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

    \115\ E.g., Avista; AWEA; RenewElec; Vote Solar.
    \116\ E.g., EEI; Duke; Idaho Power; Southern.
---------------------------------------------------------------------------

    87. However, Avista states that there are positives and negatives
to either maintaining hourly settlement with intra-hour scheduling or
modifying settlement intervals to coincide with intra-hour scheduling
intervals. Avista asserts that conforming intra-hour schedules and
imbalance settlement at 15-minute increments for all transmission
schedules would result in alignment of scheduling and imbalance billing
for all transactions and reduce gaming potential. Avista argues that
the potential for gaming by transmission customers through the
overcorrection of schedules in order to minimize imbalance charges may
require a public utility transmission provider to carry regulation
reserves in excess of what is needed. Midwest ISO agrees, citing a
report from its Independent Market Monitor indicating that large
changes in Net Scheduled Interchange caused by 15-minute intra-hour
scheduling could lead to price volatility and negative operational
impacts.\117\ Avista and Midwest ISO further state that conforming
imbalance settlement with intra-hour schedules may require substantial
and potentially costly office system changes, additional operations
staff, and other costs incurred through the communication, metering,
and storage of all customer data at 15-minute increments.
---------------------------------------------------------------------------

    \117\ Midwest ISO (Potomac Economics, 2008 State of the Market
Report for the Midwest ISO, Docket No. ZZ09-4-000 at 169 [141] (June
21, 2009)).
---------------------------------------------------------------------------

    88. Some commenters contend that intra-hour scheduling only governs
the scheduling of flows on the transmission system and, by itself, does
not necessarily affect the frequency with which generators are
dispatched.\118\ AWEA and Invenergy Wind agree that a transition to
sub-hourly dispatch is the key for increasing the flexibility of the
power system and for reducing the amount of reserves that must be held,
which in turn will reduce costs for consumers and enable cost effective
integration of VERs. Commenters recommend that the Commission require
public utility transmission providers to implement a sub-hourly, real-
time energy exchange that provides automated generation dispatch (such
as an Efficient Dispatch Toolkit or the Energy Imbalance Market as
adopted by the Southwest Power Pool and currently being studied in
WECC). In AWEA's view, a market for sub-hourly energy would allow for
netting of sub-hourly deviations and would provide price signals to
incent greater sub-hourly flexibility.
---------------------------------------------------------------------------

    \118\ E.g., AWEA; CEERT; Invenergy Wind.
---------------------------------------------------------------------------

    89. AWEA acknowledges that changes to dispatch protocols and
expansion of market options are being considered in regional efforts,
but argues that progress is uncertain and unlikely to come to fruition
in the near term. Iberdrola argues that intra-hour scheduling must be
combined with intra-hour dispatch or market purchases to achieve the
Commission's goals. Oregon and New Mexico PUC recommend that the
Commission encourage reforms such as an Energy Imbalance Market or 15-
minute calculations of available transmission capability (ATC) as a
complement to intra-hour scheduling. However, Bonneville Power suggests
distinguishing between intra-hour scheduling outside of a market region
and intra-hour dispatch in an organized market, arguing that the costs
and benefits of each may be dramatically different. Bonneville Power
explains that the resources devoted to implementing 15-minute
scheduling may be better used to pursue the development of an organized
market with frequent dispatch intervals.
    90. Some commenters assert that the Commission should consider
changes to other aspects of electricity markets to facilitate intra-
hour scheduling.\119\ Invenergy Wind contends that consistent
timeframes across all transmission and generation functions may lead to
more efficient use of transmission capacity, regulation, and other
ancillary services. American Clean Skies explains that the technology
necessary to schedule transmission in 15-minute increments will also
allow for scheduling reforms in the day-ahead market and the unit
commitment process and, therefore, the Commission should require 15-
minute scheduling reforms in these areas as well. However, PJM asserts
that real-time control issues do not exist day-ahead and, therefore,
the Commission need not consider reforms to the day-ahead market.
---------------------------------------------------------------------------

    \119\ E.g., American Clean Skies; Invenergy Wind.
---------------------------------------------------------------------------

c. Commission Determination
    91. The Commission concludes that it is appropriate to act at this
time to adopt the scheduling reforms set forth in the Proposed Rule.
Specifically, the Commission amends the pro forma OATT to provide all
transmission customers the option of using more frequent transmission
scheduling intervals within each operating hour, at 15-minute
intervals. Our actions in this Final Rule will ensure that charges for
generator imbalance service under Schedule 9 of the pro forma OATT and
for other ancillary services through which reserve-related costs are
recovered are just and reasonable and are not unduly
discriminatory.\120\
---------------------------------------------------------------------------

    \120\ In section IV.C (Generator Regulation Service Capacity)
infra, the Commission acknowledges that a range of capacity services
could be used by public utility transmission providers to recover
reserve-related costs.
---------------------------------------------------------------------------

    92. As noted in the Proposed Rule, many pro forma OATT
requirements, including hourly scheduling protocols, were developed at
a time when virtually all generation on the system could be scheduled
with relative precision.\121\ As part of the Commission's regulatory
responsibilities, we routinely review and, where appropriate, implement
reforms to ensure the provision of service that remains just and
reasonable and not unduly discriminatory. A similar review led the
Commission in Order No. 890 to exempt VERs from the third-tier of
generator imbalance penalties, given that VERs have a limited ability
to accurately follow an hourly transmission schedule and, as a result,
exposure to high imbalance penalties does not lessen their incentive to
deviate from their schedule.\122\ In this Final Rule, we take an
additional step to allow transmission customers the flexibility to
adjust their transmission

schedules, in advance of real-time, to reflect the variability of
output in generation, more accurate power production forecasts to
predict output, and other changes in load profiles and system
conditions.
---------------------------------------------------------------------------

    \121\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 38.
    \122\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 665.
---------------------------------------------------------------------------

    93. Specifically, the Commission affirms the preliminary finding in
the Proposed Rule that existing hourly scheduling protocols expose
transmission customers to excessive or unduly discriminatory generator
imbalance charges.\123\ Under Schedule 9 of the pro forma OATT,
generator imbalance charges are assessed on deviations between
generator output and a delivery schedule over a single hour.\124\ There
is no requirement to provide customers the opportunity to adjust their
transmission schedules within the hour to reflect changes in generator
output. As a result, transmission customers have no ability under the
pro forma OATT to mitigate Schedule 9 generator imbalance charges in
situations when the transmission customer knows or believes that
generation output will change within the hour. The Commission concludes
that this lack of ability to update transmission schedules within the
hour can cause charges for Schedule 9 generator imbalance service to be
unjust and unreasonable or unduly discriminatory. As a result of the
intra-hour scheduling reforms of this Final Rule, the metric against
which generator imbalances are measured will be more granular than
under current hourly scheduling protocols.
---------------------------------------------------------------------------

    \123\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 37.
    \124\ Imbalance charges are calculated by multiplying the
quantity of imbalance by a set percentage of incremental or
decremental costs defined in three deviation bands. These charges
are netted on a monthy basis and settled financially at the end of
each month. For example, any deviations greater than
7.5 percent (or 10 MW) of the scheduled transaction (applied hourly)
will be settled at 125 percent of incremental costs or 75 percent of
decremental costs. See OATT Schedule 9.
---------------------------------------------------------------------------

    94. The Commission expects that many types of entities, not only
VERs, may benefit from the availability of intra-hour scheduling. Every
transmission customer will have the ability to adjust its schedule at
15-minute intervals to reflect changing conditions. This includes, for
example, transmission customers that experience a within-hour forced
outage or transmission customers taking delivery from energy
constrained resources (such as flow-limited hydro-electric generators,
emission-limited thermal generators, and energy storage resources),
even if using point-to-point transmission internal to the system. For
example, we note that Entergy voluntarily adopted intra-hour
transmission scheduling without the presence of substantial VERs in an
effort to manage fluctuations in output from qualifying facilities on
its system.\125\ Based on this experience and the record in this
proceeding, the Commission finds that intra-hour scheduling will
provide a range of transmission customers with a necessary tool to
mitigate exposure to Schedule 9 generator imbalance charges in light of
changing conditions.
---------------------------------------------------------------------------

    \125\ See Entergy Serv. Inc., 111 FERC ] 61,314 (2005).
---------------------------------------------------------------------------

    95. The Commission also finds that, over time, implementation of
intra-hour scheduling will allow public utility transmission providers
to rely more on planned scheduling and dispatch procedures, and less on
reserves, to maintain overall system balance. Under hourly scheduling
protocols, the source balancing authority for a transaction is required
to honor its transmission schedule across an entire hour, requiring the
source balancing authority to have sufficient reserves in place to
manage imbalances within the hour, i.e., maintain consistent delivery
of the scheduled amount of energy to the sink balancing authority over
the hour. This includes reserves to respond to variations in generation
output that are moment-to-moment as well as longer-term, but occurring
within the hour, represented by the solid line in Figure 1.

[GRAPHIC] [TIFF OMITTED] TR13JY12.000

    96. By moving from hourly to 15-minute scheduling intervals, the
amount of imbalance energy for which the source balancing authority is
potentially responsible can be reduced, as reflected in Figure 1. This
can lead to a corresponding reduction in the amount of capacity held to
provide that energy and, in turn, lower reserve-related costs for the
source balancing authority, and ultimately consumers. Therefore, the
Commission also finds that implementation of intra-hour schedules is
necessary in order to ensure that charges for ancillary services
through which reserve-related costs are recovered are just and
reasonable and not unduly discriminatory.\126\
---------------------------------------------------------------------------

    \126\ One mechanism that could be used to recover reserve-
related costs is generator regulation service. The Commission
provides guidance regarding the development of generation regulation
charges in section IV.C.2 (Mechanics of Generator Regulation Charge)
infra. Among other things, public utility transmission providers
should consider the extent to which transmission customers are using
intra-hour scheduling in evaluating whether to require different
transmission customers to provide or otherwise account for different
quantities of generator regulation service.
---------------------------------------------------------------------------

    97. For these reasons, the Commission adopts the proposal set forth
in the Proposed Rule and directs public utility transmission providers,
consistent with the compliance deadlines addressed below, to revise
their OATTs to provide an opportunity for transmission customers to
submit transmission schedules at 15-minute intervals. In response to
Bonneville Power and Xcel, the Commission clarifies that this
requirement is intended to allow transmission customers to both modify
existing schedules as well as create new schedules, provided that the
transmission customer has a transmission reservation in place.\127\ The
ability to create new transmission schedules within the hour will be
particularly important to resources that may seek to provide intra-hour
energy products, as discussed further below.
---------------------------------------------------------------------------

    \127\ To be clear, this Final Rule does not alter the
transmission products of the pro forma OATT and, therefore,
implementation of intra-hour scheduling does not require (yet would
not preclude) the intra-hour calculation of ATC or sale of
transmission service.
---------------------------------------------------------------------------

    98. The Commission notes that most commenters support the practice
of intra-hour scheduling, with disagreement focused primarily on the
frequency of schedule adjustments and whether changes to existing
scheduling should be paired with other reforms. Balancing the competing
considerations raised by commenters, the Commission concludes that a
15-minute scheduling interval is appropriate and declines to impose
additional reforms at this time. The Commission appreciates that
implementation of other reforms, such as intra-hour imbalance
settlement, an intra-hour transmission product, increasing the
frequency of resource commitment through sub-hourly dispatch, or the
formation of intra-hour imbalance markets, could yield additional
benefits for public utility transmission providers and their customers.
However, these additional reforms can have significant costs. The
Commission's review of the record in this proceeding suggests that a
more measured approach is appropriate to take at this time.\128\
---------------------------------------------------------------------------

    \128\ As noted below, public utility transmission providers will
have an opportunity on compliance to demonstrate that alternative
intra-hour scheduling proposals are consistent with or superior to
the intra-hour scheduling requirements of this Final Rule. Such a
proposal could include one or more of the additional reforms
requested by commenters, such as the formation of intra-hour
imbalance markets.
---------------------------------------------------------------------------

