to all interconnection customers, regardless of size, and as a result
any reporting requirements adopted in the GIA should apply to
generators with a capacity of less than 20 MW. California PUC asks that
the Commission make clear that public utility transmission providers
are not prohibited from requesting meteorological and operational data
from small VERs. Environmental Defense Fund states that the Commission
should host a technical conference to examine issues arising from
requiring small generators to contribute information to support power
production forecasting.
---------------------------------------------------------------------------

    \218\ E.g., Bonneville Power; Idaho Power.
---------------------------------------------------------------------------

    191. Some commenters address other aspects of the Commission's
proposal to amend the pro forma LGIA. AWEA questions the Commission's
preliminary conclusion that the LGIA provides sufficient
confidentiality protection for sensitive operational and meteorological
data, stating that vendors providing forecasts to public utility
transmission providers must not be allowed to use the data they collect
for developing forecasts for the public utility transmission provider
for any other purpose without express agreement. MidAmerican asks the
Commission to clarify that there will not be any additional penalties
for failure to provide accurate meteorological and operational data,
other than the contractual remedies for breach already provided for in
the pro forma LGIA. MidAmerican states that it recognizes that
meteorological data are not always available if, for example,
communication from a collecting device is interrupted. RenewElec
recommends that the Commission set forth a data retention requirement
in the new pro forma LGIA Article 8.4 that would require public utility
transmission providers to maintain data collected from interconnection
customers whose generating facilities are VERs for at least 10 years,
facilitating follow-up studies to update power production forecasts.
f. Commission Determination
    192. The Commission affirms the Proposed Rule and amends the pro
forma LGIA to include a new Article 8.4 setting forth the reporting
requirements adopted in this Final Rule. The Commission directs all
public utility transmission providers to file a revised pro forma LGIA
within 12 months of the effective date of this Final Rule reflecting
the revisions adopted herein. As noted below, public utility
transmission providers that have already implemented meteorological or
forced outage reporting requirements may seek to demonstrate, on
compliance, that these existing business practices and market rules
adequately satisfy the requirements of this Final Rule.
    193. As set forth in the Proposed Rule, Article 8.4 of the pro
forma LGIA did not state where the meteorological and forced outage
data reporting requirements would be specified in an LGIA. The
Commission agrees with Bonneville Power that it is appropriate to state
reporting requirements for meteorological and forced outage data in
Appendix C, Interconnection Details, as this will allow the
requirements to be changed from time to time. The Commission therefore
revises proposed Article 8.4 to specify that reporting requirements for
meteorological and forced outage data would be set forth in Appendix C,
Interconnection Details, of an LGIA. A transmission provider with an
executed LGIA that seeks reporting of such data may negotiate revisions
to Appendix C related to such reporting requirements with the
interconnection customer. To the extent the parties mutually agree on
changes to Appendix C, such changes to Appendix C need not be submitted
to the Commission for review. If the parties are unable to reach
agreement on proposed modifications to Appendix C, however, these
parties may invoke their rights, as relevant, to modify the LGIA under
sections 205 or 206 of the FPA, as appropriate, and pursuant to Article
30.11 of the LGIA.
    194. The Commission disagrees with commenters suggesting that
flexibility provided by business practices or market rules makes them a
superior alternative for implementing the meteorological and forced
outage reporting requirements adopted in this Final Rule. The
Commission has sought to address public utility transmission providers'
need for flexibility by clarifying that reporting requirements are to
be set forth in Appendix C to the LGIA, while also addressing
interconnection customers' need for certainty in the obligations placed
on them. The Commission appreciates that public utility transmission
providers in some regions, including RTOs and ISOs, have already
implemented meteorological or forced outage reporting under business
practices and markets rules. Such public utility transmission providers
may seek to demonstrate in their compliance filing how continued use of
these existing business practices and 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.\219\
---------------------------------------------------------------------------

    \219\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at PP 9-10.
---------------------------------------------------------------------------

    195. The Commission declines to modify existing LGIAs already in
effect to include Article 8.4 of the pro forma LGIA as adopted in this
Final Rule. The Commission acknowledges that, in some situations, there
may be a sufficient amount of VERs already interconnected to the public
utility transmission provider's system to make data from those
resources useful or even necessary to properly implement power
production forecasting. However, several considerations lead us to
decline to modify every LGIA in effect on a generic basis. First the
Commission believes retroactive changes to every LGIA in effect could
be administratively burdensome to public utility transmission providers
and interconnection customers, especially where the public utility
transmission provider is not engaged in power production forecasting.
Second, we note that nothing in the pro forma LGIA precludes the
parties to an LGIA from mutually agreeing to revise the requirements
set forth in Appendix C to reflect the reporting of meteorological and
forced outage data. Indeed, we note that Article 9.4 of the pro forma
LGIA recognizes that Appendix C will be modified to reflect changes to
the interconnection customer's requirements as they may change from
time to time. Finally, if the parties are unable to agree to
modifications of Appendix C, we note that pursuant to Article 30.11 of
the pro forma LGIA, the transmission provider has the right to make a
unilateral filing to the Commission proposing to modify an

existing LGIA under section 205 of the FPA.
    196. For similar reasons, the Commission declines suggestions to
implement data reporting requirements through the pro forma OATT
instead of the pro forma LGIA or to include the requirements in the pro
forma SGIA. The effect of relying on the pro forma OATT would be to
impose the data reporting requirements adopted in this Final Rule on
existing interconnection customers retroactively, including those with
resources under 20 MW that are subject to the pro forma SGIA. Like data
from existing resources, data from small resources may be useful or
necessary for power production forecasting, yet the record in this
proceeding does not demonstrate that the need for data from small
resources is so great as to outweigh the potential burden that
reporting requirements could impose on smaller resources. Just as the
pro forma LGIA provides an opportunity for public utility transmission
providers to mutually agree with interconnection customers regarding
reporting requirements, nothing in the pro forma SGIA precludes the
transmission provider from negotiating with the owners and operators of
small VERs to update their SGIAs to provide for the reporting of
meteorological and forced outage data that are necessary for public
utility transmission providers to employ power production forecasting.
As with the pro forma LGIA, section 12.12 of the pro forma SGIA
provides an opportunity for parties to an SGIA to bring any
disagreement to the Commission for resolution.
    197. In response to Midwest ISO Transmission Owners, the Commission
notes that the extent to which a new LGIA is necessitated by a new
Interconnection Request or Material Modification is governed by the pro
forma LGIA and Commission precedent. To the extent a new LGIA is
warranted, the VER interconnection customer would be subject to the
relevant requirements of this Final Rule in effect at the time. Public
utility transmission providers may seek to demonstrate in their
compliance filings how continued use of 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.\220\
---------------------------------------------------------------------------

    \220\ See Id. P 910.
---------------------------------------------------------------------------

    198. With regard to AWEA's concern regarding the confidentiality of
data, the Commission agrees that meteorological and forced outage data
can be commercially sensitive, but concludes that the Article 22 of the
pro forma LGIA provides adequate safeguards for reported data.\221\ Any
vendor providing forecasts to a public utility transmission provider
would be an agent of the public utility transmission provider subject
to the confidentiality obligations of the pro forma LGIA. With regard
to MidAmerican's concern regarding penalties for failure to provide
accurate meteorological and forced outage data, the Commission notes
that the extent to which penalties beyond those set forth in the pro
forma LGIA might be appropriate for failing to satisfy data reporting
requirements will necessarily depend on the facts and circumstances
surrounding each instance of failed reporting. The Commission
appreciates that unforeseen circumstances may impair an interconnection
customer's ability to report data and that the impact of failed
reporting may in many instances be de minimus. However, it would not be
appropriate for the Commission to conclude generically that in no
circumstance would additional penalties beyond those remedies set forth
in the pro forma LGIA be appropriate for failure to comply with the
data reporting requirements of an executed LGIA.
---------------------------------------------------------------------------

    \221\ Article 22 of the pro forma LGIA defines Confidential
Information to include, among other things, all information relating
to a Party's technology, research and development, business affairs,
and pricing. Each party to an LGIA must hold in confidence and may
not disclose to any person Confidential Information during the term
of an LGIA and for a period of three years after the expiration or
termination of an LGIA.
---------------------------------------------------------------------------

    199. Finally, the Commission declines to impose special retention
requirements for reported meteorological and forced outage data as
requested by RenewElec. The time period over which a public utility
transmission provider would need to retain meteorological or forced
outage data will be a function of the type of power production
forecasting being employed by the public utility transmission provider.
2. Definition of VER
a. Commission Proposal
    200. In the Proposed Rule, the Commission sought to modify the pro
forma LGIA to include a new definition for Variable Energy Resource in
Article 1. The proposed definition identified a Variable Energy
Resource as a device for the production of electricity that is
characterized by an energy source that: (1) Is renewable; (2) cannot be
stored by the facility owner or operator; and (3) has variability that
is beyond the control of the facility owner or operator.\222\ The
Commission stated that it believed the proposed definition was
consistent with NERC's characterization of variable generation.\223\
---------------------------------------------------------------------------

    \222\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 64.
    \223\ Id. (citing NERC, Accommodating High Levels of Variable
Generation 13-14 (2009), available at http://www.nerc.com/files/IVGTF_Report_041609.pdf).
---------------------------------------------------------------------------

b. Comments
    201. EEI supports the Commission's proposed definition without
modification. California ISO supports the definition's focus on source
of energy, but suggests that the phrase ``by an energy source that'' be
replaced with ``by a fuel source that.'' California ISO states that
this change would make clear that the three conditions that follow
pertain to the fuel source and not the nature of the facility itself.
    202. Other commenters disagree with the focus on the source of
energy, arguing that a VER should be defined by reference to its
operating characteristics, including the ability to control
output.\224\ BrightSource states that this would allow for comparison
between facilities with different fuel sources on standard operational
and reliability time-frames and also avoid confusion about types of
plants that combine renewable and conventional fuel sources, such as
solar-gas hybrids. Joined by SEIA, BrightSource argues that a plant
able to maintain a high level of operational control comes close to
fulfilling the operational characteristics of a non-VER generation and
should be treated as such for purposes of the Proposed Rule's
requirements. NextEra agrees, stating that some resources can control
the variability of their facility by adjusting output through
feathering blades, self-curtailment, or similar measures. SEIA suggests
that the Commission consider alternative criteria that could provide a
distinction between VERs with a high level of control and VERs without
such controls, such as if actual production can remain within some
statistical measure of forecast accuracy during its operating hours.
MidAmerican similarly requests that the Commission adopt a definition
based on physical electrical generation output characteristics rather
than input attributes such as fuel type, suggesting that whether energy
sources qualify as ``renewable'' varies among states that have
developed their own renewable resource regulations.
---------------------------------------------------------------------------

    \224\ E.g., AWEA; BrightSource; NaturEner; NextEra; RenewElec;
SEIA.

