treatment for their own or their affiliate's requirements to ensure
that there is no undue discrimination, and to establish a process for
market participants to challenge and resolve the speed and accuracy
assumptions and requirements that public utility transmission providers
publish.\144\ Beacon and ESA also state that ideally the Commission
would require each utility to develop a conversion formula or chart
that specifies how much capacity a transmission customer must self-
supply given a certain ramp-rate and accuracy.
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    \142\ The five elements are: (1) A description of the
calculation; (2) the metric which is used to set the requirement;
(3) the average performance of the existing Regulation assets; (4)
the speed and accuracy of the units currently in place (including
ramp-rate and accuracy); and (5) sufficient data for a third party
to reproduce the results, including posting ACE data on its OASIS
reporting. ESA Comments at 12-13; Beacon Comments at 12; and
California Storage Alliance Comments at 6.
    \143\ Each entity proposes a bulleted list of nine items
including generation capacity available to provide regulation,
rates, costs, accuracy and CPS scores, and representative ACE data.
ESA Comments at 13; and Beacon Comments at 12-13.
    \144\ Morgan Stanley Comments at 10.
---------------------------------------------------------------------------

    106. ESA, Beacon, Public Interest Organizations, California Storage
Alliance, and AWEA advocate extending the requirement of accounting for
speed and accuracy in regulation service to public utilities meeting
their own needs, including via third-party suppliers, not simply to
transmission customers choosing to self-supply.\145\ AWEA argues that
holding more reserves than needed may result in rates that are not just
and reasonable.\146\ ESA, Beacon, Public Interest Organizations, and
California Storage Alliance state that third party sales to a public
utility that is purchasing ancillary services to satisfy its own OATT
requirements to offer ancillary services to its own customers
represents the most significant potential market for sales of ancillary
services in non-RTO/ISO regions. Public Interest Organizations agree,
arguing that neither the current rules nor the NOPR encourage
transmission providers to improve the speed and accuracy of their owned
or contracted frequency regulation resources, and that allowing
generators to be displaced from providing frequency regulation will
enable them to operate at a more stable output, which also can lower
energy market prices. Public Interest Organizations contend that the
existing OATT Schedule 3 rate treatment is no longer adequate to
incorporate emerging technologies, and encourage the Commission to
require that OATT Schedule 3 rates incorporate Order No. 755's
framework of an objective accuracy and performance determination, and
that the amount of frequency regulation transmission customers are
required to procure or self-supply takes into account the speed and
accuracy capability of the ancillary service provider's
technology.\147\
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    \145\ Beacon and Public Interest Organizations support ESA's
comments regarding third party sales of regulation.
    \146\ AWEA Comments at 4.
    \147\ Public Interest Organizations Comments at 8.
---------------------------------------------------------------------------

    107. Parties that support extending the proposal to public utility
transmission providers meeting their own needs also recommend that the
Commission consider performance-based rate treatment for public utility
investments and contracts with third-party ancillary service providers
that allow the public utility to reduce the total capacity and cost of
providing regulation service while maintaining the same level of
reliability.\148\ They argue that the potential benefits to ratepayers
could justify allowing a performance-based incentive rate adder that
public utility transmission providers could recover through rates, and
that if the public utility can demonstrate that it will be able to
reduce the total capacity and cost of providing regulation service and
maintain the same degree of reliability, such treatment should result
in public utilities improving the performance of their regulation fleet
and in turn reducing expenses for frequency regulation, ultimately
resulting in lower costs.
---------------------------------------------------------------------------

    \148\ See comments of ESA, Beacon, Public Interest
Organizations, and California Storage Alliance.
---------------------------------------------------------------------------

    108. TAPS asks the Commission to state explicitly that the NOPR's
proposal to account for the speed and accuracy of customer self-
supplied regulating resources includes demand resources and to state
that such a finding would be consistent with OATT Schedule 3 and Order
No. 755.\149\
---------------------------------------------------------------------------

    \149\ TAPS Comments at 27.
---------------------------------------------------------------------------

    109. EEI opposes the NOPR proposal. It contends that it is
premature to require each transmission provider to include provisions
in its OATT explaining how it will determine Regulation and Frequency
Response requirements, and requests that the Commission defer this
proposal pending experience with secondary frequency control (i.e.,
regulation) in the ISOs and RTOs following the issuance of Order No.
755.\150\ EEI requests that the Commission recognize the material
differences between primary and secondary frequency control resources
in the final rule. It argues that it is also premature to adopt
requirements regarding primary frequency control, and recommends that
the Commission encourage each balancing authority to continue
investigating the role of various types of resources, and allow the
industry to maintain its efforts to understand the relationship and
interdependencies between primary and secondary frequency response.
---------------------------------------------------------------------------

    \150\ EEI Comments at 22-26.
---------------------------------------------------------------------------

    110. EEI contends that the assumption that faster responding
technologies are necessarily more efficient than traditional methods of
frequency regulation has not been substantiated. EEI explains that
industry is still exploring frequency response, including current and
historical primary and secondary control response performance, and that
for system reliability it is important to maintain a balanced portfolio
of resources including inertial response, governor response, and
secondary frequency control (or regulation response). It further
explains that, although OATT Schedule 3 groups primary and secondary
frequency control into a single service, the nature of these

services are distinct. With regard to secondary frequency control
(regulation), EEI claims that the benefits from resources that ramp
more quickly for purposes of secondary frequency control may be offset
by a lack of capability to sustain that response, or to provide
automatic primary frequency control.
Commission Determination
    111. The Commission will adopt the NOPR proposal with modification.
Rather than requiring OATT Schedule 3 to include a description of how
resource speed and accuracy will be taken into account in determining
Regulation and Frequency Response reserve requirements, we will require
each public utility transmission provider to add to its OATT Schedule 3
a statement that it will take into account the speed and accuracy of
regulation resources in its determination of reserve requirements for
Regulation and Frequency Response service, including as it reviews
whether a self-supplying customer has made ``alternative comparable
arrangements'' as required by the Schedule. This statement will also
acknowledge that, upon request by the self-supplying customer, the
public utility transmission provider will share with the customer its
reasoning and any related data used to make the determination of
whether the customer has made ``alternative comparable arrangements.''
\151\ To aid the transmission customer's ability to make an ``apples-
to-apples'' comparison of regulation resources, the Commission will
also amend Part 35 of its Regulations by adding a new section (k) to
Sec.  37.6,\152\ to require each public utility transmission provider
to post certain Area Control Error (ACE) data described further below.
We find that these reforms are necessary to address the potential for
undue discrimination in the provision of Regulation and Frequency
Response, including in instances when a customer self-supplies this
service using its own resources or purchases from a third-party.
Acknowledging the speed and accuracy of the resources used to provide
this service will help to ensure that an appropriate quantity of
resources is utilized for self-supply, whether those resources are
faster and more accurate or slower and less accurate than those used by
the public utility transmission provider. The weight of comments
support reform in this area, including arguments that such a reform
will help foster innovation and the entry of newer resources into the
market.
---------------------------------------------------------------------------

    \151\ See Appendix B for the revised Schedule 3 of the pro forma
OATT provisions consistent with this Final Rule.
    \152\ This regulation will replace the like-numbered proposed
regulation related to historical ancillary service requirements data
posting from the NOPR that we decline to adopt in section II.A.1.b.
of this Final Rule.
---------------------------------------------------------------------------

    112. Under the current pro forma OATT, transmission customers
considering using their own or third-party resources to self-supply
regulation service are required to demonstrate to the public utility
transmission provider that they have made ``alternative comparable
arrangements.'' However, the pro forma OATT provides no further
information as to how the determination of ``alternative comparable
arrangements'' would be made. Moreover, the OATT contains no express
obligation on the part of the transmission provider to consider the
relative speed and accuracy of resources a customer might desire to use
in self-supplying Regulation and Frequency Response service. A public
utility transmission provider could require a customer seeking to self-
supply regulation services to provide a volume of regulation reserves
based on the characteristics of the resources used by the public
utility transmission provider to provide regulation service, which may
not be reflective of the characteristics of the customer's resources.
This could under- or overstate regulation reserve requirements
depending on the relative characteristics of the resources at issue. It
also could impair the customer's ability to self-supply regulation
requirements at the lowest possible cost.\153\ The Commission finds
that this lack of clarity as to the role of resource speed and accuracy
in the determination of ``alternative comparable arrangements'' for
regulation reserve requirements for self-supplying transmission
customers must be addressed in order to limit opportunities for
potential discrimination in the provision of regulation service by
public utility transmission providers.
---------------------------------------------------------------------------

    \153\ For example, a self-supplying customer could save money
either by relying on a smaller amount of high quality regulation
resources at a slightly higher per-unit price or by relying on a
larger amount of lower quality regulation resources at a much lower
per-unit price. Provided that reliability is maintained, the
transmission customer should have the ability to self-supply
consistent with its preferences.
---------------------------------------------------------------------------

    113. While the Commission initially proposed that each public
utility transmission provider should amend its OATT to include a
description of how regulation reserve requirement determinations would
take into account speed and accuracy of resources, we believe the
better course of action at this time is to place the obligation on the
public utility transmission provider to take into account speed and
accuracy without requiring it to develop detailed tariff language
describing the specific process to be used. This will provide the
public utility transmission provider with flexibility while also
providing the customer with information. While a number of commenters
suggested elements for what the public utility transmission provider
should be required to provide, the clearest proposal in the comments
related to this issue request that public utility transmission
providers be required to provide current monthly and 12-month rolling
average Control Performance Standard 1 (CPS1), Control Performance
Standard 2 (CPS2) and Balancing Authority ACE Limit (BAAL) scores for
Frequency Regulation.\154\ However, by itself availability of such
information would do nothing to explain how the public utility
transmission provider determines regulation reserve amounts.
Furthermore, while ACE information might help to characterize the speed
and accuracy of the public utility transmission provider's own
regulation resources, the Commission believes that using the relatively
long duration of monthly and 12-month rolling ACE averages implicit in
these scores may not provide information useful for measuring
performance over a fraction of an hour, which is the relevant time
frame for Regulation and Frequency Response service.
---------------------------------------------------------------------------

    \154\ CPS1 and CPS2 are described in NERC Reliability Standard
BAL-001-0.1a--Real Power Balancing Control Performance. The BAAL
criterion is expected to replace CPS2 in that Reliability Standard
when it becomes effective, pending final approval by NERC and the
Commission.
---------------------------------------------------------------------------

    114. Accordingly, the Commission declines to impose a ``one size
fits all'' approach to calculating regulation reserve requirements,
consistent with the comments of Hydro Association and California PUC,
and declines to require the inclusion of this process in Schedule 3.
Rather, we require that Schedule 3 be amended to include a statement
that the public utility transmission provider will take into account
the speed and accuracy of regulation resources in determining reserve
requirements for Regulation and Frequency Response service, including
when reviewing whether a self-supplying customer has made ``alternative
comparable arrangements.'' Self-supplying customers and their public
utility transmission providers will then have a basis to study and
negotiate appropriate arrangements case-by-case, very similar to how
such

interactions take place under other processes such as the
interconnection process.
    115. That said, we agree with the comments of ESA, Beacon, and
California Storage Alliance that transmission customers considering
whether or not there would be any economic advantage to self-supply of
Regulation and Frequency Response service requirements would need to be
able to make an ``apples-to-apples'' comparison of their resources to
those of their public utility transmission provider.\155\ Doing so
would require the transmission customer to know both the potential
avoided cost of purchasing from its public utility transmission
provider, and some measure of the speed and accuracy of the public
utility transmission provider's Regulation resources. The first
requirement is met through the rate filed in the public utility
transmission provider's OATT Schedule 3. We believe the second
requirement can only be met through a new OASIS posting requirement.
---------------------------------------------------------------------------