    99. The Commission acknowledges that implementation of intra-hour
scheduling can result in a shift of responsibility for holding certain
reserves away from the source balancing

authority for export transactions.\129\ As explained above, allowing
for more granular transmission schedules can reduce the amount of
variation in generation output for which the source balancing authority
is responsible. The Commission appreciates that, from the sink
balancing authority's perspective, scheduling at shorter intervals may
result in the purchaser of energy having to manage more frequent
changes in scheduled deliveries as compared to scheduling at hourly
intervals. As indicated in Figure 2, a purchaser under existing hourly
scheduling protocols receives a fixed quantity of energy over the hour
from the source balancing authority, whereas use of 15-minute intervals
could result in fluctuating deliveries across the hour.
---------------------------------------------------------------------------

    \129\ E.g., Xcel; Iberdrola.
    [GRAPHIC] [TIFF OMITTED] TR13JY12.001

    To the extent the purchaser desires to continue receiving a
constant delivery of energy across the hour, represented by the dotted
line in Figure 2, it may be required to obtain that energy from the
market.\130\ The Commission concludes that this is an appropriate
division of responsibility, as opposed to the current hourly system
which places all responsibility for managing variations in generation
output across the hour solely on the source balancing authority. Within
the hour, the source balancing authority retains its responsibility of
providing the energy needed for the VER to meet its schedule, while the
purchaser takes on the responsibility of managing more frequent
deliveries of scheduled energy.
---------------------------------------------------------------------------

    \130\ For example, sellers of VER energy could have existing
contractual commitments to deliver at constant volumes over
specified periods.
---------------------------------------------------------------------------

    100. By shifting responsibility for managing certain variations in
generation output to the purchasing entity, purchasing entities will
have greater incentive to manage changes in scheduled deliveries from
15-minute interval to 15-minute interval and the portfolio of resources
that ultimately manage total VER variability will likely be more cost-
effective than under current practices. Specifically, a portfolio of
resources that respond over a range of time scales, from very fast to
relatively slow, is lower cost than a portfolio that relies on
resources designed to manage only the short-run variability of
VERs.\131\ For instance, portfolio cost savings could result from using
a combination of expensive resources with automated generator control
and less expensive resources that provide following service rather than
using only resources with automated generator control. While the source
balancing area could choose to manage VER variability with a portfolio
of resources that respond over a range of time, it has little incentive
to do so because any additional costs can be recovered from
transmission customers. We expect use of a portfolio of resources to
lower the overall cost of managing VER variability. The Commission
anticipates that buyers and sellers also may respond by developing
intra-hour balancing products. EPSA notes that the additional market
liquidity created by the ability to schedule transmission intra-hourly
can provide opportunities for existing resources to manage system

variability by offering within-hour energy products. This is equally
true for market participants seeking to maximize the value of their
resources, or lower their purchased power costs, through intra-hour
trading. As the liquidity of intra-hour energy products stabilizes,
market participants also may begin to commit or otherwise acquire fewer
reserves in advance, with the knowledge that they can purchase
additional reserves on an as-needed basis from third parties. Requiring
public utility transmission providers to offer intra-hour scheduling is
a necessary predicate to facilitate these market opportunities.\132\
---------------------------------------------------------------------------

    \131\ See e.g., J. Apt, The Spectrum of Power from Wind
Turbines. Journal of Power Sources, Vol. 169, No. 2, at 369-374
(2007); cited at RenewElec comments at note 4.
    \132\ For example, the Joint Initiative has implemented an
electronic platform to facilitate bilateral intra-hour transactions,
the Intra-hour Transaction Accelerator Platform (I-TAP), also
referred to as the WebExchange. See http://www.columbiagrid.org/itap-overview.cfm.
---------------------------------------------------------------------------

    101. Notwithstanding broad support in comments for some version of
intra-hour scheduling, as noted above, there was significant
disagreement in the comments as to the appropriate time interval. Some
commenters supported the 15-minute interval proposed by the
Commission,\133\ while others argued for either shorter (e.g., 5-
minute) or longer (e.g., 30-minute) scheduling intervals.\134\ In
evaluating these comments, the Commission has balanced the competing
interests of allowing transmission customers to more closely match
schedules with anticipated generation output against not unduly
burdening public utility transmission providers in implementing the
intra-hour scheduling reform. The Commission concludes that adoption of
a 15-minute scheduling interval for purposes of the pro forma OATT is
reasonable. In its comments on the NOI, NERC states that the ideal
scheduling increment would be between 5 and 15 minutes depending on
system characteristics.\135\ NERC reasoned that, while balancing
authorities that schedule energy transactions on an hourly basis may
have sufficient regulation resources to maintain the schedule for the
hour, reducing scheduling intervals to ten minutes, for example, could
make economically dispatchable generators in an adjacent balancing
authority available to provide necessary ramping capability through an
interconnection.\136\ The Commission agrees and, as discussed above,
anticipates that the availability of intra-hour scheduling at 15-minute
intervals will facilitate the development of ramping products to manage
variability in generation output more effectively. For these reasons we
adopt 15-minute transmission scheduling as proposed.
---------------------------------------------------------------------------

    \133\ E.g., A123; Alstom Grid; ACSF; Argonne National Lab; BP
Companies; CESA; CEERT; Center for Rural Affairs; Clean Line; CGC;
Defenders of Wildlife; EPSA; Exelon; First Wind; Independent Energy
Producers; NaturEner; Organization of Midwest ISO States; Oregon &
New Mexico PUC; Powerex; Public Interest Organizations; SWEA; Tres
Amigas; Viridity Energy; Western Grid; Xcel.
    \134\ Compare Environmental Defense Fund; FriiPower; Independent
Power Producers Coalition-West; RenewElec; SEIA; Vestas; and Vote
Solar (advocates of shorter) with Bonneville Power; California PUC;
CMUA; Montana PSC; NorthWestern; Puget; Snohomish County PUD;
Southern California Edison; WUTC (advocates of longer).
    \135\ NERC April 12, 2010 Response to NOI (NERC NOI Comments).
    \136\ NERC NOI Comments.
---------------------------------------------------------------------------

    102. In adopting a 15-minute transmission scheduling interval, we
recognize that the cost of moving from hourly to 15-minute transmission
scheduling could be substantial. Several transmission providers state
that costs will depend heavily on the extent to which intra-hour
scheduling is actually used by transmission customers, estimating
staffing costs to be in the range of $1-2 million per year if widely
used.\137\ While these costs are not insignificant, greater use of
intra-hour schedules means that more transmission customers are
mitigating exposure to Schedule 9 generator imbalance charges and
providing greater opportunities for public utility transmission
providers to lower reserve-related costs. Commenters generally agree
that the cost of implementing intra-hour scheduling will correlate to
usage, with lower costs in those systems with fewer intra-hour
schedules. In contrast, substantial use of intra-hour scheduling would
affirm the usefulness of the option for transmission customers,
justifying the added expense of processing a larger number of
transmission schedules.
---------------------------------------------------------------------------

    \137\ E.g., Avista; NRECA. To the extent intra-hour scheduling
is not widely used by transmission customers, NRECA states its
members likely could implement scheduling at 15-minute intervals
with software modifications in the range of $50,000 per company,
without additional staffing requirements.
---------------------------------------------------------------------------

    103. Many of the costs cited by commenters as being specific to 15-
minute scheduling are related to the automation of systems used to
process transmission schedules and verify cross-balancing authority
aggregate schedules. The Commission notes that it is not mandating
automation of scheduling practices, although we expect that each public
utility transmission provider will consider whether automation of
certain aspects of its system are necessary to implement scheduling at
15-minute intervals. To the extent a public utility transmission
provider automates scheduling processes in response to increased
scheduling activity, the Commission agrees with NaturEner and
Independent Power Producers Coalition-West that automation of these
processes represents a secondary benefit of our transmission scheduling
reform. Several Commission staff audits have uncovered errors related
to manual processing of transmission schedules.\138\ These errors
resulted in a transmission customer submitting a transmission schedule
that resulted in a higher curtailment priority than the underlying
transmission service reservation provided, allowed use of firm network
service to deliver energy from resources that were not designated
resources and allowed use of network transmission service to deliver a
sale to a third party. As a result of these errors, the transmission
customer may have gained access to transmission service that was not
otherwise available, may have inappropriately gained additional
protection from curtailment, and avoided payment for point-to-point
transmission service. Increased automation of schedule process can
reduce such errors and, in turn, ensure that the provision of
transmission service is consistent with the pro forma OATT.
---------------------------------------------------------------------------

    \138\ E.g., Puget Sound Energy, Docket No. PA07-1-000 at 25-27;
MidAmerican Energy Co., Audit Report, 112 FERC ] 61,346 at PP 30-34
(2005); and Public Service Company of Colorado, Docket No. PA05-1-
000 at 9-11.
---------------------------------------------------------------------------

    104. Some commenters raising concerns regarding the cost of
implementing intra-hour scheduling imply that the proposed scheduling
reforms would require changes in settlement procedures for imbalance
service or the frequency of resource commitment through sub-hourly
dispatch, which they state would require significant investments. For
example, EEI and PNW Parties caution that these additional activities
would affect computer systems, such as energy management and accounting
systems.\139\ MidAmerican estimates that upgrading such systems would
cost $2.0-2.3 million. Other commenters, however, encourage the
Commission to require intra-hour imbalance settlement and sub-hourly
dispatch in order to align intra-hour scheduling with financial
settlements and resource commitment. The Commission clarifies that the
requirements of this Final Rule apply to scheduling practices, not
imbalance settlement or sub-hourly dispatch. Public utility
transmission providers may continue to calculate pro forma Schedule 9
generator imbalance charges on an hourly basis under the pro forma

OATT and rely on hourly resource commitment practices.\140\
---------------------------------------------------------------------------

    \139\ Eg., EEI; PNW Parties.
    \140\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 722;
Order No. 890-A, FERC Stats. & Regs. ] 61,297 at P 325 & n.117.
---------------------------------------------------------------------------

    105. Notwithstanding the continued ability of public utility
transmission providers to rely on hourly calculation of Schedule 9
generator imbalances, as a result of the intra-hour scheduling reforms
of this Final Rule, the metric against which generator imbalances are
measured will be more granular than under current hourly scheduling
protocols. To the extent a public utility transmission provider
believes that aligning the imbalance settlement with the intra-hour
scheduling interval or implementing sub-hourly dispatch will result in
more efficient operations, provide appropriate price signals to
customers, or address other potential issues, it may seek any
authorizations necessary from the Commission to do so under section 205
of the FPA.\141\ Such proposals could be submitted contemporaneously
with the compliance filing in response to this Final Rule or at such
other time the public utility transmission provider believes
appropriate.
---------------------------------------------------------------------------

    \141\ For example, PNW Parties and Idaho Power note that the
financial incentives some transmission customers have to maximize
output over an hour may in some instances counteract financial
incentives to adjust transmission schedules on a 15-minute basis.
---------------------------------------------------------------------------

    106. Several commenters request that the Commission allow for
regional variation in scheduling protocols.\142\ In the Western
Interconnection, many public utility transmission providers already
have implemented some form of intra-hour scheduling at 30-minute
intervals as part of an effort to enhance the operation of bilateral
markets in the Western Interconnection.\143\ Other tools recently
implemented in the West include the I-TAP electronic platform to
schedule energy and request transmission, the Dynamic Scheduling System
to facilitate dynamic scheduling,\144\ and the ACE Diversity
Interchange Program to allow netting of momentary imbalances across
participating balancing authority footprints.\145\ Public utility
transmission providers, state regulators, and others in the West are
studying the impact of these recent initiatives, as well as the
potential benefits and costs of pursuing additional market enhancements
in the future, such as formation of an energy imbalance market. The
Commission acknowledges that future market enhancements in addition to
existing 30-minute scheduling practices and the above-referenced tools,
might yield equivalent or greater benefits to transmission customers
and public utility transmission providers when compared to reducing the
scheduling interval from 30 to 15 minutes and therefore could be
consistent with or superior to the Final Rule's intra-hour scheduling
requirements.
---------------------------------------------------------------------------