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

    203. Several of these commenters question the applicability of the
proposed definition to resources that use energy storage to control
output. NaturEner provides a hypothetical example of a plant coupled
with storage and asks that the Commission provide clarification
regarding the impact of such pairing on capacity reserve obligations.
BrightSource asks the Commission to modify the definition to address
how much storage results in a plant not being considered a VER for
purposes of the Proposed Rule and any future rules. AWEA and NextEra
request clarification that the proposed definition would not prevent
VERs from electing to maintain VER status even if they use energy
storage, other firming technologies, or otherwise have the ability to
adjust output. RenewElec and SEIA argue that, regardless of the
Commission's determination on the storage issue for VERs, such
resources should not be exempt from reporting meteorological data to
their public utility transmission provider. BrightSource and SEIA state
that the applicability of the proposed definition is sufficiently
important that the Commission should consider a technical conference on
the issue.
    204. Some commenters focus on the applicability of the proposed
definition to particular types of resources, such as tidal, run-of-
river hydro, conduit hydro, co-generation, or biomass.\225\ Snohomish
County PUD argues that, although such facilities would appear to
satisfy the proposed definition, they should not be required to report
the proposed data to public utility transmission providers because the
data reporting would provide minimal benefit to grid operators while
imposing a significant burden on these resources. Focusing on run-of-
river hydro, Snohomish County PUD contends that whether such a facility
is available at any given moment has no impact on the extent to which a
sudden wind ramp might change production on the grid. NorthWestern and
Pacific Gas & Electric agree, arguing that run-of-river hydro is much
more predictable than wind or solar generation on a short-term basis
and, as a result, there would be little benefit to collecting the
meteorological data from such resources. In contrast, Entergy argues
that the proposed definition and associated reporting requirements
should be imposed on Qualifying Facilities to avoid gaps in forecasting
and to allow public utility transmission providers to accommodate the
variability that exists with both Qualifying Facilities and VERs.
---------------------------------------------------------------------------

    \225\ E.g., Grays Harbor PUD; NorthWestern; Pacific Gas &
Electric; Snohomish County PUD.
---------------------------------------------------------------------------

    205. Other commenters question the application of the proposed
definition to solar resources.\226\ California ISO explains that while
solar thermal resources store solar thermal heat, they do not store
solar irradiance itself, which is the energy source for the solar
thermal facility. California ISO asks the Commission to clarify that a
solar thermal facility would fall under the proposed definition.
BrightSource contends that the storage and variability elements of the
proposed definition appear to overlap functionally for a solar thermal
plant, given that variability during the operating day could be
controlled in many ways by the facility. BrightSource requests
clarification regarding whether a VER would have to meet both or just
one of these elements to fall within the definition.
---------------------------------------------------------------------------

    \226\ E.g., BrightSource; California ISO.
---------------------------------------------------------------------------

    206. ISO New England and NorthWestern offer opposing views on
application of the proposed definition and associated reporting
requirements on behind-the-meter generation. ISO New England recommends
that all distributed or behind-the-meter generation should be required
to provide to the balancing and transmission entities in its area, at a
minimum, specification of the technology and precise location of the
installed resource so that a forecast of output can be developed on an
aggregate scale to include in the balancing area forecast.
    207. California State Water Project argues that its wholesale
participating load resource also meets the definition of a VER.
California State Water Project explains that participating load's
primary purpose is not the provision of services to the grid, but
rather water management, and that the load is subject to variability
for reasons beyond California State Water Projects' control, such as
competing environmental and water management requirements. Accordingly,
California State Water Project requests that consideration be given to
expanding the VERs definition to include large wholesale demand
response resources that bid into markets not through a baseline
mechanism, but rather on a basis comparable to generation.
    208. ISO New England requests that the Commission afford
flexibility for entities to use existing, superior definitions of VERs.
The ISO New England Tariff already uses the term ``Intermittent Power
Resources'' for wind, solar, run-of-river hydro and other renewable
resources that do not have control over their net power output. As
such, ISO New England requests that the Commission allow entities to
use existing, superior approaches to the extent these are consistent
with the objectives of the proposed reforms. ISO New England states
that adding another term to its tariff could potentially lead to
confusion, and therefore, argues that the region should be afforded the
opportunity to consider the existing terminology in the ISO New England
Tariff, and determine whether any changes are warranted.
    209. Bonneville Power states that, in light of its position that
the pro forma LGIA provides transmission providers with the authority
to update operational requirements for VERs, the Commission's proposed
definition is unnecessary. However, Bonneville Power nonetheless states
that it supports the inclusion of the proposed definition in all new
VER interconnection agreements.
c. Commission Determination
    210. The Commission adopts the Proposed Rule's definition of VER
and, accordingly, amends Article 1 of the pro forma LGIA to include the
following definition:

    Variable Energy Resource shall mean a device for the production
of electricity that is characterized by an energy source that: (1)
is renewable; (2) cannot be stored by the facility owner or
operator; and (3) has variability that is beyond the control of the
facility owner or operator.

The Commission finds it necessary to define VERs in the pro forma LGIA
in order to identify those resources that are required to provide to
their public utility transmission provider meteorological and forced
outage data necessary to enable the public utility transmission
provider to develop and deploy power production forecasting. The
Commission therefore declines to define VERs by their operating
characteristics as suggested by BrightSource and MidAmerican or by
reference to their lack of ability to store output, self-curtail
production, or otherwise firm deliveries as suggested by BrightSource,
NextEra and others. The Commission also declines to define VERs by
their fuel type as suggested by California ISO, because fuel type is an
unduly restrictive subset of energy type.\227\
---------------------------------------------------------------------------

    \227\ ``Fuel'' is defined as a material used to produce heat or
power by burning. See Merriam Webster, http://www.Merriam-Webster.com, 2011. (November 4, 2011).
---------------------------------------------------------------------------

    211. As noted elsewhere in this Final Rule, power production
forecasting

allows the public utility transmission provider to understand the
characteristics of the input energy source for particular resources, to
use those characteristics to predict how the resources will operate,
and in turn to determine whether and to what degree the public utility
transmission provider will need to reserve capacity to manage
variability in generation output. Therefore, it is the variability of
the energy source, not the operating characteristics of the plant or
nature of output, that are critical to identifying the set of resources
that must be subject to the meteorological and forced outage data
requirements adopted above. Defining VERs by reference to operating
characteristics or level of storage could limit the reporting of data
in ways that undermines that ability of public utility transmission
providers to engage in power production forecasting.
    212. The Commission declines to establish an exemption to the data
reporting requirements in this Final Rule for VERs utilizing energy
storage or other firming technologies. Not only would this exemption
inhibit the public utility transmission provider's capacity to predict
how the VER resources will operate, but there is also insufficient
evidence in this record to identify an objective threshold for
exemption. The Commission clarifies that the purpose of this definition
is to identify the resources that are required by this Final Rule to
provide to their public utility transmission provider meteorological
and forced outage data; the purpose is not, as suggested by NaturEner,
to assign capacity reserve obligations or other charges. Nor does this
definition supersede those created by other entities for purposes
outside this rule, such as tax benefit purposes or renewable energy
credits.
    213. For similar reasons, the Commission declines to limit the VER
definition in the pro forma LGIA to solar and wind resources so as to
exclude run-of-river hydro, tidal, or other new and emerging VER
technologies. Although the Commission anticipates that public utility
transmission providers initially will engage in power production
forecasting predominantly for wind and solar VERs, we leave to the
public utility transmission providers to determine whether their
individual systems necessitate power production forecasting for other
types of VERs. Categorically excluding other types of resources would
undermine the flexibility being provided in this Final Rule. At the
same time, we decline to establish minimum reporting requirements for
non-wind and non-solar VERs and leave to the public utility
transmission providers and VERs to negotiate what data are necessary
for developing and deploying power production forecasting for these
resources, taking into account the size and configuration of the VER,
its characteristics, location, and its importance in maintaining
generation resource adequacy and transmission system reliability in its
area.\228\ Because such requirements will vary system by system, it is
not necessary to hold a technical conference to explore generic
application of the VER definition as suggested by BrightSource and
SEIA.
---------------------------------------------------------------------------

    \228\ If parties are unable to reach an agreement the public
utility transmission provider may submit a filing requesting the
data and demonstrating how it will be used for power production
forecasting pursuant to section 205 of the FPA.
---------------------------------------------------------------------------

    214. In response to California State Water Project, the Commission
clarifies that VERs are not defined herein to include demand response
resources. A demand response resource is not a device for the
production of electricity and, therefore, would not fall within the VER
definition adopted in the pro forma LGIA.\229\ In response to ISO New
England and NorthWestern, the definition potentially could apply to
behind-the-meter generation, although such resources would only be
subject to data reporting requirements adopted in this Final Rule to
the extent they enter into a new LGIA or materially modify an existing
LGIA after the effective date of this Final Rule.
---------------------------------------------------------------------------

    \229\ A demand response resource may use behind-the-meter
generation, potentially including VERs, to facilitate the provision
of demand response. Such use, however, does not mean that such
behind-the-meter generation is itself a demand response resource.
---------------------------------------------------------------------------

    215. ISO New England inquires as to the impact of the VER
definition on other definitions in a public utility transmission
provider's existing tariff. As noted above, public utility transmission
providers that are RTOs or ISOs may seek to demonstrate in their
compliance filing how existing tariffs, business practices or market
rules are 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.
    216. With regard to Entergy's request that the Commission apply the
proposed outage reporting requirement to Qualifying Facilities, we
clarify that the data-reporting requirements under this rule apply to
interconnection customers whose generating facilities are VERs as
defined herein. Specifically, when an electric utility purchases an
interconnected Qualifying Facility's total output, the relevant state
authority exercises authority over the interconnection and the
allocation of interconnection costs. But when an electric utility
interconnecting with a Qualifying Facility does not purchase all of the
Qualifying Facility's output and instead transmits the Qualifying
Facility power in interstate commerce to another purchaser, the
Commission exercises jurisdiction over the rates, terms, and conditions
affecting or related to such service, such as interconnections.\230\
Thus, for a Qualifying Facility that is a VER, when the interconnected
Qualifying Facility is selling its total output to an electric utility,
the meteorological and forced outage reporting requirements of this
Final Rule do not apply. However, when an electric utility
interconnecting with a Qualifying Facility does not purchase all of the
Qualifying Facility's output and instead transmits the Qualifying
Facility power in interstate commerce to another purchaser, the
meteorological and forced outage reporting requirements of this Final
Rule are applicable.
---------------------------------------------------------------------------

    \230\ Order No. 2003, FERC Stats. & Regs. ] 61,103 at P 813. The
Commission regulations governing the exemptions enjoyed by
Qualifying Facilities are codified at 18 CFR Part 292, Subpart F (18
CFR 292.601-292.602 (2011)). Limited exemptions from sections 205
and 206 of the FPA apply to certain sales of energy and capacity
made by Qualifying Facilities. See also Terra-Gen Dixie Valley, LLC,
132 FERC ] 61,215, at PP 45-46 (2010).
---------------------------------------------------------------------------

3. Data Sharing
a. Commission Proposal
    217. In the Proposed Rule, the Commission sought comment on whether
public utility transmission providers should be allowed or required to
share VER-related data received from interconnection customers with
other entities, like the source or sink balancing authority area for a
transaction, or a government agency, such as NOAA, assuming
confidentiality is protected.\231\
---------------------------------------------------------------------------

