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

    \311\ E.g., CPUC; ISO RTO Council; Midwest ISO; SEIA.
---------------------------------------------------------------------------

    298. Some commenters support the Commission's recognition that
certain regions may not have a need for VER power production
forecasting because of a low likelihood of VERs development.\312\ For
example, Bonneville Power states that the requirement to implement
centralized forecasting should not apply if the penetration of VERs is
less than 10 percent of load served. Puget argues that it should not be
required to use power production forecasting because it only serves one
exporting VER in its region.
---------------------------------------------------------------------------

    \312\ E.g., Bonneville Power; NextEra; PNW Parties.
---------------------------------------------------------------------------

    299. Several commenters provide detailed discussions of the various
activities that public utility providers should be required to
undertake in order to show power production forecasting is in use.
Public Interest Organizations suggest that the Commission require
public utility transmission providers to demonstrate that VER power
production forecasts are incorporated into unit commitment, scheduling,
and dispatch efforts. Oregon & New Mexico PUC state that at a minimum,
a public utility transmission provider needs to demonstrate that it has
requested meteorological and operational data from wind and solar
generators and has integrated forecast information into control room
operations.
    300. Some commenters contend that the public utility transmission
provider should demonstrate that it is using the VER forecast to
efficiently and reliably commit and dispatch resources. These parties
offer various criteria regarding costs, accepted industry practices,
and performance metrics that should be required of public utility
transmission providers in order to be deemed compliant with the Final
Rule.\313\ The California PUC states that, while it does not recommend
that the Commission set specific minimum quality standards or cost
maximums for VERs forecasts at this time, the Commission should monitor
results of public utility transmission providers' assessments. If the
quality of forecasts varies significantly among public utility
transmission providers, the Commission may determine that minimum
quality standards or maximum cost limits for VERs forecasts are
necessary to prevent unjust, unreasonable, or unduly discriminatory
rates.
---------------------------------------------------------------------------

    \313\ E.g., AWEA; California PUC; Iberdrola; NaturEner.
---------------------------------------------------------------------------

    301. Other commenters argue that the Commission should ensure that
the risks associated with inaccurate schedules or resource specific
forecasts remain with the VER.\314\ Montana PSC states that the
forecasting requirement should be the responsibility of VER instead of
the public utility transmission provider. NorthWestern states that it
is inappropriate to make

the public utility transmission provider responsible for forecasting
the VER power output when it is the responsibility of the VER to
provide its schedule. NorthWestern points out that, if the public
utility transmission provider provides a forecast of the VER power
production, as proposed by the Proposed Rule, and the VER submits a
different schedule, Control Performance Standard 2 violations may occur
that would not have occurred if an accurate power production forecast
had been submitted by the VER. NorthWestern argues that the forecasting
requirement would place the balancing authority in an unacceptable
position if the forecast or power production data is inaccurate.
Midwest ISO Transmission Owners state that regardless of whether the
public utility transmission provider requires VERs to provide
meteorological data or employs other tools in order to increase the
effectiveness of scheduling and dispatching activities, all generation
resources must retain the ultimate responsibility for determining their
unit's deliverability; accordingly, variations from scheduled
deliveries must remain the responsibility of the generating resource,
including VERs.
---------------------------------------------------------------------------

    \314\ E.g., AEP; Large Public Power Council; Midwest ISO
Transmission Owners; Montana PSC; NorthWestern.
---------------------------------------------------------------------------

    302. Bonneville Power argues that, if the Commission requires
centralized power production forecasts for public utility transmission
providers with significant amounts of VERs on their systems that intend
to differentiate their Schedule 10 pricing, it is preferable that the
Commission also require all VERs to schedule according to the
centralized forecast component for each plant. Puget explains that, if
the public utility transmission provider's forecast sets the schedule,
then there could be a perverse incentive for public utility
transmission providers to generate inaccurate forecasts and collect
larger generator imbalance charges under Schedule 9; however, if the
VER is permitted to set its own schedule that differs from the public
utility transmission provider's forecast, it remains unclear how the
public utility transmission provider is supposed to manage and deploy
its resources--according to its own forecast or to the VER's schedule.
Puget requests that these questions be clarified before the Commission
implements a power production forecasting requirement for public
utility transmission providers, whether as a stand-alone mandate or as
a precondition to Schedule 10 cost recovery.
    303. Invenergy argues that the Final Rule should hold public
utility transmission providers: (1) Accountable for the accuracy of the
forecasts that they use to determine regulation capacity requirements;
and (2) to performance levels that current technology supports.
Invenergy states that ISOs and RTOs that have implemented centralized
wind forecasting are generally realizing accuracy rates of 89 percent
or greater. Invenergy argues that the Final Rule should require the
public utility transmission provider to provide customers with
forecasting performance metrics on a periodic basis and, if forecasts
do not prove to be reliable, require the public utility transmission
provider to take immediate steps (including improving its forecasting
systems and equipment or relinquishing responsibilities to an
independent third party) to ensure that future forecasts are accurate.
    304. Commenters state that in RTO regions, the RTO would be the
more appropriate entity to conduct power production forecasting.
National Grid asks the Commission to clarify who the ``transmission
providers'' are that will undertake the energy forecasting
responsibility. National Grid states that the role of developing and
implementing energy forecasting tools is well suited to a centralized
entity with existing capabilities in data collection, region wide
system forecasting and centralized dispatch responsibilities such as
RTOs and ISOs. National Grid requests that the Commission clarify that
for the purposes of its data forecasting Final Rule the term
``transmission provider'' means the ISOs or RTOs in those regions, as
this avoids confusion where the term ``transmission provider'' can
refer to either the ISO or its members.
    305. Some commenters point out that many regions are currently
undertaking their own forecasting and data gathering initiatives or
programs to integrate VERs, and request that the Commission allow for
regional flexibility.\315\ Pacific Gas & Electric requests that
individual public utility transmission providers be given flexibility
on how to implement that requirement. 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 to gather the relevant meteorological
and operational data, and to propose incremental refinements to them,
so long as the programs maintained by these transmission providers can
accomplish the purposes set forth in the Proposed Rule for gathering
this information.
---------------------------------------------------------------------------

    \315\ E.g., Massachusetts DPU; Pacific Gas & Electric; Midwest
ISO.
---------------------------------------------------------------------------

iv. One Year Data Requirement
    306. Some commenters contend that the proposal to require public
utility transmission providers to collect power production forecasting
data for one year prior to instituting a differentiated regulation
requirement for VERs violates cost causation principles and imposes
costs of balancing reserve capacity needed for VERs on other
customers.\316\ Such commenters maintain that the one-year data
collection requirement unreasonably delays public utility transmission
providers from demonstrating that they are entitled to recover
different volumetric amounts associated with providing generator
regulation service from different types of generators.\317\ Bonneville
Power argues that there may be sound economic and operational bases for
providing or procuring differential quantities of incremental and
decremental balancing reserve capacity. Western Farmers suggest that
the Commission allow public utility transmission providers to propose
the volumetric component of the Schedule 10 charge along with the
proposed rates in their initial Schedule 10 compliance filing. Natural
Gas and Puget similarly argue that public utility transmission
providers should have an opportunity to allocate ancillary service
costs as soon as they are justifiably able to do so. MidAmerican
contends that the one-year data collection requirement is inconsistent
with the Westar precedent.
---------------------------------------------------------------------------

    \316\ E.g., Bonneville Power; Puget; MidAmerican; Southern
California Edison; Natural Gas.
    \317\ E.g., EEI; MidAmerican; Puget; WUTC.
---------------------------------------------------------------------------

    307. Some commenters suggest that public utility transmission
providers should be permitted to establish rates using historical data,
subject to adjustment as necessary over time.\318\ For example,
Bonneville Power states that rates can be updated as public utility
transmission providers gain experience with reductions in the need for
balancing reserve capacity requirements associated with intra-hourly
scheduling, centralized forecasting and any other initiatives.
Similarly, Puget suggests that reductions in the VERs volumetric
component could be incorporated into a subsequent rate filing after
implementation of 15-minute scheduling and power production forecasting
by the utility. NorthWestern suggests that, just as the Commission
routinely allows a proposed rate to take effect on an interim basis
subject to refund until final approval is received, the Commission
likewise should consider

applying a similar principle in allowing interim regulating service
cost recovery. Pacific Gas & Electric proposes that until one year's
worth of data are available, public utility transmission providers
should be able to use simulated data to estimate the relative
contribution of load, imports, VERs and other generation for the
overall need for generator regulation reserves.
---------------------------------------------------------------------------

    \318\ E.g., Bonneville Power; Southern California Edison;
California PUC; EEI; NorthWestern.
---------------------------------------------------------------------------

    308. In contrast, Vestas argues that public utility transmission
providers should be required to implement the two operational changes
immediately and then collect data over at least the next 12 months
regarding the levels of schedule deviations on their systems for all
types of generation. According to Vestas, the Commission should require
the submission of that data to the Commission and take comments from
interested market participants on the appropriate rate mechanism to
permit the recovery of any costs incurred to address remaining
variations between generator schedules and generator output.
    309. Organization of Midwest ISO States asks the Commission to
require public utility transmission providers with significant VER
capacity, such as three percent or more of total capacity, to submit
statistical data on the variability of generation across the different
types of generation resources and load. If there is a significant
difference between types of resources, Organization of Midwest ISO
States contends that the public utility transmission provider should be
required to allocate the costs of increased regulation and other
ancillary services developed in the future to the generation resources
causing those costs.
v. Other
    310. Some commenters express concern about the static nature of the
rates and volumes in Schedule 10.\319\ SEIA argues that public utility
transmission providers who have selected a methodology and begun to
apply different Schedule 10 rates for different categories of customers
should be required to revisit their forecasting methodologies and rates
on a regular basis. RenewElec notes that data collected over a one-year
period that may feature anomalies (e.g., wind droughts). RenewElec
suggests that the Commission require transmission providers to retain
data provided under the new pro forma LGIA Article 8.4 for at least 10
years and commit to performing annual follow-up studies over a period
of not less than five years that update power production forecasts with
new data received. RenewElec suggests that the Commission include a
biannual re-opener provision for VER-specific Schedule 10 charges, or
through other review and implementation combinations.
---------------------------------------------------------------------------

    \319\ E.g., SEIA, RenewElec, NaturEner.
---------------------------------------------------------------------------

    311. NaturEner asserts that an annual re-evaluation of the
integration charge needs to be undertaken to take into account the
impact of increased diversity, improved operations, market innovations
and other changed circumstances, as well as to correct any inaccuracy
in the original (or immediately prior) assessment. NaturEner also
requests clarification regarding whether a VER transmission customer
could be required to pay a VER integration charge in arrears if a
public utility transmission provider is subsequently permitted to levy
the charge.
    312. Some commenters oppose the Commission's proposal to group
resources together for the purpose of allocating Schedule 10
volumes.\320\ For example, BrightSource states that assigning all VERs
the same regulation requirement could distort the incentives created by
the cost allocation if they are evaluated as a single, undifferentiated
class. First Wind asserts that the rate should be designed to recognize
the actual variability of output of the resource paying the rate
because two wind generation projects of the same installed capacity and
energy production might have different levels of variability due to
factors such as local differences in the variability of the ``wind
resource'' (the relative wind generating value of the location); the
number, size, and manufacturer of the wind turbines; and differences in
distances between wind turbines. RenewElec offers that high capacity
wind generation units have a disproportionally smaller impact on
variability than lower capacity units. According to AWEA, the
variability of resources within a category cancels each other out to
the benefit of those resources in that category, imposing a
disadvantage on customers that are grouped in smaller categories.
---------------------------------------------------------------------------