    \142\ E.g., Avista; Bonneville Power; California ISO; CESA;
CMUA; California PUC; Detroit Edison; EEI; FirstEnergy; Grant PUD;
Idaho Power; Independent Power Producers Coalition-West; ISO/RTO
Council; Midwest ISO; National Grid; Northwestern; NRECA; New York
ISO; NV Energy; Pacific Gas & Electric; PJM; PNW Parties; Public
Power Council; Puget; SMUD; Tacoma Power; WUTC; and WestConnect.
    \143\ See e.g., Arizona Public Service Co., 137 FERC ] 61,023
(2011), NorthWestern Corp., 136 FERC ] 61,119 (2011).
    \144\ See Joint Initiative.
    \145\ See NERC, DRAFT Reliability Guideline: ACE Diversity
Interchange (June 2012), available at http://www.nerc.com/docs/oc/rs/Draft%20ADI%20Reliability%20Guideline%20-%20V1%20060112.pdf.
---------------------------------------------------------------------------

    107. The Commission therefore affirms the ability of public utility
transmission providers to submit alternative proposals that are
consistent with or superior to the intra-hour scheduling requirements
of this Final Rule and are otherwise just and reasonable and not unduly
discriminatory or preferential.\146\ To make such a showing, a public
utility transmission provider must demonstrate in its compliance filing
how its proposal provides equivalent or greater opportunities for
transmission customers to mitigate Schedule 9 generator imbalance
charges, and for the public utility transmission provider to lower its
reserve-related costs, when compared to implementation of the intra-
hour scheduling requirements of this Final Rule under market practices
currently in place within the region, including tools referenced above
that already have been implemented in the West.\147\ The public utility
transmission provider must include in its compliance filing the tariff
provisions necessary to implement its proposal, including the interval
at which transmission customers may submit transmission schedules. The
public utility transmission provider also must address how its proposed
scheduling interval is consistent with other scheduling practices
within its region. Finally, in recognition that implementation of
intra-hour scheduling can result in a shift of responsibility for
holding certain reserves away from the source balancing authority for
export transactions, public utility transmission providers may consider
the extent to which alternative proposals result in savings to
transmission customers across multiple public utility transmission
provider systems when making the demonstration required above.
---------------------------------------------------------------------------

    \146\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,770
(permitting public utility transmission providers to propose tariff
modifications that are consistent with or superior to the
requirements of the pro forma OATT).
    \147\ To the extent such an alternative proposal includes a
commitment to develop and implement additional market enhancements
in the future, the public utility transmission provider must provide
in its compliance filing: A commitment by senior management to
develop and implement the proposal; a description of collaborative
efforts to date and timeline for future efforts in support of
developing the proposal; and, the date by which the proposed market
enhancement will be implemented.
---------------------------------------------------------------------------

    108. Turning to other issues raised by commenters, the Commission
is not convinced by arguments that the current exemption from third-
tier generator imbalance penalties for intermittent resources should be
eliminated to create an incentive for VERs to take advantage of the
option to update transmission schedules every 15 minutes.\148\ In Order
No. 890, the Commission found intermittent generators cannot always
accurately follow their schedules and that high penalties will not
lessen the incentive to deviate from their schedules.\149\ While the
implementation of 15-minute scheduling provides an opportunity for VERs
to better align transmission schedules with actual generation, the
Commission continues to believe that third-tier generator imbalance
penalties are unduly punitive for VERs given their relative inability
to accurately follow schedules whether submitted on an hourly or 15-
minute interval. The Commission concludes that the ability to avoid
penalties in the first two tiers of generator imbalance charges will
provide a sufficient incentive for VERs to adjust transmission
schedules, to the extent they believe such adjustments will mitigate
exposure to Schedule 9 generator imbalance charges. If a public utility
transmission provider believes it necessary to address intentional
deviations, it may propose revisions to Schedule 9 generator imbalance
service pursuant to section 205 of the FPA.\150\ Such proposals would
need to demonstrate that VERs are not adjusting their transmission
schedules despite their reasonable ability to foresee that

output will deviate significantly from existing transmission
schedules.\151\
---------------------------------------------------------------------------

    \148\ E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.
    \149\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 665.
    \150\ Cf. id. P 676 (noting the ability of public utility
transmission providers to propose additional imbalance penalties for
intentional deviations). Alternatively, the public utility
transmission provider may propose alternative designs for other
ancillary services rates to, for example, offer lower rates to those
transmission customers committing to use intra-hour scheduling.
    \151\ The Commission notes that there is a relationship between
a public utility transmission provider's potential need for
alternative imbalance charge structures and the period used for
imbalance settlements. Reinstating third-tier imbalance penalties in
combination with shortened imbalance settlements would more likely
punish VERs for variability that they cannot control, contrary to
the exemption granted in Order No. 890 and affirmed here.
---------------------------------------------------------------------------

    109. The Commission acknowledges comments made by some,
particularly in the Pacific Northwest, asserting that the benefits of
intra-hour scheduling will not be fully realized if non-jurisdictional
entities do not adopt a consistent scheduling interval.\152\ However,
the Commission does not believe that limitations in our ratemaking
jurisdiction over non-public utilities should stop us from moving ahead
with reforms applicable to public utilities simply because the impact
of those reforms might be more significant with participation by all
entities. As explained above, requiring all public utility transmission
providers to offer 15-minute transmission scheduling will enable public
utility transmission providers and their customers to manage system
variability more effectively. Therefore, the Commission is hopeful that
non-jurisdictional transmission providers will voluntarily choose to
implement 15-minute transmission scheduling in order to better manage
variations in generation output. We understand that the existence of
compatible business practices within a region is beneficial, and we
encourage both jurisdictional and non-jurisdictional transmission
providers to continue to coordinate and collaborate in order to
maintain the continuity of the system and address issues as they arise.
This includes collaboration in the development of any alternative
compliance proposals developed by public utility transmission
providers.
---------------------------------------------------------------------------

    \152\  E.g., Avista; California ISO; Duke; Idaho Power;
NorthWestern; NV Energy; PNW Parties; Puget; Southern California
Edison; Southern; Tres Amigas.
---------------------------------------------------------------------------

    110. The Commission disagrees with comments by Southern and others
that different scheduling intervals between jurisdictional and non-
jurisdictional transmission providers may negatively affect reliability
within an interconnection.\153\ In the event a non-jurisdictional
transmission provider only accepts hourly schedules, any attempt to
submit an intra-hour schedule for delivery to the non-jurisdictional
transmission provider would be rejected, as several commenters
note.\154\ This may lead to an inability to implement 15-minute
scheduling fully and, in turn, could result in less effective
management of system variability. However, the Commission does not
believe that it would create any reliability challenges beyond those
that exist today under hourly scheduling protocols. The Commission
notes that voluntary efforts to implement intra-hour scheduling on 30-
minute intervals in the Western Interconnection referenced above have
not been uniformly applied, yet do not appear to have negatively
affected reliability.
---------------------------------------------------------------------------

    \153\ E.g., EEI; Idaho Power; NorthWestern; Southern; Tacoma
Power.
    \154\ E.g., PNW Parties; Puget; WUTC.
---------------------------------------------------------------------------

    111. In response to concerns raised by Snohomish County PUD and
Grays Harbor PUD regarding ``slice'' contracts with Bonneville Power,
the Commission acknowledges that some existing power supply
arrangements may not be flexible enough to take advantage of the
benefits of intra-hour scheduling. Over time, the Commission
anticipates that the market will respond to the availability of intra-
hour scheduling through the development of new balancing products as
well as modifications of existing arrangements where appropriate.
However, in the case where the terms of an existing contract are
inconsistent with intra-hour scheduling and cannot be modified, the
Commission appreciates that the benefits of intra-hour scheduling may
not be available with respect to that particular transaction.
    112. In response to comments by WestConnect and NorthWestern that a
15-minute scheduling interval is inconsistent with the standard 20-
minute generator ramp rate used in the West, we note that many of the
Joint Initiative transmission providers--including members from
WestConnect--have already implemented a 10-minute ramp rate to
accommodate 30-minute transmission schedules. To the extent changes in
ramping are necessary to support use of a 15-minute transmission
schedules, it does not appear that such changes present a significant
impediment for public utility transmission providers.
    113. A number of commenters question the applicability of the
intra-hour scheduling requirements to public utility transmission
providers in RTO and ISO regions.\155\ The Commission clarifies that
the implementation of 15-minute transmission scheduling will only apply
to intertie transactions in organized wholesale energy markets. The
Commission finds that a consistent scheduling interval for transactions
among all public utility transmission providers, including RTOs, is
necessary in order to attain the benefits of intra-hour scheduling
noted above. Additional reforms to other markets requested by
commenters, such as adjustments to day-ahead markets, are beyond the
scope of this rulemaking.
---------------------------------------------------------------------------

    \155\ E.g., AWEA; Iberdrola; ISO New England; Massachusetts DPU;
PJM; Public Interest Organizations; RENEW; Sunflower and Mid-Kansas;
Western Farmers.
---------------------------------------------------------------------------

2. Implementation of Intra-Hour Scheduling
    114. Commenters raise a number of additional issues related to how
the intra-hour scheduling requirements adopted in this Final Rule
should be implemented. The Commission addresses these issues below,
including the following: (1) The appropriate notification period for
submitting transmission schedules; (2) the recovery of costs associated
with implementing intra-hour scheduling; (3) clarifications regarding
the definition of transmission schedule, curtailment priorities, and
calculations of ATC; (4) review of NERC reliability standards and NAESB
business practices; and (5) other issues related to high voltage direct
current (HVDC) transmission lines, dynamic scheduling, and the
geographic location of resources used to provide reserves.
a. Notification Time for Submission of Transmission Schedule
i. Commission Proposal
    115. In the Proposed Rule, the Commission proposed to allow all
transmission customers the option of submitting intra-hour schedules up
to 15 minutes before each scheduling interval.\156\
---------------------------------------------------------------------------

    \156\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 41.
---------------------------------------------------------------------------

ii. Comments
    116. Several commenters ask the Commission to retain the existing
20-minute notification time for submission of transmission schedules,
arguing that schedules should be submitted no later than 20 minutes
prior to the start of the schedule as required by NERC Reliability
Standards INT-005, INT-006, INT-008, and NAESB WEQ-004 Appendix D.\157\
Commenters contend that allowing only 15 minutes between schedule
submission and start would not provide enough time for transmission
operators to adequately evaluate, approve, and implement transmission
schedules. ISO/RTO Council adds that changing to a 15-minute notice
period will require

transmission operators to change their current systems and increase
staff levels for processing transmission schedule requests. PJM
comments that the 20-minute notification deadline is an established
industry standard and that it should not be changed to 15 minutes.
---------------------------------------------------------------------------

    \157\ E.g., Duke; EEI; Entergy; NRECA; PJM; Puget; Southern.
---------------------------------------------------------------------------

    117. Although not opposed to the Commission's proposal, NaturEner
states that a shorter notification period would result in abbreviated
response times for everyone in the scheduling process, including
transmission customers. NaturEner asks the Commission to clarify that
transmission providers have the discretion to accept schedule changes
after the notification deadline. NaturEner contends that inclusion of
such a clarification both supports the reform's underlying rationales
and avoids any unnecessary future confusion regarding whether a
balancing authority or transmission provider possesses such discretion.
iii. Commission Determination
    118. The Commission will retain the existing 20-minute prior
notification period for the submission of a transmission schedule and
not adopt its proposal. The Commission agrees with commenters that the
existing 20-minute prior notification period is needed to adequately
evaluate, approve and implement transmission schedules. Accordingly,
the Commission retains the existing notification period set forth in
sections 13.8 and 14.6 of the pro forma OATT, which permits scheduling
changes up to 20 minutes (or a reasonable time that is generally
accepted in the region and is consistent and adhered to by the
transmission provider) before the start of the next schedule change
provided that the delivering party and receiving party also agree to
the schedule modification. In response to NaturEner, the existing
language of the pro forma OATT provides adequate flexibility for
transmission providers to adopt alternative deadlines for accepting
scheduling changes.
b. Recovery of Intra-Hour Scheduling Costs
i. Commission Proposal
    119. In the Proposed Rule, the Commission proposed to allow public
utility transmission providers to recover any costs incurred to
implement the proposed intra-hour scheduling reform pursuant to
Schedule 1 of a transmission provider's OATT.\158\
---------------------------------------------------------------------------

