topics broadly
discussed above. The following questions are designed to identify
whether resources in PJM and elsewhere that are interconnected to a
distribution system and participate in wholesale markets are
technically capable of providing reactive power to the transmission
system in such a way that these resources should be eligible for
reactive power capability compensation through transmission rates.
Commenters need not answer every question enumerated below.
    a. For a distribution-connected resource, is reactive power
dispatchable by direction of the transmission provider? Please explain,
including whether the answer to this question depends on whether the
resource has a

Commission-jurisdictional interconnection agreement with the
transmission system owner/operator and whether the resource is
synchronous or non-synchronous.
    b. If reactive power produced by a distribution-connected resource
cannot be dispatched by the transmission system operator to provide
voltage support to the transmission system, should a distribution-
connected resource be compensated through transmission rates for its
reactive power capability? Why or why not?
    c. If distribution-connected resources are dispatchable for
reactive power by the transmission provider, to what extent are
distribution-connected resources able to provide reactive power
capability service to the transmission system? Are there physical
characteristics (e.g., distribution-connected resource characteristics
and location, system topology, etc.) or other indicators that could be
analyzed to determine accurately whether a distribution connected
resource is able to provide reactive power capability service to the
transmission system?
    d. Are resources connected to a distribution system subject to
reactive power capability testing requirements? If so, what are those
requirements?

III. Comment Procedures

    37. The Commission invites interested persons to submit comments on
the matters and issues proposed in this notice, including any related
matters or alternative proposals that commenters may wish to discuss.
Initial Comments are due January 31, 2022, and Reply Comments are due
February 28, 2022. Comments must refer to Docket No. RM22-2-000, and
must include the commenter's name, the organization they represent, if
applicable, and their address in their comments.
    38. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website 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.
    39. Those unable to file electronically may mail comments via the
U.S. Postal Service to: Federal Energy Regulatory Commission, Secretary
of the Commission, 888 First Street NE, Washington, DC, 20426. Hand-
delivered comments or comments sent via any other carrier should be
delivered to: Federal Energy Regulatory Commission, 12225 Wilkins
Avenue, Rockville, MD 20852.
    40. 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.

IV. Document Availability

    41. 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). At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the President's March 13, 2020
proclamation declaring a National Emergency concerning the Novel
Coronavirus Disease (COVID-19).
    42. 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.
    43. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
[email protected].

    By direction of the Commission.

    Issued: November 18, 2021.
Kimberly D. Bose,
Secretary.
[FR Doc. 2021-26032 Filed 11-29-21; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 76, Number 191 (Monday, October 3, 2011)]
[Notices]
[Pages 61140-61143]
[FR Doc No: 2011-25327]

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DEPARTMENT OF TRANSPORTATION

Federal Motor Carrier Safety Administration

[Docket No. FMCSA-2011-0194]

Qualification of Drivers; Exemption Applications; Diabetes
Mellitus

AGENCY: Federal Motor Carrier Safety Administration (FMCSA), DOT.

ACTION: Notice of applications for exemption from the diabetes mellitus
standard; request for comments.

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SUMMARY: FMCSA announces receipt of applications from 16 individuals
for exemption from the prohibition against persons with insulin-treated
diabetes mellitus (ITDM) operating commercial motor vehicles (CMVs) in
interstate commerce. If granted, the exemptions would enable these
individuals with ITDM to operate CMVs in interstate commerce.

DATES: Comments must be received on or before November 2, 2011.

ADDRESSES: You may submit comments bearing the Federal Docket
Management System (FDMS) Docket No. FMCSA-2011-0194 using any of the
following methods:
     Federal eRulemaking Portal: Go to http://www.regulations.gov. Follow the on-line instructions for submitting
comments.
     Mail: Docket Management Facility; U.S. Department of
Transportation, 1200 New Jersey Avenue, SE., West Building Ground
Floor, Room W12-140, Washington, DC 20590-0001.
     Hand Delivery: West Building Ground Floor, Room W12-140,
1200 New Jersey Avenue, SE., Washington, DC, between 9 a.m. and 5 p.m.,
Monday through Friday, except Federal holidays.
     Fax: 1-202-493-2251.
    Instructions: Each submission must include the Agency name and the
docket numbers for this notice. Note that all comments received will be
posted without change to http://

www.regulations.gov, including any personal information provided.
Please see the Privacy Act heading below for further information.
    Docket: For access to the docket to read background documents or
comments, go to http://www.regulations.gov at any time or Room W12-140
on the ground level of the West Building, 1200 New Jersey Avenue, SE.,
Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday,
except Federal holidays. The Federal Docket Management System (FDMS) is
available 24 hours each day, 365 days each year. If you want
acknowledgment that we received your comments, please include a self-
addressed, stamped envelope or postcard or print the acknowledgement
page that appears after submitting comments on-line.
    Privacy Act: Anyone may search the electronic form of all comments
received into any of our dockets by the name of the individual
submitting the comment (or of the person signing the comment, if
submitted on behalf of an association, business, labor union, etc.).
You may review DOT's Privacy Act Statement for the FDMS published in
the Federal Register on January 17, 2008 (73 FR 3316), or you may visit
http://edocket.access.gpo.gov/2008/pdf/E8-785.pdf.