    \231\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 63.
---------------------------------------------------------------------------

b. Comments
    218. Clean Line and RenewElec state that operational and
meteorological data should be made public to the maximum extent
possible. RenewElec argues that there is a significant lack of
operational data available to researchers in the area of VERs
integration, and asks that the Commission require that: (1) VER data be
made public within six months of the date on which such data is
submitted by the interconnection customer, and (2)

operational data, including VER data, used by transmission providers to
develop VER power production forecasting be made available to
interested parties.
    219. While generally stating support for the sharing of data, some
commenters raise confidentiality concerns and point out the
commercially-sensitive nature of data subject to the reporting
requirements contemplated in the Proposed Rule.\232\ For example,
Southern California Edison supports sharing VER-related data for the
purposes of increasing forecasting accuracy, as long as the data are
not proprietary data that the public utility transmission provider is
prohibited from disclosing to other parties. Bonneville Power and a few
others contend that while sharing data from individual VERs poses
confidentially issues, sharing aggregate VER data does not pose the
same problems.\233\ Sunflower and Mid-Kansas state that, within RTOs,
the stakeholders should decide which entities should be provided VER
data. Western Farmers request that the Commission confirm that, where
the transmission provider is not the balancing authority, the data
should also be provided to the relevant balancing authority. NextEra
and AWEA only support sharing data with other balancing authorities
when the resource is being dynamically scheduled or dispatched into
that balancing authority. Bonneville Power suggests that, at a minimum,
the Commission should allow public utility transmission providers and
balancing authorities to share aggregate forecasts for VER output with
all parties to an e-tag.
---------------------------------------------------------------------------

    \232\ E.g., CGC; California PUC; EEI; NextEra; PJM; SMUD; ISO
New England.
    \233\ E.g., Bonneville Power; California ISO; Exelon; SEIA.
---------------------------------------------------------------------------

    220. Several commenters support sharing VER-related meteorological
data with NOAA, including having the data incorporated into
foundational models run by NOAA.\234\ Commenters, including NOAA,
request that the Commission require VERs to submit meteorological data
to NOAA for the purpose of improving atmospheric characterization and
forecast accuracy.\235\ In response to confidentiality concerns, NOAA
states that private sector proprietary data can be protected from
distribution and anonymized in the analysis and generation of
forecasts, which would then allow improved predictions to be available
for the private sector to incorporate into power production forecasts.
---------------------------------------------------------------------------

    \234\ E.g., AWEA; Bonneville Power; CGC; Iberdrola; ISO New
England; MidAmerican; NaturEner; NOAA.
    \235\ E.g., Bonneville Power; Iberdrola; NOAA.
---------------------------------------------------------------------------

c. Commission Determination
    221. The Commission declines to expand the Proposed Rule to require
public utility transmission providers to share VER related data with
other entities such as a balancing authority area or NOAA. However, the
Commission strongly encourages the voluntary sharing of data where
appropriate. Many commenters assert that significant benefits might
flow from VERs sharing data with entities such as a balancing authority
area or NOAA. The Commission finds that VERs are in the best position
to negotiate what data are needed and to weigh the benefits that may be
expected as a result of providing such data. In addition, negotiating
directly with other entities will allow VERs to ensure that adequate
confidentiality protections are in place for information that they may
consider to be commercially sensitive or otherwise confidential. If
helpful to industry participants, the Commission will consider making
staff available to work through issues and, if appropriate, take
additional steps to facilitate the voluntary sharing of information.
4. Cost Recovery
a. Commission Proposal
    222. In the Proposed Rule, the Commission refrained from proposing
a single method of cost recovery for the development and implementation
of power production forecasts. Instead, the Commission sought comments
on how public utility transmission providers may recover costs incurred
to develop and deploy power production forecasting tools.\236\
---------------------------------------------------------------------------

    \236\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 57.
---------------------------------------------------------------------------

b. Comments
    223. Among those seeking flexibility, AWEA states that the
Commission is correct to not propose a single uniform method for
allocating these costs, and instead should defer to public utility
transmission providers and others to determine how these costs should
be allocated. Several commenters request that the Final Rule provide
flexibility to public utility transmission providers and/or regions to
propose cost recovery approaches.\237\ For example, EEI contends that
generally no interconnected resource should be exempt from the
responsibility for costs that it causes to be incurred, but asks that
the Commission not mandate how costs should be allocated at this time,
allowing regions to develop appropriate cost-recovery solutions.
---------------------------------------------------------------------------

    \237\ E.g., AWEA; California PUC; Duke; ISO New England;
MidAmerican; Pacific Gas & Electric.
---------------------------------------------------------------------------

    224. Some commenters recommend that the cost of forecasting be
spread among all transmission customers.\238\ Independent Power
Producers Coalition-West argues that forecasting tools will ultimately
reduce costs to utilities and generators, and will ultimately be a
small cost of doing business in a world where forecasting can and
should be a constant element of the power scheduling process. Public
Interest Organizations state that the costs of centralized forecasting
infrastructure should be spread across all those who benefit from the
improved accuracy and decreased costs, provided those costs are
demonstrated to be just and reasonable. Joined by NextEra, Public
Interest Organizations argue that the broad benefits of forecasting
justify the sharing of related costs across the transmission system(s)
that benefit.
---------------------------------------------------------------------------

    \238\ E.g., Iberdrola; Independent Power Producers Coalition-
West; NextEra; Public Interest Organizations; Exelon.
---------------------------------------------------------------------------

    225. Iberdrola contends that there is no difference in the costs
incurred to develop and deploy power production forecasting tools and
the costs of developing and implementing other market design features.
Iberdrola states that these types of costs typically are not directly
assigned to one set of market participants, but are spread to all users
of the transmission system because they benefit all users of the
system. Iberdrola states that the costs incurred to develop and deploy
power production forecasting tools should similarly be spread to all
system users.
    226. Exelon recommends recovering the cost of forecasting within
administrative charges, the approach taken by PJM and ERCOT. Exelon
provides an example of ERCOT's handling of the costs: the cost of
developing the ramp probability tool was a one-time investment that was
recovered by the transmission provider in uplift to the market. The
ongoing cost of using the tool is also spread across the market. Exelon
states that this approach avoids the problem of free-ridership by
future market participants that would occur if these costs were
recovered solely from existing market participants.
    227. Other commenters argue either that the VERs, or the
beneficiaries of VERs, should be financially responsible for the costs
of forecasting.\239\ These

commenters generally contend that public utility transmission providers
should be able to recover the costs incurred to develop and deploy
power production forecasting by imposing a fee or rate upon the VERs
causing the costs to be incurred. For example, NRECA argues that non-
VER transmission customers are neither causing nor benefiting from the
enhancements to power production forecasting and, therefore, should not
be forced to subsidize its costs, citing Northern States Power
Company.\240\ Montana PSC suggests that all VERs of 1 MW or greater
should be responsible for power production forecasting costs. Pacific
Gas & Electric notes the approach taken in the California ISO's
Participating Intermittent Resources Program, in which the California
ISO charges a fee to VERs to recover costs to develop and deploy power
production forecasts.
---------------------------------------------------------------------------

    \239\ E.g., Bonneville Power; ELCON; Large Public Power Counci;
MidAmerican; Midwest ISO Transmission Owners; Montana PSC;
NorthWestern; NRECA; Oregon & New Mexico PUC; PNW Parties; SMUD;
Southern California Edison; Tacoma Power.
    \240\ NRECA (citing N. States Power Co., 64 FERC ] 61,324, at P
63,379 (1993)).
---------------------------------------------------------------------------

    228. ELCON and Tacoma Power argue that any resource, whether or not
it is a VER, should be held fully accountable for the costs it causes
the transmission provider to incur on its behalf. ELCON argues that
meteorological forecasting is simply a cost of doing business for wind
energy, just as a nuclear power plant must pay for storage of spent
fuel. ELCON argues that these costs should not be recovered in uplift
charges in regions served by ISOs or RTOs, or allocated to non-
customers of VER transactions.
    229. SEIA recommends that the Commission examine whether there may
be market entities that would consider contributing to the costs of the
forecast service providers in the non-organized market regions, e.g.,
power traders may be willing to pay for the aggregate day-ahead and
hour-ahead forecasts across such regions. SEIA states that these
revenues could be used to develop aggregated forecasts for more
geographical areas within a region that could further reduce
integration costs.
    230. Duke argues that the Commission should allow public utility
transmission providers to update any costs associated with the Proposed
Rule's reporting and power production forecasting requirements without
triggering a general rate case. Duke suggests that one possible option
would be through a formula rate that is updated periodically for
changes in costs related to forecasting and data reporting.
    231. Finally, some commenters request that the Commission recognize
that the costs of centralized forecasting go beyond the expense of
forecasting tools.\241\ These additional costs include gathering data,
installing and operating onsite telemetry, equipment to record
meteorological data, and data management. Southern California Edison
points out that data and telemetry are only as good as the personnel
assessing the information.
---------------------------------------------------------------------------

    \241\ E.g., Pacific Gas & Electric; Southern California Edison;
NorthWestern.
---------------------------------------------------------------------------

c. Commission Determination
    232. The Commission finds that it is not necessary to prescribe a
single method of cost recovery for developing and implementing power
production forecasting, as it is likely that not all public utility
transmission providers will develop power production forecasting, given
regional differences in the types and penetration of VERs. Moreover,
the record in this proceeding demonstrates that the circumstances under
which a public utility transmission provider may decide to develop and
deploy power production forecasting may vary by system. In some
instances, public utility transmission providers might develop and
employ power production forecasting in order to manage more effectively
the commitment of reserves associated with the provision of generator
regulation service, as discussed in other sections of this Final Rule.
In other circumstances, public utility transmission providers might
develop and employ power production forecasting to manage reserve costs
recovered under other ancillary services. In addition, public utility
transmission providers may seek to recover costs associated with power
production forecasting in different ways, as cost recovery may be
sought via a general rate case, formula rate, or other mechanism. Given
the myriad of factors that may be relevant to the allocation and
recovery of such costs, the Commission finds it appropriate to evaluate
requests for the recovery of costs incurred to develop and deploy power
production forecasts on a case-by-case basis consistent with FPA
section 205 and Commission precedent.