    \158\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 41.
---------------------------------------------------------------------------

ii. Comments
    120. Several commenters support the Commission's proposal, arguing
that the benefits of intra-hour scheduling apply to more than VERs and,
thus, costs relating to the implementation of intra-hour scheduling
should be allocated to all transmission customers under Schedule 1 of
the pro forma OATT.\159\ For example, NextEra contends that intra-hour
scheduling would provide long-term benefits for all customers through
savings on reserve procurement. Public Interest Organizations agree,
arguing that the initial costs of establishing 15-minute scheduling are
an upfront investment that will yield exponential returns over time in
the form of direct economic savings from increased grid efficiency and
reliability, as well as energy security, greenhouse gas and other
pollutant reductions, and job creation that accompanies increased
renewable VER penetration. Center for Rural Affairs supports recovery
of intra-hour scheduling costs to all beneficiaries through Schedule 1
in order to mitigate any challenge that this reform may present for
small transmission providers, especially in rural communities with
smaller areas of distribution. NaturEner points to the Joint Initiative
as an example of allocating the hardware and software costs associated
with implementation of intra-hour scheduling to all participants using
the intra-hour scheduling system, i.e., the balancing authorities,
transmission providers, and transmission customers. While Organization
of Midwest ISO States supports the proposal, it asks that a clear
showing of the costs incurred to implement intra-hour scheduling be
required prior to allowing for recovery of those costs.
---------------------------------------------------------------------------

    \159\ E.g., Environmental Defense Fund; NextEra; Public Interest
Organizations.
---------------------------------------------------------------------------

    121. Other commenters disagree with the Commission's proposal to
allow the costs associated with implementing intra-hour scheduling to
be recovered through Schedule 1 and, instead, contend that such costs
should be allocated to VERs and their customers.\160\ These commenters
argue that intra-hour scheduling will be predominantly used by and
benefit VERs and their customers.\161\ ELCON contends that traditional
generation resources do not require intra-hour scheduling. In the
Pacific Northwest, WUTC claims that intra-hour scheduling would be
utilized almost exclusively by wind and other VERs, and not by thermal
or hydropower resources. WUTC agrees that assignment of costs to those
who cause them is essential to fair and just rates and to economic
efficiency. Puget agrees that the only parties to benefit from 15-
minute scheduling are VERs that are potentially able to reduce Schedule
9 generator imbalance charges by adjusting their schedules within the
hour in response to changing wind conditions. Natural Gas argues that
strict adherence to cost causation principles is central to ensuring
that the proposals are limited to removing barriers and do not have the
unintended consequence of subsidization and, ultimately, departure from
the central precept of fuel neutrality.
---------------------------------------------------------------------------

    \160\ E.g., Avista; ELCON; Grant PUD; Montana PSC; Natural Gas;
NorthWestern; NRECA; Puget; WUTC.
    \161\ E.g., Avista; ELCON; Grant PUD; MidAmerican; NorthWestern;
NRECA; Puget; WUTC.
---------------------------------------------------------------------------

    122. Montana PSC states that traditional generation choosing to
utilize intra-hour scheduling should be allocated a portion of
implementation costs; however, absent this election VERs should be
responsible for all costs related to development, operations, and
maintenance of intra-hour scheduling.\162\ NRECA similarly contends
that, if transmission customers other than VERs make use of the new
scheduling regime, it would be appropriate for those entities to share
in the cost through Schedule 1 charges. Grant PUD argues that there is
no guarantee that other resources may benefit from a shorter scheduling
period and that some resources may actually incur costs to maintain 15-
minute schedules, in which case they would pay twice for the shift to
shorter schedules.
---------------------------------------------------------------------------

    \162\ Similarly, NorthWestern asserts that unless intra-hour
scheduling is made mandatory for all transmission customers, the
VERs opting to use intra-hour scheduling should pay for the
increased scheduling flexibility and the non VER customers should
not be required to subsidize any particular generator type.
---------------------------------------------------------------------------

    123. Avista asserts that allowing recovery through Schedule 1 will
allocate costs not only to all transmission customers, but also to
bundled retail native load customers. Avista argues that native load
customers achieve no cost savings when a VER is located within a
balancing authority area and is used to serve load within the same
balancing area. Avista states that in this situation the native load
customers bear all of the costs associated with following the output of
the VER and do not need or benefit from intra-hour scheduling. Thus,
Avista requests that none of the costs of implementing intra-hour
scheduling be

borne by a transmission provider's bundled retail native load
customers.
    124. Several of these commenters recommend that the Commission
consider other mechanisms for recovering the costs of implementing
intra-hour scheduling as opposed to a broad cost allocation scheme
through Schedule 1.\163\ For example, Avista asks the Commission to
allow a transmission provider to directly assign the costs of
implementing these reforms to the VER transmission customers that are
the cause of such reforms through an appropriate charge included in
either Schedule 1 or Schedule 10. NRECA argues that there is more than
one method that a public utility transmission provider could use to
recover costs and requests that the Commission provide public utility
transmission providers the flexibility to choose the method that works
best for each system and demonstrate a just and reasonable rate
pursuant to section 205 of the FPA. NRECA also urges the Commission to
include costs incurred to comply with any new Reliability Standards
that ensue from the Final Rule.
---------------------------------------------------------------------------

    \163\ E.g., Avista; Grant PUD; NRECA; Puget.
---------------------------------------------------------------------------

iii. Commission Determination
    125. The Commission adopts its proposal and allows public utility
transmission providers to recover any costs incurred to implement the
intra-hour scheduling reforms adopted in this Final Rule pursuant to
Schedule 1 of the transmission provider's OATT. The Commission is not
persuaded by commenters opposing the proposal that recovery of these
costs through Schedule 1 will result in an overly broad assignment of
costs. Such commenters argue that only a subset of transmission
customers is likely to use intra-hour scheduling and that only those
customers should bear the cost of implementing intra-hour scheduling
reforms. The Commission disagrees. As discussed above, intra-hour
scheduling provides all transmission customers with the tools needed to
mitigate exposure to Schedule 9 generator imbalance charges in light of
changing conditions.\164\ Implementation of intra-hour scheduling is
also necessary to the extent sellers wish to develop intra-hour energy
products to maximize the value of available resources or to allow load
serving entities to lower purchased power costs.\165\ The Commission
finds that these benefits will be spread broadly across customer
classes.
---------------------------------------------------------------------------

    \164\ See supra Sec.  IV.A.1 (Intra-Hour Scheduling
Requirement).
    \165\ Id.
---------------------------------------------------------------------------

    126. Moreover, commenters opposing the Commission's proposal fail
to reconcile their position with existing approaches used to recover
scheduling-related costs under Schedule 1 of the pro forma OATT.
Transmission providers do not currently parse scheduling costs into,
for example, categories for network customers and point-to-point
customers even though at times scheduling reforms have focused on one
set of customers and not the other.\166\ Rather, transmission customers
as a whole have allocated the costs of scheduling-related activities
through Schedule 1: Scheduling, System Control and Dispatch Service,
and relevant allocations to retail native load have been made by public
utility transmission providers. Commenters have failed to justify why
the Commission should depart from this precedent during implementation
of intra-hour scheduling practices.
---------------------------------------------------------------------------

    \166\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 770.
---------------------------------------------------------------------------

    127. In response to NRECA, the Commission's focus in this
proceeding is on the implementation of intra-hour scheduling and, as
relevant here, the recovery of scheduling-related implementation costs
pursuant to Schedule 1 of the pro forma OATT. The Commission did not
propose to address, and does not address here, recovery of other costs
associated with compliance with NERC Reliability Standards.
c. Clarify Proposed Rule Language
i. Comments
    128. Commenters ask the Commission to clarify what is intended by
the terms schedule and scheduling interval. Southern and EEI state that
the term ``schedule'' is not well defined throughout the electric
industry and requests that the Commission clarify that ``schedule'' is
equivalent to ``Interchange Transaction'' in the NERC Reliability
Standards Glossary of Terms. TVA suggests that ``scheduling intervals''
coincide with the ``ramp start'' times as defined in the Timing
Requirements tables of the NERC Reliability Standards INT-005-3,
Interchange Authority Distributes Arranged Interchange; INT-006-3,
Response to Interchange Authority; and INT-008-3, Interchange Authority
Distributes Status. TVA contends that to view the term ``scheduling
interval'' otherwise would deviate from NERC Reliability Standards and
potentially have an adverse effect on assessment periods for
reliability.
    129. Bonneville Power requests that the Commission clarify the
responsibilities of source and sink balancing authorities in regards to
holding contingency reserves associated with scheduling of VER
generation. Bonneville Power states that there is a debate regarding
whether and when a source or sink balancing authority should deploy
contingency reserves when a VER scheduling error exhausts the available
balancing reserve capacity. Bonneville Power asks the Commission to
clarify that a transmission provider can establish a base obligation to
provide balancing reserve capacity to balance VERs and that the
transmission provider can negotiate options for additional service
beyond the base obligation with individual transmission customers.
    130. A few commenters request clarification of the appropriate
curtailment priority for intra-hour transmission schedules under the
proposed reform.\167\ Specifically, these commenters inquire as to
whether a firm transmission reservation that is scheduled for less than
the full hour would have priority over a non-firm hourly schedule.
Bonneville Power and NRECA contend that submission of a firm intra-hour
schedule should not necessarily result in the curtailment of lower
priority hourly schedules. MidAmerican requests that the Commission
clarify whether the submission of an intra-hour schedule by a
transmission customer with firm transmission rights, after a competing
intra-hour schedule from a transmission customer with only non-firm
transmission rights, has curtailment priority.
---------------------------------------------------------------------------

    \167\ E.g., Bonneville Power; EEI; MidAmerican; NRECA.
---------------------------------------------------------------------------

    131. Other commenters question how ATC calculations should be
performed after implementation of intra-hour scheduling.\168\ Public
Interest Organizations state that current policy in the West does not
allow ATC associated with transmission reservations that are not
scheduled day-ahead to be used by other customers. Public Interest
Organizations suggest that this policy may severely constrain or
prohibit the effectiveness of intra-hour scheduling. In addition,
Tacoma Power suggests that it may be appropriate to align ATC
calculations with intra-hour scheduling intervals. Invenergy Wind
asserts that the entire operational construct needs to shift from an
hourly to a 15-minute basis in order to increase the efficiency of
operating

the transmission system and acquiring sufficient reserves in order to
integrate VERs on a non-discriminatory basis. However, NorthWestern
argues that continued use of hourly transmission service reservations
would not be inconsistent with implementation of intra-hour
transmission scheduling, stating that administering intra-hour
transmission reservations would be difficult and costly.
---------------------------------------------------------------------------

    \168\ E.g., Public Interest Organizations; Tacoma Power.
---------------------------------------------------------------------------

    132. Grant PUD makes reference to the Commission's use of the term
``reasonable control'' in the Proposed Rule, where the Commission
states that it is unduly discriminatory to continue to require a
resource to match an hourly schedule, especially when the output of the
resource fluctuates beyond its reasonable control.\169\ Grant PUD
contends that what is reasonable depends on the current state of
technology and requests that the Commission clarify that the definition
of ``reasonable control'' is expected to improve over time.
---------------------------------------------------------------------------

    \169\ Grant PUD (citing Proposed Rule, FERC Stats. & Regs. ]
32,664 at P 39).
---------------------------------------------------------------------------

ii. Commission Determination
    133. In response to Southern and EEI, the Commission clarifies that
the term ``schedule'' as used in this Final Rule is equivalent to its
use in Schedule 9 of the OATT: ``* * * a delivery schedule from [a]
generator to (1) another Control Area or (2) a load within the
Transmission Provider's Control Area.'' \170\ The procedures for
submitting and revising a transmission schedule are delineated in
sections 13.8 and 14.6 of the pro forma OATT, as changed by this Final
Rule. Any transmission service schedule currently submitted pursuant to
OATT sections 13.8 and 14.6 can therefore be modified or created in 15-
minute intervals under this Final Rule.
---------------------------------------------------------------------------