    \155\ ESA Comments at 8-10; Beacon Comments at 7-9; and
California Storage Alliance Comments at 5-6.
---------------------------------------------------------------------------

    116. As noted earlier, the public utility transmission provider's
CPS1, CPS2, and BAAL scores might address this need in concept, except
that they currently reflect long-term averages that do not match the
relevant time frame for Regulation and Frequency Response service. We
believe the one-minute and ten-minute average ACE data collected by
public utility transmission providers to produce the CPS1, CPS2, and
BAAL scores would be more useful for this purpose because it does match
the relevant time frame. Accordingly, in order to ensure a level of
transparency adequate to support self-supply decision-making by
transmission customers, we will require public utility transmission
providers to post historical one-minute and ten-minute ACE data on
OASIS. For this purpose, we find that historical data for the most
recent calendar year, updated once per year, should meet the need. This
information is already collected and provided to NERC, through
balancing area operators and reliability coordinators, so there should
be minimal incremental burden associated with posting it on OASIS.
    117. The Commission's standard filing requirements, including
opportunity for intervention and comment, address Morgan Stanley's
request to establish a process for market participants to challenge and
resolve speed and accuracy assumptions. For example, as is the case in
interconnection agreement proceedings, the transmission service
agreement that reflects an individually negotiated self-supply
arrangement for Regulation and Frequency Response service can be filed
by the public utility transmission provider unexecuted. This will leave
the transmission customer free to protest relevant aspects of the
public utility transmission provider's determination of whether the
customer has made ``alternative comparable arrangements,'' including as
those arrangements relate to the speed and accuracy of the customer's
proposed Regulation resources.
    118. With respect to Morgan Stanley's request that public utilities
demonstrate equivalent treatment for their own or their affiliate's
regulation requirements, we find that the increased transparency
required by this Final Rule will accomplish this goal. The requirements
adopted above apply to the public utility transmission provider's own
regulation resources, in the sense that it must apply the same
procedures for determining regulation reserve requirements to itself as
it does to self-supplying customers.
    119. With respect to the request of TAPS that the Commission state
explicitly that the NOPR's proposal to account for the speed and
accuracy of customer self-supplied regulating resources includes demand
resources, we note that OATT Schedule 3, as amended by Order No. 890
makes clear that Regulation and Frequency Response service may be
provided from non-generation resources capable of providing the
service. Accordingly, a transmission provider's determination of
regulation reserve requirements should take into account the speed and
accuracy characteristics of the resources in question, whether they are
generation-based or otherwise.
    120. Turning to the various requests that the Commission step
beyond the NOPR proposals, the Commission declines to require two-part
pricing for regulation capacity and performance set forth in Order No.
755. We conclude that the requirements adopted above will allow
customers and the Commission to ensure that the speed and accuracy of
resources used for regulation reserves are properly taken into account
in reserve level determinations within the context of the bilateral
markets within which non-RTO/ISO public utility transmission providers
operate. The Commission also declines commenter requests to provide
incentive rate treatment for purchases of Regulation and Frequency
Response service by public utility transmission providers to meet their
OATT requirements. Commenters are not clear as to what mechanism they
believe the Commission should use to require such treatment, and the
Commission sees no reason to implement an incentives program in the
context of ancillary services rate design.
    121. With respect to EEI's comments regarding differences between
primary frequency response and secondary frequency regulation, the
Commission acknowledges these distinctions. Improving the transparency
regarding the resources used to provide Regulation and Frequency
Response service under OATT Schedule 3 does not alter the ability of
any balancing authority to maintain adequate reserves to meet
reliability requirements. The Commission thus sees no need to wait for
the industry to better understand the relationship and
interdependencies between primary and secondary frequency response
prior to adopting the requirements of this final rule. The Commission
will evaluate a public utility transmission provider's compliance
proposal as part of the case-by-case review discussed above, which will
provide the public utility transmission provider the opportunity to
demonstrate how it establishes its regulation reserve requirements.

Accounting and Reporting for Energy Storage Operations

    122. In the NOPR, the Commission proposed to revise certain
accounting and reporting requirements under its USofA and its forms,
statements, and reports contained in Form Nos. 1, 1-F, and 3-Q. The
Commission stated that the revisions were needed so that entities
subject to the Commission's accounting and reporting requirements could
better account for and report transactions associated with energy
storage devices used in public utility operations. Moreover, the
Commission noted that this information is important in developing and
monitoring rates, making policy decisions, compliance and enforcement
initiatives, and informing the Commission and the public about the
activities of entities subject to the accounting and reporting
requirements.
    123. The Commission proposed that new electric plant and associated
O&M expense accounts be created to provide for the recording of
investment and O&M costs of energy storage assets. The Commission also
proposed to create a new purchased power account to provide for
recording the cost of power purchased for use in storage operations. In
addition, the Commission proposed that new Form Nos. 1 and 1-F
schedules be created and existing schedules in the forms and Form No.
3-

Q be amended to report operational and statistical data on storage
assets. Finally, the Commission inquired about whether entities seeking
to recover costs of energy storage assets and operations simultaneously
under cost-based and market-based rates should be required to forego
previously granted accounting and reporting waivers associated with
market-based rates, and if so, should the requirement to forego the
waivers be subject to some percentage threshold based on a ratio of
cost-based cost recovery to total cost to be recovered.
    124. While most commenters support the Commission's proposal to
revise the accounting and reporting requirements, there were several
recommendations to make adjustments to the proposals and also requests
for clarification of certain proposals. Only Solar Energy Association
opposed the proposal, stating, without elaboration, that it believes it
is premature to establish reporting requirements for energy
storage.\156\ In the NOPR, the Commission responded to similar
arguments regarding maturity of the energy storage industry as it
relates to the use of energy storage assets to provide public utility
services, and found those arguments unconvincing.\157\ The Commission
explained that there is a need for certainty in the accounting and
reporting treatment for energy storage assets and operations,
especially in instances where utilities seek to recover costs of energy
storage operations in cost-based rates. Solar Energy Association has
not provided new information that we could consider on this issue,
therefore we find Solar Energy Association's argument unconvincing.
---------------------------------------------------------------------------

    \156\ Solar Energy Association Comments at 7.
    \157\ NOPR, FERC Stats. & Regs. ] 32,690 at P 71.
---------------------------------------------------------------------------

1. Electric Plant Accounts
Commission Proposal
    125. In the NOPR, the Commission stated that the existing primary
plant accounts do not explicitly provide for recording the cost of
energy storage assets. The Commission concluded that this could lead to
inconsistent accounting and reporting for these assets by utilities
subject to the accounting and reporting requirements, making it
difficult for the Commission and others to determine costs related to
energy storage assets for cost-of-service rate purposes. The Commission
also noted that the lack of transparency affects interested parties',
including the Commission's, ability to monitor these utilities'
operations to prevent and discourage cross-subsidization between cost-
based and market-based activities. To address these issues, the
Commission proposed to create electric plant accounts in the existing
functional classifications--production, transmission, and
distribution--for new energy storage assets.\158\
---------------------------------------------------------------------------

    \158\ Account 348, Energy Storage Equipment-Production; Account
351, Energy Storage Equipment--Transmission; and Account 363, Energy
Storage Equipment--Distribution, respectively.
---------------------------------------------------------------------------

    126. The Commission proposed that the installed costs of energy
storage assets be recorded in the accounts based on the function or
purpose the asset serves. On this basis, an asset that performs a
single function will have its cost recorded in a single plant account.
In instances where an energy storage asset is used to perform more than
one function or purpose, the Commission proposed that the cost of the
asset be allocated among the relevant energy storage plant accounts
based on the functions performed by the asset and the allocation of the
asset's costs through cost-based rates that are approved by a relevant
regulatory agency, whether federal or state.\159\
---------------------------------------------------------------------------

    \159\ NOPR, FERC Stats. & Regs. ] 32,690 at P 81.
---------------------------------------------------------------------------

Comments
    127. In general, the commenters applaud the Commission's efforts to
improve transparency and prevent double-recovery of energy storage-
related costs. The proposal to require utilities to record the costs of
single-function energy storage assets in a single plant account
garnered widespread support. However, the proposal to require utilities
to allocate the costs of multi-function energy storage assets to the
relevant energy storage plant accounts based on the functions performed
and approved rate recovery, received comments supporting and opposing
the proposal. Commenters that agree with the proposal generally
indicate that the accounting would provide necessary transparency of a
utility's operations,\160\ while commenters that oppose the proposal
generally indicate that the accounting would place an undue
administrative burden on utilities and is inconsistent with the
Commission's existing accounting rules.\161\
---------------------------------------------------------------------------

    \160\ Public Interest Organizations Comments at 9-10; California
PUC Comments at 9; NU Companies Comments at 4; APPA Comments at 5;
ESA Comments at 18-19; TAPS Comments at 28-29; and California
Storage Association Comments at 11-12.
    \161\ Southern California Edison Comments at 8; SDG&E Comments
at 2-3; and EEI Comments at 29-30.
---------------------------------------------------------------------------

    128. Public Interest Organizations state that they support the
development of requirements that can reveal the activities and costs of
energy storage operations thorough greater transparency and detail.
California PUC similarly states that in the event an energy storage
developer intends to use a facility to perform multiple functions, the
proposed accounting and reporting should provide transparency. NU
Companies state that they support flexible rate treatment for energy
storage assets and believe the proposed accounting will provide
transparency required to guard against inappropriate cross
subsidization of various services and double recovery cost.
    129. In opposition to the proposal, SDG&E contends that while it
generally agrees with the Commission's allocation ``concept'' to
account for energy storage assets by functional category, i.e.,
production, transmission, and distribution, it is concerned that
generally applicable financial tools may not be able to efficiently
track or monitor up to three functional categories for one asset
without increased and ongoing manual intervention.\162\ SDG&E argues
that it agrees that the initial allocation concept would capture
expenses by each function as the Commission intends; however, if the
utility subsequently changes its initial allocation in the future the
proposed accounting would create an unnecessary administrative burden
that if a mistake is made could result in costs of the asset being
stranded. SDG&E contends that to ensure the asset is accounted for
properly so that asset costs are not stranded, a utility would be
required to continuously monitor the asset to make sure its initial
allocation is consistent with the asset's actual usage. SDG&E
acknowledges that the NOPR addresses this concern; \163\ however, SDG&E
asserts that there is a more straightforward approach that can be used
to allocate the costs of a multi-function energy storage asset. SDG&E
advocates, instead of using multiple plant accounts, that the cost of
an energy storage asset be recorded in a single plant account and its
cost allocated to the various functions it performs using current
ratemaking methods.
---------------------------------------------------------------------------

    \162\ SDG&E Comments at 2-3.
    \163\ SDG&E cites to the NOPR proposal that a utility transfer
reallocated cost of an energy storage asset in accordance with the
instructions of Electric Plant Instruction No. 12, Transfers of
Property, 18 CFR Part 101 (2012). See SDG&E Comments at 3-4 (citing
to NOPR, FERC Stats. & Regs. ] 32,690 at P 82).
---------------------------------------------------------------------------

    130. Similar to SDG&E, Southern California Edison and EEI also
complain of an increased administrative burden resulting from
allocating an energy

storage asset's cost across multiple plant accounts as proposed in the
NOPR. Southern California Edison and EEI contend that it would be
necessary to create multiple unique property records for an energy
storage asset to allocate its costs across multiple functions. Southern
California Edison and EEI argue that having multiple records for each
asset would require significant manual intervention while providing
little practical value.\164\ Additionally, Southern California Edison
and EEI assert, without providing any detail, that the NOPR proposal is
inconsistent with the general principle that each asset should have a
single record within an accounting system.\165\ Southern California
Edison and EEI contend that there is neither a precedent for creating
multiple property records for a single asset, nor a precedent for
creating a record for a partial asset. Further, EEI argues that to the
extent the different functions the cost of an energy storage asset
could be spread across are subject to different depreciation rates, a
single asset with a unique, individual economic life would be
depreciated over multiple periods.
---------------------------------------------------------------------------