    \320\ E.g., BrightSource; FirstWind; RenewElec; AWEA.
---------------------------------------------------------------------------

    313. Snohomish County PUD questions whether it is appropriate to
apportion any volume of generator regulation reserves to behind-the-
meter generation. Snohomish County PUD contends that variations in
output from the behind-the-meter generator are, from the perspective of
the public utility transmission provider, indistinguishable from
variations in the distribution utility's load. Accordingly, Snohomish
County PUD asks the Commission to clarify that behind-the-meter
generators--those that are interconnected directly to and consumed by
the load of the local distribution utility rather than a transmission
utility--will not be required to purchase generator balancing capacity
from the public utility transmission provider in the absence of a
voluntary agreement between the public utility transmission provider
and the generator to install appropriate metering that measures the
variability of the generator and to pay the Schedule 10 charges
justified by that variation.
    314. Several commenters suggest that the Commission convene a
technical conference or require other processes to determine the
appropriate per-unit and volumetric rates under the proposed Schedule
10.\321\ AWEA states that a technical conference would be appropriate
to establish consistent principles for determining the methodology that
should be used for calculating and allocating Schedule 10 costs. Some
commenters request that the Commission require stakeholder involvement
in connection with the development of Schedule 10 volumes.\322\ For
example, First Wind requests that the Commission require RTOs to
conduct a robust and transparent stakeholder process which attempts to
reach consensus prior to them making an allocation filing, and that
non-RTO public utility transmission providers conduct public workshops
prior to any allocation filing.
---------------------------------------------------------------------------

    \321\ E.g., AWEA; BrightSource; EPSA; SEIA.
    \322\ E.g., California PUC; First Wind; SEIA.
---------------------------------------------------------------------------

b. Commission Determination
    315. For the reasons discussed above, the Commission is not
implementing a generic Schedule 10 to the pro forma OATT for generator
regulation service. Instead, the Commission takes this opportunity to
respond to the individual commenter concerns regarding the proper
design of a generator regulation service charge in order to provide
guidance in the development of proposals for such services.
    316. In response to the Large Public Power Council and Puget, those
public utility transmission providers that choose to propose a rate
schedule for generator regulation service may include opportunity costs
for generator regulation service in certain circumstances. Such
resources are often dispatched in the middle of their operating range
to allow the generator to provide regulation-up as well as

regulation-down and as a result forego other opportunities. Not to
allow compensation would create a barrier to the provision of services
by frustrating the recovery of legitimate costs.
    317. A number of commenters question the appropriate design of the
volumetric component of Schedule 10 rates, i.e., the component in the
Proposed Rule that allowed public utility transmission providers to
require different transmission customers (or generator classes) to
purchase or otherwise account for different quantities of regulation
reserves based on cost causation principles. The Commission agrees that
calculating the relative impact of individual customers or customer
classes on a public utility transmission provider's overall generation
regulating reserve needs and allocating those costs accordingly can be
a difficult and complex determination. However, the Commission believes
that the complexity of these proceedings can be mitigated where
entities take note of, and incorporate, the following principles.
    318. First, public utility transmission providers seeking to
distinguish customers into classes for the purpose of requiring them to
purchase or otherwise account for different quantities of generation
regulating reserves should do so only to the extent such classes and
distinctions among classes are reasonably related to operational
similarities and differences among those resources.\323\
---------------------------------------------------------------------------

    \323\ See Westar, 137 FERC ] 61,142 at PP 27-28.
---------------------------------------------------------------------------

    319. Second, to the extent a public utility transmission provider
proposes to break customers into specific groups based on operational
characteristics, we expect public utility transmission providers to
provide detailed explanations as to why such classifications are
appropriate if and when they propose to allocate different generating
regulation reserve obligations to different customer classes. The
Commission has required that overall generator regulation requirements
be established by taking diversity benefits into account. Diversity
benefits result from aggregating the variations of all resources so
that one resource's negative deviation can offset some or all of
another resource's positive deviation. When the transactions of two
customers result in diversity benefits, it is incorrect to say that one
customer is benefitting the other but not vice versa. Instead, the
diversity benefits result from both transactions and sharing of these
benefits among the customers is reasonable. In Westar, the Commission
found that this portfolio-wide approach to assessing generator
regulation charges appropriately shares diversity benefits among
generators and load.\324\ Ultimately, this concept will need to be
reconciled with any customer classifications proposed by the public
utility transmission provider in a way that prevents any over-recovery
of these capacity costs.
---------------------------------------------------------------------------

    \324\ See Westar, 130 FERC ] 61,215 at PP 37-38.
---------------------------------------------------------------------------

    320. Third, to the extent a public utility transmission provider
proposes to differentiate among customers (or customer classes) in
determining their relative regulating reserve responsibilities, the
public utility transmission provider must demonstrate that the overall
quantity of regulating reserve it requires of its transmission
customers accounts for diversity benefits among all resources and
loads, and the allocations to individual customers (or customer
classes) of their proportionate share is based on the operational
characteristics of such customers (or customer classes).
    321. Fourth, weather events such as droughts may affect the
required quantity of generator regulating reserves that the public
utility transmission provider must have in reserve more or less during
one portion of the year versus another portion of the year. In such
cases, these diversity events, though perhaps characterized as
anomalies, should be included in the data set so that the quantity and
costs of such reserves are more reflective of actual system operations.
    322. Fifth, there is a relationship between the use of intra-hour
scheduling by transmission customers and the quantity of reserves
needed to provide Schedule 9 generator imbalance service. In other
sections of this Final Rule, the Commission requires all public utility
transmission providers to offer transmission customers the option of
using more frequent transmission scheduling intervals within each
operating hour, at 15-minute intervals, noting that over time public
utility transmission providers will be able to rely more on planned
scheduling and dispatch procedures and less on reserves to maintain
overall system balance. In the Proposed Rule, the Commission sought
comment on whether to condition the ability of public utility
transmission providers to require different transmission customers to
purchase or otherwise account for different quantities of generator
regulating reserves on the implementation of intra-hour scheduling
reforms. Given that such reforms are mandated in this Final Rule, the
Commission concludes that condition to be satisfied.\325\ In designing
any proposals for generator regulation service charges, a public
utility transmission provider should consider the extent to which
transmission customers are using intra-hour scheduling in evaluating
whether to require different transmission customers to purchase or
otherwise account for different quantities of generator regulating
reserves.
---------------------------------------------------------------------------

    \325\ See supra IV.A.1 (Intra-Hour Scheduling Requirement).
---------------------------------------------------------------------------

    323. Sixth, there also is a relationship between the use of power
production forecasting and the allocation of generator regulation
reserve quantities to a particular class of customers. The record in
this proceeding demonstrates that the quantity of reserves used to
provide generator regulation service can be most efficiently managed
with the implementation of power production forecasting (as well as
intra-hour scheduling) by public utility transmission providers. While
commenters disagree on the extent to which power production forecasting
may affect reserve commitments, the Commission finds that power
production forecasts can provide public utility transmission providers
with advanced knowledge of system conditions needed to manage the
variability of VER generation through the unit commitment and dispatch
process, rather than through the deployment of reserve services, such
as regulation reserve. Without the increased situational awareness of
projected variability provided by power production forecasts, the
public utility transmission provider's ability to commit or de-commit
resources providing regulation reserves efficiently can be constrained.
This lack of situational awareness potentially can result in rates for
generator regulation service that are unjust and unreasonable or unduly
discriminatory.
    324. We recognize that conditioning the allocation of different
quantities of regulation reserves to different transmission customers
on the public utility transmission provider developing and deploying
power production forecasting is contentious. On one hand certain public
utility transmission providers believe that they should either be able
to use historical data or make other approximations to establish the
quantity of regulation reserves to be required of a given transmission
customer or class of customers. On the other hand, transmission
customers that are VERs contend that the Commission has not gone far
enough and that additional reforms are necessary to

ensure that VERs do not disproportionately bear the burden of the cost
of regulating reserves. The Commission believes that public utility
transmission providers need an effective opportunity to file for cost
recovery, while VERs need assurance that they are not unduly assigned
costs.
    325. Accordingly, while the Commission reserves judgment as to the
appropriate power production forecasting requirements for a particular
public utility transmission provider, we expect that the implementation
of power production forecasting will be addressed in any proposal to
require different transmission customers to purchase or otherwise
account for different quantities of generator regulating reserves. For
example, a public utility transmission provider could demonstrate that
it is utilizing power production forecasts (or other comparable
technique) to manage system operating costs and/or to improve
reliability by enabling the more efficient commitment and dispatch of
resources. The Commission agrees with the California PUC that, as part
of such a demonstration, the public utility transmission provider
should explain how the data required from VERs are incorporated into
the power production forecast and how the resulting forecast is used to
support the management of operating costs and/or reserves or otherwise
ensure that capacity costs incurred to provide Schedule 9 service are
prudently incurred.
    326. The Commission declines to require the additional forecasting-
related showings suggested by NaturEner and others. The technologies
and techniques for power production forecasting are still being refined
and may differ from region to region. While the recommendations made by
AWEA, Iberdrola, and NaturEner may be appropriate benchmarks for power
production forecasts utilizing today's technology, the Commission
believes that pre-defining these additional criteria would not provide
the flexibility needed for public utility transmission providers to
adopt new forecasting techniques or technologies as they are developed.
The Commission also declines to adopt the further recommendations of
the California PUC and others to include monitoring and reporting
requirements for public utility transmission providers that engage in
power production forecasting. The Commission finds adopting these
requirements to be unnecessary at this time.
    327. However, the Commission agrees with Iberdrola and others that
the public utility transmission provider should make the results of any
centralized forecast used by the public utility transmission provider
available through a secure information exchange to VER generators
providing related data. The Commission believes that the VERs should be
able to access the results of the public utility transmission
provider's forecast in order to ensure that the forecasting service is
producing accurate results. Thus, public utility transmission providers
proposing to require different transmission customers to purchase or
otherwise account for different quantities of generator regulating
reserves should explain in their proposals how forecasting results will
be shared.
    328. In response to comments regarding forecasting risk, the
Commission clarifies that the transmission customer is responsible for
the accuracy of transmission schedules and the public utility
transmission provider is responsible for the reliability of its system.
Therefore, the public utility transmission provider would utilize the
power production forecast to identify the necessary amount of reserves
and to use those reserves to maintain reliability of the transmission
system. The obligation of the transmission customer is to submit
schedules for deliveries. Power production forecasting is intended to
inform the transmission provider regarding aggregate system variability
that results from having VERs on its system, not to replace
transmission schedules from transmission customers delivering from
VERs. Public utility transmission providers using power production
forecasts should do so to manage uncertainty in the same manner they
use other forecasts of uncertainty for the transmission system. For
example, despite service agreements to serve load, public utility
transmission providers develop and use load forecasts to assure load
can be met reliably and efficiently. Similarly, despite transmission
schedules to deliver from a VER, public utility transmission providers
should use power production forecasts to assure energy can be provided
to load in a reliable and efficient manner.
    329. Therefore, the Commission agrees with NorthWestern and others
that the transmission customer maintains responsibility for the
accuracy of its transmission schedule. However, we disagree with
NorthWestern's interpretation concerning NERC Control Performance
Standard 2 violations. A public utility transmission provider is not
responsible for submitting a transmission schedule on behalf of a VER.
As explained above, power production forecasting would be utilized to
identify and acquire the appropriate amount of reserves needed to
integrate VERs reliably. Nothing in this Final Rule alleviates the
public utility transmission provider's obligations under NERC
Reliability Standards.
    330. The Commission declines to require transmission customers
delivering from a VER to submit transmission schedules according to the
public utility transmission provider's forecast, as suggested by
Bonneville Power. While the public utility transmission provider is
able to forecast the aggregate variability of the system with greater
accuracy through centralized power production forecasting, the
individual VER may be better able to produce the most accurate schedule
for its particular facility. Requiring a transmission customer to
submit transmission schedules for VER deliveries according to a
centralized forecast would cloud the delineation between the
obligations of the VER and the obligations of the public utility
transmission provider with respect to the provision of transmission
service.
    331. The Commission disagrees with Puget's example, and clarifies
that the public utility transmission provider's obligation should be to
deploy its resources according to its own forecast in order to maintain
the reliability of the system. The public utility transmission provider
retains the risk and responsibility for inaccurate procurement of
reserve requirements while the transmission customer retains the
financial risk and responsibility for inaccurate schedules. The
Commission finds that the incentive to avoid Schedule 9 generator
imbalance penalties and any relevant charges for generator regulation
service provides sufficient incentive for VERs to submit an accurate
schedule.
    332. The Commission agrees with National Grid and others that, as
the entity providing transmission service under an OATT, the ISO or RTO
would engage in power production forecasting within its region. In
response to Pacific Gas & Electric and others requesting flexibility to
implement power production forecasting, the Commission finds that the
guidance provided affords sufficient flexibility to allow public
utility transmission providers to tailor their forecasting programs to
meet their needs, whether for the purpose of developing proposals for
generator regulation charges or otherwise.
    333. The Commission emphasizes that the foregoing discussion is
intended to provide a framework to assist public utility transmission
providers in