FOR FURTHER INFORMATION CONTACT: Elaine M. Papp, Chief, Medical
Programs,<PHONE_NUMBER><EMAIL_ADDRESS>FMCSA, Department of
Transportation, 1200 New Jersey Avenue, SE., Room W64-224, Washington,
DC 20590-0001. Office hours are from 8:30 a.m. to 5 p.m., Monday
through Friday, except Federal holidays.

SUPPLEMENTARY INFORMATION:

Background

    Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption
from the Federal Motor Carrier Safety Regulations for a 2-year period
if it finds ``such exemption would likely achieve a level of safety
that is equivalent to or greater than the level that would be achieved
absent such exemption.'' The statute also allows the Agency to renew
exemptions at the end of the 2-year period. The 16 individuals listed
in this notice have recently requested such an exemption from the
diabetes prohibition in 49 CFR 391.41(b)(3), which applies to drivers
of CMVs in interstate commerce. Accordingly, the Agency will evaluate
the qualifications of each applicant to determine whether granting the
exemption will achieve the required level of safety mandated by the
statutes.

Qualifications of Applicants

Mark D. Andersen

    Mr. Andersen, age 40, has had ITDM since 2010. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Andersen understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Andersen meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class A Commercial Driver's License
(CDL) from Iowa.

David A. Basher

    Mr. Basher, 55, has had ITDM since 2006. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Basher understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Basher meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
ophthalmologist examined him in 2011 and certified that he does not
have diabetic retinopathy. He holds a Class A CDL from Massachusetts.

Brian H. Berthiaume

    Mr. Berthiaume, 44, has had ITDM since 1994. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Berthiaume understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Berthiaume meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class B CDL from Vermont.

Eric D. Blocker, Sr.

    Mr. Blocker, 56, has had ITDM since before September 2009. His
endocrinologist examined him in 2011 and certified that he has had no
severe hypoglycemic reactions resulting in loss of consciousness,
requiring the assistance of another person, or resulting in impaired
cognitive function that occurred without warning in the past 12 months
and no recurrent (2 or more) severe hypoglycemic episodes in the last 5
years. His endocrinologist certifies that Mr. Blocker understands
diabetes management and monitoring, has stable control of his diabetes
using insulin, and is able to drive a CMV safely. Mr. Blocker meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
ophthalmologist examined him in 2011 and certified that he has stable
nonproliferative diabetic retinopathy. He holds a Class A CDL from
North Carolina.

Barry W. Campbell

    Mr. Campbell, 45, has had ITDM since 2009. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Campbell understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Campbell meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class D operator's license from
Wisconsin.

Kevin M. Donohue

    Mr. Donohue, 27, has had ITDM since 2005. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Donohue understands

diabetes management and monitoring, has stable control of his diabetes
using insulin, and is able to drive a CMV safely. Mr. Donohue meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
ophthalmologist examined him in 2011 and certified that he does not
have diabetic retinopathy. He holds a Class D operator's license from
New Jersey.

Milton T. Gardiner

    Mr. Gardiner, 43, has had ITDM since 2010. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Gardiner understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Gardiner meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class 10 operator's license from Rhode
Island.

Raymond A. Jack

    Mr. Jack, 52, has had ITDM since 2010. His endocrinologist examined
him in 2011 and certified that he has had no severe hypoglycemic
reactions resulting in loss of consciousness, requiring the assistance
of another person, or resulting in impaired cognitive function that
occurred without warning in the past 12 months and no recurrent (2 or
more) severe hypoglycemic episodes in the last 3 years. His
endocrinologist certifies that Mr. Jack understands diabetes management
and monitoring, has stable control of his diabetes using insulin, and
is able to drive a CMV safely. Mr. Jack meets the requirements of the
vision standard at 49 CFR 391.41(b)(10). His ophthalmologist examined
him in 2011 and certified that he has stable proliferative diabetic
retinopathy. He holds a Class A CDL from Washington.

Quency T. Johnson

    Mr. Johnson, 47, has had ITDM since 2004. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Johnson understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Johnson meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class A CDL from Wisconsin.

Kenny B. Keels, Jr.

    Mr. Keels, 27, has had ITDM since 1997. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Keels understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Keels meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
ophthalmologist examined him in 2011 and certified that he does not
have diabetic retinopathy. He holds a Class D operator's license from
South Carolina.