    \164\ Southern California Edison Comments at 8; and EEI Comments
at 30.
    \165\ Southern California Edison Comments at 8 and n 8 citing
Definition No. 8 Paragraph (A)(5), Continuing Plant Inventory
Record, 18 CFR Part 101 (2012); and EEI Comments at 30.
---------------------------------------------------------------------------

    131. EEI indicates that while it generally opposes the NOPR's
proposed accounting, it believes that in some circumstances the
proposal may be a practical alternative for companies desiring to use
it.\166\ Therefore, EEI advocates that utilities be afforded two
options to account for energy storage assets that are used to perform
multiple functions. EEI proposes that utilities be allowed to either:
(1) Record the costs of multi-function storage asset costs as proposed
in the NOPR or (2) record the costs of the assets in a single plant
account based on the primary function of the asset and to allocate
costs to specific functions performed through the ratemaking process.
Moreover, EEI recommends that the Form Nos. 1, 1-F, and 3-Q be amended
to provide for reporting the option each company uses. EEI contends
that allowing both options will afford companies the ability to
maintain accounting and reporting records in the most efficient manner
while providing transparency via reporting and uniformity in the
ratemaking process.
---------------------------------------------------------------------------

    \166\ EEI Comments at 29-31.
---------------------------------------------------------------------------

    132. Southern California Edison supports EEI's option (2). Southern
California Edison and EEI contend that the option (2) approach is
consistent with the approach used for certain assets that provide both
state-jurisdictional and FERC-jurisdictional functions.\167\ Southern
California Edison and EEI explain that the ratemaking process may
include a formula or special study in order to appropriately allocate
the costs across functions.
---------------------------------------------------------------------------

    \167\ Southern California Edison Comments at 8; and EEI Comments
at 31-32.
---------------------------------------------------------------------------

Commission Determination
    133. SDG&E's, Southern California Edison's, and EEI's arguments
that requiring utilities to allocate the costs of energy storage assets
that perform multiple functions across the relevant energy storage
plant accounts places an undue administrative burden on utilities are
unpersuasive. These commenters generally argue that this perceived
undue administrative burden results from a requirement that utilities
maintain records that track the usage of energy storage assets and
costs associated with such use. However, utilities would be required to
maintain records with this information whether accounting for the costs
of an asset in multiple accounts as proposed in the NOPR or accounting
for the costs in a single account as proposed by SDG&E, Southern
California Edison and EEI. For example, information on the allocation
of the cost of an energy storage asset to a particular function will
have to be maintained by utilities operating multi-function, multi-cost
recovery energy storage assets, regardless of whether the information
is required to be reported in the reporting forms as proposed in the
NOPR or if the information is not reported in the forms yet is used in
ratemaking determinations as proposed by SDG&E, EEI, and Southern
California Edison. Because utilities with energy storage operations
that recover any portion of costs on a cost-of-service basis will be
required to maintain use and cost allocation information on the assets,
requiring these utilities to implement the NOPR's accounting proposal
does not result in an additional burden on utilities that could be
considered unduly burdensome.
    134. Moreover, SDG&E's argument that costs could possibly be
stranded if a utility does not appropriately account for energy storage
operations is also unconvincing. This possibility exists throughout the
utility industry and is not uniquely attributable to utilities with
energy storage operations. Administrative errors, such as errors in
accounting, that lead to costs being stranded due to inadequate or
insufficient internal controls over policies, practices, and procedures
used to track costs associated with assets represent a risk for all
utilities whether or not the utilities own energy storage assets. Risks
of this nature are inherent to all utilities' operations. Utilities
must maintain adequate, sufficient, and reliable internal controls to
reduce the probability of this risk affecting operations.
    135. As support for their argument that the NOPR's proposed
accounting causes an undue administrative burden and that their
advocated accounting avoids the burden, Southern California Edison and
EEI contend that their proposal to record the costs of an energy
storage asset in a single plant account could require utilities to
implement a formula or special study to appropriately allocate the
costs of the asset across multiple functions. However, this contention
does not support their argument. A formula or special study would
require utilities to maintain the same information on the functions
performed by an energy storage asset and costs associated with such
performance, as would be required by the NOPR's proposed accounting.
Thus, a formula or special study would not avoid the administrative
burden associated with accounting for energy storage assets and
operations. Furthermore, Southern California Edison and EEI have not
provided information to support a determination that the burden would
be decreased by implementing their proposed accounting. Their proposal
would result in less transparent reporting of information on energy
storage operations as compared to the NOPR's proposed accounting.
    136. While the commenters argue that the accounting proposal might
require increased manual intervention to account for and report storage
assets, it is not clear that such intervention, if any, results in an
undue administrative burden. As the Commission observed in the NOPR,
uniform, transparent, and consistent reporting of information on energy
storage operations by utilities is essential, especially by those
seeking to recover costs of energy storage services in cost-based
rates.\168\ We believe that adopting the NOPR's proposed accounting and
reporting revisions will improve transparency.\169\ The revisions will
enhance the Commission's and other form users' ability to make a
meaningful assessment of a utility's cost-of-service rates, and will
provide for better monitoring for cross-subsidization. In instances
where an energy storage asset performs multiple

functions, it is imperative that costs associated with each function be
transparent and allocable to the function performed so that cross-
subsidization of costs can be prevented. SDG&E, EEI, and Southern
California Edison have not provided information that would refute the
Commission's determination in the NOPR that the accounting proposal is
not overly burdensome.
---------------------------------------------------------------------------

    \168\ NOPR, FERC Stats. & Regs. ] 32,690 at P 71.
    \169\ Id. P 72.
---------------------------------------------------------------------------

    137. EEI's recommendation that utilities be afforded two options to
account for and report storage assets that provide multiple services
and recover associated costs simultaneously under cost-based and
market-based rate methods is not consistent with the intent of the
NOPR's proposed accounting and reporting revisions. The NOPR proposed
one method to account for energy storage assets performing multiple
functions under multiple cost recovery mechanisms to ensure that
utilities account for the assets on a uniform and consistent basis.
EEI's proposal for two methods of accounting could result in similarly-
situated utilities with energy storage assets reporting the same type
of transaction differently. This would not provide the uniformity
sought by the accounting and reporting proposals and could disrupt
consistency, which would make it difficult to compare utilities with
energy storage operations across the industry. In addition, adopting
EEI's proposal to record the costs of the assets in a single account
would reduce the transparency of information reported in the forms.
This information is critical to the clarity and transparency needed to
support a reasonable analysis of a utility's cost. Consequently, we
will not adopt EEI's proposal.
    138. Southern California Edison's assertion that the NOPR
requirement adopted here is not consistent with Definition No. 8,
Continuing Plant Inventory Record, is incorrect.\170\ While the
definition pre-dates the NOPR's accounting and reporting requirements,
the definition is broad enough such that its premise is as relevant for
energy storage assets as it is for conventional electric plant assets.
The accounting and reporting proposals require utilities to maintain a
detailed record of the descriptive operational and cost information
associated with energy storage assets consistent with the provisions of
Definition No. 8.
---------------------------------------------------------------------------

    \170\ 18 CFR Part 101 (2012).
---------------------------------------------------------------------------

    139. Further, Southern California Edison's and EEI's contentions
that there is no precedent for creating multiple property records for a
single or partial asset misconstrues the proposed accounting and
reporting requirements. The accounting and reporting proposals we adopt
here do not require utilities to maintain multiple records for a single
or partial asset as Southern California Edison and EEI contend. Rather,
the reforms maintain the existing requirement of Definition No. 8 that
utilities maintain descriptive operational and cost information on each
asset. Moreover, we do not consider allocating the cost of a single
asset to multiple property accounts to be the same as creating multiple
property records as though there were multiple assets. A utility can
maintain information on a single energy storage asset with costs
allocated to multiple plant accounts in a single record that provides
descriptive operational and cost information on the asset.
Additionally, in accordance with General Instruction No. 12, Records
for Each Plant, utilities are required to maintain a record, by
electric plant accounts, on the book costs of each plant owned.\171\
The requirement to record the cost of a multi-function, multi-cost
recovery energy storage asset to more than one plant account is
consistent with this instruction.
---------------------------------------------------------------------------

    \171\ The instructions indicate that the term ``plant'' means
each generating station and each transmission line or appropriate
group of transmission lines. This term is also applicable to energy
storage facilities. 18 CFR Part 101 (2012).
---------------------------------------------------------------------------

    140. EEI argues that if different depreciation rates are applied to
a single energy storage asset in accordance with each function the
asset performs the various allocated costs of the asset would be
depreciated over multiple periods. EEI is correct that there is a
possibility of this occurring if costs of a single asset were subjected
to multiple differing depreciation rates. However, this has neither
been the experience of this Commission nor do we expect that a
utility's primary rate regulator would subject a single asset to
multiple depreciation rates. Although the costs of an energy storage
asset may be allocated across multiple plant accounts, we agree with
EEI that the asset is a single unique asset with a single economic
life. Thus, there should be a single depreciation rate applied to the
asset that allocates in a systematic and rational manner the service
value of the asset over its service life. To the extent possible, a
utility should apply a single depreciation rate to an energy storage
asset.
    141. The reforms adopted here are designed to provide needed
transparency, but also to reflect a fair balance between the need for
information and the additional burden on the utility. We believe these
accounting reforms for energy storage reflect this balance.
Accordingly, Account 348, Energy Storage Equipment--Production, Account
351, Energy Storage Equipment--Transmission, and Account 363, Energy
Storage Equipment--Distribution, as proposed in the NOPR are adopted in
this Final Rule.
2. Power Purchased Account
Commission Proposal
    142. In the NOPR, the Commission noted that to provide some
electrical services, energy storage devices may need to maintain a
particular state of charge, or as in the case of compressed air
facilities, may need to maintain some minimum pressure, and that some
companies may be required to purchase power to maintain a desired state
of charge or pressure. Further, the Commission determined that the
benefits of enhanced transparency, in this instance, resulting from
having the cost of power purchased for energy storage operations
reported separately from other power purchases, outweighs the
associated burden of requiring the accounting. Therefore, the
Commission proposed a new Account 555.1, Power Purchased for Storage
Operations, to report the cost of: (1) Power purchased and stored for
resale; (2) power purchased that will not be resold but instead
consumed in operations during the provisioning of services; (3) power
purchased to sustain a state of charge; and (4) power purchased to
initially attain a state of charge, with item 4 being capitalized as a
component cost of initially constructing the asset.
Comments
    143. Most commenters support the proposed accounting. For example,
ESA and others state that the new account will enhance the transparency
of reporting the operations of storage resources.\172\ Hydro
Association indicates that similar accounting should be established for
the cost of power purchased for pumped storage operations to account
for initial unit testing and commissioning.\173\
---------------------------------------------------------------------------

    \172\ ESA Comments at 21-22.
    \173\ Hydro Association Comments at 12-13.
---------------------------------------------------------------------------

    144. Hydro Association states, in particular, for closed-loop
pumped storage projects, the first unit testing entails pumping or
charging the upper reservoir. Hydro Association explains that at an
early stage of development of a pumped storage project, the generating
station is months away from being declared ``commercial'' and testing
the station requires energy from the grid to initially attain a fully
charged state (i.e., a full upper reservoir). Hydro Association argues
that these initial

charging costs should be capitalized. Further, Hydro Association
contends that costs incurred to test the generating station should
likewise be capitalized into the cost of the project. In contrast to
Hydro Association's assertion that the existing accounting requirements
for pumped storage operations are not sufficient, EEI argues that the
existing requirements appropriately and transparently provide for
pumped storage plants.\174\
---------------------------------------------------------------------------