    \170\ OATT Schedule 9.
---------------------------------------------------------------------------

    134. In response to TVA, the Commission clarifies that the 15-
minute scheduling interval will be treated the same as the current one-
hour scheduling interval with respect to ramp start and stop times as
defined in the Timing Requirements tables of NERC Reliability Standards
INT-005-3, INT-006-3, and INT-008-3. As an example, in the Eastern
Interconnection ramp start times will begin five minutes before the
start of the 15-minute scheduling interval and end five minutes after
the start of the 15-minute scheduling interval.
    135. Regarding responsibilities for holding contingency reserves,
the Commission did not propose any changes to existing rules regarding
the use of contingency reserves in this proceeding. As Bonneville Power
notes, there is ongoing debate in the industry regarding when and how
contingency reserves may be used under NERC Reliability Standards. The
Commission concludes it is appropriate, in the first instance, for
stakeholders to address these questions through the NERC
processes.\171\
---------------------------------------------------------------------------

    \171\ The Commission addresses requests by Bonneville Power and
others to limit the amount of capacity it must make available to
transmission customers for generator regulation service under
Schedule 10 in Sec.  IV.C.1 (Schedule 10--Generator Regulation and
Frequency Response Service) below.
---------------------------------------------------------------------------

    136. The Commission also did not propose any changes to curtailment
policies or ATC calculation. The Commission recognizes that
transmission providers have flexibility under the pro forma OATT to
award transmission service based on transmission capability that
becomes available when firm transmission service is not scheduled by
10:00 a.m. the day prior to operation.\172\ The Commission appreciates
that, when a transmission provider makes service available under these
circumstances, application of curtailment priorities and ATC
calculation rules become more complicated. However, that is already the
case under hourly transmission schedules. Therefore, the Commission did
not propose any change to those practices to accommodate the
possibility of intra-hour transmission schedules. All transmission
schedules for firm service will continue to have curtailment priority
over all transmission schedules for non-firm service \173\ and
transmission providers will continue to be required to follow existing
rules governing the calculation of ATC.\174\
---------------------------------------------------------------------------

    \172\ The pro forma OATT states that ``[s]chedules for the
Transmission Customers' Firm Point-To-Point Transmission Service
must be submitted no later than 10:00 a.m. * * * of the day prior to
commencement of such service.'' OATT Schedule 13.8.
    \173\ The pro forma OATT makes clear that ``(p)arties requesting
Non-Firm Point-To-Point Transmission Service for the transmission of
firm power do so with the full realization that such service is
subject to availability and to Curtailment or Interruption under the
terms of the Tariff.'' OATT Schedule 14.5.
    \174\ In compliance with Order No. 890, public utility
transmission providers have documented rules governing their
calculation of ATC in Schedule C of their OATTs. See Order No. 890,
FERC Stats. & Regs. ] 31,241 at P 193.
---------------------------------------------------------------------------

    137. In response to the request from Grant PUD for clarification of
the term ``reasonable control,'' the Commission explains that use of
the term ``reasonable control'' is not intended to be a metric or a
determining factor, but illustrative of the difficulty VERs experience
when attempting to follow hourly schedules accurately. The Commission
does not find it necessary to offer any further clarification.
d. NERC and NAESB Standards
i. Commission Proposal
    138. In the Proposed Rule, the Commission noted that many
commenters, in response to the NOI, claimed that shorter scheduling
intervals may enhance reliability. The Commission therefore stated that
it did not believe that an independent review of NERC Reliability
Standards is necessary in order to propose implementation of intra-hour
scheduling. However, the Commission sought comment on the issue to
ensure that there is no inconsistency between relevant NERC standards
and the proposed intra-hour scheduling tariff reform.\175\
---------------------------------------------------------------------------

    \175\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 37.
---------------------------------------------------------------------------

ii. Comments
    139. NERC states that certain entities currently offer 15-minute
scheduling and that it is unaware of any conflicts with Reliability
Standards. However, NERC asserts that wide spread use of intra-hour
scheduling will likely require review and refinement of several
existing Reliability Standards. Based on its preliminary review of
Reliability Standards in coordination with industry stakeholders, NERC
states that it does not believe there are any insurmountable hurdles
that prevent industry from implementing 15-minute transmission
scheduling. NERC explains that sufficient time must be allowed for
Reliability Standards to be modified through the NERC Reliability
Standards Committee prioritization process, but that transitioning to
broad intra-hour scheduling flexibility is achievable in a reasonable
timeframe.
    140. Some commenters do not anticipate that a review of NERC
Reliability Standards is necessary to ensure reliability upon the
implementation of intra-hour scheduling.\176\ NaturEner argues that an
independent review of NERC standards may not be necessary, but if such
a review occurs it should not delay implementation of intra-hour
scheduling. Pacific Gas & Electric agrees that implementation of intra-
hour scheduling can be achieved without a review of NERC standards, but
recommends that NERC and other industry experts review and update
current planning and operating criteria to ensure that balancing
authorities have the necessary tools to flexibly balance

loads and resources with the advent of increased VER penetration.
---------------------------------------------------------------------------

    \176\ E.g., NaturEner; Southern California Edison.
---------------------------------------------------------------------------

    141. Other commenters contend that review and modification of
standards may be necessary, but not a prerequisite to
implementation.\177\ Southern and Xcel state that only modest, if any,
changes would be needed to NERC Reliability Standards. Southern
indicates that several standards may need to be reviewed and revised as
they currently contemplate hourly intervals. Xcel contends that
standards related to the maximum lead times required for entry and
approval of a schedule may require changes. Xcel explains that the lead
times for entry and approval of a tag may exceed the length of a
scheduling interval, thus diminishing the usefulness of intra-hour
scheduling. AEP and Duke Energy suggest that sensitivity studies should
be performed by an industry forum or working group to determine the
reliability impacts of the proposed scheduling changes on real-time
system operations.
---------------------------------------------------------------------------

    \177\ E.g., NERC; Pacific Gas & Electric.
---------------------------------------------------------------------------

    142. Several commenters argue that review and revision of NERC
Reliability Standards, as well as NAESB business practice standards,
may be necessary for the implementation of intra-hour scheduling at 15-
minute intervals.\178\ These commenters point out that many Reliability
Standards and business practices are largely predicated on hourly
scheduling intervals and govern transactions both internal to a
particular balancing authority as well as across neighboring balancing
authorities. Although most commenters did not identify specific changes
to standards that would be necessary, some commenters suggest that NERC
Reliability Standards related to some or all of the following areas be
reviewed: Interchange Scheduling and Maintenance Coordination (INT),
Resource and Demand Balancing (BAL), Emergency Preparedness and
Operations (EOP), and Transmission Operations (TOP) standards.\179\
Additionally, commenters indicate that reliability scheduling tools,
such as the Interchange Distribution Calculator used in the Eastern
Interconnection and the WebSAS system used in the Western
Interconnection for scheduling, curtailment and ``check out'' processes
may also require modification.\180\
---------------------------------------------------------------------------

    \178\  E.g., Bonneville Power; Duke; EEI; MidAmerican; NRECA;
PNW Parties; Southern.
    \179\ E.g., Duke; EEI; NERC; NRECA; PNW Parties; Southern.
    \180\ E.g., NERC; NRECA; Southern.
---------------------------------------------------------------------------

    143. NRECA cautions that any modifications to NERC standards should
allow for the implementation of intra-hour scheduling but not mandate
this practice. NRECA suggests that NERC be allowed to complete any
updates to its standards associated with implementation of intra-hour
scheduling prior to NAESB undertaking a review to ensure uniformity of
approaches. NV Energy notes that, in order to schedule at 30 minute
intervals or less, the protocols to effectuate such transactions must
be agreed upon by all entities in WECC. Therefore, NV Energy requests
that the Commission defer issuance of the Final Rule until the industry
has had the opportunity to address NERC, WECC and NAESB standards
issues.
    144. PNW Parties state that the Joint Initiative participants found
it necessary to review NERC and NAESB standards as part of their
development of a 30-minute scheduling program, but did not identify in
comments whether any changes to standards or business practices were
needed. PNW Parties suggests, however, that applicable standards and
business practices be reviewed and revised as necessary prior-to
implementing more granular scheduling.
    145. Some commenters within the VER industry request clarification
and/or modification of NERC scheduling protocols to allow for a
resource to be indentified as a ``sink.'' \181\ These commenters claim
that this is necessary because under the Commission's proposed reforms
VERs will be transacting on an intra-hour basis in order to supplement
their variable supply. Iberdrola explains that, in order to enter into
bilateral transactions for balancing energy where a VER's 15-minute
schedule is less than its hour-ahead schedule, the additional balancing
energy purchased from a generator with excess energy would need to be
tagged as the ``source'' and the VER would need to be tagged as the
``sink.'' Iberdrola claims that this is necessary because VERs will be
transacting bilaterally in the sub-hourly timeframe in an effort to
maintain the schedule that was entered prior to the operating hour.
AWEA agrees, arguing that some of the benefits of intra-hour scheduling
will not be realized without this additional clarification. In response
to the potential concerns of transmission providers regarding
generators being tagged as sinks, AWEA and Iberdrola argue that
reliability concerns would only be present when the ultimate delivery
point is unknown.\182\ AWEA explains that the case presented by a VER
transacting as a sink for intra-hour scheduling purposes is entirely
different, as the ultimate delivery point is already known. In this
case, AWEA points out that there is a schedule to deliver energy to a
real load and explains that this schedule is delivering energy to the
load which the VER is unable to serve. Therefore, AWEA and Iberdrola
conclude that such scheduling practices do not present reliability
concerns.
---------------------------------------------------------------------------

    \181\ E.g., AWEA; Iberdrola.
    \182\ E.g., AWEA; Iberdrola.
---------------------------------------------------------------------------

iii. Commission Determination
    146. The Commission concludes that an independent review of NERC
standards and NAESB business practices is not necessary prior to the
implementation of intra-hour scheduling. As noted by NERC, several
entities currently offer intra-hour scheduling without any apparent
conflict with Reliability Standards. NERC comments that it does not
believe there are any existing standards that prohibit industry from
implementing intra-hour scheduling, and no commenters have pointed to
specific NAESB business practices that prevent industry from
implementing intra-hour scheduling. The Commission therefore concludes
that it is not necessary to delay adoption of the intra-hour scheduling
requirements of this Final Rule pending further review of NERC
Reliability Standards and NAESB business practices. To the extent
industry believes it is beneficial to refine one or more existing NERC
Reliability Standards or NAESB business practices to reflect intra-hour
scheduling, stakeholders can use existing processes to pursue such
refinements.
    147. With regard to the requests from AWEA and Iberdrola to allow a
VER resource to be designated as a ``sink'' for purposes of
transmission scheduling, rules for scheduling transmission segments are
set forth in NAESB's Coordinate Interchange Standards,\183\ which have
been incorporated into the Commission's regulations by reference.\184\
The Proposed Rule did not propose any changes to those rules and the
Commission declines to interpret the application to any particular
transactions in this generic rulemaking proceeding.
---------------------------------------------------------------------------

    \183\ NAESB WEQ-004, App. C, Sec.  2 (Commercial Timing Table).
    \184\ See 18 CFR 38.2 (2011).
---------------------------------------------------------------------------