developing proposals for generator regulation service should they
desire to do so. The Commission does not intend this guidance to
preclude a public utility transmission provider from making an
alternative proposal under section 205 of the FPA. However, it does
provide guidance to public utility transmission providers regarding the
facts and circumstances that the Commission may find relevant in
evaluating such proposals.
    334. A number of commenters challenged the Commission's proposal to
condition proposals that require different transmission customers to
purchase or otherwise account for different quantities of generator
regulating reserves on performance of the activities discussed above.
These arguments have largely been rendered moot by the Commission's
decision not to adopt the Proposed Rule in that regard. Even as applied
to the guidance provided above, the Commission disagrees that a future
decision by the Commission to condition proposals that require
different transmission customers to purchase or otherwise account for
different quantities of generator regulating reserves on the
performance of certain actions would violate cost causation principles
or otherwise would preclude public utility transmission providers from
recovering prudently incurred costs. In reviewing any future proposal
to allocate a greater quantity of capacity costs to a particular set of
transmission customers, it would be reasonable for the Commission to
consider whether the public utility transmission provider has taken
steps to mitigate such costs. This does not mean, as some commenters
imply, that the public utility transmission provider has no other means
to recover its costs. The public utility transmission provider could
continue to rely on existing rate mechanisms to recover reserve costs
or may propose to require a uniform quantity of generation regulating
reserves from all transmission customers that is commensurate with
transmission customers' proportionate effect on net system variability
and taking diversity benefits into account.
    335. The Commission agrees with commenters that implementing other
reforms, such as consolidating balancing authority areas or
implementing an ancillary services market, may be beneficial to the
reliable and efficient integration of VERs. However, the Commission is
not persuaded that these additional reforms are a necessary
precondition to proposals that require different transmission customers
to purchase or otherwise account for different quantities of generator
regulating reserves. As noted in the Proposed Rule, many of these
additional reforms are being discussed in other forums. The Commission
will continue to monitor these proposals as they develop and modify our
approach to this issue as appropriate as conditions develop.
3. Use of Contingency Reserves
a. Commission Proposal
    336. In the Proposed Rule, the Commission sought comments from NERC
and industry stakeholders on the steps needed to resolve confusion
regarding the use of contingency reserves to manage extreme ramp events
of VERs.\326\ The Commission also sought comments from NERC and
industry stakeholders on the extent to which some additional type of
contingency reserve service (beyond the services provided under
Schedule 5 and 6 of the pro forma OATT) would ensure that VERs are
integrated into the interstate transmission system in a non-
discriminatory manner while remaining consistent with NERC Reliability
Standards.\327\
---------------------------------------------------------------------------

    \326\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 100
(citing Schedule 5 (Operating Reserve--Spinning Reserve Service) and
Schedule 6 (Operating Reserve--Supplemental Reserve Service) respond
to contingency events. Spinning Reserve Service is used to serve
load ``immediately in the event of a system contingency'' whereas
Supplemental Reserve Service ``is not available immediately to serve
load but rather within a short period of time.'').
    \327\ Id. P 100.
---------------------------------------------------------------------------

b. Comments
    337. NERC indicates that large wind ramping events are similar to
conventional generator contingency events in that they are large and
relatively infrequent, yet they differ in that wind ramps are much
slower than instantaneous contingency events and may be possible to
forecast. NERC states that the use of contingency reserves to address
wind ramps is similar to what is used to address large, relatively
infrequent wind ramps because contingency reserves are seldom deployed,
yet long ramp durations can make it difficult to include wind ramps as
actual contingencies. NERC explains that Resource and Demand Balancing
(BAL) Reliability Standard BAL-002 (Disturbance Control Performance)
requires ACE to be restored 15 minutes following the disturbance (R4)
and the contingency reserves to be restored within 105 minutes (90
minutes after the 15 minute disturbance recovery period--R6). NERC
states that both of these requirements can be problematic for wind
ramps because they can be longer than the disturbance recovery period
as well as the reserve restoration period.
    338. Still, NERC indicates that it may be appropriate to use
contingency reserves in response to a portion of a wind ramp. NERC
states that shared contingency reserves could be used to initiate the
response, allowing time for alternate supply (or load reduction) to be
implemented. NERC suggests that the industry consider developing rules
governing reserve deployment and restoration, similar to those that
currently address conventional contingencies.
    339. Other commenters express openness to using contingency
reserves for wind events.\328\ Commenters indicate that there are
discussions in the Northwest Power Pool (NWPP) about the use of
contingency reserves for wind events.\329\ AWEA contends that
contingency reserves should be used for the initial period of an
extreme wind ramp because both contingency events and extreme wind ramp
events are very infrequent, and therefore, the use of contingency
reserves for extreme wind ramp events would be highly unlikely to
coincide with a need to use those reserves for a conventional
generator's contingency event. NextEra urges the Commission to convene
a technical conference to address how to deploy contingency reserves to
address ramp events in a manner that will promote reliability.
---------------------------------------------------------------------------

    \328\ E.g., Powerex; NaturEner; California PUC; MidAmerican.
    \329\ E.g., Powerex; Tacoma Power.
---------------------------------------------------------------------------

    340. Xcel indicates that there is confusion regarding the use of
contingency reserves to manage extreme ramping events. Xcel states that
the confusion arises as entities attempt to define the allowable
triggering events for the activation of contingency reserves. Xcel
recommends that the standard for contingency reserve activation include
disturbances related to less-than-anticipated VER (e.g., wind)
production, sudden drop-off of VER production, or associated ramp
limitations on balancing resources due to forecast errors. Xcel
contends that ramp events related to VERs are not necessarily caused by
the sudden failure of generation, but instead may be due to an
incorrect wind forecast or limited dispatchable generation response.
For these reasons, Xcel recommends: (1) Expanding the definition of
disturbances to include ramp events which may occur over a half-hour
time frame; (2) including a measurement technique related to a ramp
event in BAL-002; (3) identifying a specific

restoration period in BAL-002 (e.g., 45 minutes) related to contingency
reserves that were deployed for ramping events; and (4) identifying
compliance metrics and other issues related to deployment of
contingency reserves for ramp-limited events. Xcel recommends that the
Commission request that NERC begin a standards drafting process to
consider revisions to the existing BAL-002 standard to address the
issues discussed by Xcel.
    341. Other commenters express reservations with using contingency
reserves in response to wind events is an improper use of contingency
reserves.\330\ Duke indicates to the extent that there is a need for a
new service to address VER ramp rates, a new rate schedule should be
developed for such a service. Pacific Gas & Electric states that there
may be a need for new integration services to incorporate VERs into the
reliable operation of the grid. Pacific Gas & Electric submits that
various industry activities are already underway to consider these
issues, and the Final Rule should endorse their continued efforts.
---------------------------------------------------------------------------

    \330\ E.g., Tacoma Power; ENBALA; Grant PUD; California ISO;
Duke; Pacific Gas & Electric.
---------------------------------------------------------------------------

c. Commission Determination
    342. Based on comments received, the Commission concludes that the
issues related to the appropriate use of contingency reserves under
NERC Reliability Standards need further study and vetting before any
action is considered. Indeed, comments range from expressing confusion
over what would constitute an extreme VER event to asking the
Commission to define ``ramp'' with some specificity. Rather than
opining on any of the comments and risk providing guidance without the
benefit of more information, the Commission finds that the better
course of action is to allow industry to continue its work and direct
our staff to monitor those efforts and engage industry as appropriate.