    \174\ EEI Comments at 27.
---------------------------------------------------------------------------

Commission Determination
    145. We will adopt the new Account 555.1, Power Purchased for
Storage Operations, as proposed in the NOPR. The accounting reforms
here requiring initial charging and testing costs to be capitalized
seek to apply existing requirements for conventional electric plant,
such as pumped storage plant, to new energy storage assets. The
requirements do not seek to differentiate the accounting for new energy
storage assets from pumped storage plant in this instance.
    146. We disagree with Hydro Association's assertion that the
existing accounting requirements for pumped storage operations are not
sufficient. Contrary to Hydro Association's assertion, pumped storage
is not prohibited, for accounting purposes, by the existing accounting
rules and regulations from capitalizing costs incurred to initially
bring a pumped storage facility into operation nor is it prohibited
from capitalizing costs incurred to test pump storage facilities prior
to commercial operation. Electric Plant Instruction No. 3, Components
of Construction Cost, provides that expenses incidental to the
construction of plant such as cost to initially attain a fully charged
state to bring the plant into operation may be capitalized as a
component cost of the plant.\175\ Further, Electric Plant Instruction
No. 9, Equipment, provides that the costs of plant shall include
necessary costs of testing or running plant or parts thereof during the
test period prior to the plant becoming ready for or being placed in
service.\176\ Consequently, we agree with EEI's statement that the
existing accounting requirements for pumped storage are sufficient. The
NOPR proposals for Account 555.1 are adopted in this Final Rule as
proposed.
---------------------------------------------------------------------------

    \175\ 18 CFR Part 101 (2012).
    \176\ Id.
---------------------------------------------------------------------------

3. Operation and Maintenance Expense Accounts
Commission Proposal
    147. In the NOPR, the Commission observed that there are O&M
expenses related to the use of energy storage assets to provide utility
services, and there are no existing O&M expense accounts in the USofA
specifically dedicated to accounting for the cost of energy storage
operations. Therefore, the Commission proposed new O&M expense accounts
for energy storage-related O&M expenses that are not specifically
provided for in the existing O&M expense accounts in the USofA and
revision of certain existing O&M expense accounts. Specifically, the
Commission proposed that energy storage expenses be recorded in Account
548.1, Operation of Energy Storage Equipment, and Account 553.1,
Maintenance of Energy Storage Equipment, for energy storage plant
classified as production; Account 562.1, Operation of Energy Storage
Equipment, and Account 570.1, Maintenance of Energy Storage Equipment,
for energy storage plant classified as transmission; and Account 582.1,
Operation of Energy Storage Equipment, and Account 592.2, Maintenance
of Energy Storage Equipment, for energy storage plant classified as
distribution, to the extent that the existing O&M expense accounts do
not adequately support recording of the cost.\177\
---------------------------------------------------------------------------

    \177\ NOPR, FERC Stats. & Regs. ] 32,690 at P 96.
---------------------------------------------------------------------------

Comments
    148. The commenters support the proposed O&M expense accounts. Most
commenters state that the proposed accounts will provide sufficient
transparency of energy storage-specific O&M expenses.\178\
---------------------------------------------------------------------------

    \178\ See, e.g., ESA Comments at 22; Beacon Power Comments at
21-22; and California Storage Alliance Comments at 17.
---------------------------------------------------------------------------

Commission Determination
    149. This Final Rule adopts the NOPR proposals for the O&M expense
accounts with the exception that the account number for Account 582.1
will be changed to Account 584.1. The name and text of the account will
remain as proposed in the NOPR.
    150. In addition, the NOPR proposed that the text of Account 592,
Maintenance of Station Equipment (Major only), and Account 592.1,
Maintenance of Structures and Equipment (Nonmajor only), be revised
such that the accounts do not provide for O&M expenses related to
energy storage operations and also to remove the reference to Account
363. Accordingly, the following text is struck from Accounts 592 and
592.1:

``and account 363, Storage Battery Equipment.''
4. New and Amended Form Nos. 1, 1-F, and 3-Q Schedules
Commission Proposal
    151. In the NOPR, the Commission acknowledged that the existing
schedules in the Form Nos. 1, 1-F, and 3-Q do not provide for reporting
information on new types of energy storage assets such as batteries and
flywheels.\179\ Consequently, the Commission proposed to amend several
schedules of the Form Nos. 1, 1-F, and 3-Q to include energy storage
plant, purchased power, and O&M expense accounts.\180\ In addition, the
Commission proposed to add new schedule pages 414-416, Energy Storage
Operations (Large Plants), and pages 419-420, Energy Storage Operations
(Small Plants), to the Form Nos. 1 and 1-F to provide for reporting
operational and statistical information on new types of energy storage
assets.\181\ The Commission proposed that filers with energy storage
assets having a rated capacity of 10,000 kilowatts (KW) or more record
the operations of the assets on schedule pages 414-416, and filers with
energy storage assets with less than 10,000 KW of capacity record the
operations on schedule pages 419-420. In addition, the Commission
sought comment on whether 10,000 KW is an appropriate threshold for
requiring utilities to report more detailed plant and cost information
for energy storage plant.\182\ The Commission noted that certain
existing schedules in the Form No. 1 have a 10,000 KW threshold.\183\
However, the Commission opined that this threshold may not be
appropriate for new energy storage assets that in

many instances may be rated below 10,000 KW.
---------------------------------------------------------------------------

    \179\ NOPR, FERC Stats. & Regs. ] 32,690 at P 101.
    \180\ NOPR, FERC Stats. & Regs. ] 32,690 at P 106; and Appendix
B Proposed Amendments to Form Nos. 1, 1-F and 3-Q.
    \181\ The text of the NOPR indicated that the schedules pages
were 414-417 and 419-421 for the respective Large and Small Plant
schedules. However, the proposed schedules included in Appendix B of
the NOPR used different page numbers. We clarify that the schedule
page numbers are 414-416 and 419-420, for the respective Large and
Small Plant schedules, as indicated in this Final Rule.
    \182\ NOPR, FERC Stats. & Regs. ] 32,690 at P 103.
    \183\ See Form No. 1, schedule pages 408-409, Generating Plant
Statistics (Large Plants) and schedule pages 410-411, Generating
Plant Statistics (Small Plants). Schedule pages 408-409 require
filers to report more detailed information for generating assets
with a rated capacity of 10,000 KW or more than schedule pages 410-
411, which require less detailed information for generating assets
with a rated capacity of less than 10,000 KW.
---------------------------------------------------------------------------

Comments
    152. Most commenters support the NOPR's forms proposals, and a few
commenters recommend revisions to the forms in addition to those
proposed.\184\ Consistent with its recommendation that the Commission
implement two options to account for energy storage assets, EEI
proposes that the forms provide for disclosing the specific option a
utility is using to account for the assets.\185\ However, because we
are not adopting EEI's recommendation for two accounting options, its
disclosure proposal is unnecessary as utilities will have one uniform
method for accounting for energy storage assets.
---------------------------------------------------------------------------

    \184\ See, e.g., APPA Comments at 5; Beacon Comments at 22-23;
California Storage Alliance Comments at 19; and ESA Comments at 23.
    \185\ EEI Comments at 5.
---------------------------------------------------------------------------

    153. Hydro Association contends that there are shortcomings in the
way the Form No. 1 treats existing pumped storage plants, as they are
now used, and it suggests modifications that it believes will improve
reporting of information on the assets. Hydro Association recommends
that the heading of Line 6 ``Plant Hours Connect to Load While
Generating'' of schedule pages 408-409, Pumped Storage Generating Plant
Statistics (Large Plants), in the Form No. 1 be changed to read ``Plant
Hours Connect to Load.'' \186\ Hydro Association reasons that the total
hours a facility is synchronized and connected to the grid are
important to identify. Hydro Association explains that a facility's
effectiveness is based on its total utilization factor, which Hydro
Association describes as the sum of hours generating, pumping, and
condensing. Hydro Association asserts that this sum should be reported
on Line 6 under its proposed heading. Alternatively, Hydro Association
proffers that if further detail is needed, the heading of Line 6 can
remain as is and two new line items can be added to the schedule to
report pumping and condensing hours.
---------------------------------------------------------------------------

    \186\ Hydro Association Comments at 11.
---------------------------------------------------------------------------

    154. Further, Hydro Association also contends that Line 38,
``Expenses for KWh (line 37/9)'' incorrectly calculates the cost per
kilowatt hour (KWh) of pumped storage operations.\187\ Hydro
Association asserts that the calculation should include energy
generated and energy used for pumping operations. Hydro Association
proposes that Line 38 be revised to read as ``Expenses for KWh (line
37/9+10).''
---------------------------------------------------------------------------

    \187\ Id.
---------------------------------------------------------------------------

    155. TAPS recommends revisions to new schedule pages 414-416,
Energy Storage Operations (Large Plants).\188\ TAPS observes that the
instruction for column heading (l) refers to ``revenues from energy
storage operations'' while the name of the column is ``Revenues from
the Sale of Stored Energy.'' TAPS asserts that because revenues from
energy storage operations can be garnered by means other than from
energy sales, the name of the column should be revised to be consistent
with the instructions of the column or additional columns should be
created, with corresponding instructions, to report other types of
revenues.
---------------------------------------------------------------------------

    \188\ TAPS Comments at 28-29.
---------------------------------------------------------------------------

    156. In regard to the 10,000 KW threshold, California Storage
Alliance states that it believes 10,000 KW is an appropriate threshold
for requiring a difference in the reporting requirements for the
assets.\189\ In contrast, Beacon and ESA recommend a higher threshold
of 20,000 KW.\190\ Beacon and ESA assert that this threshold would
align with the Small Generator Interconnection threshold and the
capacity value for many existing and planned energy storage assets.
---------------------------------------------------------------------------

    \189\ California Storage Alliance Comments at 19.
    \190\ Beacon Comments at 22; and ESA Comments at 22-23.
---------------------------------------------------------------------------