C. Generator Regulation Service-Capacity

    233. In the Proposed Rule, the Commission preliminarily found that
clarifying the manner by which public utility transmission providers
may recover the costs associated with fulfilling their obligation to
offer generator regulation service would remove barriers to the
integration of VERs by eliminating public utility transmission
providers' uncertainty regarding cost recovery.\242\ As discussed
below, the Commission concludes that adoption of this reform could
inhibit the flexibility to design capacity services that align with the
operational practices or needs of a particular public utility
transmission provider. The Commission therefore declines to adopt a
generic Schedule 10 for generation regulation service this reform and
instead provides guidance to assist public utility transmission
providers and their customers in the development and evaluation of
proposals related to recovering the costs of regulation reserves
associated with VER integration.
---------------------------------------------------------------------------

    \242\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 87.
---------------------------------------------------------------------------

1. Schedule 10--Generator Regulation and Frequency Response Service
    234. In the Proposed Rule, the Commission proposed incorporating
into the pro forma OATT a new ancillary service schedule for Generator
Regulation and Frequency Response Service. The Commission introduced
this proposal with a review of the adoption in Order Nos. 888 \243\ and
890 \244\ of ancillary services schedules for Regulation and Frequency
Response Service (regulation service), energy imbalance service, and
generator imbalance service.\245\ The Commission repeats that
introduction here for background.
---------------------------------------------------------------------------

    \243\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,703-04.
    \244\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 627.
    \245\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at PP 66-71.
---------------------------------------------------------------------------

    235. Regulation service, offered under Schedule 3 of the pro forma
OATT, provides the capacity reserve necessary for the continuous
balancing of resources (generation and interchange) with load to
maintain a scheduled interconnection frequency of 60 cycles per second
(60 Hz).\246\ In Order No. 888, the Commission required public utility
transmission providers to offer regulation service for transmission
service within or into the public utility transmission provider's
balancing authority area to serve load in that area.\247\ However, the
Commission did not require public utility transmission providers to
offer regulation service for transmission service out of or through the
public utility transmission provider's balancing authority area to

serve load in another balancing authority area.\248\
---------------------------------------------------------------------------

    \246\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,707-08.
    \247\ Id. at 31,717.
    \248\ Id.
---------------------------------------------------------------------------

    236. Energy imbalance service, offered under Schedule 4 of the pro
forma OATT, accounts for hourly energy deviations between a
transmission customer's scheduled delivery of energy and the actual
energy used to serve load.\249\ In Order No. 888, the Commission
required public utility transmission providers to offer energy
imbalance service for transmission service within and into the public
utility transmission provider's balancing authority area to serve load
in that area.\250\ Like regulation service, the Commission did not
require public utility transmission providers to offer energy imbalance
service for transmission service being used to serve load in another
balancing authority area.
---------------------------------------------------------------------------

    \249\ Id. at 31,708.
    \250\ Id. at 31,717.
---------------------------------------------------------------------------

    237. Regulation service and energy imbalance service, while
different in function, are complementary services through which public
utility transmission providers maintain their systems' balance and
recover both the capacity (regulation service) and energy (energy
imbalance service) costs of doing so from transmission customers
serving load on their systems. At the time of Order No. 888, the
Commission believed that it was reasonable to provide only standardized
ancillary service schedules for transmission used to service load
because load (rather than generation) exhibited the greatest amount of
variability.\251\ The Commission noted that generators should be able
to deliver scheduled hourly energy with precision and that the
requirements for generators to meet their schedules should be contained
in interconnection agreements.
---------------------------------------------------------------------------

    \251\ In 1996, when Order No. 888 was developed and issued, wind
generation was not a significant energy source, with a total
capacity of approximately 1,698 MW. See Imbalance Provisions for
Intermittent Resources; Assessing the State of Wind Energy in
Wholesale Electricity Markets, Notice of Proposed Rulemaking, FERC
Stats. & Regs. ] 32,581, at P 7 (2005).
---------------------------------------------------------------------------

    238. In Order No. 890, the Commission noted that the existing
energy imbalance charges were the subject of significant concern and
confusion in the industry.\252\ The Commission expressed concern about
the variety of different methodologies used for determining imbalance
charges and whether the level of the charges provided the proper
incentive to keep schedules accurate without being excessive.\253\ Such
concerns led the Commission to revise existing pro forma energy
imbalance service provisions and require public utility transmission
providers to offer a new service, generator imbalance service, to
account for hourly energy deviations between a transmission customer's
scheduled delivery of energy from a generator and the amount of energy
actually generated.\254\ The Commission found that formalizing
generator imbalance provisions in the pro forma OATT would standardize
future treatment of such imbalances, thereby lessening the potential
for undue discrimination, increasing transparency, and reducing
confusion in the industry that resulted from the then current plethora
of different approaches.
---------------------------------------------------------------------------

    \252\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 634.
    \253\ Id.
    \254\ Id. P 663.
---------------------------------------------------------------------------

    239. While the pro forma generator imbalance service provides a
mechanism for public utility transmission providers to recover the cost
of providing the energy needed to manage hourly generator imbalances,
it does not provide a mechanism for public utility transmission
providers to recover the costs of holding reserve capacity associated
with providing generator imbalance energy.\255\ Although the Commission
in Order No. 890 did not create a new rate schedule to expressly
account for these capacity costs, it acknowledged the likelihood that
such costs would be incurred in connection with the provision of
generator imbalance service.\256\ Accordingly, the Commission provided
a mechanism by which public utility transmission providers could
recover these costs, explaining that ``[t]o the extent a [public
utility] transmission provider wishes to recover costs of additional
regulation reserves associated with providing imbalance service, it
must do so via a separate FPA section 205 filing demonstrating that
these costs were incurred correcting or accommodating a particular
entity's imbalances.'' \257\ In Order No. 890-A, the Commission
clarified that public utility transmission providers may propose to
assess regulation charges to generators selling in the balancing
authority area, as well as generators selling outside the balancing
authority area, and that the Commission will consider such proposals on
a case-by-case basis.\258\
---------------------------------------------------------------------------

    \255\ Id. P 689 (``The Commission concludes that excluding
additional regulation costs as a general matter is appropriate
because much of those costs would be demand costs.'').
    \256\ Id. P 690.
    \257\ Id. at P 689 & n.401 (referring to costs associated with
capacity used to provide generator imbalance service that otherwise
are not recovered through Schedule 3).
    \258\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 313.
---------------------------------------------------------------------------

a. Commission Proposal
    240. In the Proposed Rule, the Commission sought to add a new rate
schedule to the pro forma OATT that complements the generator imbalance
service provided under Schedule 9 of the pro forma OATT. The Commission
noted that, in order to meet their obligations to offer generator
imbalance service under Schedule 9, public utility transmission
providers must hold unloaded resources in reserve to respond to moment-
to-moment variations attributable to generation. The Proposed Rule
recognized this de facto obligation and proposed to establish a generic
rate schedule (Schedule 10--Generator Regulation and Frequency Response
Service) through which public utility transmission providers may
recover the costs of providing this service. The Commission
preliminarily found that clarifying the manner by which public utility
transmission providers may recover the costs associated with fulfilling
their obligation to offer this service will remove barriers to the
integration of VERs by eliminating public utility transmission
providers' uncertainty regarding cost recovery.\259\
---------------------------------------------------------------------------

    \259\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 87.
---------------------------------------------------------------------------

    241. In the Proposed Rule, the Commission stated that Schedule 10
is modeled on Schedule 3--Regulation and Frequency Response Service of
the pro forma OATT. Where Schedule 3 allows public utility transmission
providers to recover the costs of regulation reserves associated with
variability of load within its balancing authority area, proposed
Schedule 10 would provide a mechanism through which public utility
transmission providers can recover the costs of providing regulation
reserves associated with the variability of generation resources both
when they are serving load within the public utility transmission
provider's balancing authority area and when they are exporting to load
in other balancing authority areas.\260\
---------------------------------------------------------------------------

    \260\ Id. P 88.
---------------------------------------------------------------------------

    242. The Commission proposed that, consistent with Order No. 890,
public utility transmission providers would not be permitted to charge
transmission customers for regulation reserves under both Schedule 3
and Schedule 10 for the same transaction.\261\ The Commission

emphasized that in establishing Schedule 10, it was not changing the
nature of the services that a public utility transmission provider must
offer its transmission customers. The Commission stated that nothing in
the Proposed Rule would affect the manner in which balancing
authorities are required to maintain balanced systems that are operated
in a safe and reliable fashion, consistent with NERC Reliability
Standards. The Commission explained that it simply proposed to
establish a generic cost recovery mechanism for a service that public
utility transmission providers already are obligated to offer customers
taking transmission service within their balancing authority area.\262\
---------------------------------------------------------------------------

    \261\ Id. P 89 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 690 (requiring transmission providers to demonstrate
that any proposals to recover capacity costs associated with
Generator Imbalance Service do not lead to double recovery); Entergy
Serv., Inc., 120 FERC ] 61,042, at PP 62-66 (2007); Sierra Pac. Res.
Operating Cos., 125 FERC ] 61,026 (2008); Westar Energy Inc., 130
FERC ] 61,215, at P 4 (2010)).
    \262\ Id. P 91.
---------------------------------------------------------------------------

    243. In the Proposed Rule, the Commission explained that public
utility transmission providers are not permitted to disclaim the
obligation to offer to provide transmission customers with the capacity
reserves associated with the provision of generator imbalance
service.\263\ Therefore, the Commission proposed that, under Schedule
10, a public utility transmission provider must offer generator
regulation service to the extent it is physically feasible to do so
from its resources or from resources available to it, to transmission
customers using transmission service to deliver energy from a generator
located within the public utility transmission provider's balancing
authority area.\264\
---------------------------------------------------------------------------

    \263\ Id. P 84 (citing NorthWestern, Corp., 129 FERC ] 61,116,
at P 27 (2009)).
    \264\ Id. P 89.
---------------------------------------------------------------------------

b. Comments
i. Proposed Schedule 10
    244. Although several commenters support the Commission's proposal
to establish a schedule for the recovery of capacity costs for
regulation reserves, much of that support is tempered by concern about
the scope and design of proposed Schedule 10, as well as the
flexibility afforded public utility transmission providers to design
services relevant to recover all costs associated with the integration
of VERs under proposed Schedule 10.\265\ For example, while EEI
indicates that it supports the establishment of a cost recovery
mechanism for regulation reserves from transmission customers as
promoting rate certainty and transparency, it also cautions the
Commission that the proposal may unduly condition cost recovery and may
not encompass all cost incurred by the transmission provider. While
Independent Power Producers Coalition--West supports the concept of a
generic generator imbalance tariff to bring certainty to disparate
tariffs that must now be negotiated in WECC, it contends that the
Commission should require utilities to revise operating agreements,
business practices or other procedures such that independently owned
generator resources are available to balancing authorities in the WECC
to reduce generator imbalance costs for VERs. Large Public Power
Council supports the new Schedule 10 provided it is implemented in a
way that allows transmission providers to receive full compensation for
providing the service.
---------------------------------------------------------------------------

    \265\ CMUA at 10-11; EEI at 25-33; Midwest ISO at 14; NRECA at
23-24; Organization of Midwest ISO States at 8-9.
---------------------------------------------------------------------------