V. Other Issues

1. Regulatory Text
a. Commission Proposal
    343. As part of the Proposed Rule, the Commission sought comment on
a minor revision to 18 CFR 35.28. To date, when amending its
regulations concerning the open access requirements of the pro forma
OATT, the Commission has listed by name Commission rulemaking
proceedings promulgating and amending the pro forma OATT when
explaining the details of a public utility transmission provider's
obligation to have an OATT on file with the Commission. The Commission
proposed to no longer explicitly reference, by name, prior Commission
rulemaking proceedings promulgating and amending the pro forma OATT in
its regulations. Likewise, the Proposed Rule included a similar change
with respect to a public utility transmission provider's obligation to
have standard generator interconnection procedures and agreements and
standard small generator interconnection procedures and agreements on
file with the Commission.\331\
---------------------------------------------------------------------------

    \331\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 12 &
n.29.
---------------------------------------------------------------------------

b. Comments
    344. No comments were received on this aspect of the Proposed Rule.
c. Commission Determination
    345. The Commission adopts its proposed minor revision to 18 CFR
35.28. We find that the existing process for amending regulations
concerning the pro forma OATT, which necessitates listing by name
Commission rulemaking proceedings promulgating and amending the pro
forma OATT when explaining the details of a public utility transmission
provider's obligation to have an OATT on file with the Commission, is
increasingly cumbersome and provides little, if any, benefit. Thus, the
Commission will no longer explicitly reference, by name, prior
Commission rulemaking proceedings promulgating and amending the pro
forma OATT in its regulations. Likewise, the Final Rule adopts a
similar change with respect to a public utility transmission provider's
obligation to have standard generator interconnection procedures and
agreements and standard small generator interconnection procedures and
agreements on file with the Commission.
2. Market Mechanisms
a. Comments
    346. Several commenters ask the Commission to revise specific RTO
and ISO market rules not at issue in the Proposed Rule, while other
commenters seek to have the Commission address additional market
mechanisms for the non-RTO and ISO areas. For example, Environmental
Defense Fund states that the Proposed Rule does not reform the day-
ahead market to increase VER participation and decrease the amount of
costly out-of-market commitments, leading to unjust and unreasonable
rates, and undue discrimination against VERs. In addition, ACSF asserts
that scheduling in the day-ahead market and in the unit commitment
process should be reformed. ACSF states that the technology that makes
15-minute schedules feasible in the spot market also makes reforms
possible in these other areas. According to ACSF, it is important to
prevent the least clean and efficient generation from dominating
dispatch at all hours, especially in the unit commitment process.
    347. Environmental Defense Fund further states that because VERs
are only permitted to bid a portion of their capacity into the market,
they generally receive a lower price. According to Environmental
Defense Fund, many capacity markets require bidders to also participate
in the day-ahead market, which most VERs do not do because of the
financial risk associated with failing to meet day-ahead obligations.
Thus, Environmental Defense Fund argues that the Commission must
consider the available options to facilitate VER participation in
capacity markets.
    348. With regard to non-RTO regions, EPSA states that the Proposed
Rule does not sufficiently address the lack of market mechanisms
available in non-RTO regions to conventional generation resources,
which have the ability to contribute to VERs integration. EPSA suggests
that possible market mechanisms and other competitive options for
integrating VERs in the non-RTO regions should be considered as part of
the technical conference that EPSA has requested. Similarly,
Independent Power Producers Coalition--West states that without an
organized ISO or RTO market, public utilities must face regulatory
pressure to advance their integration of VERs and sharing of data,
otherwise the utilities have little incentive to move toward better
integration between transmission providers and balancing authorities.
Independent Power Producers Coalition--West contends that the lack of a
competitive ancillary services market that would allow independent
power producers the opportunity to provide generator imbalance services
in WECC results in unjust and unreasonable rates.
    349. Tres Amigas contends that Order Nos. 888 and 890 have left
little room for a market to develop balancing services outside of an
ISO/RTO, because the primary provider of these services, the balancing
authority, has to acquire the capability to provide the ancillary
services on behalf of all its transmission customers and then sell the
services at cost-based rates. Tres Amigas states that the Commission
should have a two-fold objective: (1) Determining how market

forces can identify and competitively price the resources that will be
used by balancing authorities for balancing; and (2) establishing
appropriate mechanisms for allocating the costs incurred by balancing
authorities to acquire these resources in the marketplace. Further,
Tres Amigas asserts that the Commission should grant market-based rates
to new entrants in order to promote formation of a vibrant market for
balancing services that includes participation by new technologies.
Tres Amigas states that the balancing authorities should then file
proposals to allocate the costs incurred to balance the system among
load and generation (including generation within the control area that
is scheduled to another control area). According to Tres Amigas, these
cost allocation proposals should take into account the extent to which
different market participants contribute to the costs of acquiring
balancing services and benefit from such services.
    350. Recycled Energy urges the Commission to consider implementing
various payments designed to compensate efficient gas generators and
combined heat and power facilities for the flexibility they provide to
utilities. In addition, Recycled Energy asserts that the Commission
could improve the grid's reliability and efficiency by encouraging the
placement of distributed generators in ways that reduce line losses and
obtain ancillary benefits. Similarly, Business Council asserts that the
OATT should be revised to ensure that flexible resources (such as
natural gas and pumped storage facilities) are better able to provide
their services to system operators who integrate VERs, and that these
services are properly valued. Business Council explains that flexible
generation resources should be given more opportunities to sell their
balancing services to transmission providers and should be paid a just
and reasonable rate for these services. Business Council argues that if
the Commission adopts a universal requirement for 15-minute scheduling,
it should make clear that generators should be able to supply balancing
services on the same 15-minute (or less) basis.
b. Commission Determination
    351. The pro forma OATT terms and conditions of service create the
platform by which the public utility transmission provider makes
available non-discriminatory open, access transmission service. Since
the issuance of Order No. 888, the Commission has taken numerous
actions to ensure that the principles enunciated in that rule continue
to remain true, allowing all types of resources--existing and new--
access to the grid for the benefit of developing competitive markets.
In response to commenters like Independent Power Producers-West, EPSA
and Tres Amigas who assert that the Commission should take various
steps to establish a competitive ancillary services market or other
market mechanisms, we believe that the reforms in this Final Rule
continue to facilitate the development of competitive markets without
imposing any particular type of structure for doing so. The Commission
allows third party sellers to make sales of ancillary services at
market-based rates, requires all public utility transmission providers
to offer open access transmission service and undertake open and
transparent transmission planning, and allows transmission customers to
self-supply their own ancillary services. The Commission has long-
standing precedent on cost allocation and has long supported reserve
sharing and power pooling arrangements. Nothing in this rule is
intended to prevent or create a barrier to the further development of
competitive markets. Indeed, we think that the reforms adopted herein
should help to facilitate the further development of competitive
markets by allowing transmission customers to tailor their transmission
schedules and, in turn, better manage generator imbalance and ancillary
services costs. 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.
    352. For similar reasons we decline the request from Recycled
Energy and Business Council to expand the scope of this rulemaking
proceeding to include additional payments to flexible generation. Both
commenters urge the Commission to adopt mechanisms that would increase
payments to flexible generation resources, such as high-efficiency
natural gas facilities, so as to properly value the flexibility they
provide to transmission providers. The Commission has already
addressed, in the context of the organized markets, compensation for
resources providing frequency regulation and is currently exploring a
similar issue in bilateral markets outside of RTOs and ISOs.\332\ In
this proceeding, the Commission is primarily concerned with providing
reforms that will provide public utility transmission providers with
greater awareness of the variability experienced on their systems, as
well as providing transmission customers with a tool to manage
imbalances from schedules by providing for 15-minute adjustments to
schedules. How these public utility transmission providers choose to
provide this service is beyond the scope of this inquiry.
---------------------------------------------------------------------------

    \332\ See Frequency Regulation Compensation in the Organized
Wholesale Power Markets, Order No. 755, 76 FR 67260 (Oct. 31, 2011),
FERC Stats. & Regs. ] 31,324 (2011); Third-Party Provision of
Ancillary Services; Accounting and Financial Reporting for New
Electric Storage Technologies, 139 FERC ] 61,245 (NOPR).
---------------------------------------------------------------------------

    353. With regard to commenters that request additional changes to
the RTO and ISO day-ahead and capacity markets to facilitate VER
integration, we fail to see the direct connection between the specific
reforms of the Commission's Proposed Rule and the reforms requested.
Commenters did not establish that connection and failed to demonstrate
that the Commission's proposed reforms are unjust and unreasonable
without the additional requested reforms. Instead, these commenters
merely asked that the Commission extend the scope of the rule. As such,
we find that commenters' requests that we require additional reforms to
RTO/ISO day-ahead, residual unit commitment, and capacity market rules
are beyond the scope of this proceeding.
    354. Finally, we cannot allow sales of energy or capacity at
unchecked rates, even by new entrants, as suggested by Tres
Amigas.\333\ As noted above, the Commission allows for sales at market-
based rates upon a showing of lack of market power and is in the
process of considering ways to streamline the market-based rate showing
for certain ancillary services.\334\
---------------------------------------------------------------------------

    \333\ See Market-Based Rates For Wholesale Sales Of Electric
Energy, Capacity And Ancillary Services By Public Utilities, Order
No. 697, 72 FR 39904 (July 20, 2007), FERC Stats. & Regs. ] 61,295,
at P 320 (2007).
    \334\ See Third-Party Provision of Ancillary Services;
Accounting and Financial Reporting for New Electric Storage
Technologies, 139 FERC ] 61,245 (NOPR).
---------------------------------------------------------------------------

c. Pipeline Transportation Nomination Procedures
i. Comments
    355. Some commenters assert that if the Commission requires
transmission providers to allow intra-hour transmission scheduling to
accommodate VERs, the Commission must also consider the impact of such
requirements on the operation of natural-gas-fired electric generation

units, and the concomitant need to modify pipeline transportation
service nomination procedures to calibrate gas transportation and usage
more closely with the operation of natural gas-fired electric
generation units to support VERs.\335\ Specifically, APPA contends that
despite access to real-time electronic metering and flow control and
technological advances that enable the electronic submission of gas
nominations, the current time period used to process pipeline
transportation service nominations and to schedule natural gas is the
same time period (up to 4 hours) that was adopted over a decade and a
half ago. APPA notes that this already substantial disconnect between
the nomination and scheduling procedures used in the natural gas and
electric power industries will only become more severe if intra-hour
scheduling is adopted. Similarly, Joint Parties request that the
Commission open a companion docket to examine barriers that may exist
in the natural gas industry that inhibit the timely access to natural
gas that is needed to ensure the seamless integration of VERs.\336\
---------------------------------------------------------------------------

    \335\ E.g., Joint Parties; TVA; Midwest Energy; APPA.
    \336\ TVA contends that the Commission should reevaluate its
policy of not allowing a firm gas transportation holder to take
precedence over (i.e., bump) a non-firm customer, because gas-fired
generators paying for firm gas transportation service must be able
to support electric needs in general and in integrating VERs
specifically.
---------------------------------------------------------------------------

    356. American Gas and INGAA state that gas transmission systems
have developed innovative services to accommodate the needs of gas-
fired generators to access gas supplies quickly in response to electric
system dispatch orders. American Gas and INGAA explain that these
offerings demonstrate that individual, tailored solutions may better
address gas-electric coordination concerns than a modification of the
gas nomination schedule. For this reason, American Gas encourages the
Commission to continue to be open to creative market solutions to meet
the needs of gas-fired generators in ways that do not unnecessarily
affect existing shippers in adverse ways. American Gas also encourages
the Commission to hold a technical conference or other non-NAESB forum
to discuss ways in which the natural gas and electric industries can
work together.
    357. American Gas further contends that the Commission's
consideration of gas-electric coordination issues should not focus
narrowly on the gas nomination and scheduling cycle as a primary
solution to the reliability issues which both industries face. While
American Gas believes that a single, nationwide gas nomination schedule
is essential to the efficient functioning of the natural gas system, a
modification to that schedule alone is not the most effective means to
address gas-electric coordination issues.
    358. AEP adds that while the proposed scheduling option appears on
the surface to be feasible within the power industry, the increased
quantity of VERs and subsequent increased ramping capability
requirements will further exacerbate the operational difficulties
associated with the varied scheduling timelines existing between the
gas and power industries. AEP concludes that such discrepancies place
the gas-fired generation operators, whose typically superior ramping
capabilities will become increasingly beneficial, in a position of
speculating on fuel supply needs because they are unsure whether the
increase in variable generation will mean an increased need for the
faster ramping capabilities of gas.
    359. AEP notes that these differences have existed for many years,
and managing them has become more challenging with the introduction of
RTO-administered markets, as unit commitment is generally made by the
RTO, and not the individual asset owner. AEP argues that any proposed
scheduling practices related to incremental VER penetration must
account for such inter-market dependencies.
    360. Spectra Entities notes that the interface issues between the
gas and electric industries go beyond revisiting coordinating and the
gas/electric scheduling timelines. Spectra Entities argues that there
are regulatory policy and market barriers discouraging the electric
industry in some markets from contracting for adequate firm gas supply
and firm transportation arrangements to serve those generators which
must run in order to maintain the reliability of the electric grid. For
example, the Commission's ``no-bump'' policy and the need to coordinate
scheduling of interruptible services are irrelevant during peak or high
load days in natural gas markets, because interruptible capacity is
rarely available on the pipeline grid under those conditions. Spectra
Entities argue that unless these barrier issues are addressed, any
changes to coordination and scheduling or the offering of innovative
transportation solutions will not be sufficient to achieve the
Commission's goals.
ii. Commission Determination
    361. While comments asking the Commission to undertake reforms to
natural gas pipeline rules and procedures in order to facilitate
greater cross-market coordination are beyond the scope of this
proceeding, we agree that the interdependence of these two industries
merits careful attention. The Commission has recently addressed
proposed changes to the gas pipeline nomination procedures. In the
past, the Commission has urged the industry, working through NAESB, to
consider changes to its nomination procedures to provide better
coordination between gas and electric scheduling.\337\ More recently,
in Order No. 587-U, the Commission acknowledged that NAESB lacked
consensus to implement any such changes and did not find a nationwide
scheduling solution in response to concerns over gas pipeline
nomination procedures (including the ``no-bump'' rule).\338\ While
eschewing nationwide changes, Order No. 587-U emphasized that
``individual pipelines may be able to offer special services or
increased nomination opportunities that better fit the profile of gas-
fired generation.'') \339\ In fact, some pipelines have begun to offer
special services to facilitate the flexibility needs of gas-fired
generation.\340\
---------------------------------------------------------------------------