Commission Determination
    157. We generally agree with the premise of Hydro Association's
contention that Line 6 of schedule pages 408-409 could benefit from
additional detail. However, the cost of additional detail must be
weighed against any associated benefit that could result. To this end,
we strive to achieve a balance such that the cost of implementing new
reporting requirements does not excessively exceed the benefits of
implementation. A particularly important benefit to the Commission of
additional detail is that it provides data necessary for the regulation
and review of companies' operations. Hydro Association has neither
explained how information on pumping and condensing hours is needed for
the regulation and review of pumped storage operations nor has it
explained how the information would be beneficial for other uses. Hydro
Association indicates that this information will provide for a measure
of a facility's effectiveness, however, it is not clear that the cost
of requiring this information is on par with any perceived benefits or
that the requirement would not be overly burdensome. Consequently, we
will not adopt Hydro Association's proposal to include the sum of
generating, condensing and pumping on Line 6, nor will we adopt its
alternate proposal to add two new line items to the schedule.
    158. With regard to Hydro Association's contention that Line 38 of
schedule pages 408-409 incorrectly calculates the cost per KWh of
pumped storage operations, this line is not intended to report this
cost, rather it is intended to report the cost per KWh of energy
generated and transmitted to the grid. Line 38 of the schedule includes
a formula that requires filers to divide total production expenses
reported on Line 37 by energy generated and transmitted to the grid
reported on Line 9. Nevertheless, we recognize Hydro Association's
underlying concern that, as a conforming change given the other
accounting requirements in this Final Rule, the schedule should report
this information, including the energy generated and energy used in
pumping, as illustrated in the formula example submitted by Hydro
Association--Line 37/9+10.
    159. We agree that reporting this information on schedule pages
408-409 will help create a more accurate database for benchmarking and
O&M cost studies, and this information also will assist interested
parties', including the Commission's, review of the operations of
pumped storage facilities across the industry. We note that the data
inputs needed to perform the calculation are currently required to be
reported on Lines 9, 10 and 37 of schedule pages 408-409, so this
requirement is not wholly new and the burden on utilities to calculate
and report the information specifically on schedule pages 408-409 is
minimal. Accordingly, the item on Line 38 of schedule pages 408-409 is
revised to read ``Expenses per KWh of Generation (line 37/line 9)'' and
a new Line 39 is added which reads ``Expenses per KWh of Generation and
Pumping (line 37/(line 9 + line 10)).''
    160. TAPS asserts that revenues from energy storage operations can
originate from activities other than energy sales, thus it recommends
that proposed schedule pages 414-416 be revised to provide for other
types of revenues. We agree that there are potentially other activities
that energy storage operators can engage in to generate revenue. For
example, as TAPS noted, an energy storage operator can conceivably earn
revenues from the sale of storage capacity. While we are not aware of
any instances where these types of storage capacity transactions have
occurred, to ensure that the schedule provides

adequate flexibility to allow for the reporting of all revenues from
energy storage operations we will revise the name of the column to read
``Revenues from Energy Storage Operations.'' We will not create
additional columns to report the various types of revenue because the
instructions to the schedule already require filers to disclose this
information in a footnote.
    161. Beacon and ESA recommend that the Commission align the
threshold for detailed reporting in the new schedules with the existing
20,000 KW threshold established in Order No. 2006 for the
interconnection of small generators.\191\ To this end, Beacon and ESA
propose a 20,000 KW threshold as opposed to the 10,000 KW proposed in
the NOPR. However, the 20,000 KW threshold in Order No. 2006 was
established notwithstanding the requirement that small generators
having 10,000 KW or more but less than 20,000 KW that are subjected to
the Commission's accounting and reporting requirements would be
subjected to a higher reporting burden than companies with generators
of less than 10,000 KW. In this instance, the Commission determined
that while there is a need to further remove barriers to participation
in energy markets by establishing terms and conditions under which
public utilities must provide interconnection service, there is also a
parallel need for detailed information on the activities and operations
of companies using these assets in the provisioning of utility
services. Thus, the Commission maintained its existing 10,000 KW
threshold for these small generators.
---------------------------------------------------------------------------

    \191\ Standardization of Small Generator Interconnection
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ]
31,180, order on reh 'g, Order No. 2006-A, FERC Stats. & Regs. ]
31,196 (2005), order on clarification, Order No. 2006-B, FERC Stats.
& Regs. ] 31,221 (2006). This order originally set forth the terms
and conditions under which public utilities must provide
interconnection service to Small Generating Facilities of no more
than 20,000 KW.
---------------------------------------------------------------------------

    162. Beacon and ESA have not provided information that supports a
decreased reporting burden for energy storage assets over 10,000 KW as
compared to the reporting burden of conventional assets that are
currently subject to the 10,000 KW threshold. Nor has Beacon or ESA
provided information that would support increasing the existing 10,000
KW threshold for conventional assets to maintain parity between those
assets and energy storage assets. Their proposal may result in an
unduly discriminatory reporting requirement for energy storage assets
compared to conventional assets, therefore we will not adopt the
recommended 20,000 KW reporting threshold.
    163. We will adopt the NOPR's proposed 10,000 KW threshold as this
amount is neither unduly conservative nor is it overly burdensome. As
we indicated in the NOPR, information that would be reported for energy
storage assets and operations differs little from other data public
utilities maintain under the USofA.\192\ If a utility owns and operates
these energy storage assets, reporting information on them in the
proposed accounts and FERC form schedules should not be burdensome.
---------------------------------------------------------------------------

    \192\ NOPR, FERC Stats. & Regs. ] 32,690 at P 73.
---------------------------------------------------------------------------

    164. Finally, we will amend schedule pages 2-4, 204-207, 320-323,
324a-324b, 326-327, 397, and 401a of the Form Nos. 1, 1-F, and 3-Q as
proposed in the NOPR.\193\ We note that these amendments include
revising schedule page 401a, Electric Energy Account, of the Form No. 1
to change the title of line item 10 to ``Purchases (other than for
Energy Storage)'' and add a new line item 11 ``Purchases for Energy
Storage'' to provide for reporting power purchased for energy storage
operations. These changes require an additional line item on Form No. 1
schedule page 401a to provide for reporting stored energy because total
net sources of energy must equal total disposition of energy as
instructed by the requirement on Line 30 of the schedule. Utilities
with energy storage operations that have stored energy as of the
reporting date of the form must report the amount by megawatt hour in
the schedule so that total net sources of energy is equal to total
disposition of energy reported. Accordingly, as a conforming change, a
new line item titled ``Total Energy Stored'' will be added to schedule
page 401a under the heading ``Disposition of Energy.''
---------------------------------------------------------------------------

    \193\ NOPR, FERC Stats. & Regs. ] 32,690 at Appendix B Proposed
Amendments to Form Nos. 1, 1-F, and 3-Q.
---------------------------------------------------------------------------

5. Other Accounting and Reporting Issues
a. Existing Waivers of Accounting and Reporting Requirements
Commission Proposal
    165. In the NOPR, the Commission proposed that public utilities
currently providing jurisdictional services and recovering costs of the
services under market-based rates that have been granted waiver of the
accounting and reporting requirements and that seek recovery of a
portion of service costs under cost-based rates, be required to forego
the previously issued waivers and account for and report all cost and
operational information to the Commission in accordance with its
accounting and reporting requirements.\194\ In addition, the Commission
also inquired whether there should be a percentage of cost recovery
threshold or other determining factor that triggers the accounting and
reporting obligations in this situation, or should any instance of
multiple cost recovery, regardless of the percentage of a utility's
total costs, trigger the accounting and reporting obligations.
---------------------------------------------------------------------------

    \194\ Id. P 75.
---------------------------------------------------------------------------

Comments
    166. Most commenters agree with the proposal to rescind previously
issued waivers and many of these commenters argue that there should not
be a percentage threshold that triggers the requirement. California
Storage Alliance states that rescinding the waivers will enhance
transparency and facilitate development and monitoring of the cost-
based portion of rates.\195\ Further, California Storage Alliance
states that there should not be a percentage threshold that triggers
accounting and reporting requirements. California Storage Alliance, and
others,\196\ also recommend that in instances where a competitive
solicitation process is used to determine recovery of the cost-based
portion of rates, a public utility should not be required to forego any
reporting and accounting waivers. In further describing their position,
these commenters suggest that a particular ``storage asset may be
capable of simultaneously providing two distinct functions, one
traditionally cost-based use, and another generally market-based.''
They then posit the possibility of a public utility issuing a
competitive solicitation solely for the ``cost-based use.'' Their
comments then assert that the winning bidder would be obligated to
provide the ``cost-based service'' and would be paid through a ``rate-
based mechanism.'' \197\ We also received requests to clarify that the
waivers will only be rescinded if energy storage is involved.\198\
---------------------------------------------------------------------------

    \195\ California Storage Alliance Comments at 10.
    \196\ California Storage Alliance Comments at 10-11; ESA
Comments at 18; and Beacon Comments at 18.
    \197\ Id.
    \198\ Indicated Suppliers Comments at 6-11; EPSA Comments at 13;
and EEI Comments at 33-34.
---------------------------------------------------------------------------

Commission Determination
    167. We will adopt the NOPR proposal requiring public utilities to
forego previously issued accounting and reporting waivers in instances
where the utility seeks to recover costs associated with operation of
an energy storage asset simultaneously under market-based and

cost-based rate recovery mechanisms. We will not impose a percentage
recovery threshold, therefore any cost-based recovery of the cost will
trigger rescission of previously granted accounting and reporting
waivers.
    168. Regarding the comments of California Storage Alliance, ESA,
and Beacon, the Commission clarifies that sellers under a competitive
solicitation that meets the requirements of this Final Rule \199\ will
not be required to forego any prior accounting and reporting waivers.
However, we feel it necessary to explain that the reason for this
outcome differs from what these commenters seem to propose.
---------------------------------------------------------------------------

    \199\ See supra PP 87-90.
---------------------------------------------------------------------------

    169. Their comments seem to indicate a belief that there are some
products that are inherently cost-based and others that are inherently
market-based, and that if a competitive solicitation were held for a
cost-based product, the resulting rates would still be cost-based. We
are not persuaded by these commenters' arguments that products should
be classified as inherently cost-based or market-based. Some potential
sellers of these products will qualify to sell them at market-based
rates because they either lack market power in the relevant product
market, or it has been adequately mitigated. Other sellers who do not
qualify to make market-based sales, because they either have market
power or cannot prove they lack it, will be limited to charging cost-
based rates.
    170. Under the competitive solicitation proposal at bar, proof that
the competitive solicitation meets the requirements of this Final Rule
will demonstrate that a seller qualifies to make market-based sales at
the rates resulting from the solicitation, and thus can avoid having to
justify those rates on a cost-of-service basis. Because such sellers
will still only be making market-based sales, there is no reason to
rescind the prior accounting and reporting waivers that were granted
because they would only be making market-based rate sales. Cost-based
sales of ancillary services have always been an option for third party
sellers, and remain an option for them after issuance of this Final
Rule. However, all of the requirements of cost-of-service regulation,
such as the very accounting and reporting requirements at issue here,
would apply to such sales. We also clarify that the requirement for a
company to forego previously issued accounting and reporting waivers,
in this instance, is only applicable when energy storage is involved.
There may be other occasions when previously issued waivers may be
rescinded however those occasions are outside the scope of this
rulemaking.
b. Definition of Energy Storage Asset or Technology
    171. EEI asks that the Commission clarify the definition of energy
storage assets or technologies that are subject to these accounting and
reporting requirements.\200\ EEI proposes that the Commission define
energy storage assets as ``commercially available technology that is
capable of absorbing energy, storing energy, and subsequently releasing
the energy to the electric system.'' \201\ Further, EEI states that
certain other energy storage assets should be exempted from the Final
Rule, and thus the new accounts, if the function of the asset is so
clearly related to activities properly reflected in existing accounts
such that the asset is not designed to be used as an ``energy storage
asset'' under the definition articulated in this Final Rule. EEI
states, for example, that the following assets or technologies should
be exempted:
---------------------------------------------------------------------------

    \200\ EEI Comments at 26-28.
    \201\ Id.