3. Other Issues
a. Comments
    148. Several commenters question the application of intra-hour
scheduling reforms to HVDC transmission lines. Clean Line states that
HVDC

transmission lines can precisely control power and, thus, are typically
expected to submit schedules to public utility transmission providers.
Clean Line requests that HVDC transmission lines receive equal
treatment and be allowed to submit intra-hour schedules on the same
basis as generators. In contrast, ALLETE and Midwest ISO Transmission
Owners both request that the Commission grant an exemption from 15-
minute schedules for HVDC transmission lines. These commenters argue
that 15-minute scheduling of HVDC transmission lines could lead to an
increase in the duty on the load tap changers of HVDC converter
transformers, potentially resulting in an increase in maintenance costs
and an increased potential of transformer failure.
    149. Bonneville Power raises questions regarding the impact of
intra-hour scheduling on dynamic scheduling practices. Bonneville Power
states that 15-minute scheduling will lead to increased ramping and
inhibit the availability of dynamic transfer capability in areas where
dynamic transfer capability is limited, such as the Bonneville Power
system and other parts of the West. Bonneville Power contends that 30-
minute scheduling relieves this problem and requests that the
Commission gain a better understanding of the impacts that 15-minute
scheduling will have on dynamic transfers. In contrast, First Wind
requests that the Commission encourage dynamic transfers in addition to
implementing intra-hour scheduling, suggesting that dynamic transfers
can reduce regulation service requirements for transmission owners and
transfer regulation requirements to purchasers of VER energy. First
Wind also argues that intra-hour scheduling and dynamic transfers will
allow for better tracking of real-time generation and reduce the need
for ancillary services while increasing opportunities for flexible
generation and demand response.
    150. M-S-R Public Power Agency states that shortening the
scheduling interval does not reduce the intermittency of the VERs
themselves. M-S-R Public Power Agency offers that as a matter of
physics a VER requires a back-up resource to ``balance'' its
intermittency, irrespective of scheduling, adding that while a shorter
scheduling interval may mitigate the number of megawatts needed to
assure reliability, it will not mitigate the location or cost of back-
up reserves. M-S-R Public Power Agency goes on to state that VER
penetration levels of 20-25 percent start to exhaust the capability of
even the most robust systems and that the proposed mitigation may be
insufficient. M-S-R Public Power Agency explains that the raw energy of
VERs must be converted to conditioned energy (traditional resources) at
the source, and not shifted to other locations through mitigation, or
there will be a degradation of services to all VERs within that system.
M-S-R Public Power Agency states that intermittent resources require
that the transmission owner have nearly infinite capability to provide
backup resources; however, even the most robust balancing authority has
limitations of how fast, how often, and when it can provide back up
resources. M-S-R Public Power Agency offers that, with both the cost of
transmission and reliability (back-up generation) challenges, VERs may
be uneconomic. M-S-R Public Power Agency encourages the Commission to
solicit input on this issue.

Commission Determination

    151. All transmission customers that are currently eligible to
submit hourly energy schedules will be eligible to participate in
intra-hour scheduling, including HVDC lines that currently submit
hourly energy schedules. To the extent a transmission provider believes
an exemption is appropriate, it has the right to request a waiver of
all or part of the OATT requirements as described in 18 CFR 35.28(d):
``A public utility subject to the requirements of this section and
Order No. 889, FERC Stats. & Regs. ]31,037 (Final Rule on Open Access
Same-Time Information System and Standards of Conduct) may file a
request for waiver of all or part of the requirements of this section,
or Part 37 (Open Access Same-Time Information System and Standards of
Conduct for Public Utilities), for good cause shown.'' Waiver requests
will be evaluated in separate proceedings if and when they are
submitted based on the facts and circumstances of each request.
    152. With regard to the use of dynamic schedules, the Commission
did not propose and is not adopting any change in policy with regard to
dynamic scheduling. The Commission is not persuaded by arguments from
Bonneville Power that 15-minute scheduling intervals will negatively
affect dynamic transfer capability. However, the Commission
acknowledges that a transmission provider's implementation of charges
for generator regulation service, as discussed in the following
section, may have the result of encouraging the use of dynamic
scheduling to avoid such charges.
    153. In response to M-S-R Public Power Agency, the Commission
appreciates that the location of a particular resource can be relevant
in determining whether it can be used to satisfy reserve obligations.
That is, a public utility transmission provider providing ancillary
services under the pro forma OATT, or a transmission customer self-
supplying such ancillary services needs transmission capacity to ensure
deliverability of a particular resource. Whether that is the case will
be fact specific and we expect the transmission provider to take the
appropriate steps to ensure such transmission capacity is available.

B. Data Reporting To Support Power Production Forecasting

    154. The second of the two reforms adopted in this Final Rule
relates to the submission of meteorological and forced outage
data,\185\ by new interconnection customers whose generating facilities
are VERs, to the public utility transmission provider with which the
customer is interconnected if the public utility transmission provider
is doing power production forecasting. As discussed below, the
Commission amends the pro forma LGIA to effectuate this data reporting
requirement. The Commission concludes that, without these reporting
requirements in place, the terms of the pro forma LGIA may impair the
ability of public utility transmission providers to develop and deploy
power production forecasting, which in turn can lead to rates for
jurisdictional services that are unjust and unreasonable or unduly
discriminatory.
---------------------------------------------------------------------------

    \185\ The Proposed Rule used the term ``operational data'' and
specified forced outages as a particular type of operational data.
To reflect the limited nature of data to be reported under this
Final Rule more accurately, the Commission instead refers more
specifically to ``forced outage data'' in our determinations here
and accompanying revisions to the pro forma LGIA. We also note that
Section 9.7.1 of the LGIA requires Transmission Providers and
Interconnection Customers to coordinate and report planned outages.
Within the context of this Final Rule, the Commission references the
term ``forced outage'' as defined by NERC. See NERC Glossary of
terms available at http://www.nerc.com/files/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------

1. Data Requirements
a. Commission Proposal
    155. To facilitate the development and deployment of power
production forecasting by public utility transmission providers, the
Proposed Rule set forth revisions to the pro forma LGIA that would
require interconnection customers whose generating facilities are VERs
to provide certain meteorological and operational data to the public
utility transmission provider with whom they are

interconnected, if doing forecasting. The Commission proposed that such
data would be transmitted from the interconnection customer to the
public utility transmission provider at or near real-time. The
Commission stated that this proposal built on existing Commission data-
sharing requirements by outlining specific meteorological and
operational data necessary to develop power production forecasts.\186\
---------------------------------------------------------------------------

    \186\ See Proposed Rule, FERC Stats. & Regs. ] 32,664 at PP 60-
61.
---------------------------------------------------------------------------

    156. With regard to the reporting of meteorological data, the
Commission proposed revisions to the pro forma LGIA that would result
in different types of meteorological information being provided by
interconnection customers based on the type of VER they own and/or
operate. The Commission proposed to require interconnection customers
whose generating facilities are wind-based VERs to provide public
utility transmission providers with site-specific meteorological data
including, but not limited to, temperature, wind speed, wind direction,
and atmospheric pressure. The Commission proposed to require
interconnection customers whose generating facilities are solar-based
VERs to provide public utility transmission providers with site-
specific meteorological data including, but not limited to,
temperature, atmospheric pressure, and cloud cover. The Commission
recognized that different power production forecasts may require
meteorological instruments to be located at hub height, up-wind of
resources, or at ground level. However, the Commission refrained from
proposing specific requirements in this respect and, instead, proposed
to allow the public utility transmission provider and interconnection
customers to negotiate these details taking into account the size and
configuration of the VER facility, its characteristics, location, and
importance in maintaining generation resource adequacy and transmission
system reliability in its area. The Commission stated that resource-
specific data requirements contained in individual LGIAs must be
negotiated on a not unduly discriminatory basis.\187\
---------------------------------------------------------------------------

    \187\ See id. P 61.
---------------------------------------------------------------------------

    157. With respect to the reporting of operational data, the
Commission proposed to revise the pro forma LGIA to require
interconnection customers whose generating facilities are VERs to
report to the public utility transmission provider any forced outages
that reduce the generating capability of the resource by 1 MW or more
for 15 minutes or more. The Commission noted that provision of VER
outage data at this level of granularity would allow a public utility
transmission provider to ascertain the extent to which current VER
power production is a result of unit availability as opposed to
changing weather conditions.\188\ The Commission preliminarily found
that having such information would eliminate a significant source of
forecasting errors by ensuring that the public utility transmission
provider has accurate information regarding the capacity actually
available to produce electricity during the time-frame of the
operational forecasts.\189\
---------------------------------------------------------------------------

    \188\ See id. P 62 (citing Cal. Indep. Sys. Operator Corp., 131
FERC ] 61,087, at P 64 (2010)).
    \189\ Id. P 62.
---------------------------------------------------------------------------

    158. The Commission sought comment on the extent to which the lists
of basic meteorological and operational data articulated above may be
inadequate or incomplete in achieving the stated power production
forecasting goals.\190\
---------------------------------------------------------------------------

    \190\ Id. P 63.
---------------------------------------------------------------------------

b. Comments
    159. Commenters addressing the reporting of meteorological data
generally support requiring the provision of data as necessary to
enable public utility transmission providers to employ power production
forecasts.\191\ While disagreeing that public utility transmission
providers should be responsible for power production forecasting,
Montana PSC argues that, should the Commission impose forecasting
requirements, public utility transmission providers should have access
to all meteorological data that are site-specific to the VER, provided
that the parties have a confidentiality agreement in place to protect
proprietary information. BP Companies and First Wind request that the
Commission clarify that the proposal is only relevant to instances in
which the public utility transmission provider is developing and/or
implementing VER power production forecasting.
---------------------------------------------------------------------------

    \191\ E.g., AWEA; Bonneville Power; California ISO; CEERT; Clean
Line; California PUC; Exelon; First Wind; Iberdrola; Independent
Energy Producers; Independent Power Producers Coalition-West; ISO/
RTO Council; ISO New England; Large Public Power; Midwest ISO;
Midwest ISO Transmission Owners; NaturEner; NextEra; NRECA; Pacific
Gas & Electric; PJM; Powerex.
---------------------------------------------------------------------------

    160. Several commenters support the Commission's identification of
certain categories of meteorological data to be provided by wind and
solar resources.\192\ For example, with regard to wind resources,
Iberdrola agrees that wind speed, wind direction, temperature and
pressure are all key atmospheric variables related to wind farm output
and are the most important fields to measure. With regard to solar
resources, NextEra, SEIA, and Xcel generally support the minimum
categories of data identified in the Proposed Rule, but they suggest
that the Commission revise the reference to cloud cover because it is
ambiguous. Specifically, NextEra and SEIA recommend that the Commission
require solar resources to report diffuse, direct, and global
horizontal irradiance. NextEra adds that humidity should also be
provided for a solar VER using concentrating thermal solar technology,
while SEIA suggests that plane of array irradiance or direct normal
radiation may also be necessary. These commenters note that irradiance
is often a better measure because it actually drives energy production.
---------------------------------------------------------------------------

    \192\ E.g., AWEA; Iberdrola; ISO New England; RENEW.
---------------------------------------------------------------------------

    161. Commenters generally support the Commission's proposal to
allow the public utility transmission provider and interconnection
customer to negotiate additional meteorological and operational data
reporting requirements.\193\ Commenters identified a variety of
additional meteorological and facility-specific data that may be useful
in developing and deploying power production forecasts. These
commenters generally note that regional differences may dictate
additional data needs,\194\ with several asking the Commission to
acknowledge that additional data beyond that specifically identified in
the Proposed Rule may be needed by a public utility transmission
provider.\195\
---------------------------------------------------------------------------

    \193\ E.g., Bonneville Power; ISO New England; ISO/RTO Council;
Large Public Power Council; Midwest ISO; NRECA; PNW Parties; RENEW;
Xcel.
    \194\ E.g., Bonneville Power; First Energy; ISO New England;
ISO/RTO Council; NextEra; MidAmerican; Midwest ISO; Midwest ISO
Transmission Owners; NorthWestern; NRECA; Pacific Gas & Electric;
Xcel.
    \195\ E.g., Bonneville Power; ISO New England; Midwest ISO;
NextEra; NRECA.
---------------------------------------------------------------------------

    162. Several commenters raise concerns regarding the Commission's
discussion of the location of meteorological towers and other equipment
necessary to record and report data to public utility transmission
providers.\196\ NextEra asks that the Commission refrain from allowing
public utility transmission providers to require VERs to install
multiple meteorological towers, arguing that data beyond what is
available through one meteorological tower has little value for
advanced power production forecasting methods. Invenergy similarly
argues that a single meteorological tower per

facility is usually sufficient for predicting plant output.
---------------------------------------------------------------------------