    \337\ See Standards for Business Practices for Interstate
Natural Gas Pipelines: Standards for Business Practices for Public
Utilities, Order No. 698, FERC Stats, & Regs ] 31,251, at P 69
(2007).
    \338\ Order No. 587-U, FERC Stats. & Regs. ] 31,307 at P 27.
    \339\  Id.
    \340\ See Texas Gas Transmission LLC, 138 FERC ] 61,176 (2012).
---------------------------------------------------------------------------

    362. On March 30, 2012, a number of entities submitted further
comments on gas-electric coordination issues in response to a notice
issued in Docket No. AD12-12-000 that requested comments in response to
a set of questions and other text concerning gas-electric
interdependence issued by Commissioner Moeller on February 3, 2012. The
Commission is currently evaluating these comments to determine what, if
any, additional steps would be appropriate to take to facilitate
coordination between the gas and electric industries.
3. Power Factor Design
a. Comments
    363. Midwest ISO Transmission Owners state that Order No. 661
exempted wind generators from having to maintain power factor design
criteria absent a specific finding in the relevant system impact study
that the generator needs to maintain a specific power factor in order
to ensure safety and reliability. Midwest ISO Transmission Owners
submit that the Commission should convene a technical conference to
examine this issue, or allow

individual transmission providers to file to eliminate this exemption
from their pro forma LGIAs or generator interconnection agreements.
Midwest ISO Transmission Owners explain that wind and other VERs have
obtained significant penetration levels in many areas of the country,
such that wind is no longer a new technology that needs protection.
Midwest ISO Transmission Owners contend that eliminating this exemption
will ensure that wind does not receive an unfair competitive basis.
b. Commission Determination
    364. Since issuance of the Proposed Rule in this proceeding, the
Commission has directed staff to convene a technical conference in
Docket No. AD12-10-000 to examine whether the Commission should
reconsider or modify the reactive power provisions of Order No. 661-A
and examine what evidence could be developed under Order No. 661 to
support a request to apply reactive power requirements more broadly
than to individual wind generators during the interconnection study
process.\341\ The Commission concludes that potential issues regarding
the exemption provided under Order No. 661-A are better addressed in
that proceeding.
---------------------------------------------------------------------------

    \341\ Reactive Power Resources, Notice of Technical Conference,
Docket No. AD12-10-000 (issued Feb. 17, 2012).
---------------------------------------------------------------------------

VI. Compliance

A. Commission Proposal

    365. In the Proposed Rule, the Commission indicated that each
public utility transmission provider must submit a compliance filing
within six months of the effective date of the Final Rule revising its
OATT and LGIA to demonstrate compliance with the Final Rule. The
Commission indicated that to demonstrate compliance, a public utility
transmission provider must file: (1) Revisions to its OATT to implement
15-minute scheduling; (2) revisions to its LGIA to include a
requirement for interconnection customers whose generating facility is
a VER to provide data to the public utility transmission provider when
the public utility transmission provider is developing and deploying
power production forecasting for VERs; and (3) the addition of Schedule
10 to the OATT, which includes the same per unit rate from their
currently effective Schedule 3, and a blank or unfilled volumetric
component, among other things.
    366. The Commission acknowledged that public utility transmission
providers may have provisions in their existing OATTs and LGIAs that
the Commission has deemed to be consistent with or superior to the pro
forma OATT and LGIA. The Commission indicated that where these
provisions are being modified by the Final Rule, public utility
transmission providers must either comply with the Final Rule or
demonstrate that these previously-approved variations continue to be
consistent with or superior to the pro forma OATT and LGIA as modified
by the Final Rule.
    367. The Commission also proposed that transmission providers that
are not public utilities would have to adopt the requirements of the
Final Rule as a condition of maintaining the status of their safe
harbor tariff or otherwise satisfying the reciprocity requirement of
Order No. 888.\342\
---------------------------------------------------------------------------

    \342\ Order No. 888, FERC Stats. & Regs. at 31,760-763.
---------------------------------------------------------------------------

B. Comments

    368. Commenters addressing the six month timeframe generally argue
that the proposed compliance deadline does not provide enough time for
the industry to implement intra-hour scheduling effectively.\343\
Specifically, commenters assert that additional time is needed to allow
transmission providers time to: (1) Develop necessary revisions to
inter-regional agreements and procedures, and finish ongoing pilot
programs; and (2) evaluate all potential impacts to operations and
address issues regarding reliability via NERC, and perhaps business
standards via NAESB.
---------------------------------------------------------------------------

    \343\ E.g., MidAmerican; EEI; FriiPwr; NRECA; Southern
California Edison; Pacific Gas & Electric; Grant PUD; NextEra; PNW
Parties; Powerex; NV Energy; New York ISO; ISO/RTO Council.
---------------------------------------------------------------------------

    369. Southern California Edison argues that regional differences
and the need to implement intra-hour scheduling efficiently require
careful consideration of each region's scheduling rules. Specifically,
Southern California Edison suggests that the Commission provide three
years to implement 30-minute scheduling followed by an 18-24 month
evaluation period before deciding if 15-minute intra-hour scheduling is
necessary. Pacific Gas & Electric recommends that the Commission
lengthen the implementation timeline for intra-hour scheduling, so that
regional technical conferences on intra-hour scheduling can be convened
for affected transmission providers, and so that ongoing pilot studies
on intra-hour scheduling may be completed.
    370. NorthWestern comments that six months is insufficient time for
a compliance filing implementing the intra-hour scheduling requirements
of the Proposed Rule. NorthWestern argues that compliance will include,
but not be limited to, implementation of software and hardware
upgrades, adoption of common regional scheduling practices in the
region with jurisdictional and non-jurisdictional balancing
authorities, and hiring and properly training of additional staff.
NorthWestern encourages the Commission to be flexible and allow
balancing authorities the ability to define implementation timeframes,
perhaps up to one year before the compliance filing is due.
    371. Commenters also point more generally to areas of the Proposed
Rule that may require additional time for compliance. Midwest ISO
Transmission Owners state, for example, that additional time may be
needed to make changes that are highly technical or require an
extensive stakeholder process to implement.\344\ Midwest ISO suggests
that at least 18 months should be allotted for transmission providers
to submit compliance filings revising their OATT, LGIA, or other
documents.\345\ MidAmerican recommends that sufficient time be
allocated so that transmission providers may (1) evaluate and address
all potential impacts to operations and reliability and (2) be afforded
the necessary time to procure resources, develop and adopt
administrative processes, conduct training, and perform testing and
validation critical to successfully effectuate the proposed reforms.
---------------------------------------------------------------------------

    \344\ Midwest ISO Transmission Owners at 16.
    \345\ Midwest ISO at 15.
---------------------------------------------------------------------------

    372. EEI suggests that the Commission not require the changes set
forth in the Proposed Rule until the regional planning and cost
allocation Final Rules have gone through any rehearing and legal
challenges that may develop. On the other hand, Iberdrola supports the
Commission's proposal to require a compliance filing within six months;
however, if the Commission extends the deadline, Iberdrola recommends
that implementation of Schedule 10 occur coincidentally with the
implementation of the other two proposed operational changes.

C. Commission Determination

    373. The Commission extends the deadline for compliance filings by
6 months so that public utility transmission providers will have 12
months from the effective date of this Final Rule to submit their
compliance filings. The Commission also provides the pro forma tariff
language that public utility transmission providers must include in
their OATTs and LGIAs, with modifications to the language based

upon the comments received, as discussed within the body of this Final
Rule.\346\
---------------------------------------------------------------------------

    \346\ See Appendix A and B for the adopted pro forma OATT and
LGIA provisions consistent with this Final Rule.
---------------------------------------------------------------------------

    374. Consistent with the discussion in the intra-hourly scheduling
section, the Commission requires public utility transmission providers
to revise their OATTs to provide an opportunity for transmission
customers to submit transmission schedules at 15-minute intervals
within 12 months of the effective date of this Final Rule.\347\ Public
utility transmission providers with provisions in their existing OATTs
that the Commission has deemed to be consistent with or superior to the
pro forma OATT being modified by the Final Rule can seek to demonstrate
in their compliance filings that those previously-approved variations
continue to be consistent with or superior to the pro forma OATT as
modified by the Final Rule. In addition, public utility transmission
providers may 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.\348\
---------------------------------------------------------------------------

    \347\ See Appendix A for the revised section 13.8 and 14.6 of
the pro forma OATT provisions consistent with this Final Rule. As
noted supra Sec.  IV.A.1 (Intra-Hour Scheduling Requirement), the
implementation of 15-minute scheduling will only apply to intertie
transactions in organized wholesale energy markets.
    \348\ See supra Sec.  IV.A.1 (Intra-Hour Scheduling
Requirement).
---------------------------------------------------------------------------

    375. Consistent with the discussion in the data reporting section,
the Final Rule modifies the compliance obligation set forth in the
Proposed Rule and requires public utility transmission providers to
modify their pro forma LGIAs to effectuate the data reporting
requirement within 12 months of the effective date of this Final Rule
rather than the six months initially proposed.\349\ The Commission
adopts proposed Article 8.4 of the pro forma LGIA, as modified per the
discussion in the data reporting section. The Commission also adopts
the proposed definition of VER. The Commission appreciates that public
utility transmission providers in some regions, including RTOs and
ISOs, have already implemented meteorological or forced outage
reporting under relevant tariffs, business practices and/or markets
rules. Such public utility transmission providers may seek to
demonstrate in their compliance filings how continued use of these
existing tariffs, business practices and/or market rules is adequate to
satisfy the requirements of this Final Rule using the independent
entity variation standard set forth in Order No. 2003, if relevant, or
by demonstrating variations from the pro forma OATT are consistent with
or superior to the requirements of this Final Rule.\350\
---------------------------------------------------------------------------