Batteries used primarily in connection with the control and
switching of electric energy produced and the protection of electric
circuits and equipment that are recorded in the following existing
---------------------------------------------------------------------------
FERC accounts:

Account 315, Accessory Electric Equipment
Account 324, Accessory Electric Equipment (Major Only)
Account 345, Accessory Electric Equipment

Batteries used in connection with controlling station equipment or
for general station purposes that are recorded in the following
existing FERC accounts:

Account 353, Station Equipment

Batteries used in connection with controlling station equipment or
for general station purposes that are recorded in the following
existing FERC accounts:

Account 362, Station Equipment

Compressed air systems used for pneumatic or air tools that are
recorded in the following existing FERC accounts:

Account 316, Miscellaneous Power Plant Equipment
Account 325, Miscellaneous Power Plant Equipment (Major Only)
    Account 346, Miscellaneous Power Plant Equipment
Commission Determination
    172. We agree with EEI that there are certain assets that are
excluded from the scope of this Final Rule, however, we will not adopt
EEI's proposed definition for an energy storage asset or technology.
The definition is too broad and could be interpreted to include
storage-type technologies that are outside the scope of this Final
Rule. As EEI indicated, the assets listed above are the type of assets
that should be excluded. This list is not exhaustive; rather it is an
example of the type of assets and activities served by those assets
that are a baseline indicator of assets that are outside the scope of
the accounting and reporting requirements adopted in this Final Rule.
For the purposes of this Final Rule, an energy storage asset shall be
defined as property that is interconnected to the electrical grid and
is designed to receive electrical energy, to store such electrical
energy as another energy form,\202\ and to convert such energy back to
electricity and deliver such electricity for sale, or to use such
energy to provide reliability or economic benefits to the grid. The
term may include hydroelectric pumped storage and compressed air energy
storage, regenerative fuel cells, batteries, superconducting magnetic
energy storage, flywheels, thermal energy storage systems, and hydrogen
storage, or combination thereof, or any other technologies as the
Commission may determine.\203\
---------------------------------------------------------------------------

    \202\ Electrical energy may be converted to and stored as
several different forms of energy such as chemical, mechanical, and
thermal energies.
    \203\ Although hydroelectric pumped storage is an energy storage
technology in accordance with our definition, the accounting and
reporting requirements of this rulemaking do not apply to the
assets, notwithstanding the revisions to schedule pages 408-409. As
we indicated previously, our existing accounting and reporting
requirements for pumped storage sufficiently accommodate pumped
storage assets and operations.
---------------------------------------------------------------------------

c. Incorporating Energy Storage Plant Accounts Into Existing Formula
Rates
    173. EEI requests that the Commission pre-authorize inclusion of
the new energy storage plant and O&M expense accounts in existing
formula rates without the need for separate, company-specific section
205 proceedings.\204\ EEI contends that many jurisdictional utilities
that own and operate energy storage technologies account for the assets
in existing accounts that are incorporated in formula rates. EEI states
that to the extent the new accounts require a revision to existing
filed rates, the Commission should allow such changes to be filed in a
compliance filing in this proceeding.
---------------------------------------------------------------------------

    \204\ EEI Comments at 32-33.
---------------------------------------------------------------------------

Commission Determination
    174. We agree with EEI that utilities currently owning and
operating these assets are using existing accounts and reporting
schedules. Moreover, in many instances these accounts are incorporated
in the companies' formula rate templates and costs reported in the
accounts are through operation of the formula rate included in rate

determinations. For some of these companies, transferring amounts from
an existing plant account under a particular functional classification
to a new energy storage plant account under the same functional
classification may involve a relatively straight-forward transfer of
cost. In this type of situation, a compliance filing will provide
adequate transparency to allow interested parties, including the
Commission, to review amounts being transferred from one account to
another and also to establish the incorporation of the new energy
storage plant and O&M expense accounts in the formula rate tariff.
However, a compliance filing may not be suitable for all situations.
    175. For example, in instances where a company intends on recording
the costs of an energy storage asset to multiple plant accounts in
accordance with a plan to support multiple functions using the asset, a
compliance filing may not provide for an adequate review of the many
variables involved that can impact the determination of the appropriate
allocation of the cost and rates charged based on the allocation.
Moreover, if a company intends on recovering capital and O&M costs of
the asset simultaneously under cost-based and market-based rate
recovery mechanisms, a compliance filing would not provide sufficient
notice or review of the cost to be recovered under the two rate
mechanisms. Consequently, because a compliance filing is not
appropriate for all situations, we will limit approval of its use to
companies that are transferring amounts from an existing plant account
under a particular functional classification to a new energy storage
plant account under the same functional classification. Transfers of
the costs to other plant accounts after this initial compliance filing
shall be subject to the requirements of Electric Plant Instruction
No.12, Transfers of Property,\205\ as proposed in the NOPR,\206\ and
the provisions of utilities' formula rate tariffs, as applicable.
Utilities that do not qualify to use the compliance filing process must
first receive approval from a relevant rate regulator to revise their
existing formula rate tariffs to incorporate the new energy storage
accounts.
---------------------------------------------------------------------------

    \205\ 18 CFR Part 101 (2012).
    \206\ NOPR, FERC Stats. & Regs. ] 32,690 at P 82.
---------------------------------------------------------------------------

d. Depreciation Rates for Energy Storage Assets
Commission Proposal
    176. In the NOPR, the Commission proposed that the cost of energy
storage assets be charged to depreciation expense using the
depreciation rates developed for each function.\207\
---------------------------------------------------------------------------

    \207\ Id.
---------------------------------------------------------------------------

Comments
    177. Commenters generally support this proposal. For example,
Beacon and ESA acknowledge support for the proposal.\208\ EEI
recommends that instead of requiring depreciation rates to be based on
a utility's existing rate for a particular function, the Commission
allow utilities to set initial depreciation rates for new energy
storage battery equipment based on the manufacturer's estimated useful
life, prior to the utilities receiving approval of new depreciation
rates through a rate proceeding where new approved rates are ordered
for these accounts.\209\ EEI explains that the current life of storage
batteries is expected to be approximately 10 to 15 years and it
contends that this expected life can be substantially less than the
life used to calculate the depreciation rate for the function the asset
may be classified under.
---------------------------------------------------------------------------

    \208\ Beacon Comments at 19; and ESA Comments at 19.
    \209\ EEI Comments at 32.
---------------------------------------------------------------------------

Commission Determination
    178. For accounting purposes, utilities are required to use
percentage rates of depreciation that are based on a method of
depreciation that allocates in a systematic and rational manner the
service value of depreciable property over the service life of the
property.\210\ Where composite depreciation rates are used, the rate
should be based on the weighted average estimated useful lives of
depreciable property comprising the composite group. Furthermore,
estimated service lives of depreciable property must be supported by
engineering, economic, or other depreciation studies.\211\ To the
extent that an energy storage asset, such as a battery, has an
estimated useful service life that is supported by engineering,
economic, or other studies of the manufacturer or utility, the
depreciation rate derived from such study must result in a systematic
and rational allocation of the asset's costs over the estimated service
life. Therefore, for accounting purposes, utilities may set initial
rates for new energy storage assets based on manufacturer or utility
estimated service lives that are supported by engineering, economic or
other studies. In addition, as we indicated above, utilities should use
a single depreciation rate for an energy storage asset regardless the
number of functions to which the costs of the asset are allocated.\212\
---------------------------------------------------------------------------

    \210\ General Instruction No. 22, Depreciation Accounting, 18
CFR Part 101 (2012).
    \211\ Id.
    \212\ See supra P 128.
---------------------------------------------------------------------------

e. Jurisdictional Authority
    179. The California PUC warns that the Commission's authority over
the accounting and reporting for energy storage assets should not limit
or infringe upon States' jurisdictional authority over the assets as
the majority of the assets are likely to be financed pursuant to state
jurisdictional procurement authority.\213\
---------------------------------------------------------------------------

    \213\ California PUC Comments at 8.
---------------------------------------------------------------------------

Commission Determination
    180. The accounting and reporting requirements of this rulemaking
are not intended to limit or infringe upon States' jurisdictional
authority. Pursuant to section 301(a) of the Federal Power Act (FPA),
the Commission has authority to prescribe a system of accounts and
rules and regulations that are applicable in principle to all licensees
and public utilities subject to the Commission's accounting and
reporting requirements.\214\ The Commission may determine the accounts
in which particular outlays and receipts will be entered, charged or
credited. The amendments to the accounting and reporting requirements
are in accordance with the authority bestowed upon the Commission under
the FPA and as such do not preempt or affect any jurisdiction a State
commission or other State authority may have under applicable State and
Federal law or limit the authority of a State commission in accordance
with State and Federal law.
---------------------------------------------------------------------------

    \214\ 16 U.S.C. 825(a).
---------------------------------------------------------------------------

f. Implementation Date
    181. EEI requests clarification of the implementation date of the
proposed accounting and reporting requirements. EEI states that it
believes assets and related amounts recorded in other accounts under
the existing accounting requirements should be reclassified to the new
energy storage accounts provided the asset meets the definition of an
energy storage asset.\215\ However, EEI argues that it would not be
beneficial or cost effective to require utilities to retroactively
amend prior year reports to implement the requirements. Therefore, EEI
recommends that the accounting and reporting requirements be effective
prospectively only.
---------------------------------------------------------------------------

    \215\ EEI Comments at 28-29.

---------------------------------------------------------------------------

Commission Determination
    182. While we agree with EEI that it may not be cost effective to
require utilities with energy storage assets to retroactively amend
prior year reports to implement the accounting and reporting
requirements of this Final Rule; we disagree with EEI's contention that
it would not be beneficial to interested parties desiring more
transparent reporting of the costs associated with energy storage
operations. In these instances, the Commission must weigh the perceived
cost of implementing a requirement against the expected benefits of
implementation. Although requiring utilities with energy storage assets
to retroactively implement the requirements would provide a more
transparent historical record of these utilities energy storage
operations, this information would not be necessary to provide
oversight of these utilities energy storage operations going forward.
Moreover, it is not clear that the benefits of retroactive
implementation are sufficient to justify the cost. Consequently, we
will not require utilities to retroactively implement the accounting
and reporting requirements.
    183. Utilities subject to the Commission's accounting and reporting
requirements must implement the requirements as of January 1, 2013.
Utilities are not required to adjust prior year, comparative
information reported in 2013 Form Nos. 1 and 1-F that must be filed by
April 18, 2014, nor are they required to adjust prior year, comparative
information reported in 2013 Form No. 3-Q reports. However, a footnote
disclosure must be provided describing any amounts transferred from an
existing account to a new energy storage account.
    184. Due to outdated software, discussed in more detail below, the
adopted new and revised schedules of Form Nos. 1, 1-F and 3-Q will not
be available for use as of the effective date of this Final Rule.
Consequently, utilities with energy storage assets and those that
acquire the assets at a later date must continue or begin, as
appropriate, using the existing form schedules to report energy storage
assets pending availability of the new and revised schedules.
Furthermore, we direct the Chief Accountant to issue interim accounting
and reporting guidance for utilities to report to the Commission the
costs of energy storage operations contemplated in this Final Rule
until the new and revised schedules are available.
    185. Regarding the reporting software issues, the Commission's
forms software applications are built with Visual FoxPro development
tools and must be installed on a Windows-based computer. Microsoft, the
Visual FoxPro vendor, announced in 2007 that it would no longer sell or
issue new versions of Visual FoxPro and would provide support for it
only through 2015. Also, over time, the Commission has found that it is
difficult to update tables in the software to accommodate revisions to
existing schedules and add new schedules to the forms because Visual
FoxPro does not allow data tables to exceed two gigabytes. These data
size limitations will soon restrict the Commission's ability to add
data fields in the forms. These limitations make the forms software
application outmoded, ineffective, and unsustainable.
    186. Pursuant to Sections 141.1, 141.400, and 385.2011 of the
Commission's Regulations,\216\ Form Nos. 1 and 3-Q must be submitted
using electronic media.\217\ Due to technology changes that will render
the current forms filing process outmoded, ineffective, and
unsustainable, the Commission will discontinue the use of Commission-
distributed software to file forms. Moreover, because of the software
limitations, the new and revised form schedules will not be available
to utilities with energy storage assets and those that acquire the
assets later as of the effective date of this Final Rule. Consequently,
due to the time lag between implementation of the accounting and
reporting requirements adopted here and the availability of a filing
platform that accommodates the Commission's reporting forms, utilities
should submit their 2013 Form No. 1 and 2014 Form No. 3-Qs using the
existing forms filing process until an updated filing platform is made
available by the Commission. Commission staff will issue appropriate
notices and hold technical conferences if necessary concerning changes
to the filing process.\218\
---------------------------------------------------------------------------

    \216\ 18 CFR 141.1, 141.400, and 385.2011 (2012), respectively.
    \217\ Form No. 1-F filers may also submit the reports
electronically; however, the Commission's regulations do not
explicitly require these filers to submit the reports
electronically. See 18 CFR 141.2 (2012).
    \218\ Filers with energy storage assets and operations may be
required to amend and refile their 2013 Form Nos. 1 and 1-F and 2014
Form No. 3-Q to report energy storage operation information in the
schedules adopted in this final rule as a result of the anticipated
new filing platform. However, these filers will not be required to
amend and refile previously submitted 2013 Form No. 3-Qs.
---------------------------------------------------------------------------