    245. NRECA indicates that it also supports the cost recovery
proposal embodied in proposed Schedule 10; however, it expresses
concern that Schedule 10 should not be limited to just the recovery of
regulation costs, and should instead be expanded to allow public
utility transmission providers the opportunity to demonstrate that
additional VER integration costs should be recovered through individual
Schedule 10s. According to NRECA, such costs may include the following:
(1) Intra-hour schedule implementation costs; (2) power production
forecasting implementation costs; or (3) other various costs such as
load-following service, ramping costs, out-of-merit dispatch costs, and
additional spinning and supplemental reserves, among other things.
    246. Public Power Council and Puget express similar concerns that
the proposed Schedule 10 would not allow for full recovery of all costs
of balancing and integrating VERs. According to Public Power Council,
Schedule 3 recovers the costs of balancing reserves deployed for
frequency and regulation control, which in turn leads Schedule 10 to
only recover the costs of regulation (capacity following near
instantaneous changes in generation) but not the costs arising from
either load following capacity (capacity used minute-to-minute over
approximately a 10-minute period) or capacity needed to make up a
variable generator's schedule error for the scheduling period. Public
Power Council also argues that Schedule 10 charges should include the
costs of power production forecasting systems as these would not be
needed but for the integration of variable generation. The PNW Parties
agree and suggest that Schedule 10 should be expanded further to allow
for the recovery of all costs incurred by the public utility
transmission provider in providing regulating reserves that are not
recoverable through the generation imbalance rate, including but not
limited to, extra energy costs and operation and maintenance costs.
    247. Southern states that the capacity required to provide
generator imbalance service or otherwise respond to operational
challenges presented by substantial swings in output from generators
(particularly VERs) may mostly be conceptualized as providing a
``regulation'' service, but it should be understood that some public
utility transmission providers may also incur additional costs that may
implicate other ancillary services, such as reactive power and load
following, if not contingency response. Southern asserts that the
Commission should not categorically foreclose or limit in advance the
right of public utility transmission providers under section 205 to
file tariffs or tariff amendments on a case-by-case basis to recover
any and all additional reasonable costs specific to VER-related
regulation reserve requirements. Southern requests that the Commission
confirm that the invitation in Order No. 890 for public utility
transmission providers to file rate schedules and amendments to address
costs of generator imbalances on a case-by-case basis remains open.
    248. Public Interest Organizations contend that it may be unjust
and unreasonable to charge VERs regulation rates for capacity
requirements that can be addressed by less expensive ancillary
services. Public Interest Organizations state that the Commission could
address this problem either by reforming Schedule 10 into a slower
service akin to load-following or non-spinning reserves, or by
clarifying that Schedule 10 is designed to compensate only for the
moment-to-moment balancing associated with generation variability, and
not for VER variability that affects the system beyond the balancing
timeframe.
    249. AWEA suggests that the Commission focus on such longer-term
variability, requesting that the Commission reformulate proposed
Schedule 10 as a system non-spinning service to accommodate the
aggregate system variability that is not accommodated through other
ancillary services. AWEA states that this type of service would benefit
all users of the system by providing inexpensive reserves to
accommodate all types of gradual variability on the power system,
including changes driven by inaccurate

load forecasts, changes in demand driven by large electricity users, as
well as aggregate changes of many small users. AWEA notes that wind and
solar exhibit little variability over the regulation time period while
variability over the course of an hour can be more significant. AWEA
argues that a system non-spinning service would be well-suited for
accommodating the incremental increase in system variability caused by
the addition of such resources.
    250. Similarly, Iberdrola recommends the Commission structure
Schedule 10 as a following reserves service rather than regulation
reserve, arguing that the rate of change associated with wind ramps is
not instantaneous but rather occurs over longer time periods within the
hour and often for multiple hours. To the extent that the Commission
does not reformulate Schedule 10 in this way, Iberdrola requests that
the Commission convene a technical conference that focuses on the
ancillary services needed to support VERs. NextEra agrees that the
Commission should convene a technical conference to address what kind
of ancillary services should be developed to complement the growth of
VERs, among other things.
    251. Duke suggests that the Commission should unbundle regulation
and frequency response service into separate ancillary service
schedules. In support, Duke points to such industry activities as NERC
developing a revision to Frequency Response Reliability Standard BAL-
003-0, which will prescribe specific amounts of frequency response that
each balancing authority must procure; the Commission report prepared
by the Lawrence Berkeley National Laboratory, which discusses
operational characteristics and distinctions of primary and secondary
frequency control reserves (Docket No. AD11-8-000); and the
Commission's Notice of Proposed Rulemaking in Docket Nos. RM11-7-000
and AD10-11-000, which also distinguishes frequency response from
regulation.
    252. American Clean Skies argues that the Proposed Rule should
require RTOs to offer additional ancillary services, such as load
following (on a minute-to-minute basis), reactive power and other
comparable backup capabilities. Coalition for Green Capital similarly
asks the Commission to encourage the development of power and ancillary
services products that match the technical and commercial capabilities
of VERs to allow VERs to integrate into the bulk power grid at rates
and on terms and conditions that are just and reasonable and not unduly
discriminatory or preferential. Independent Energy Producers assert
that, while it is critical that ancillary service products be
identified and developed to permit VERs to be integrated, it is equally
critical that the necessary compensation measures be developed to
ensure that dispatchable generation is available when and where it is
needed to support the ancillary services products, particularly within
the California ISO market.
    253. With regard to charging transmission customers under both
Schedule 3 and the proposed Schedule 10, Bonneville Power agrees with
the Commission's decision in Order No. 890 regarding the potential for
double recovery if energy settlement charges (under Schedules 4 and 9
of the OATT) are imposed on both the generator and load when they
reside in the same balancing authority, but argues that there are
significant differences between energy settlement charges and capacity
charges recovered under Schedule 3 and Proposed Schedule 10. Bonneville
Power states that the public utility transmission provider must
maintain balancing reserve capacity for movement of both the load and
the generators located in its balancing authority area because the
deviations from schedule for the load and generation move independently
from one another, and that the transmission provider should be allowed
to recover costs for capacity it is providing to both generation and
load.
    254. Duke similarly argues that the Commission should allow the
public utility transmission provider to recover both Schedule 3 and 10
costs if both services are utilized by the transmission customer. Duke
contends that it is appropriate in some circumstances to charge a load
for Schedule 3, and a generator for Schedule 10, even if they are owned
by the same party. According to Duke, unless the generator is coupled
to the load by an energy management system (i.e., the generator is
controlling to the load), or the generator is dynamically serving a
load (i.e., where its output can be controlled to match the load it
serves), a public utility transmission provider should be permitted to
charge for both Schedule 3 and Schedule 10 as they are two different
services which can be provided at the same time (e.g., where a load
serving entity owns load within a control area, as well as a
generator).
    255. Finally, several commenters contend that Schedule 10 is not
necessary in organized markets.\266\ PJM interprets Schedule 10 as
optional and seeks clarification that this interpretation is correct.
Sunflower and Mid-Kansas submit that the SPP market rules already are
consistent with or superior to the pro forma OATT as the Commission
proposed to amend it in the Proposed Rule and believes it is highly
likely that all of the other RTOs' rules are also superior to what has
been proposed. Clean Line contends that the potential of double
recovery exists for generators receiving compensated through organized
market mechanisms. AWEA contends that the Commission should clarify
that the creation of Schedule 10 service should apply only in areas of
the country that do not have functioning ancillary services markets.
Likewise, Iberdrola explains that a Schedule 10-type product is not
necessary in organized markets, as most organized markets balance the
system's energy and reserve requirements through use of simultaneously
co-optimized Security Constrained Unit Commitment and Security
Constrained Economic Dispatch algorithms that clear and dispatch energy
and reserves.
---------------------------------------------------------------------------

    \266\ E.g., AWEA; California ISO; Iberdrola; ISO New England,
New York ISO; Sunflower and Mid-Kansas.
---------------------------------------------------------------------------

ii. Obligation To Offer Generator Regulation Service
    256. Several commenters seek clarification regarding the extent to
which the public utility transmission provider must provide generator
regulation service. NaturEner states that public utility transmission
providers should not be able to avoid providing regulating reserves
based upon claims that they themselves do not own generation in
sufficient amounts to supply the service. Xtreme Power asks that the
Commission make clear that, in the event that a public utility
transmission provider's existing resources are not adequate to meet the
obligation to provide generator regulation service and new resources
are needed to accommodate additional variability, the public utility
transmission provider is obligated to procure a sufficient quantity of
the appropriate resources.
    257. Grant PUD asks whether a public utility transmission provider
must procure additional regulation resources if the demand for these
services exceeds the contractual and owned resources available to the
public utility transmission provider that can provide regulation
service at the time of the request for service. NorthWestern requests
that the Commission clarify

that the phrase ``or from resources available to it'' refers to
acquisition of generator regulation service from third parties and is
not intended to mean that, if the utility does not have access to its
own resource or resources from the market, the utility must build
generation for Schedule 10 service. Independent Power Producers
Coalition--West states that transmission providers should not be
permitted to charge VERs for generator imbalance services unless they
provide VERs with the capability to obtain those services from third
parties on a non-discriminatory basis. If a public utility transmission
provider does not have access to its own resources or resources from
the market and chooses to build new generation to offer Schedule 10
service, EEI asks the Commission to clarify that these costs can be
recovered from the resources that trigger the need to build. EEI also
states that the language ``or from resources available to it'' could be
read to require the public utility transmission provider to violate
reliability standards by using resources set aside for contingency
reserves to support generation regulation service.\267\ EEI requests
that the Commission clarify the statement as follows: ``a public
utility transmission provider must offer generator regulation service;
to the extent it is physically feasible to do so from its existing
resources or from resources currently available to it, without
violating applicable reliability standards.'' \268\
---------------------------------------------------------------------------

    \267\ EEI at 32.
    \268\ Id.
---------------------------------------------------------------------------

    258. Puget asks that the Commission clarify that public utility
transmission providers are only required to provide Schedule 10 service
within a defined confidence interval commensurate with the public
utility transmission provider's level of regulation capacity set aside
for cost recovery under the Schedule 10. If those resources'
capabilities are exceeded or if system conditions otherwise warrant,
Puget suggests that the public utility transmission provider should
retain the right to curtail generation production or export schedules
to preserve reliability. Public Power Council and Bonneville Power also
question whether the obligation to provide generator regulation service
is unlimited, suggesting that such service could require firming of
every generation delivery, which would be extremely expensive.
Bonneville Power contends that the source balancing authority should
have the ability to offer a base level quantity of balancing reserve
capacity and should have the right to use operational tools to limit
the deployment of reserves to that quantity. In support, Bonneville
Power explains that it has developed Dispatcher Standing Order 216 (DSO
216) to require reductions in wind generation or changes to wind
generators' transmission schedules when the schedule error of the wind
fleet exhausts the total amount of balancing reserve capacity that
Bonneville Power has made available for wind and load.
    259. Bonneville Power states that it is currently providing enough
balancing reserve capacity to meet the needs of the wind fleet in its
balancing authority during 99.5 percent of the forecast VER variability
events. Bonneville Power describes the remaining 0.5 percent as
representing the most extreme variability in VER generation (i.e.,
``tail events''). Because of the substantial wind generation exports
from Bonneville Power's balancing authority area, Bonneville Power
explains that it needs a mechanism to ``clip the tails'' of wind ramps
when they exhaust the total amount of balancing reserve capacity that
Bonneville Power makes available for wind and load. Bonneville Power
states that DSO 216 allows it to establish the amount of balancing
reserve capacity that will be deployed and, because there is a set
limit, it is able to quantify its obligation and risks for rate
setting, system planning, and reliability purposes. Bonneville Power
contends that a requirement to maintain balancing reserve capacity at
all times to manage tail events would be significantly expensive.
    260. Bonneville Power also asks the Commission to clarify that the
public utility transmission provider is required to offer to provide
Schedule 10 service only to the extent it can do so without harming
system reliability or risking non-compliance with state and Federal law
and other non-power requirements that affect system operations.
Snohomish County PUD and Grays Harbor PUD similarly ask the Commission
to clarify that Bonneville Power should not be required to offer
capacity from the Federal System to meet demand for services under
Schedule 10 where that capacity is not available due to statutory and
regulatory obligations that limit the availability of the Federal
System's capacity. Grays Harbor PUD adds that the Commission should
make clear that, during periods when Bonneville Power's system is
limited by statutory and regulatory constrains, it is not ``physically
feasible'' for Bonneville Power to use that capacity to support
integration of VERs and, therefore, during those periods is exempt from
requirements to do so. Bonneville Power further requests that the
Commission clarify that the public utility transmission provider is
obligated to provide generator regulation service pursuant to Schedule
10 and generator imbalance service pursuant to Schedule 9 only to the
extent that balancing reserve capacity is made available pursuant to
Schedule 10. In addition, Bonneville Power suggests that the Commission
should address the pricing policy articulated in the Avista line of
cases, which restricts public utility transmission providers that are
not in organized markets to recovering cost-based rates for ancillary
services, to ensure public utility transmission providers have the
ability to obtain the necessary balancing reserve capacity.\269\ Tres
Amigas concurs with Bonneville Power and suggests that the Commission
alter its approach so that these services can be bought and sold
competitively outside of organized RTO markets as they are in most
RTOs.
---------------------------------------------------------------------------