    \349\ See Appendix B for the revisions to the pro forma LGIA
consistent with this Final Rule. Specifically, a new Article 8.4 and
a new definition in Article 1 have been added to the pro forma LGIA
and conforming revisions have been made to the table of contents.
    \350\ See Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 910.
---------------------------------------------------------------------------

    376. The Commission concludes that 12 months is a reasonable amount
of time to implement the requirements of this Final Rule. Many public
utility transmission providers have already implemented some form of
sub-hourly scheduling, resolving many of the issues that must be
addressed in order to accept transmission schedules on a 15-minute
interval. Twelve months also is an adequate amount of time for public
utility transmission providers to determine the extent to which
meteorological and forced outage data are necessary to support power
production forecasting. Although we are extending the compliance
deadline to 12 months from the compliance schedule in the Proposed
Rule, we do not believe that more than 12 months will be necessary.
Therefore, we will not extend the compliance deadline beyond 12 months,
nor will we adopt commenters' other proposed recommendations.
    377. Finally, the Commission also adopts the proposal that
transmission providers that are not public utilities must adopt the
requirements of the Final Rule as a condition of maintaining the status
of their safe harbor tariff or otherwise satisfying the reciprocity
requirement of Order No. 888.\351\
---------------------------------------------------------------------------

    \351\ Order No. 888, FERC Stats. & Regs. at 31,760-63.
---------------------------------------------------------------------------

VII. Information Collection Statement

    378. The Office of Management and Budget (OMB) regulations require
approval of certain information collection and data retention
requirements imposed by agency rules.\352\ Upon approval of a
collection(s) of information, OMB will assign an OMB control number and
an expiration date. Respondents subject to the filing requirements of a
rule will not be penalized for failing to respond to these collections
of information unless the collections of information display a valid
OMB control number.
---------------------------------------------------------------------------

    \352\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------

    379. The Commission is submitting the proposed modifications to its
information collections to OMB for review and approval in accordance
with section 3507(d) of the Paperwork Reduction Act of 1995.\353\ In
the Proposed Rule, the Commission solicited comments on the need for
this information, whether the information will have practical utility,
the accuracy of provided burden estimates, ways to enhance the quality,
utility, and clarity of the information to be collected or retained,
and any suggested methods for minimizing the respondent's burden,
including the use of automated information techniques. The Commission
also included a table that listed the estimated public reporting
burdens for the proposed reporting requirements, as well as a
projection of the costs of compliance for the reporting requirements.
---------------------------------------------------------------------------

    \353\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    380. The Commission did not receive any comments specifically
addressing the burden estimates provided in the Proposed Rule. However,
commenters did respond to questions in the NOPR regarding the specific
hardware, software, and personnel changes that are necessary to
implement intra-hour scheduling. As noted in Section IV above, some
parties argue that the cost to implement intra-hour scheduling will be
modest, while other commenters state that implementation costs may be
significant. In addition to the Commission's responses to the comments
previously provided, the Commission believes that the revised burden
estimates below are representative of the average burden on
respondents.
    381. In the Final Rule, the Commission adds two burden categories
that were not included in the Proposed Rule burden estimates. First,
the Commission includes a burden estimate for transmission providers
who choose to share power production forecast results with VERs.
Second, the Commission includes a burden estimate for transmission
providers who choose to voluntarily share VER-provided meteorological
and forced outage data with third parties. Neither of these additional
categories is required under the Final Rule. However, the Commission
assumes that all Transmission Providers will implement these changes
for the purposes of calculating a burden estimate. The Commission also
notes that certain VERs will have increased burden due to submission of
intra-hour schedules to transmission providers. However, the Commission
assumes that only VERs who choose to participate in intra-hour
scheduling are those who will receive at

least as much benefit as the cost that must be expended. For this
reason, the Commission is not including a burden estimate for this
category in the table below.
    Burden Estimate and Information Collection Costs: The estimated
Public Reporting burden and cost for the requirements contained in this
Final Rule follow.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Number of
Data collection FERC 516 (as contained      Number and type of      responses per      Hours per response                 Total annual hours
       in Final Rule in RM10-11)               respondents           respondent
                                        (1)......................             (2)  (3)......................  (1 x 2 x 3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Conforming tariff changes to require    142 Transmission                        1  8 first year only........  1,136 first year only.
 intra-hourly scheduling, waiver, or     Providers.\354\
 deviation request; and rate treatment
 terms for Ancillary Service.
Implementation of intra-hourly          142 Transmission                        1  30 reoccurring...........  4,260 reoccurring.
 scheduling.                             Providers.
Conforming changes to LGIA.\355\        142 Transmission                        1  20 first year only.......  2,840 first year only.
                                         Providers.
Sharing of power production             142 Transmission                        1  30 reoccurring...........  4,260 reoccurring.
 forecasting results with VER.           Providers.
Sharing of VER provided meteorological  142 Transmission                        1  30 reoccurring...........  4,260 reoccurring.
 and forced outage data with third       Providers.
 party entities (e.g. NOAA, balancing
 authority area).
Provision of meteorological and forced  160 Interconnection                     1  60 reoccurring...........  9,600 reoccurring.
 outage data to public utility           Customers with VERs per
 transmission providers for use in       year.\357\
 power production forecasting.\356\
                                       -----------------------------------------------------------------------------------------------------------------
    Totals............................  .........................  ..............  .........................  26,356 first year + reoccurring.\358\
                                                                                -------------------------------------------
                                                                                22,380 subsequent years.\359\
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the total cost of
compliance to be $3,004,584 in the first year, and $2,551,330 each year
after.
---------------------------------------------------------------------------

    \354\ The Commission estimated in the NOPR that 134 transmission
providers would have additional burdens due to the Proposed Rule.
Since then, the Commission has identified eight additional
transmission providers who are non-public utilities that file
reciprocity open access transmission tariffs that are also expected
to voluntarily comply with this rule.
    \355\ Consistent with the approach taken in Order No. 2003,
public utility transmission providers with power production
forecasting systems in place via tariff provisions and/or other
mechanisms will be required to demonstrate that deviations from the
pro forma LGIA are consistent with or superior to the pro forma
LGIA.
    \356\ Once a data exchange is implemented, the Commission
expects that this process will be automated and require little to no
day to day burden.
    \357\ The Commission estimates that there will be approximately
160 VERs that will sign an LGIA each year during the period from
July 2012-July 2015 potentially subject to this requirement. This
update from the NOPR represents more recent data.
    \358\ First year hours total 26,356, the sum of first year and
reoccurring hours.
    \359\ Annual hours total 22,380, the sum of all reoccurring
hours.
---------------------------------------------------------------------------

    Total Annual Hours in the first year (26,356 hours) @ $114 an hour
[average cost of attorney ($200 per hour), consultant ($150), technical
($80), and administrative support ($25)] = $3,004,584.
    Total Annual Hours in subsequent years (22,380 hours) @ $114 an
hour = $2,551,320.
    Title: FERC-516, Electric Rate Schedules and Tariff Filings
    Action: Proposed Collection.
    OMB Control No. 1902-0096.
    Respondents for this Rulemaking: Transmission Providers (an RTO or
ISO also may file some materials on behalf of its members) and Variable
Energy Resources.
    Frequency of Information: As indicated in the table.
    Necessity of Information: The Federal Energy Regulatory Commission
is adopting these amendments to the pro forma OATT to remedy
operational challenges related to the increased integration of VERs to
the bulk electric system. The purpose of this Final Rule is to
strengthen the pro forma OATT, so VERs can be reliably and efficiently
integrated into the electric grid and to ensure that Commission-
jurisdictional services are provided at rates, terms and conditions
that are just and reasonable and not unduly discriminatory or
preferential. This Final Rule seeks to achieve this goal by amending
the pro forma OATT and LGIA to incorporate provisions that require
intra-hourly transmission scheduling and require interconnection
customers whose generating facilities are VERs to provide
meteorological and operational data to public utility transmission
providers for the purpose of power production forecasting. The
Commission also provides guidance regarding the development of
proposals for generator regulation service.
    Internal Review: The Commission has reviewed the proposed changes
and has determined that the changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has assured itself, by means of internal review, that there
is specific, objective support for the burden estimates associated with
the information collection requirements.
    382. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director], email:
<EMAIL_ADDRESS>Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>.
Comments concerning the collection of information and the associated
burden estimate(s), may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission, phone:<PHONE_NUMBER>, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically
to the following email address:

<EMAIL_ADDRESS>Comments submitted to OMB should include
OMB Control No. 1902-0096 and Docket No. RM10-11-000.

VIII. Environmental Analysis

    383. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\360\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Rule under Sec.
380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\361\
---------------------------------------------------------------------------

    \360\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats.
& Regs. Preambles 1986-1990 ] 30,783 (1987).
    \361\ 18 CFR 380.4(a)(15) (2010).
---------------------------------------------------------------------------

IX. Regulatory Flexibility Act Analysis

    384. The Regulatory Flexibility Act of 1980 (RFA) \362\ generally
requires a description and analysis of Final Rules that will have a
significant economic impact on a substantial number of small entities.
This Final Rule applies to public utilities that own, control or
operate interstate transmission facilities \363\ and to variable energy
resources. The total estimated number of small public utility
transmission providers \364\ impacted by this Final Rule is estimated
to be ten. The Commission assumes that the Final Rule will impact all
the applicable small transmission providers equally at an average cost
of $13,500 per year. The Commission does not consider this to be a
significant economic impact. In any event, each of these entities may
seek waiver of these requirements.\365\ The Commission estimates that
all of the applicable VERs (160 per year) are small. Of these 160
entities, approximately 100 that are greater than 20 MW will be
required to comply with the Final Rule and approximately 60 that are 20
MW or less will have the option to comply with the rule. The Commission
estimates that each VER will have an average cost of $6,800 per year
because of the Final Rule. The Commission does not consider this to be
a significant economic impact on these small entities. The costs
incurred by VERs due to this rule are offset by an expected reduction
in energy imbalance penalties that will be assessed to VERs in the
future due to improved forecasting and reduced uncertainty across 15-
minute scheduling periods compared to hour-long scheduling periods.
Accordingly, the Commission certifies that this Final Rule will not
have a significant economic impact on a substantial number of small
entities.
---------------------------------------------------------------------------

    \362\ 5 U.S.C. 601-612 (2006).
    \363\ Other than those that have received waiver of the
obligation to comply with Order Nos. 888, 889, and 890.
    \364\ A ``small entity'' as referenced in the RFA refers to the
definition provided in section 3 of the Small Business Act where a
firm is ``small'' if, including its affiliates, it is primarily
engaged in the generation, transmission, and/or distribution of
electric energy for sale and its total electric output for the
preceding fiscal year did not exceed 4 million megawatt hours.
    \365\ The criteria for waiver that would be applied under this
rulemaking for small entities is unchanged from that used to
evaluate requests for waiver under Order Nos. 888, 889, and 890.
---------------------------------------------------------------------------

X. Document Availability

    385. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5:00
p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC
20426.
    386. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    387. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
XI. Effective Date and Congressional Notification

    388. These regulations are effective September 11, 2012. The
Commission has determined, with the concurrence of the Administrator of
the Office of Information and Regulatory Affairs of OMB, that this rule
is not a ``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996. The Commission will submit
this Final Rule to both houses of Congress and the Government
Accountability Office.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.