    \196\ E.g., AWEA; Invenergy; NextEra.
---------------------------------------------------------------------------

    163. With regard to the frequency of reporting meteorological data,
several commenters suggest that the frequency of data reporting should
match the use of the data, which may not be at or near real-time.\197\
For example, AWEA, Iberdrola, and NextEra state that second-by-second
or minute-by-minute meteorological recordings yield minimal benefits
for forecasting accuracy and could be costly and burdensome. AWEA and
Clean Line suggest that a reasonable requirement for the frequency at
which real-time meteorological and operational data is reported from a
wind plant is 10 minutes or more. NorthWestern, however, states that it
would be helpful to require each VER to update the forecasting data
that it has provided to the public utility transmission provider when
it provides a new energy schedule.
---------------------------------------------------------------------------

    \197\ E.g., AWEA; Clean Line; Iberdrola; NextEra; NaturEner;
NorthWestern; Public Interest Organizations.
---------------------------------------------------------------------------

    164. AWEA and Iberdrola also contend that distinctions should be
made between the types of data that should be provided in real-time and
the types of data that should be provided historically. These
commenters state that archived time series data are crucial to
statistical forecasting techniques and that this application is not
done in real-time. AWEA and Iberdrola state that data needed for
forecast training can be compiled into larger datasets and transmitted
at less frequent intervals at a much lower cost. RenewElec and
Bonneville Power generally agree that there is significant value in
historical data recorded by VERs.
    165. With regard to the operational data reporting requirements,
some commenters urge the Commission to adopt the proposed requirement
that VERs report to the public utility transmission provider any forced
outages that reduce the generating capacity of a resource by 1 MW or
more for 15 minutes or more.\198\ For example, Bonneville Power states
that having access to forced outage information will enable public
utility transmission providers to determine whether forecast inaccuracy
results from unit availability, changing weather conditions, or a
combination of the two. Bonneville Power further states that without
such information it will be difficult to verify forecasts and improve
forecast accuracy. California ISO requests that the Commission not
overturn its recent decision approving California ISO's 1 MW threshold
for reporting a forced outage of an eligible intermittent resource.
California ISO argues that outage reporting requirements that are less
stringent than those proposed would increase the likelihood that the
forecasting algorithm would accumulate inaccurate data.
---------------------------------------------------------------------------

    \198\ E.g., Bonneville Power; California ISO; NRECA.
---------------------------------------------------------------------------

    166. Other commenters acknowledge that forced outage data are
useful in developing power production forecasts, but disagree on the
exact reporting requirements.\199\ Some commenters contend that a 1 MW
reporting threshold would pose an unnecessary burden on a wind plant
owner/operator, yield minimal benefits for forecast accuracy, and pose
compliance difficulties.\200\ Instead of the proposed requirement,
NaturEner recommends requiring that only planned outages of greater
than 15 percent of the generator's capacity should be reported as soon
as they are known by the generator. AWEA suggests that reporting apply
only to forced outages that exceed 10 percent of the nameplate capacity
of a plant, a requirement that AWEA states is similar to the one
imposed on conventional generators. NextEra similarly asks that the
outage reporting requirements be identical to those that apply to
conventional resources. MidAmerican recommends that VER transmission
customers be required to report forced outages lasting more than 24
hours and involving the lesser of either 20 MW or 50 percent of
nameplate capacity. Xcel recommends that the Commission ask NERC to
analyze and determine the appropriate threshold level for reporting VER
outages to public utility transmission providers and balancing
authorities.
---------------------------------------------------------------------------

    \199\ E.g., AWEA; Exelon; NaturEner; SEIA; Xcel; MidAmerican;
NextEra.
    \200\ E.g., AWEA; Iberdrola; NaturEner; MidAmerican; PJM.
---------------------------------------------------------------------------

    167. SEIA contends that the forced outage reporting requirement may
be appropriate for large solar photovoltaic generators, but not for
concentrating solar plants that experience frequent changes in power
output. SEIA states that, with respect to concentrating solar power-
generating facilities, the Commission should consider a threshold for
reporting such fluctuations based either on the total capacity of the
facility or particular types of maintenance or repair activities that
would result in an outage at a percentage of the facility.
    168. Exelon asks the Commission to clarify what constitutes a
forced outage for purposes of the requirement to report operational
data, suggesting it should only include unanticipated outage events.
NRECA notes that the Proposed Rule did not identify the frequency for
reporting operational data to the public utility transmission provider.
NRECA contends that the public utility transmission provider should be
notified as soon as the VER is aware of an outage.
    169. Several commenters recommend that the Commission provide
regional flexibility with respect to the operational data reporting
requirements.\201\ For example, Iberdrola states that VER forced outage
reporting requirements should be regional and: (1) Based on the
penetration of VERs in the region; (2) based on the ability of the
transmission provider to incorporate the data into power production
forecasting from VERs that is in turn used for reliably operating the
system; and (3) limited to an interval that enables the use of
predictive outage reporting capability.
---------------------------------------------------------------------------

    \201\ E.g., Iberdrola; ISO New England; Midwest ISO Transmission
Owners; PJM; Southern California Edison.
---------------------------------------------------------------------------

    170. Some commenters argue that the Commission should acknowledge
the importance of standardized regional reporting mechanisms when
considering these proposed reforms.\202\ For example, Midwest ISO notes
that IEC Standard 61400-25 already exists to facilitate the exchange of
information between individual wind turbines, their constituent
components, wind power plants, area control, and other external
systems. Midwest ISO suggests that use of a common format for
communicating data between the VER and public utility transmission
provider would promote the development of power production forecasting.
However, Invenergy asks that the Commission make clear that public
utility transmission providers are required to accept reasonable
alternative means of data communication and not implement uniform
standards that impose unnecessary costs on wind projects.
---------------------------------------------------------------------------

    \202\ E.g., Alstom; EEI; Midwest ISO.
---------------------------------------------------------------------------

c. Commission Determination
    171. The Commission adopts, as modified below, the proposed
requirement that interconnection customers whose generating facilities
are VERs provide meteorological and forced outage data to the public
utility transmission provider with which the customer is
interconnected, where necessary for that public utility transmission
provider to develop and deploy power production forecasting. As
discussed below, power production forecasting can be used by public
utility transmission providers to operate their

systems and manage reserves more efficiently. To the extent a public
utility transmission provider seeks to rely on power production
forecasting, the Commission concludes it is appropriate to require new
interconnection customers whose generating facilities are VERs to
provide related data to the public utility transmission provider under
the circumstances below. The Commission therefore directs public
utility transmission providers to modify their pro forma LGIAs to
effectuate the data reporting requirement.
    172. As the Commission noted in the Proposed Rule, industry studies
demonstrate the potential for significant benefits from the
incorporation of power production forecasts into scheduling and unit
commitment processes. In WECC alone, NREL estimated the use of VER
power production forecasts has the potential to reduce operating costs
by up to 14 percent or $5 billion per year.\203\ NERC has similarly
concluded that forecasting the output of variable generation is
critical to bulk power system reliability in order to ensure that
adequate resources are available for ancillary services and ramping
requirements.\204\ NERC has therefore recommended that forecasting
techniques be incorporated into day-to-day operational planning and
real-time operations routines/practices including unit commitment and
dispatch.\205\ The Commission notes that the benefits of power
production forecasting can accrue across a variety of time frames,
including the operating day, day-ahead, and seasonally.
---------------------------------------------------------------------------

    \203\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 45
(citing National Renewable Energy Laboratory, Western Wind and Solar
Integration Study ES-18 (2010), available at http://www.nrel.gov/wind/systemsintegration/wwsis.html).
    \204\ NERC, Accommodating High Levels of Variable Generation 54
(2009), available at http://www.nerc.com/files/IVGTF_Report_041609.pdf.
    \205\ Id. at 59.
---------------------------------------------------------------------------

    173. However, power production forecasts are only as good as the
data on which they rely. The ability of public utility transmission
providers to use power production forecasting in the commitment and de-
commitment of resources may be limited without adequate meteorological
and forced outage data from VERs. The current lack of meteorological
and forced outage data reporting requirements in the pro forma LGIA
therefore may limit efforts by public utility transmission providers to
more efficiently manage operating costs associated with the integration
of VERs interconnecting to their systems. Under the existing
requirements of the pro forma LGIA, public utility transmission
providers are permitted to request this information, but there is no
obligation for interconnection customers whose generating facilities
are VERs to provide it. The Commission remedies this deficiency by
adopting reporting requirements for new interconnection customers whose
facilities are VERs, commensurate with the power production forecasting
employed by the public utility transmission provider, to allow for more
accurate commitment and de-commitment of resources providing reserves,
ensuring that reserve-related charges imposed on customers remain just
and reasonable and not unduly discriminatory or preferential. The
Commission implements this requirement by requiring public utility
transmission providers to modify their pro forma LGIAs to include the
reporting requirements discussed below.
    174. The reporting requirements adopted in this Final Rule are
specifically designed to support the development and deployment of
power production forecasting by public utility transmission providers.
As a result, nothing in this Final Rule should be construed as creating
an obligation for interconnection customers whose generating facilities
are VERs to provide meteorological and forced outage data in cases
where the public utility transmission provider is not engaging in power
production forecasting. The Commission recognizes that VER potential
and penetration varies across public utility transmission provider
systems and that, at this time, not all public utility transmission
providers have sufficient levels of VERs to warrant engaging in power
production forecasting. The Commission is nonetheless amending the pro
forma LGIA to ensure that those public utility transmission providers
seeking to develop and deploy power production forecasting in response
to increasing VER penetration have adequate information to do so. To
make the conditional nature of the reporting requirements clear, the
Commission revises the proposed Article 8.4 of the pro forma LGIA to
state that all requirements for meteorological and forced outage data
must be consistent with the power production forecasting employed by
the Transmission Provider, if any, to manage reserve commitments. The
Commission believes that this strikes a reasonable balance between the
requirement to provide the data and the public utility transmission
provider's use of the data to manage reserve commitments more
efficiently.
    175. Turning to the particular reporting requirements imposed on
interconnection customers whose generating facilities are VERs, the
Commission affirms the approach set forth in the Proposed Rule allowing
public utility transmission providers flexibility in identifying the
specific meteorological and forced outage data to be reported. As
proposed, Article 8.4 of the pro forma LGIA would specify certain
categories of data to be provided by interconnection customers with
VERs having wind or solar as the energy source, with the exact
specifications of data to be provided taking into account the size and
configuration of the VER, its characteristics, location, and its
importance in maintaining generation resource adequacy and transmission
system reliability in its area. Some commenters generally support this
approach, stating that the type of power production forecasting
deployed by public utility transmission providers and the tools used to
perform forecasts could vary widely, and therefore any reporting
requirements associated with power production forecasting should be
flexible.\206\ This approach will provide public utility transmission
providers the flexibility to negotiate, in the first instance, with
interconnection customers whose generating facilities are VERs to
identify the particular data to be reported by the customer.
---------------------------------------------------------------------------

    \206\ E.g., Iberdrola; NextEra.
---------------------------------------------------------------------------

    176. The Commission finds that this flexible approach to
establishing data reporting requirements will ensure that all reporting
of meteorological and forced outage data corresponds with the power
production forecasting being employed by the public utility
transmission providers. To be clear, however, public utility
transmission providers cannot unduly discriminate among interconnection
customers with regard to data reporting requirements. By linking the
requirement to provide meteorological and forced outage data to the use
of these data by the public utility transmission provider in power
production forecasting to manage reserve commitments, the Commission
seeks to minimize opportunities for undue discrimination as well as
needless burden on interconnection customers. At the same time, to the
extent meteorological and forced outage data are needed for the public
utility transmission provider to engage in power production
forecasting, they must be provided by the interconnection customer,
even if that means investment in additional equipment by the
customer.\207\ To the extent there are

concerns of discriminatory or unnecessary application of data reporting
requirements, interconnection customers can request that the public
utility transmission provider file with the Commission an unexecuted
LGIA in order to resolve the disagreement.\208\
---------------------------------------------------------------------------