D. Other Issues

    187. Some commenters raised issues beyond the scope of the NOPR.
WSPP argues that public utility participation in a competitive market
for ancillary services is hindered by certain OATT requirements
applicable to network transmission customers. Specifically, WSPP refers
to the requirement that network resources be undesignated as such, and
thus lose their firm network transmission service, when they are
committed to third-party sales instead of network load obligations.
WSPP points to timing mismatches between the operational needs of
ancillary service use and the undesignation requirements of the OATT as
the main source of this issue. It argues that the Commission previously
acknowledged these issues in connection with contingency reserves under
the Southwest Reserve Sharing Group.\219\ WSPP argues that this
undesignation requirement hinders robust participation from network
transmission customers, including the transmission providers
themselves, in ancillary service markets.
---------------------------------------------------------------------------

    \219\ WSPP Comments at 19-21.
---------------------------------------------------------------------------

    188. EEI makes similar arguments with respect to the network
resource undesignation requirements, and asks that the Commission
remain receptive to utility-specific requests for flexibility.\220\
---------------------------------------------------------------------------

    \220\ EEI Comments 21-22.
---------------------------------------------------------------------------

    189. Hydro Association and Public Interest Organizations argue that
the Commission should develop policies that facilitate long-term
contracts with energy storage owners. Hydro Association asserts that
the Commission should solicit further input on policies that would
allow RTO, ISO, and stand-alone transmission providers to enter into
long-term contracts with energy storage owners.\221\ Public Interest
Organizations make similar arguments.\222\
---------------------------------------------------------------------------

    \221\ Hydro Association Comments at 4-6.
    \222\ Public Interest Organizations Comments at 11.
---------------------------------------------------------------------------

    190. Shell Energy suggests that the current distinction between
Energy Imbalance and Generator Imbalance is unnecessary, and that the
two services should be combined into a single product. Shell Energy
cites similar definitions in the EQR Data Dictionary, and states that
treating the two services as different products provides little
benefit, creates unnecessary complexity and may result in confusion and
regulatory uncertainty.\223\
---------------------------------------------------------------------------

    \223\ Shell Energy Comments at 3-4.
---------------------------------------------------------------------------

    191. Shell Energy also urges the Commission to recognize
``Balancing Reserves'' as a separate energy and capacity product used
to firm variable energy resources. Shell Energy argues that such a
product would be differentiated from ancillary services because, unlike
ancillary services, it would not be limited to addressing

contingencies. Shell Energy seeks clarification that such a product
would not be considered an ancillary service, and thus would not be
subject to the Avista restrictions. Rather it would be subject to a
seller's existing authorization to sell energy and capacity at market-
based rates.\224\ EPSA makes similar arguments regarding the need for a
new, non-contingency-related balancing reserves product.\225\ While
WSPP's comments do not specifically seek to identify a new product
based on whether or not it can be used for issues other than
contingencies, as do Shell Energy and EPSA, WSPP nevertheless makes
certain similar arguments in part of its comments. WSPP asserts that
sellers may not always wish to sell specific ancillary services, but
rather may wish to sell ``flexible capacity'' products capable
generally of fulfilling multiple OATT schedules. While its comments are
not entirely clear on this point, WSPP could be interpreted to argue
that the Commission should recognize flexible capacity as a product
different from ancillary services.\226\
---------------------------------------------------------------------------

    \224\ Shell Energy Comments at 5-6.
    \225\ EPSA Comments at 10-11.
    \226\ WSPP Comments at 7.
---------------------------------------------------------------------------

    192. AWEA requests that the Commission explore the role that
dynamic transfer capability, or lack thereof, plays in protecting
against exertion of market power. AWEA argues that lack of dynamic
transfer capability severely constrains competitive ancillary service
markets in many parts of the country. AWEA suggests that the Commission
could require transmission providers to analyze, inventory, and market
dynamic scheduling capability on a non-discriminatory basis.\227\
---------------------------------------------------------------------------

    \227\ AWEA Comments at 3.
---------------------------------------------------------------------------

    193. Powerex argues that there may be certain locations where there
is sufficient market liquidity such that a seller should be able to
make ancillary service sales without performing a separate market power
analysis. Powerex believes that these locations might be defined by
some measure of market liquidity, or by a specific minimum number of
potential sellers, and gives as examples the trading hubs of Mid-
Columbia, California-Oregon Border, Palo Verde, Four Corners, and Mead.
Powerex does not suggest specific liquidity metrics, but does have
suggestions regarding the appropriate minimum number of potential
suppliers. It suggests that third-party sales to a transmission
provider could be deemed competitive any time there are: (1) At least
three potential suppliers, each capable of providing 100 percent of the
buyer's needs for the ancillary service in question; or (2) at least
five potential suppliers, each capable of meeting a significant portion
(e.g., at least 25 percent) of the buyer's need for the ancillary
service in question.
Commission Determination
    194. With respect to WSPP's request for more flexibility on the
requirements for network resource undesignation, the Commission
declines to consider such changes on a generic basis at this time. This
undesignation requirement is intended to ensure that network
transmission customers cannot inappropriately withhold firm
transmission capacity from potential competitors. While WSPP is correct
that the Commission has permitted limited deviations from this
requirement in connection with established reserve sharing groups, we
are not persuaded that a more general relaxation is justified. WSPP
indicates in its comments that a public utility is unable to
undesignate the network resource providing the energy associated with
the provision of ancillary services because the unit providing the
energy may differ from the unit providing the capacity. This suggests
that the public utility will be using transmission service from a unit
that is different from the unit for which transmission service has been
reserved. Thus, WSPP is essentially asking the Commission to permit a
public utility transmission provider to implicitly use firm point-to-
point transmission service without reserving it or paying for it. The
Commission has previously expressly prohibited this practice and
nothing in the comments suggests that the Commission's concerns are no
longer valid.\228\ Further, participating in a reserve sharing group
differs from making third-party market sales of ancillary services. A
reserve sharing group essentially expands a public utility transmission
provider's native load obligations to serving other load serving
entities' native load in the event of a contingency with like
protection in return. Permitting a public utility transmission provider
to deliver energy associated with its reserve sharing group obligations
without undesignating the resource providing the energy is an
appropriate recognition of the network service elements of reserve
sharing arrangements. On the other hand, market sales of ancillary
services must be delivered using point-to-point transmission service.
---------------------------------------------------------------------------

    \228\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 834.
---------------------------------------------------------------------------

    195. With respect to the requests of Hydro Association and Public
Interest Organizations to facilitate long-term contracting with energy
storage owners, we see no basis for any additional action at this time.
In bilateral markets, assuming that parties are able to avoid the
Avista restrictions through use of one of the options provided in this
rule, potential buyers including transmission owners and sellers are
free to transact through contracts of whatever length they find
mutually agreeable.
    196. Shell Energy's suggestion that Energy Imbalance and Generator
Imbalance services be combined into a single product is beyond the
scope of this rulemaking, and Shell Energy's arguments in support of
this idea do not rise to a level concrete enough to justify such an
expansion at this time.
    197. With respect to Shell Energy and EPSA's comments regarding
recognition of non-contingency-related balancing reserves as separate
from ancillary services, and WSPP's similar discussion of ``flexible
capacity,'' we clarify that sales of energy and capacity at market-
based rates are permissible, provided the buyer may not use the
purchases to meet its OATT obligations to provide Regulation and
Frequency Response or Reactive Supply and Voltage Control ancillary
services.
    198. AWEA's comments regarding dynamic transfer capability raise
issues beyond the scope of this rulemaking, which have not been fully
explored in this proceeding, and whose resolution is not necessary to
the completion of this rulemaking. Accordingly, the Commission will not
direct changes with respect to dynamic scheduling or dynamic transfer
capability at this time.
    199. Regarding Powerex's argument for development of a new market
liquidity screen for ancillary service market power, we decline to
attempt such development at this time. The record does not currently
support either development of a generic market liquidity metric, or the
particular minimum participant number thresholds proposed by Powerex.
We remain open to a more detailed discussion of these ideas in the
future if needed, but at this time will move forward with the rule
changes contained elsewhere in this Final Rule, which we hope will
reduce the need to develop alternative market power analyses.

III. Summary of Compliance and Implementation

BILLING CODE 6717-01-P

[GRAPHIC] [TIFF OMITTED] TR30JY13.004

[GRAPHIC] [TIFF OMITTED] TR30JY13.005

BILLING CODE 6717-01-C
    201. While the authorization is effective as of the date specified
in this Final Rule, sellers should file this tariff revision the next
time they make a market-based rate filing with the Commission. To the
extent sellers do not currently have this provision in their tariff but
wish to make third-party sales of ancillary services, they should
include this revised provision in their tariff the next time they make
a market-based rate filing with the Commission.
    202. With regard to sales of Operating Reserves, as discussed
above, both sellers that have a market-based rate tariff on file and
applicants seeking new market-based rate authority must satisfactorily
make the required showing and receive Commission authorization before
making sales of Operating Reserve-Spinning and Operating Reserve-
Supplemental to a public utility that is purchasing Operating Reserve-
Spinning and Operating Reserve-Supplemental to satisfy its own open
access transmission tariff requirements to offer ancillary services to
its own customers.
    203. With respect to the Final Rule's reforms to provide greater
transparency with regard to reserve requirements for Regulation and
Frequency Response, within 30 days from the effective date of this
Final Rule, we require each public utility transmission provider to
revise its OATT Schedule 3 consistent with the revised Schedule 3 in
accordance with Appendix B to this Final Rule.
    204. With respect to Final Rule's reforms to our accounting and
reporting regulations, utilities subject to these requirements must
implement the requirements as of January 1, 2013. Utilities are not
required to adjust prior year, comparative information reported in 2013
Form Nos. 1 and 1-F that must be filed by April 18, 2014, nor are they
required to adjust prior year, comparative information reported in 2013
Form No. 3-Q reports. However, a footnote disclosure must be provided
describing any amounts transferred from an existing account to a new
energy storage account.
    205. Due to outdated software, discussed in more detail in the body
of this Final Rule, the adopted new and revised schedules of Form Nos.
1, 1-F and 3-Q will not be available for use as of the effective date
of this Final Rule. Consequently, utilities with energy storage assets
and those that acquire the assets at a later date must continue or
begin, as appropriate, using the existing form schedules to report
energy storage assets pending availability of the new and revised
schedules.