By the Commission. Commissioner LaFleur is dissenting in part with a
separate statement attached.

    Commissioner Clark voting present.

Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission amends Part 35,
Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

    Authority:  16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 71-7352.

0
2. Amend Sec.  35.28 as follows:
0
a. Paragraphs (c)(1) introductory text and (c)(1)(i) through
(c)(1)(iii) are revised.
0
b. Paragraphs (c)(1)(v) and (c)(1)(vi) are revised.
0
c. Paragraphs (c)(3) introductory text and (c)(3)(ii) are revised.
0
d. Paragraph (c)(4) is revised.
0
e. Paragraph (d) is revised.
0
f. Paragraphs (e)(1) introductory text, (e)(1)(ii), and (e)(2) are
revised.
0
g. Paragraphs (f)(1) introductory text and (f)(1)(i) are revised.
0
h. Paragraphs (f)(1)(ii) through (f)(1)(iv) are removed and reserved.
0
i. Paragraph (f)(3) is revised.
0
j. Paragraph (f)(4) is removed.

Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (c) Non-discriminatory open access transmission tariffs.
    (1) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce must have on file with the Commission an open access
transmission tariff of general applicability for transmission services,
including ancillary services, over such facilities. Such tariff must be
the pro forma tariff promulgated by the Commission, as amended from
time to time, or such other tariff as may be approved by the Commission
consistent with the principles set forth in Commission rulemaking
proceedings promulgating and amending the pro forma tariff.

    (i) Subject to the exceptions in paragraphs (c)(1)(ii),
(c)(1)(iii), (c)(1)(iv), and (c)(1)(v) of this section, the open access
transmission tariff, which tariff must be the pro forma tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff, and accompanying rates must be filed no later than 60
days prior to the date on which a public utility would engage in a sale
of electric energy at wholesale in interstate commerce or in the
transmission of electric energy in interstate commerce.
    (ii) If a public utility owns, controls, or operates facilities
used for the transmission of electric energy in interstate commerce, it
must file the revisions to its open access transmission tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff, pursuant to section 206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in accordance with the procedures
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
    (iii) If a public utility owns, controls, or operates transmission
facilities used for the transmission of electric energy in interstate
commerce, such facilities are jointly owned with a non-public utility,
and the joint ownership contract prohibits transmission service over
the facilities to third parties, the public utility with respect to
access over the public utility's share of the jointly owned facilities
must file the revisions to its open access transmission tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff pursuant to section 206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in accordance with the procedures
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
* * * * *
    (v) If a public utility obtains a waiver of the tariff requirement
pursuant to paragraph (d) of this section, it does not need to file the
open access transmission tariff required by this section.
    (vi) Any public utility that seeks a deviation from the pro forma
tariff promulgated by the Commission, as amended from time to time,
must demonstrate that the deviation is consistent with the principles
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
* * * * *
    (3) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce, and that is a member of a power pool, public utility holding
company, or other multi-lateral trading arrangement or agreement that
contains transmission rates, terms or conditions, must have on file a
joint pool-wide or system-wide open access transmission tariff, which
tariff must be the pro forma tariff promulgated by the Commission, as
amended from time to time, or such other open access transmission
tariff as may be approved by the Commission consistent with the
principles set forth in Commission rulemaking proceedings promulgating
and amending the pro forma tariff.
* * * * *
    (ii) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed on or before May 14,
2007, a public utility member of such power pool, public utility
holding company or other multi-lateral arrangement or agreement that
owns, controls, or operates facilities used for the transmission of
electric energy in interstate commerce must file the revisions to its
joint pool-wide or system-wide open access transmission tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff pursuant to section 206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in accordance with the procedures
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
* * * * *
    (4) Consistent with paragraph (c)(1) of this section, every
Commission-approved ISO or RTO must have on file with the Commission an
open access transmission tariff of general applicability for
transmission services, including ancillary services, over such
facilities. Such tariff must be the pro forma tariff promulgated by the
Commission, as amended from time to time, or such other tariff as may
be approved by the Commission consistent with the principles set forth
in Commission rulemaking proceedings promulgating and amending the pro
forma tariff.
    (i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to its open access
transmission tariff required by Commission rulemaking proceedings
promulgating and amending the pro forma tariff pursuant to section 206
of the FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Commission rulemaking
proceedings promulgating and amending the pro forma tariff.
    (ii) If a Commission-approved ISO or RTO can demonstrate that its
existing open access transmission tariff is consistent with or superior
to the pro forma tariff promulgated by the Commission, as amended from
time to time, the Commission-approved ISO or RTO may instead set forth
such demonstration in its filing pursuant to section 206 in accordance
with the procedures set forth in Commission rulemaking proceedings
promulgating and amending the pro forma tariff.
    (d) Waivers. 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.
Except as provided in paragraph (f) of this section, an application for
waiver must be filed no later than 60 days prior to the time the public
utility would have to comply with the requirement.
    (e) Non-public utility procedures for tariff reciprocity
compliance.
    (1) A non-public utility may submit an open access transmission
tariff and a request for declaratory order that its voluntary
transmission tariff meets the requirements of Commission rulemaking
proceedings promulgating and amending the pro forma tariff.
* * * * *
    (ii) If the submittal is found to be an acceptable open access
transmission tariff, an applicant in a Federal Power Act (FPA) section
211 or 211A proceeding against the non-public utility shall have the
burden of proof to show why service under the open access transmission
tariff is not sufficient and why a section 211 or 211A order should be
granted.
    (2) A non-public utility may file a request for waiver of all or
part of the reciprocity conditions contained in a public utility open
access transmission tariff, for good cause shown. An application for
waiver may be filed at any time.
    (f) Standard generator interconnection procedures and agreements.
    (1) Every public utility that is required to have on file a non-
discriminatory open access transmission tariff under this section must
amend such tariff by adding the standard interconnection procedures and

agreement and the standard small generator interconnection procedures
and agreement required by Commission rulemaking proceedings
promulgating and amending such interconnection procedures and
agreements, or such other interconnection procedures and agreements as
may be required by Commission rulemaking proceedings promulgating and
amending the standard interconnection procedures and agreement and the
standard small generator interconnection procedures and agreement.
    (i) Any public utility that seeks a deviation from the standard
interconnection procedures and agreement or the standard small
generator interconnection procedures and agreement required by
Commission rulemaking proceedings promulgating and amending such
interconnection procedures and agreements, must demonstrate that the
deviation is consistent with the principles set forth in Commission
rulemaking proceedings promulgating and amending such interconnection
procedures and agreements.
* * * * *
    (3) A public utility subject to the requirements of this paragraph
(f) may file a request for waiver of all or part of the requirements of
this paragraph (f), for good cause shown.
* * * * *

    Note:  The following appendices will not be published in the
Code of Federal Regulations.

Appendix A: List of Short Names of Commenters on the Federal Energy
Regulatory Commission's Notice of Proposed Rulemaking on Integration of
Variable Energy Resources--Docket No. RM10-11-000, November 2010

------------------------------------------------------------------------
    Short name or acronym                      Commenter
------------------------------------------------------------------------
A123.........................  A123 Systems, Inc.
AEP..........................  American Electric Power Service
                                Corporation
ALLETE.......................  ALLETE Inc.
ACSF.........................  American Clean Skies Foundation
Alstom.......................  Alstom Grid, Inc.
American Gas.................  American Gas Association
APPA.........................  American Public Power Association
Argonne National Lab.........  Argonne National Laboratory
Arizona Corporation            Arizona Corporation Commission
 Commission.
Avista.......................  Avista Corporation
AWEA.........................  American Wind Energy Association
Beacon Power.................  Beacon Power Corporation
Bonneville Power.............  Bonneville Power Administration
BP Companies.................  BP Energy Company and BP Wind Energy
                                North America, Inc.
BrightSource.................  BrightSource Energy, Inc.
Business Council.............  Business Council for Sustainable Energy
CESA.........................  California Energy Storage Alliance
California State Water         California Department of Water Resources
 Project.                       State Water Project
California ISO...............  California Independent System Operator
                                Corporation
California PUC...............  California Public Utilities Commission
CEERT........................  Center for Energy Efficiency and
                                Renewable Technologies
Center for Rural Affairs.....  Center for Rural Affairs
CMUA.........................  California Municipal Utilities
                                Association; Cities of Alameda, Anaheim,
                                Azusa, Banning, Burbank, Cerritos,
                                Colton, Corona, Glendale, Gridley,
                                Healdsburg, Hercules, Lodi, Lompoc,
                                Moreno Valley, Needles, Palo Alto,
                                Pasadena, Pittsburg, Rancho Cucamonga,
                                Redding, Riverside, Roseville, Santa
                                Clara, Shasta Lake, Ukiah, and Vernon;
                                the Imperial, Merced, Modesto, and
                                Turlock Irrigation Districts; the
                                Northern California Power Agency;
                                Southern California Public Power
                                Authority; Transmission Agency of
                                Northern California; Lassen Municipal
                                Utility District; Power and Water
                                Resources Pooling Authority; Sacramento
                                Municipal Utility District; the Trinity
                                and Truckee Donner Public Utility
                                Districts; the Metropolitan Water
                                District of Southern California; and the
                                City and County of San Francisco, Hetch-
                                Hetchy
Clean Line...................  Clean Line Energy Partners, LLC
CGC..........................  Coalition for Green Capital
Defenders of Wildlife........  Wilderness Society and Defenders of
                                Wildlife
Detroit Edison...............  Detroit Edison Company
Dominion.....................  Dominion Resources Services, Inc.
Duke.........................  Duke Energy Corporation
EEI..........................  Edison Electric Institute
ELCON........................  Electricity Consumers Resource Council
EPSA.........................  Electric Power Supply Association
ENBALA.......................  ENBALA Power Networks
Entergy......................  Entergy Services, Inc.
Environmental Defense Fund...  Environmental Defense Fund
E.ON C&R.....................  E.ON Climate & Renewables North America
Exelon.......................  Exelon Corporation
Federal Trade Commission.....  Federal Trade Commission
FirstEnergy..................  FirstEnergy Service Company
First Wind...................  First Wind Energy, LLC
FriiPwr......................  FriiPwr USA Ltd
Grant PUD....................  Public Utility District No. 2 of Grant
                                County, Washington
Grays Harbor PUD.............  Public Utility District No. 1 of Grays
                                Harbor County, Washington
Iberdrola....................  Iberdrola Renewables, Inc.
Idaho Power..................  Idaho Power Company
Independent Energy Producers.  Independent Energy Producers Association