    \207\ The Commission acknowledges the concern of some commenters
that the installation of multiple meteorological towers would
increase costs for an interconnection customer. Whether data from a
single meteorological tower is sufficient to support the power
production forecasting deployed by the public utility transmission
provider should be addressed as part of the negotiation of the LGIA.
    \208\ See 16 U.S.C. 824d (2006); 18 CFR 35.13 (2010).
---------------------------------------------------------------------------

    177. Notwithstanding the flexibility provided for party-specific
negotiations of data reporting requirements, the record in this
proceeding also confirms that some categories of meteorological data
from VERs having wind or solar as the energy source will be relevant to
most, if not all, power production forecasting deployed by a public
utility transmission provider for these resources. Therefore, the
Commission adopts the proposal to require certain categories of
meteorological data from VERs having wind or solar as the energy
source. Specifically, an interconnection customer with a VER having
wind as the energy source must provide, at a minimum, site-specific
meteorological data including: Temperature, wind speed, wind direction,
and atmospheric pressure. An interconnection customer with a VER having
solar as the energy source must provide, at a minimum, site-specific
meteorological data including: temperature, atmospheric pressure, and
irradiance. The exact specifications of data to be provided by the
interconnection customer will remain subject to negotiation between the
parties, which as noted above must take into account the size and
configuration of the VER, its characteristics, location, and its
importance in maintaining generation resource adequacy and transmission
system reliability in its area. It may also include additional
meteorological data commensurate with the power production forecasting
employed by the public utility transmission provider. As with other
data reporting requirements, the public utility transmission provider
may file an unexecuted LGIA pursuant to FPA section 205 seeking to
demonstrate the necessity of requests for additional information if the
parties cannot reach mutual agreement as to the specifications of data
to be provided.\209\
---------------------------------------------------------------------------

    \209\ Id.
---------------------------------------------------------------------------

    178. By defining certain categories of data that must be provided,
while leaving the exact specifications of data to negotiation between
the interconnection customer and the public utility transmission
provider, the Commission has sought to balance the competing interests
of clarity and flexibility. The Commission appreciates that defining
all data requirements with precision in this Final Rule might result in
rules that are easier to implement. However, it also could lead to
interconnection customers incurring costs to provide data at a level of
granularity, for example, that is of no use to the public utility
transmission provider given the type of power production forecasting
deployed. By linking the reporting requirements to the data needs of
the public utility transmission provider, the Commission seeks to
facilitate the deployment of power production forecasting without
unduly burdening the interconnection customer.
    179. In the Proposed Rule, the Commission included ``cloud cover''
within the categories of data required of interconnection customers
with a VER having solar as the energy source. The Commission agrees
with commenters that the term ``cloud cover'' is imprecise and thus we
modify Article 8.4 of the pro forma LGIA to refer to ``irradiance.''
However, the Commission declines to distinguish between types of
irradiance and also declines to include ``humidity'' in the minimal
categories of data. These additional characteristics may be more
relevant for some types of facilities than others, so we leave to
public utility transmission providers and their interconnection
customers to identify the specifications of data relevant for
reporting.
    180. With regard to the frequency and timing of data reporting, the
Commission modifies the Proposed Rule and allows public utility
transmission providers and interconnection customers whose generating
facilities are VERs to negotiate the frequency and timing of data
submittals. The Proposed Rule would have required the reporting of data
at or near real-time. In response, commenters such as AWEA and
Iberdrola note that some power production forecasts use archived time
series data that may be compiled and transmitted to public utility
transmission providers at a significant costs savings when compared to
the ongoing reporting of data at or near real-time, whereas
NorthWestern suggests that data could be provided on a ten-minute or
longer basis. Based on comments received, the Commission concludes it
is more appropriate for the frequency and timing data submittals to be
negotiated by the parties to ensure that the reporting of data is
consistent with the type of power production forecasting being deployed
by the public utility transmission provider. The Commission revises
Article 8.4 of the pro forma LGIA accordingly.
    181. In the Proposed Rule, the Commission sought to require the
reporting of forced outages of 1 MW or more for 15 minutes or more. In
response, commenters disagree as to the relevant level of granularity
for outage data. Rather than establish a specific megawatt reporting
threshold or frequency that could result in the reporting of data that
are not used by the public utility transmission provider, the
Commission concludes it is more appropriate for the public utility
transmission provider and interconnection customer to negotiate the
exact specifications of forced outage data to be provided, taking into
account the size and configuration of the VER, its characteristics,
location, and its importance in maintaining generation resource
adequacy and transmission system reliability in its area. As noted in
the Proposed Rule, this will provide the flexibility necessary to
ensure that the reporting of forced outage data is commensurate with
the power production forecasting being employed by the public utility
transmission provider, consistent with any regional practices that may
exist. Therefore, the Commission modifies the Proposed Rule to align
the reporting of forced outages with the power production forecasting
being employed by the public utility transmission provider. The
Commission also declines to adopt alternative minimum thresholds or
pre-define forced outages for purposes of reporting requirements as
requested by some commenters.
    182. Some commenters request that the Commission standardize
protocols for reporting meteorological or forced outage data required
by this Final Rule. The Proposed Rule did not contain standard
protocols for data reporting and, as a result, the merits of such a
requirement have not been fully addressed in the record. Whether
standardization of data communications would facilitate or hinder
development of power production forecasting may implicate a variety of
data and communications issues that would benefit from broad industry
input through standards development processes such as those used by
NAESB and other organizations.
d. LGIA
    183. In order to effectuate the reporting requirements discussed
above, the Proposed Rule set forth amendments to the pro forma LGIA
adding a new section Article 8.4, Provision of Data from a Variable
Energy Resource.

Consistent with the approach of Order Nos. 2003 and 661,\210\ the
Commission proposed not to require retroactive changes to LGIAs that
are already in effect. However, the Commission sought comment as to
whether this approach would prevent public utility transmission
providers from effectively implementing power production
forecasting.\211\ The Commission also preliminarily found that the pro
forma LGIA includes adequate confidentiality protections for sensitive
data obtained from VERs.\212\
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    \210\ Order No. 661, FERC Stats. & Regs. ] 31,186 at P 120;
Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 910.
    \211\ See Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 64.
    \212\ Id. P 60 (citing Pro Forma LGIA Article 22, which sets
forth the confidentiality provisions applicable to data exchanged
through the interconnection process).
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    184. The Commission noted that it was proposing revisions only to
interconnection customers whose generating facilities are VERs greater
than 20 MW and, as a result, proposing revisions only to the pro forma
LGIA and not the pro forma Small Generator Interconnection Agreement
(SGIA). The Commission sought comment on whether the proposed reforms
should also apply to interconnection customers whose generating
facilities are VERs of 20 MW or less, so as to require revisions to the
pro forma SGIA.
e. Comments
    185. The Commission received a variety of comments on its proposal
to not require retroactive changes to LGIAs that are in effect.
NaturEner argues that without data from existing resources, power
production forecasts would be less reliable or robust, resulting in
artificially high required reserves and attendant expenses. AWEA, Clean
Line, and Iberdrola state that they would not oppose requiring data
from resources that have executed an LGIA, provided that the
interconnection customers are only required to report data that are
currently gathered by the VER. AWEA explains that data already are
being collected by many wind plants deployed since 2005 and that many
public utility transmission providers have already imposed reporting
requirements. However, Southern MN Municipal asserts that the proposed
reforms should not be extended to resources that have already executed
an interconnection agreement. Bonneville Power asserts that Articles
9.3 and 9.4 of the LGIA give the transmission provider a unilateral
right to update its instructions and operating protocols and procedures
regardless of whether the proposed Article 8.4 is applied
retroactively.
    186. Midwest ISO Transmission Owners request that the Commission
address the circumstances under which a VER with an existing
interconnection agreement might become subject to the new power
production forecasting requirement if it is applied prospectively.
Midwest ISO Transmission Owners state that, at the very least, any
increase in a facility's generating capacity or material modification
that would necessitate a new LGIA should be sufficient to subject the
VER generator to the new power production forecasting-related data
requirements under the applicable tariff.
    187. Some commenters suggest implementing reporting requirements
for meteorological and forced outage data through the pro forma OATT in
order to impose those requirements on existing resources or otherwise
allow for changes in reporting requirements over time.\213\ AWEA
contends that, if the Commission determines to apply the reporting
requirements to existing resources, it would be more appropriate to
place the requirements in the pro forma OATT. Sunflower and Mid-Kansas
agree, noting that the pro forma LGIA already requires parties to
operate their facilities consistent with Applicable Laws and
Regulations, including OATT requirements. Large Public Power argues
that it is important that all VERs provide the operational information
required by a transmission provider and, therefore, also recommends
placing reporting requirements in the transmission tariff. Southern
California Edison contends that placing reporting requirements in the
pro forma OATT would allow greater flexibility in structuring
agreements by referencing requirements in the California ISO Tariff, as
they may change from time to time.
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    \213\ E.g., AWEA; Large Public Power; Southern California
Edison; Sunflower and Mid-Kansas.
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    188. Other commenters ask the Commission to allow reporting
requirements to be stated in market rules or business practices.\214\
ISO New England requests that the Commission afford flexibility for
public utility transmission providers to determine the mechanism by
which to collect the required VER data. National Grid states that
rather than requiring a proscriptive amendment of the pro forma LGIA,
the Commission should require each region to work with its stakeholders
to develop appropriate methods for forecasting the energy output from
VERs. Pacific Gas & Electric requests that in its Final Rule the
Commission provide latitude for the California ISO and other similarly-
situated transmission providers to continue their existing programs for
gathering relevant meteorological and operational data, and proposing
incremental refinements to them, so long as they conform to the
purposes of the Final Rule. Xcel similarly argues that the specific
data requirements for individual public utility transmission providers
should be identified through a business practice or other OASIS posting
to allow adjustments due to changing system operating needs,
improvements in meteorological forecasting technologies, or
modifications in NERC reliability requirements.
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    \214\ E.g., California PUC; Dominion; ISO New England; National
Grid; Pacific Gas & Electric.
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    189. With regard to the Commission's question as to whether the pro
forma SGIA needs to be revised, many parties argue that the provision
of data under the SGIA may be appropriate in some instances.\215\ PJM
and Snohomish County PUD note that the costs of reporting the proposed
data to public utility transmission providers by small VERs could be
higher than for larger resources. As such, they argue that the
Commission should carefully consider these costs when applying
reporting requirements. Several other commenters acknowledge
difficulties associated with gathering data from resources subject to
the SGIA, and propose a variety of thresholds to determine whether
reporting requirements should apply to the resource.\216\ For example,
AWEA states that it makes sense to apply similar data reporting
requirements to smaller-scale generators where it can be demonstrated
that the data will be used for improving VER forecast accuracy and that
the benefits exceed the cost of data collection. Others state that
small resources should use alternative reporting requirements.\217\
Southern California Edison recommends that the Commission consider an
approach that aggregates individual site data from small generators in
a geographic area, which reduces cost impacts to smaller projects.
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    \215\ E.g., California ISO; EEI; Duke; ISO New England;
MidAmerican; NRECA; Pacific Gas & Electric; PNW Parties; Snohomish
County PUD; Southern California Edison; Tacoma Power; Xcel.
    \216\ E.g., AWEA; RenewElec; SEIA; Tacoma Power; Xcel.
    \217\ E.g., Alstom Grid; RENEW.
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    190. Commenters contend that the public utility transmission
provider should have the flexibility to identify and require data from
small

generators.\218\ For example, Bonneville Power argues that the
Commission should require small VERs to provide meteorological and
operational data according to the requirements established by their
public utility transmission provider. These commenters generally agree
that public utility transmission providers may have different
forecasting needs, and that they require flexibility to address such
issues. NextEra argues that there is no convincing reason to limit the
forecasting requirement to resources larger than 20 MW, and that the
impact of small VERs on system variability is the same as resources
greater than 20 MW. Midwest ISO Transmission Owners note that the
Midwest ISO pro forma Generator Interconnection Agreement (GIA) applies