    \269\ Bonneville Power (referencing Avista Corp., 87 FERC ]
61,223 (1999); Market-Based Rates For Wholesale Sales Of Electric
Energy, Capacity And Ancillary Services By Public Utilities, Order
No. 697, 119 FERC ] 61,295 (2007) (Order No. 697)).
---------------------------------------------------------------------------

iii. Self-Supply of Generator Regulation Service
    261. First Wind asks the Commission to clarify that Schedule 10
charges would be imposed on VERs only to the degree they take
transmission service or otherwise elect to take Schedule 10 service.
AEP contends that the Proposed Rule contains a loophole in that
purchasers of VER energy outside of the resource's native balancing
authority's footprint would be able to avoid any ancillary service
charges caused by their purchase and transport of energy. Other
commenters discuss how the balancing authority into which generation is
dynamically scheduled would be compensated for providing regulation
service.\270\ These commenters contend that because the sink balancing
authority is providing the regulation service for that generator in
these situations, it should be clear in Schedule 10 that the sink
balancing authority will be paid for providing that service.
---------------------------------------------------------------------------

    \270\ E.g., Duke; EEI; Exelon.
---------------------------------------------------------------------------

    262. Commenters address the option for transmission customers to
self-supply generator regulation service. Bonneville Power states that
it recognizes that VERs may find it economical to self-supply balancing
reserve capacity to provide balancing service and asks the Commission
to clarify in Schedule 10 that a customer electing to self-supply is
subject to the public utility transmission provider's requirements for
Schedule 10 service

and the transmission provider's reliability and operational protocols,
including any transmission curtailments and generation limitations in
the event the self-supplying VER fails to meet the transmission
provider's standards. Powerex agrees that the public utility
transmission provider should have discretion to decide whether a method
of self-supply is acceptable but argues that the public utility
transmission provider should be required to describe what it considers
to be acceptable comparable arrangements in posted business practices.
    263. Xtreme Power similarly contends that, in order for self-supply
or third-party procurement of generator regulation service to be a
viable option, the public utility transmission provider must specify
how a customer's generator regulation service requirements are
determined and how the requirements may be satisfied through self-
supply or third-party procurement. NaturEner contends that the self-
supply provision should be administered on a flexible basis and this
could include use of self-curtailment, carrying of a portion of the
regulating reserve capacity on a dynamic basis, and carrying of a
varying level of regulating reserves because a constant level is not
necessary. Independent Power Producers Coalition--West argues that
public utility transmission providers should only be permitted to
charge VERs for generator imbalance services if they provide VERs with
the capability to obtain those services from third parties on a non-
discriminatory basis.
    264. Beacon Power indicates that entities subject to Schedule 10
should be allowed to work with public utility transmission providers in
non-RTO/ISO markets to determine different volumes of self-supplied
regulation reserve capacity required based on the ramp-rate capability
of its regulation resource(s). CESA agrees that, if a transmission
customer subject to the Schedule 10 chooses to self-supply its
regulation reserve capacity, the amount of capacity self-supplied
should account for the fact that a MW of reserve capacity from a fast-
ramping resource provides more regulation value to the grid per MW than
a slow-ramping resource. NEMA indicates that some resources that
provide generator regulation service, such as batteries and flywheels,
can dampen variations much more quickly than can traditional
generators. Therefore, NEMA contends that the generator regulation
service requirements should be based on the amount of generator
regulation service actually provided, rather than solely the capacity
of regulation service. A123 recommends that the Commission clarify the
phrase ``alternative comparable arrangements'' to include resources
that may differ in MW capacity but supply equivalent or superior
regulation performance when compared to the public utility transmission
provider's default service.
    265. Powerex asks that the Commission confirm that self-supply
includes the ability of the transmission customer to self-supply by
purchasing regulation reserve capacity from third parties.\271\ Powerex
states that it could be helpful for the Commission to provide guidance
on what should qualify as an ``alternative comparable arrangement.''
SEIA supports providing transmission customers with the opportunity to
avoid regulation service costs through dynamic scheduling or self-
supply arrangements, but ask the Commission to clarify how self-supply
would allow solar plants to avoid regulation reserve requirements,
which SEIA believes would assign a constantly varying share of the
Schedule 10 requirement to a solar plant capable of providing
regulation service. The Federal Trade Commission asserts that the self-
supply option under Schedule 10 is vague and should recognize that VERs
could address their regulation requirements by matching their
generation variability to demand variability.
---------------------------------------------------------------------------

    \271\ Powerex at 22.
---------------------------------------------------------------------------

    266. Other commenters request that additional requirements be
included in Schedule 10 with regard to self-supply. CGC states that the
Proposed Rule fails to require public utility transmission providers to
provide dynamic transfer capability out of their balancing authority
area or provide an ancillary services market through which a generator
could self-supply generator regulation service. CGC asks the Commission
to require all public utility transmission providers, either by
themselves or in association with other public utility transmission
providers, to provide access to a fully functioning competitive
ancillary services market and/or dynamic transfer capabilities. ELCON
asserts that the Commission should specify that public utility
transmission providers must consider using dispatchable demand response
resources to provide Schedule 10 service. CESA recommends that FERC
allow Schedule 10 self-supply requirements to vary based on the ramp-
rate of the resources providing the service, offering that faster-
acting resources provide more ACE correction than slower resources.
c. Commission Determination
    267. The Commission declines to amend the pro forma OATT to include
a standardized ancillary services schedule for generator regulation
services as proposed in the Proposed Rule. As indicated above, the
Commission intended for proposed Schedule 10 to be a clearly defined
mechanism for public utility transmission providers to recover the
costs of capacity held in reserve to provide generator imbalance
service under Schedule 9 of the pro forma OATT, while also providing
customers with certainty as to the rates they will be required to pay
when taking this service. The Commission also sought to confirm the
right of public utility transmission providers to recover the
reasonably incurred costs of providing this capacity service and to
distinguish, where appropriate, among classes of customers who cause
such costs to be incurred.
    268. In response to the Proposed Rule, the Commission received
numerous comments urging flexibility in the design of capacity services
needed to integrate VERs into transmission systems, suggesting that the
proposed pro forma generator regulation service may not be the most
efficient and economical service with which to integrate VERs. For
example, Southern notes that the recovery of capacity costs incurred to
provide Schedule 9 generator imbalance service could implicate a range
of services, from regulation to load following, depending on how the
public utility transmission provider conceptualizes the service
provided. Iberdrola suggests that VER integration has more significant
implications for within hour spinning and non-spinning capacity than
moment-to-moment regulation capacity. In light of these comments, the
Commission concludes that the adoption of a standardized pro forma
Schedule 10 could inhibit the flexibility commenters seek to design
capacity services that align with the operational needs of a particular
public utility transmission provider. Accordingly, the Commission
declines to adopt the proposed Schedule 10 component of the Proposed
Rule and will continue to evaluate proposals to recover capacity costs
incurred to provide Schedule 9 generator imbalance service on a case-
by-case basis. In this way, public utility transmission providers will
remain free to propose capacity services that best respond to the needs
of their customers and will not have to expend resources adopting the
one-size-fits-all generator regulation service discussed in the

Proposed Rule, even in situations where some other service or rate
design may be more appropriate.
    269. To be clear, the Commission emphasizes that our decision not
to implement a generic rate schedule for generator regulation service
should not be interpreted as an unwillingness to consider individual
proposals brought by public utility transmission providers. The
Commission recognizes that a public utility transmission provider may
incur capacity costs associated with fulfilling obligations to provide
Schedule 9 generator imbalance service and that existing rate
mechanisms may be inadequate for some public utility transmission
providers to properly allocate and recover those costs. For many years,
the Commission has evaluated proposals to recover such capacity costs
on a case-by-case basis in light of the specific facts and
circumstances in each case.\272\ The Commission concludes that
continuation of this case-by-case approach is more appropriate to
tailor the particular capacity services needed by a public utility
transmission provider to its operations. At the same time, the
Commission is sensitive to commenter requests to provide guidance
regarding the proper design of a generator regulation service charge
should a public utility transmission provider desire to propose one. In
the section that follows, the Commission provides a framework that can
be used for those public utility transmission providers seeking to
develop a proposal to recover capacity costs incurred to provide
Schedule 9 generator imbalance service.\273\
---------------------------------------------------------------------------

    \272\ See Florida Power Corp., 89 FERC ] 61,263, at 61,765
(1999) (Florida Power) (``The Commission concludes that a generator
imbalance capacity obligation is imposed on the transmission
provider for export transactions, and therefore the Commission
accepts Florida Power Corp's Generator Regulation Service as a
reasonable proposal in those circumstances where the service is not
already covered in an interconnection agreement or a separate
generator tariff.''); Entergy, 120 FERC ] 61,042 at PP 62-66
(accepting a generator regulation service rate schedule for
independent power producers selling out of the control area that
retained charges that had been previously negotiated between Entergy
and the relevant independent power producers); Sierra Pac. Res.
Operating Cos., 125 FERC ] 61,026, at P 10 (2008) (accepting a
generator regulation service rate schedule to provide the capacity
necessary to follow the moment-to-moment changes caused by
generators selling outside of the transmission provider's control
area).
    \273\ See infra Sec.  IV.C.2 (Mechanics of a Generator
Regulation Charge). While this section is framed primarily in terms
of a generator regulation service, the principles discussed would
also apply more broadly to other capacity services designed to
recover capacity costs incurred to provide Schedule 9 generator
imbalance service.
---------------------------------------------------------------------------

    270. Before turning to the mechanics of a generator regulation
service charge, the Commission clarifies in response to comments that
our decision not to adopt a generic Schedule 10 does not relieve public
utility transmission providers of obligations under the pro forma OATT
to provide Schedule 9 generator imbalance service. This in turn
requires the public utility transmission provider to maintain
sufficient capacity to provide that service.\274\ However, as the
Commission explained in Order No. 890-A, if it is not physically
feasible for a transmission provider to offer generator imbalance
service using its own resources, either because they do not exist or
they are fully subscribed, the public utility transmission provider
must attempt to procure alternatives to provide the service, taking
appropriate steps to offer an option that customers can use to satisfy
their obligation to acquire generator imbalance service as a condition
of taking transmission service.\275\ The Commission explained that each
transmission provider can state on its OASIS the maximum amount of
generator imbalance service it is able to offer from its resources,
based on an analysis of the physical characteristics of its system.
Alternatively, a public utility transmission provider may consider
requests for generator imbalance service on a case-by-case basis,
performing, as necessary, a system impact study to determine the
precise amount of additional generation it can accommodate and still
reliably respond to the imbalances that could occur.\276\
---------------------------------------------------------------------------