IV. Information Collection Statement

    206. The following collections of information contained in this
Final Rule have been submitted to the Office of Management and Budget
(OMB) for review under Section 3507(d) of the Paperwork Reduction Act
of 1995.\229\ OMB's regulations require approval of certain information
collection requirements imposed by agency rule.\230\ Upon approval of a
collection of information, OMB will assign an OMB control number and an
expiration date. Respondents subject to the filing requirements of a
rule will not be penalized for failing to respond to these collections
of information if the collections of information do not display a valid
OMB control number.
---------------------------------------------------------------------------

    \229\ See 44 U.S.C. 3507(d).
    \230\ 5 CFR 1320.11 (2012).
---------------------------------------------------------------------------

    Burden Estimate: The additional estimated public reporting burdens
and costs for the reporting requirements in this Final Rule are as
follows.\231\
---------------------------------------------------------------------------

    \231\ In the NOPR, the Commission proposed changes to FERC-919
(related to the `20 percent screen'). The FERC-919 is not affected
by the Final Rule. In addition, changes to FERC-516, which were not
contained in the NOPR, are included in the Final Rule.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Change in  the total
                                                              Change in the number                            annual hours  for      Estimated  annual
                                                               of hours per filing        Filings per          this  collection       cost  (averaging
          Data collection            Number of  respondents        (averaging         respondent  per year        (averaging        implementation over
                                               (a)             implementation over            (c)            implementation over    Yrs. 1-3)  (at $120/
                                                              Yrs. 1-3) \232\  (b)                           Yrs. 1-3)  (aXbXc=d)    hr.)  (dX$120/hr.)
                                                                     (hrs.)                                         (hrs.)                  ($)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Form No. 1.........................  210...................  7 [3 hrs. (one-time     1....................  1,470................  176,400
                                                              implementation in
                                                              Year 1), plus 6 hrs.
                                                              annually].
Form No. 1-F.......................  5.....................  7 [3 hrs. (one-time     1....................  35...................  4,200
                                                              implementation in
                                                              Year 1), plus 6 hrs.
                                                              annually].
Form No. 3-Q.......................  213...................  1.....................  3....................  639..................  76,680
FERC-917 [includes one-time filing   132...................  17.33 averaged over     1....................  2,288 averaged over    274,560 averaged over
 of Pro forma open-access                                     Years 1-3 [4 hrs. one-                         Years 1-3.             Years 1-3
 transmission tariff (OATT) & data                            time in Yr. 1, plus
 sharing] \233\.                                              an average recurring
                                                              burden in Years 1-3
                                                              of 16 hrs.].
FERC-516...........................  no change.............  no change.............  no change............  no change............  no change

FERC-717 (OASIS posting under 18     176...................  1.....................  1....................  176..................  9,889 \234\
 CFR 37.6k).
    Total..........................  ......................  ......................  .....................  4,608 (averaged over   $541,729 (averaged
                                                                                Years 1-3).            over Years 1-3)
--------------------------------------------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------

    \232\ For the Forms 1 and 1-F, the one-time implementation
burden in Year 1 is estimated to be 3 hours per respondent. However,
for the burden and cost estimates, we are averaging those additional
3 hours over Years 1-3, giving an average annual one-time
implementation burden of 1 hour. That 1 hour is in addition to the
normal annual filing burden of 6 hours each, giving an average
annual estimate of 7 hours for Forms 1 and 1-F, for Years 1-3.
    \233\ This includes the one-time refiling of OATT Schedule 3
(estimated average of 4 hours per utility respondent), and if
requested, the utility's sharing data and a narrative description
with its self-supplying customer(s) (estimated average of 4 customer
requests per utility respondent per year, taking 4 hours per
request). The estimated annual burden per utility is
     Year 1: 4 hrs. (for one-time refiling) + (4 requests *
4 hrs.), giving an estimate of 20 hrs. per utility
     Years 2 and 3, each: 4 requests * 4 hrs., giving 16
hrs. per utility per year. When the one-time implementation burden
(of 4 hours) is averaged over Years 1-3, the annual additional
burden per utility is 17.33 hours.
    \234\ Based on the 2012 data from the Bureau of Labor Statistics
at http://bls.gov/oes/current/naics2_22.htm, the hourly cost of
salary plus benefits would be $56.19.
---------------------------------------------------------------------------

    In paragraph 96, the Commission is requiring that any third-party
seller seeking to sell ancillary services to a public utility
transmission provider through a competitive solicitation will need to
demonstrate compliance with the competitive solicitation requirements
of this rule, through a filing under section 205 of the Federal Power
Act. This requirement for submittal in a section 205 filing would be
made under FERC-516 (OMB Control No. 1902-0096). The filing would be
submitted by the seller to the Commission prior to commencement of
service under the third-party ancillary service sales agreement that
results from the competitive solicitation. The filing will include both
the actual sales agreement and a narrative description of how the
buyer's competitive solicitation meets the requirements of this Final
Rule. Meeting those requirements demonstrates the justness and
reasonableness of the resulting rate. If the seller did not have this
option to sell under the competitive solicitation, the seller could not
use market-based rates and would have to either submit an application
for cost-based rates under FERC-516 or an application seeking waiver of
the Avista restrictions on a case-by-case basis.\235\ The Commission
believes that the burden associated with the new requirements is far
less burden than a full cost-of-service rate filing and approximately
the same burden as the burden associated with an Avista waiver filing.
In addition, the numbers of respondents and filings are not expected to
change significantly. Therefore, no changes are proposed to the burden
or number of responses for FERC-516.
---------------------------------------------------------------------------

    \235\ See, e.g., Powerex, 125 FERC ] 61,179 (2008).
---------------------------------------------------------------------------

    Title: FERC Form No. 1, ``Annual Report of Major Electric
Utilities, Licensees, and Others;'' FERC Form No. 1-F, ``Annual Report
for Nonmajor Public Utilities and Licensees;'' FERC Form No. 3-Q,
``Quarterly Financial Report of Electric Utilities, Licensees and
Natural Gas Companies;'' FERC-917, ``Non-discriminatory Open Access
Transmission Tariff;'' FERC-516, '' Electric Rate Schedules and Tariff
Filings,'' and FERC-717, ``Open Access Same-Time Information System and
Standards for Business Practices & Communication Protocols.''
    Action: Proposed revisions to information collections.
    OMB Control Nos.: 1902-0021 (FERC Form No. 1); 1902-0029 (FERC Form
No. 1-F); 1902-0205 (FERC Form No. 3-Q); 1902-0233 (FERC-917), 1902-
0096 (FERC-516), and 1902-0173 (FERC-717).
    Respondents: Businesses or other for profit and/or not-for-profit
institutions.
    Frequency of responses: Annually (FERC Form Nos. 1 and 1-F, and
FERC-717); quarterly (FERC Form No. 3-Q); and as needed (FERC-917 and
FERC-516).
    Necessity of the Information: The final rule amends the
Commission's regulations to reflect changes that are occurring in the
electric industry due to the availability of new energy storage
technologies that are being used in the provision of large-scale
utility operations. These technologies are providing services that were
typically provided by traditional single-purpose production,
transmission and distribution resources. The addition of these new
plant accounts and new and amended reporting forms are intended to
enhance transparency and provide detailed information on transactions
and events affecting public utilities and licensees that file reports
with the Commission. The accounting regulations currently found in the
USofA and related reporting requirements capture financial and
operational information along traditional primary business functions
but do not provide sufficient detailed information concerning energy
storage operations, and in particular, the costs incurred by
organizations using these resources to simultaneously provide multiple
utility services with a single asset. The addition of these accounts is
intended to improve the transparency, completeness and consistency of
accounting practices for the cost of assets, the expenses incurred in
providing services, along with revenues collected. Without specific
instructions and accounts for recording and reporting the above
transactions and events, inconsistent and incomplete accounting and
reporting will result.
    Internal Review: The Commission has reviewed the requirements
pertaining to the USofA and to the reports it prescribes and determined
that the proposed amendments are necessary because the Commission needs
to establish uniform accounting and reporting requirements for the
costs of utility assets and the expenses incurred for providing
services as part of its operations.
    These requirements conform to the Commission's need for efficient
information collection, communication, and management within the energy
industry. The Commission has assured itself, by means of internal
review, that there is specific, objective support for

the burden estimates associated with the information collection
requirements.
    Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director], email:
<EMAIL_ADDRESS>Phone<PHONE_NUMBER>, fax:<PHONE_NUMBER>.
    Comments on the collection of information and the associated burden
estimates in the rule should be sent to the Commission in this docket
and may also be sent to the Office of Information and Regulatory
Affairs, Office of Management and Budget, Washington, DC 20503
[Attention: Desk Officer for the Federal Energy Regulatory Commission].
For security reasons, comments to OMB should be submitted by email to:
<EMAIL_ADDRESS>Please refer to OMB Control Nos. 1902-
0021 (FERC Form No. 1), 1902-0029 (FERC Form No. 1-F), 1902-0205 (FERC
Form No. 3-Q), and 1902-0233 (FERC-917), 1902-0096 (FERC-516), and
1902-0173 (FERC-717) and Docket Number RM11-24.

Environmental Analysis

    207. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\236\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Final Rule under
section 380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale subject to the Commission's
jurisdiction, plus the classification, practices, contracts, and
regulations that affect rates, charges, classifications, and
services.\237\
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    \236\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs.
Regulations Preambles 1986-1990 ] 30,783 (1987).
    \237\ 18 CFR 380.4(a)(15) (2012).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

    208. The Regulatory Flexibility Act of 1980 (RFA) \238\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. The RFA
mandates consideration of regulatory alternatives that accomplish the
stated objectives of a proposed rule and that minimize any significant
economic impact on a substantial number of small entities. The Small
Business Administration's (SBA) Office of Size Standards develops the
numerical definition of a small business.\239\ The SBA has established
a size standard for electric utilities, stating that a firm is small
if, including its affiliates, it is primarily engaged in the
transmission, generation and/or distribution of electric energy for
sale and its total electric output for the preceding twelve months did
not exceed four million megawatt hours.\240\ The rule applies
exclusively to public utilities that own, control, or operate
facilities for transmitting electric energy in interstate commerce and
not electric utilities per se. Based on the filers of the 2011 annual
FERC Form No. 1 and Form No. 1-F, as well as the number of companies
that have obtained waivers, we estimate that 44 entities (20 percent of
the filers) affected by this proposed rule are ``small.'' For each of
the 44 ``small'' entities, the Commission estimates an additional
annual burden of only ten hours (seven hours for the annual Form 1 or
Form 1-F (averaging implementation over years 1-3), plus one hour per
quarter for the Form 3-Q). The Commission believes this rule will not
have a significant economic impact on a substantial number of small
entities, and therefore no regulatory flexibility analysis is required.
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    \238\ 5 U.S.C. 601-612.
    \239\ 13 CFR 121.101 (2011).
    \240\ 13 CFR 121.201, Sector 22, Utilities.
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VII. Document Availability

    209. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
    210. 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.
    211. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>    Effective Date and Congressional Notification. These regulations
are effective November 27, 2013. The Commission has determined, with
the concurrence of the Administrator of the Office of Information and
Regulatory Affairs of OMB, that this rule is not a ``major rule'' as
defined in section 351 of the Small Business Regulatory Enforcement
Fairness Act of 1996.

List of Subjects

18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and
recordkeeping requirements

18 CFR Part 101

    Electric power, Electric utilities, Uniform System of Accounts.

    By direction of the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission amends Parts 35
and 101, Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority:  16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.

0
2. Amend Sec.  35.37 by revising paragraph (c)(1) to read as follows:

Sec.  35.37  Market power analysis required.

* * * * *
    (c)(1) There will be a rebuttable presumption that a Seller lacks
horizontal market power with respect to sales of energy, capacity,
energy imbalance, and generator imbalance services if it passes two
indicative market power screens: A pivotal supplier analysis based on
annual peak demand of the relevant market, and a market share analysis
applied on a seasonal basis. There will be a rebuttable presumption
that a Seller lacks horizontal market power with respect to sales of
operating reserve-spinning and operating reserve-supplemental services
if the Seller passes these two indicative market power screens and
demonstrates in its market-based rate application how the scheduling
practices in its region

support the delivery of operating reserve resources from one balancing
authority area to another. There will be a rebuttable presumption that
a seller possesses horizontal market power with respect to sales of
energy, capacity, energy imbalance, generator imbalance, operating
reserve-spinning, and operating reserve-supplemental services if it
fails either screen.
* * * * *

0
3. Amend Sec.  35.38 as follows:
0
a. Paragraph (a) is revised.
0
b. Paragraph (b) introductory text is revised.
0
c. Paragraph (c) is added.
    The revisions and addition read as follows:

Sec.  35.38  Mitigation.

* * * * *
    (a) A Seller that has been found to have market power in generation
or ancillary services, or that is presumed to have horizontal market