Gene A. Michaels

    Mr. Michaels, 67, has had ITDM since 1985. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Michaels understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Michaels meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
ophthalmologist examined him in 2011 and certified that he has stable
nonproliferative diabetic retinopathy. He holds a Class A CDL from
Michigan.

Jason M. Pritchett

    Mr. Pritchett, 39, has had ITDM since 1990. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Pritchett understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Pritchett meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
ophthalmologist examined him in 2011 and certified that he has stable
nonproliferative diabetic retinopathy. He holds a Class A CDL from
Michigan.

Steven R. Sibert

    Mr. Sibert, 42, has had ITDM since 2011. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Sibert understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Sibert meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class A CDL from Minnesota.

Cassie J. Silbernagel

    Mr. Silbernagel, 33, has had ITDM since 2011. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Silbernagel understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Silbernagel meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class A CDL from South Dakota.

Lewis B. Taylor

    Mr. Taylor, 39, has had ITDM since 2011. His endocrinologist
examined him

in 2011 and certified that he has had no severe hypoglycemic reactions
resulting in loss of consciousness, requiring the assistance of another
person, or resulting in impaired cognitive function that occurred
without warning in the past 12 months and no recurrent (2 or more)
severe hypoglycemic episodes in the last 5 years. His endocrinologist
certifies that Mr. Taylor understands diabetes management and
monitoring, has stable control of his diabetes using insulin, and is
able to drive a CMV safely. Mr. Taylor meets the requirements of the
vision standard at 49 CFR 391.41(b)(10). His optometrist examined him
in 2011 and certified that he does not have diabetic retinopathy. He
holds a Class A CDL from Illinois.

James A. Terilli

    Mr. Terilli, 61, has had ITDM since 2008. His endocrinologist
examined him in 2011 and certified that he has had no severe
hypoglycemic reactions resulting in loss of consciousness, requiring
the assistance of another person, or resulting in impaired cognitive
function that occurred without warning in the past 12 months and no
recurrent (2 or more) severe hypoglycemic episodes in the last 5 years.
His endocrinologist certifies that Mr. Terilli understands diabetes
management and monitoring, has stable control of his diabetes using
insulin, and is able to drive a CMV safely. Mr. Terilli meets the
requirements of the vision standard at 49 CFR 391.41(b)(10). His
optometrist examined him in 2011 and certified that he does not have
diabetic retinopathy. He holds a Class D operator's license from New
York.

Request for Comments

    In accordance with 49 U.S.C. 31136(e) and 31315, FMCSA requests
public comment from all interested persons on the exemption petitions
described in this notice. We will consider all comments received before
the close of business on the closing date indicated in the date section
of the notice.
    FMCSA notes that section 4129 of the Safe, Accountable, Flexible
and Efficient Transportation Equity Act: A Legacy for Users requires
the Secretary to revise its diabetes exemption program established on
September 3, 2003 (68 FR 52441).\1\ The revision must provide for
individual assessment of drivers with diabetes mellitus, and be
consistent with the criteria described in section 4018 of the
Transportation Equity Act for the 21st Century (49 U.S.C. 31305).
---------------------------------------------------------------------------

    \1\ Section 4129(a) refers to the 2003 notice as a ``final
rule.'' However, the 2003 notice did not issue a ``final rule'' but
did establish the procedures and standards for issuing exemptions
for drivers with ITDM.
---------------------------------------------------------------------------

    Section 4129 requires: (1) Elimination of the requirement for 3
years of experience operating CMVs while being treated with insulin;
and (2) establishment of a specified minimum period of insulin use to
demonstrate stable control of diabetes before being allowed to operate
a CMV.
    In response to section 4129, FMCSA made immediate revisions to the
diabetes exemption program established by the September 3, 2003 notice.
FMCSA discontinued use of the 3-year driving experience and fulfilled
the requirements of section 4129 while continuing to ensure that
operation of CMVs by drivers with ITDM will achieve the requisite level
of safety required of all exemptions granted under 49 USC. 31136(e).
    Section 4129(d) also directed FMCSA to ensure that drivers of CMVs
with ITDM are not held to a higher standard than other drivers, with
the exception of limited operating, monitoring and medical requirements
that are deemed medically necessary.
    The FMCSA concluded that all of the operating, monitoring and
medical requirements set out in the September 3, 2003 notice, except as
modified, were in compliance with section 4129(d). Therefore, all of
the requirements set out in the September 3, 2003 notice, except as
modified by the notice in the Federal Register on November 8, 2005 (70
FR 67777), remain in effect.

    Issued on: September 26, 2011.
Larry W. Minor,
Associate Administrator for Policy.
[FR Doc. 2011-25327 Filed 9-30-11; 8:45 am]
BILLING CODE 4910-EX-P