    \274\ NorthWestern Corp., 129 FERC ] 61,116, at P 24 (2009),
order denying reh'g, 131 FERC ] 61,202, at PP 17-18 (2010).
    \275\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at PP 289-
90.
    \276\ Id. P 289.
---------------------------------------------------------------------------

    271. Because a proposal for generator regulation service would be
associated with generator imbalance service, it follows that the public
utility transmission provider would use a similar analysis to identify
any limitations on its ability to offer either service.\277\ Just as it
can for generator imbalance service, the public utility transmission
provider could explain on its OASIS the maximum amount of generator
regulation service it is able to offer after having attempted to
procure alternative resources to provide the service. Alternatively,
the public utility transmission provider could perform a system impact
study to determine the precise amount of generator regulation service
it can provide. In response to NorthWestern, this Final Rule does not
place any obligation on the public utility transmission provider to
build generation.
---------------------------------------------------------------------------

    \277\ In the unlikely event that there are no additional
resources available to enable the public utility transmission
provider to meet its obligation to offer generator regulation
service, the public utility transmission provider must accept the
use of dynamic scheduling with a neighboring control area. See id. P
290.
---------------------------------------------------------------------------

    272. With regard to comments regarding self-supply of ancillary
services, the Commission acknowledges that self-supply may come from
many sources, including purchased capacity and the use of non-
generation resources, as suggested by ELCON. The option to self-supply
certain ancillary services has been in place since Order No. 888, and
the Commission declines here to specify any particular requirements for
self-supply arrangements for generator regulation service proposals. To
do so could restrict flexibility to develop competitively priced
options tailored to particular customer needs. As suggested by some
commenters, such options could include the use of faster ramping
resources to provide the service.
    273. In response to Powerex, the Federal Trade Commission and
others, the Commission does not believe that the self-supply option is
vague or that additional guidance is necessary on what should qualify
as an ``alternative comparable arrangement.'' The Commission notes that
public utility transmission providers already are obligated to post on
their public Web sites all rules, standards, and practices, to the
extent they exist, that relate to transmission service.\278\ The
provision of ancillary services is necessary to accomplish transmission
service and, therefore, we conclude this posting obligation applies
equally to ancillary services.\279\ Public utility transmission
providers must post any rules, standards, and practices regarding self-
supply requirements pursuant to their obligation to allow self-supply
of ancillary services.\280\ The Commission declines to adopt further
requirements at this time regarding the self-supply of ancillary
services.\281\
---------------------------------------------------------------------------

    \278\ Order No. 890, FERC Stats.& Regs. ] 31,241 at P 1652.
    \279\ The Commission notes that this obligation is subject to
audit as are all other OATT requirements.
    \280\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,705.
    \281\ Id.
---------------------------------------------------------------------------

    274. In response to the Federal Trade Commission, the Commission
encourages transmission providers, generators, and transmission
customers to work together to explore options to find the least cost
methods of balancing the system as a whole and to provide maximum
flexibility for products and services that meet the needs of the
customers and the transmission

providers alike. This includes, for example, evaluating the extent to
which regulation service obligations can be addressed by matching
generation variability to demand variability, as suggested by the
Federal Trade Commission. Indeed, in Order No. 888, the Commission
stated that the pricing of ancillary services should include the amount
of each ancillary service that the transmission customer must purchase,
self-supply, or otherwise procure and must be readily determinable from
the transmission provider's tariff and comparable to obligations to
which the transmission provider itself is subject.\282\ The Commission
also specified that the transmission provider is required to identify
the regulating margin requirements for transmission customers serving
loads in its balancing authority area and to develop procedures by
which customers can avoid or reduce such requirements.\283\
---------------------------------------------------------------------------

    \282\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,721.
    \283\ Id. at 31,717. Order No. 890 did not alter the
requirements of Order No. 888 in this regard, but did clarify that
regulation and frequency response, as well as imbalance energy, may
be provided by public utility transmission providers or through
self-supply using generating units as well as other non-generation
resources such as demand resources where appropriate. Order No. 890,
FERC Stats. & Regs. ] 21,241 at P 888.
---------------------------------------------------------------------------

    275. For reasons explained elsewhere in this Final Rule, the
Commission declines to adopt CGC's suggestion to require transmission
providers to provide dynamic transfer capability out of their balancing
authority area or mandate the creation of an ancillary services market
through which a generator could self-supply generator regulation
service.\284\
---------------------------------------------------------------------------

    \284\ See supra IV.A.1 (Intra-Hour Scheduling Requirement).
---------------------------------------------------------------------------

2. Mechanics of a Generator Regulation Charge
    276. The Proposed Rule stated that, as with Schedule 3, the
proposed Schedule 10 charge would be the product of two components: a
per-unit rate for regulation reserve capacity, and a volumetric
component for regulation reserve capacity.\285\ The Commission proposed
to require each public utility transmission provider to submit a
compliance filing that includes the addition of a Generator Regulation
and Frequency Response rate schedule to the OATT that includes the same
per unit rate from their currently effective Regulation and Frequency
Response rate schedule and a blank or unfilled volumetric
component.\286\
---------------------------------------------------------------------------

    \285\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 92. The
Commission is exploring potential reforms to ancilliary services
pricing in other proceedings. See Third-Party Provision of Ancillary
Services; Accounting and Financial Reporting for New Electric
Storage Technologies, Notice of Proposed Rulemaking, 139 FERC ]
61,245 (2012) (NOPR).
    \286\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 101.
---------------------------------------------------------------------------

    277. The Commission preliminarily found that the per-unit rate for
service under proposed Schedule 10 should be the same as the rate for
service under existing Schedule 3.\287\ The Commission explained that
Schedule 3 and the proposed Schedule 10 are both designed to recover
the costs of holding regulation reserve capacity to meet system
variability. Because the service provided under both schedules is
functionally equivalent, the Commission proposed to find that it is
just and reasonable to use the same rate currently established in a
public utility transmission provider's Schedule 3 when charging
transmission customers under Schedule 10. The Commission stated that,
for a public utility transmission provider to apply a different rate
under the proposed Schedule 10, the public utility transmission
provider would have to demonstrate that the per-unit cost of regulation
reserve capacity is somehow different when such capacity is utilized to
address system variability associated with generator resources. The
Commission also noted that the use of a common rate is consistent with
Commission policy utilizing the same rate structure for energy and
generator imbalance service, as well as the generator regulation rate
that the Commission accepted in Westar Energy Inc.\288\
---------------------------------------------------------------------------

    \287\ Id. P 94.
    \288\ Id. P 93 (citing Westar Energy Inc., 130 FERC ] 61,215
(2010) (Westar)).
---------------------------------------------------------------------------

    278. With regard to the volumetric component of the Schedule 10
rate, the Commission proposed to provide each public utility
transmission provider with the opportunity to justify a proposal: (1)
To require all transmission customers who are delivering energy from
generators to purchase, or otherwise account for, the same volume of
generator regulation reserves; or (2) to require transmission customers
who are delivering energy from VERs to purchase, or otherwise account
for, a different volume of generator regulation reserves than it
proposes to charge transmission customers delivering energy from other
generating resources.\289\ The transmission provider's proposal would
be made in a section 205 filing after the acceptance of its compliance
filing.
---------------------------------------------------------------------------

    \289\ The Commission noted its expectation that, in any
subsequent filing to establish a volumetric component in Schedule
10, public utility transmission providers would address how Schedule
10 and Schedule 3 work together to allow for the recovery of total
regulation reserve costs. Id. P 105 & n.206.
---------------------------------------------------------------------------

    279. Where a public utility transmission provider proposes the same
volume of generator regulation reserves for all generators, the
Commission proposed that it demonstrate that the volume of regulation
reserves required of transmission customers delivering energy from
generators located within its balancing authority area be commensurate
with their proportionate effect on net system variability, taking
account of diversity benefits.\290\ The Commission stated that such a
filing must show that the public utility transmission provider has
fully implemented (or been granted waiver from) the intra-hourly
scheduling requirement set forth in the Proposed Rule.\291\ The
Commission recognized that a public utility transmission provider with
few VERs located in its balancing authority area may choose to apply
only one volumetric regulation requirement for all generating resources
in its balancing authority area. The Commission noted that this also
may be the case to the extent the impact of VERs on a public utility
transmission provider's system is minimal and the public utility
transmission provider, in its judgment, deems the administrative burden
of justifying two separate volumetric regulation requirements is
uneconomic.\292\
---------------------------------------------------------------------------

    \290\ The Commission explained that diversity benefits result
from the aggregation of the variations of all resources such that
one resource's negative deviation can offset some or all of another
resource's positive deviation. The Commission stated that, 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 Commission preliminarily found that
diversity benefits would result from both transactions and that
sharing of these benefits among the customers would be reasonable.
Westar,130 FERC ] 61,215 at P 37.
    \291\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 105.
    \292\ Id. P 94.
---------------------------------------------------------------------------

    280. The Commission proposed that where a public utility
transmission provider proposes to require transmission customers who
are delivering energy from VERs to purchase, or otherwise account for,
a different volume of generator regulation reserves than it proposes to
charge transmission customers delivering energy from other generating
resources, the Commission proposed that it demonstrate that the volumes
of regulation reserves required of those subsets of transmission
customers delivering energy from generators located within its
balancing authority area are commensurate with their proportionate
effect on net system

variability and taking account of diversity benefits.\293\ That is, any
proposal for different volumes of generator regulation reserves based
on the generating resource would need to be supported by data showing
that, on the public utility transmission provider's system, VERs have a
different per unit impact on overall system variability than
conventional generating units.\294\ The Commission proposed that such a
filing must also show that the public utility transmission provider has
fully implemented (or been granted waiver from) the intra-hourly
scheduling requirement set forth in the Proposed Rule and has developed
and deployed power production forecasting for VERs.\295\
---------------------------------------------------------------------------

    \293\ Id. P 106.
    \294\ Id. P 95.
    \295\ Id. P 106.
---------------------------------------------------------------------------

    281. Specifically, the Commission proposed that any filing by
public utility transmission providers including different volumetric
requirements for different subsets of transmission customers must be
supported with actual data collected over a one-year period subsequent
to the deployment of power production forecasting for VERs and the
implementation of intra-hourly scheduling at 15-minute intervals. The
Commission acknowledged that this proposal could delay a public
utility's ability to recover the cost associated with providing
generator regulation service. The Commission further acknowledged that
there may be alternative methods for developing the data necessary to
support different volumetric requirements for different subsets of
transmission customers. The Commission sought comment as to such
methods of demonstration, how they could support a Commission finding
that the Schedule 10 filing is just and reasonable, and ways in which
these methods of demonstration may be preferable to this aspect of the
Commission's proposal.\296\
---------------------------------------------------------------------------

    \296\ Id. P 107.
---------------------------------------------------------------------------