Independent Power Producers    Arizona Competitive Power Alliance;
 Coalition-West.                Colorado Independent Energy Association;
                                Independent Energy Producers Association
                                (California); New Mexico Independent
                                Power Producers Coalition; and the
                                Northwest & Intermountain Power
                                Producers Coalition.
INGAA........................  Interstate Natural Gas Association of
                                America
Invenergy Wind...............  Invenergy Wind Development LLC
ISO New England..............  ISO New England Inc. and the New England
                                Power Pool
ISO/RTO Council..............  Alberta Electricity System Operator;
                                California Independent System Operator;
                                Electric Reliability Council of Texas;
                                Independent Electricity System Operator
                                of Ontario; ISO New England, Inc.;
                                Midwest Independent Transmission System
                                Operator, Inc.; New Brunswick System
                                Operator; New York Independent System
                                Operator, Inc.; PJM Interconnection,
                                L.L.C.; and Southwest Power Pool, Inc.
ITC Companies................  ITCTransmission; Michigan Electric
                                Transmission Company, LLC; ITC Midwest
                                LLC; and ITC Great Plains, LLC
Joint Parties................  Arizona Public Service Company; The
                                Boeing Company, El Paso Electric; New
                                York Independent System Operator; Old
                                Dominion Electric Cooperative; PJM
                                Interconnection, L.L.C.; Salt River
                                Project Agriculture Improvement and
                                Power District; Southwest Power Pool;
                                Tennessee Valley Authority; Tucson
                                Electric Power Company; UNS Gas, Inc.;
                                and the Vermont Department of Public
                                Service
Joint Initiative.............  Joint Initiative Facilitators
Large Public Power Council...  Austin Energy; Chelan County Public
                                Utility District No. 1; Clark Public
                                Utilities, Colorado Springs Utilities;
                                CPS Energy (San Antonio); ElectriCities
                                of North Carolina; Grant County Public
                                Utility District; IID Energy (Imperial
                                Irrigation District); JEA (Jacksonville,
                                FL); Long Island Power Authority; Los
                                Angeles Department of Water and Power;
                                Lower Colorado River Authority; MEAG
                                Power; Nebraska Public Power District;
                                New York Power Authority; Omaha Public
                                Power District; Orlando Utilities
                                Commission; Platte River Power
                                Authority; Puerto Rico Electric Power
                                Authority; Sacramento Municipal Utility
                                District; Salt River Project; Santee
                                Cooper; Seattle City Light; Snohomish
                                County Public Utility District No. 1;
                                and Tacoma Public Utilities
LADWP........................  Department of Water and Power of the City
                                of Los Angeles
Massachusetts DPU............  Massachusetts Department of Public
                                Utilities
MidAmerican..................  MidAmerican Energy Holdings Company
Midwest Energy...............  Midwest Energy, Inc.
Midwest ISO..................  Midwest Independent Transmission System
                                Operator, Inc.
Midwest ISO Transmission       Ameren Services Company, as agent for
 Owners.                        Union Electric Company d/b/a Ameren
                                Missouri; Ameren Illinois Company d/b/a
                                Ameren Illinois and Ameren Transmission
                                Company of Illinois; American
                                Transmission Company LLC; Big Rivers
                                Electric Corporation; City Water, Light
                                & Power (Springfield, IL); Dairyland
                                Power Cooperative; Duke Energy
                                Corporation for Duke Energy Ohio, Inc.,
                                Duke Energy Indiana, Inc., and Duke
                                Energy Kentucky, Inc.; Great River
                                Energy; Hoosier Energy Rural Electric
                                Cooperative, Inc. (``Hoosier''); Indiana
                                Municipal Power Agency; Indianapolis
                                Power & Light Company (``IPL'');
                                Michigan Public Power Agency;
                                MidAmerican Energy Company; Minnesota
                                Power (and its subsidiary Superior
                                Water, L&P); Montana-Dakota Utilities
                                Co.; Northern Indiana Public Service
                                Company; Northern States Power Company,
                                a Minnesota corporation, and Northern
                                States Power Company, a Wisconsin
                                corporation, subsidiaries of Xcel Energy
                                Inc. (``Xcel Energy''); NorthWestern
                                Wisconsin Electric Company; Otter Tail
                                Power Company; Southern Illinois Power
                                Cooperative; Southern Indiana Gas &
                                Electric Company (d/b/a Vectren Energy
                                Delivery of Indiana); Southern Minnesota
                                Municipal Power Agency; Wabash Valley
                                Power Association, Inc.; and Wolverine
                                Power Supply Cooperative, Inc.
M-S-R Public Power Agency....  Modesto Irrigation District; City of
                                Santa Clara, California; and City of
                                Redding, California
Montana PSC..................  Montana Public Service Commission
NEMA.........................  National Electrical Manufacturers
                                Association
National Grid................  National Grid USA
NRECA........................  National Rural Electric Cooperative
                                Association
Natural Gas..................  Natural Gas Supply Association
NaturEner....................  NaturEner USA, LLC
NE Conference of PUCs........  New England Conference of Public
                                Utilities Commissioners
NESCOE.......................  New England States Committee on
                                Electricity
NV Energy....................  Nevada Power Company and Sierra Pacific
                                Power Company
New York ISO.................  New York Independent System Operator,
                                Inc.
NextEra......................  NextEra Energy, Inc.
NERC.........................  North American Electric Reliability
                                Corporation
NAESB........................  North American Energy Standards Board
NOAA.........................  National Oceanic and Atmospheric
                                Administration
NorthWestern.................  NorthWestern Corporation
Organization of Midwest ISO    Organization of Midwest ISO States
 States.
Oregon & New Mexico PUC......  Public Utility Commissioners of Oregon
                                and New Mexico and Paul Newman, Arizona
                                Commissioner
Pacific Gas & Electric.......  Pacific Gas and Electric Company
PNW Parties..................  Avista Corporation; the Bonneville Power
                                Administration; Idaho Power Company;
                                NorthWestern Corporation, dba
                                NorthWestern Energy; PacifiCorp;
                                Portland General Electric Company; the
                                Public Generating Pool (Tacoma Power,
                                Eugene Water and Electric Board, and
                                Public Utility Districts for Chelan,
                                Clark, Cowlitz, Douglas, Grant,
                                Klickitat, Pend Oreille, and Snohomish
                                counties); the Public Power Council;
                                Puget Sound Energy, Inc.; and Seattle
                                City Light

PJM..........................  PJM Interconnection, L.L.C.
Powerex......................  Powerex Corporation
Public Interest Organizations  Alliance for Clean Energy New York;
                                Center for Rural Affairs; Citizens
                                Utility Board of Wisconsin; Climate and
                                Energy Project; Conservation Law
                                Foundation; Defenders of Wildlife;
                                Energy Conservation Council of
                                Pennsylvania; Energy Future Coalition;
                                Environment Northeast; Environmental
                                Defense Fund; Environmental Law & Policy
                                Center; Fresh Energy; Great Plains
                                Institute; Natural Resources Defense
                                Council; Office of the Ohio Consumers'
                                Counsel; Pace Energy and Climate Center;
                                Project for Sustainable FERC Energy
                                Policy; Sierra Club; The Wilderness
                                Society; Union of Concerned Scientists;
                                Western Grid Group; Western Resource
                                Advocates; and Wind on the Wires
Public Power Council.........  Public Power Council
Puget........................  Puget Sound Energy, Inc.
Recycled Energy..............  Recycled Energy Development
RENEW........................  Renewable Energy New England, Inc.
RenewElec....................  The RenewElec Project
SMUD.........................  Sacramento Municipal Utility District
San Diego Gas & Electric.....  San Diego Gas & Electric Company
Snohomish County PUD.........  Public Utility District No. 1 of
                                Snohomish County, Washington
SEIA.........................  Solar Energy Industries Association and
                                the Large-Scale Solar Association
Southern California Edison...  Southern California Edison Company
Southern.....................  Southern Company Services, Inc.
Southern MN Municipal........  Southern Minnesota Municipal Power Agency
SWEA.........................  Southwest Energy Alliance
Southwestern.................  Southwestern Power Administration
Spectra Entities.............  Spectra Energy Transmission, LLC and
                                Spectra Energy Partners, LP
Sunflower and Mid-Kansas.....  Sunflower Electric Power Corporation and
                                Mid-Kansas Electric Company, LLC
TA Miller....................  T.A. Miller
Tacoma Power.................  City of Tacoma, Department of Public
                                Utilities, Light Division (Washington)
Tres Amigas..................  Tres Amigas LLC
TVA..........................  Tennessee Valley Authority
US Bureau of Reclamation.....  United States Bureau of Reclamation
Utility Economic Engineers...  Utility Economic Engineers
Vestas.......................  Vestas-American Wind Technology, Inc.
Viridity Energy..............  Viridity Energy, Inc.
Vote Solar...................  Vote Solar Initiative
WUTC.........................  Washington Utilities and Transportation
                                Commission
WestConnect..................  Arizona Public Service Company; El Paso
                                Electric Company, Imperial Irrigation
                                District; NV Energy, Public Service
                                Company of Colorado; Public Service
                                Company of New Mexico; Sacramento
                                Municipal Utility District; Salt River
                                Project; Southwest Transmission
                                Cooperative, Inc.; Transmission Agency
                                of Northern California; Tri-State
                                Generation and Transmission Association,
                                Inc.; Tucson Electric Power Company and
                                Western Area Power Administration
Western Farmers..............  Western Farmers Electric Cooperative
Western Grid.................  Western Grid Group
Xcel.........................  Xcel Energy Services Inc.
Xtreme Power.................  Xtreme Power Inc.
------------------------------------------------------------------------

Appendix B: Pro Forma Open Access Transmission Tariff

    The Commission amends the following sections of the pro forma
OATT:

a. Section 13.8
b. Section 14.6

    13.8 Scheduling of Firm Point-To-Point Transmission Service:
Schedules for the Transmission Customer's Firm Point-To-Point
Transmission Service must be submitted to the Transmission Provider
no later than 10:00 a.m. [or a reasonable time that is generally
accepted in the region and is consistently adhered to by the
Transmission Provider] of the day prior to commencement of such
service. Schedules submitted after 10:00 a.m. will be accommodated,
if practicable. Hour-to-hour and intra-hour (four intervals
consisting of fifteen minute schedules) schedules of any capacity
and energy that is to be delivered must be stated in increments of
1,000 kW per hour [or a reasonable increment that is generally
accepted in the region and is consistently adhered to by the
Transmission Provider]. Transmission Customers within the
Transmission Provider's service area with multiple requests for
Transmission Service at a Point of Receipt, each of which is under
1,000 kW per hour, may consolidate their service requests at a
common point of receipt into units of 1,000 kW per hour for
scheduling and billing purposes. Scheduling changes will be
permitted up to twenty (20) minutes [or a reasonable time that is
generally accepted in the region and is consistently adhered to by
the Transmission Provider] before the start of the next scheduling
interval provided that the Delivering Party and Receiving Party also
agree to the schedule modification. The Transmission Provider will
furnish to the Delivering Party's system operator, hour-to-hour and
intra-hour schedules equal to those furnished by the Receiving Party
(unless reduced for losses) and shall deliver the capacity and
energy provided by such schedules. Should the Transmission Customer,
Delivering Party or Receiving Party revise or terminate any
schedule, such party shall immediately notify the Transmission
Provider, and the Transmission Provider shall have the right to
adjust accordingly the schedule for capacity and energy to be
received and to be delivered.
    14.6 Scheduling of Non-Firm Point-To-Point Transmission Service:
Schedules for Non-Firm Point-To-Point Transmission Service must be
submitted to the Transmission Provider no later than 2:00 p.m. [or a
reasonable time that is generally accepted in the region and is