    282. In the Proposed Rule, the Commission stated that the increased
use of power production forecasts in transmission systems where VERs
are located can provide transmission providers with improved
situational awareness, enable transmission providers to utilize
existing system flexibility through the unit commitment and dispatch
processes, and, ultimately, lead to a reduction in the amount of
reserve products needed to maintain system reliability. The Commission
also recognized that, in areas of the country with very limited
production from VERs, the implementation of power production
forecasting for VERs could be less useful.\297\ The Commission sought
comment in the Proposed Rule on the manner by which a public utility
transmission provider should be required to show it has developed and
deployed power production forecasts to support a proposal to require a
differentiated volumetric component of rates for generator regulation
reserves under proposed Schedule 10.\298\
---------------------------------------------------------------------------

    \297\ Id. P 55 n.125.
    \298\ Id. P 106.
---------------------------------------------------------------------------

a. Comments
i. General
    283. Invenergy Wind requests that the Commission clarify that, in
requiring initial Schedule 10 charges to adopt the utility's then-
effective Schedule 3 charges, the application of the rate will be
consistent. Invenergy Wind states that Schedule 3 charges are typically
applied on the basis of a percentage of the customer's schedule. Beacon
Power questions the reliance on existing regulation service charges,
stating that a transmission provider in non-RTO/ISO markets could
optimize the performance of its existing fleet to potentially lower
costs to customers under Schedule 3 or 10. Beacon Power requests that
the Commission encourage such transmission providers to evaluate the
technologies and benefits they provide. Xtreme Power agrees, asking the
Commission to require public utility transmission providers to make a
showing that the rates proposed for Schedule 10 are based on an
appropriate type and quantity of resources needed, considering the
technologies available in the market today rather than using dated
rates from Schedule 3. CESA suggests that the reforms proposed for
Schedule 3 in the Commission's Frequency Regulation Notice of Proposed
Rulemaking be included in Schedule 10 for RTO and ISO markets.\299\
---------------------------------------------------------------------------

    \299\ CESA; See also Notice of Proposed Rulemaking on Frequency
Regulation Compensation in the Organized Wholesale Electric Markets,
134 FERC ] 61,124 (2010) (Frequency Regulation NOPR); Frequency
Regulation Compensation in the Organized Wholesale Power Markets,
Order No. 755, 76 FR 67260 (Oct. 31, 2011), FERC Stats. & Regs. ]
31,324 (2011), reh'g denied, Order No. 755-A,138 FERC ] 61,123
(2012).
---------------------------------------------------------------------------

    284. Some commenters suggest that public utility transmission
providers be permitted to recover opportunity costs associated with
providing generator regulation service.\300\ For example, the Large
Public Power Council states that, consistent with the decision in
Puget, generator regulation service rates should be fully compensatory,
and may legitimately reflect a utility's full opportunity cost.\301\
According to Puget, there may also be lost opportunity costs associated
with reserving unloaded generation capacity during peak market
conditions. NRECA argues the integration of a significant amount of
VERs will cause the Schedule 3 rate to rise as Schedule 10 demand
increases particularly in regions with a lot of hydropower, where the
additional VERs cause the need for more thermal reserves, which are
more expensive than the existing reserve rate base.
---------------------------------------------------------------------------

    \300\ E.g., SMUD; WUTC; EEI; Large Public Power Council; Puget.
    \301\ E.g., Large Public Power Council (citing Puget Sound
Energy, 132 FERC ] 61,128 (2010)).
---------------------------------------------------------------------------

ii. Quantity of Reserves
    285. Some commenters request further direction from the Commission
regarding the calculation of the volumetric component of Schedule 10,
i.e., the quantity of reserves transmission customers are required to
purchase or otherwise account for.\302\ For example, the California PUC
asserts that the Commission should recommend or require that a public
utility transmission provider consider the system's resource mix and
the amount of operational flexibility of the transmission system's
generation fleet to develop the volumetric component of Schedule 10.
LADWP indicates that measures of alleged diversity benefits may lead to
unintended results if significant diversity occurs in one part of a
year and forms the basis for a smaller volumetric component than is
necessary for another part of the year.
---------------------------------------------------------------------------

    \302\ E.g., CPUC; LADWP; SEIA.
---------------------------------------------------------------------------

    286. Some commenters question whether the Commission should allow
public utility transmission providers the opportunity to file for
differentiated volumetric rates under Schedule 10. AWEA contends that
it would be unjust and unreasonable and break with Commission precedent
to allocate to generators the costs of Schedule 10, whether kept as a
regulation reserve or reformulated to a system non-spin service, while
allocating other ancillary services costs broadly to load. AWEA states
that all users of the grid add variability and uncertainty and that all
benefit when the grid is better able to accommodate variability and
uncertainty. AWEA also argues that the capacity used to provide
Schedule 10 service would be available to provide a number of other
ancillary services, not to mention to the public utility transmission
provider to meet peak demand.
    287. Western Grid states that the integration costs of other types
of generation are largely ignored and the

regulation and frequency costs imposed by large loads are broadly
socialized. Western Grid therefore contends that grid integration costs
related to VERs should be recovered in a manner comparable to the way
grid integration costs imposed by large conventional generators are
recovered. Argonne National Lab argues that calculating the net impact
of VERs on regulation service needs is likely to be difficult and
contentious and that to ensure just and reasonable treatment of all
resources, the Commission should be careful in imposing specific
requirements on VERs without considering the specific impacts on system
reliability and operating reserve costs from other generating resources
as well. Similarly, the Federal Trade Commission recommends that the
Commission consider whether the costs of imbalance services provided to
other types of generators can readily be identified and charged to the
responsible parties.
    288. Some commenters support the proposal to condition the
implementation of differentiated volumetric rates on whether that
transmission provider has implemented power production forecasting and
intra-hour scheduling reforms.\303\ AWEA states that Schedule 10 should
not be charged at all until a transmission provider has fully
implemented the Efficient Dispatch Toolkit and the Commission's
proposed sub-hourly scheduling and variable energy forecasting
operating reforms. Clean Line states that implementation of forecasting
should be required before any special charges are assigned to renewable
generators. Clean Line argues that, before transmission providers can
charge a just and reasonable rate to recover ancillary service costs,
they must use reasonable means to minimize those costs--such as
forecasting.
---------------------------------------------------------------------------

    \303\ E.g., AWEA; BP Energy; Iberdrola; Independent Power
Coalition West; NextEra; Oregon & New Mexico PUC; Public Interest
Organizations; Vestas.
---------------------------------------------------------------------------

    289. Some commenters suggest that differentiated volumetric rates
should be conditioned on implementation of additional reforms beyond
those set forth in the Proposed Rule.\304\ For example, Environmental
Defense Fund maintains that a public utility transmission provider
should not be permitted to establish different volumetric reserve
requirements for VERs unless it has demonstrated to the Commission that
the balancing authority area is optimally sized or cooperating with
other balancing authority areas. Oregon & New Mexico PUC similarly
state that Schedule 10 charges for VERs should be conditioned on a
demonstration by the public utility transmission provider regarding the
measures it has considered to increase cooperation with other balancing
authorities to lower the cost of integrating wind and solar. First Wind
argues that public utility transmission providers should only be
permitted to charge for generator regulation service once they have
implemented procedures for dynamic transfers in addition to intra-hour
scheduling. CESA contends that, before imposing any generator
regulation costs on VERs, public utility transmission providers should
first implement fast intra-hour markets and intra-hourly scheduling; a
robust ancillary services market; the option for third-party or self
supply of ancillary services; dynamic transfer capability out of the
balancing authority area; and Area Control Error (ACE) diversity
interchange or an energy imbalance service market.
---------------------------------------------------------------------------

    \304\ E.g., Iberdrola; First Wind; Oregon & New Mexico PUC;
Environmental Defense Fund.
---------------------------------------------------------------------------

    290. In contrast, ELCON asserts that Schedule 10 as proposed is a
mechanism for the socialization of costs that should be directly
assigned to VERs or their customers. Grant PUD argues that variable
loads and variable resources should be charged differently for
regulation service according to the nature of the different costs
placed on the public utility transmission provider. A number of other
commenters agree, objecting to any delay in cost recovery associated
with providing generator regulation service.\305\ For example, Pacific
Gas & Electric and Idaho Power argue that public utility transmission
providers incur costs to provide generator regulation service
regardless of whether they are employing intra-hourly scheduling and,
thus, preventing recovery of generator regulation service costs shifts
those costs to other customers in violation of cost causation
principles.
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    \305\ E.g., Tacoma Power; Montana PSC; Pacific Gas & Electric;
PNW Parties; NV Energy; Public Power Council; Natural Gas; WUTC.
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    291. EEI opposes requiring a public utility transmission provider
to commit specific actions before seeking rate recovery under section
205, particularly when such actions violate cost causation principles.
EEI states that as articulated by the Commission in Northern States
Power Company, ``[t]he fundamental theory of Commission ratemaking is
that costs should be recovered in the rates of those customers who
utilize the facilities and thus cause the cost to be incurred.'' \306\
According to EEI, the D.C. Circuit echoed this sentiment in KN Energy,
Inc. v. FERC, ``[s]imply put, it has been traditionally required that
all approved rates reflect to some degree the costs actually caused by
the customer who must pay them.'' \307\ EEI and others state that, to
the extent the Commission conditions generator regulation service cost
recovery on implementing the Proposed Rule's reforms, the Commission
should explain how such a limitation does not effectively force public
utility transmission providers to waive their sections 205 and 206
rights under the FPA in contravention of Atlantic City Electric
Company.\308\
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    \306\ EEI at 29 (citing N. States Power Co., 64 FERC ] 61,324,
at P 13 (1993) (emphasis supplied) (citations omitted)).
    \307\ EEI at 29 (citing KN Energy, Inc. v. FERC, 968 F.2d 1295,
1300 (D.C. Cir. 1992); Alcoa Inc. v. FERC, 564 F.3d 1342, 1346 (D.C.
Cir. 2009); Illinois Commerce Commission v. FERC, 576 F.3d 470, 476
(7th Cir. 2009); Pub. Serv. Comm. of Wisc. v. FERC, 545 F.3d 1058,
1067 (D.C. Cir. 2008); Pac. Gas & Electric Co. v. FERC, 373 F.3d
1315, 1320 (D.C. Cir. 2004)).
    \308\ EEI at 27-28 (citing Atlantic City Elec. Co., 295 F.3d 1,
10 (2002) (finding that the Commission lacks the authority to
require public utility transmission providers to cede their rights
under section 205 of the FPA); MidAmerican at 26; Puget at 17
(questioning whether whether requiring one-year of data reporting
interferes with a public utility transmission provider's rights
under section 205 of the FPA); WUCT at 7 (questioning whether
requiring 15-minute scheduling and one-year of data reporting
interfere with a public utility transmission provider's rights under
section 205 of the FPA)).
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    292. Southern opposes conditioning public utility transmission
providers' rights to recover rates under section 205 of the FPA for
generator regulation and frequency response service on the
implementation of such reforms. Southern argues that utilities have a
statutory right to establish just and reasonable rates under sections
205 and 206 of the FPA. If the Commission pursues these limitations,
Southern asks the Commission to explain how such a limitation does not
effectively force public utility transmission providers to waive their
section 205 and 206 rights.
    293. LADWP argues that the proposed requirements would place public
utility transmission providers in a defensive role. LADWP states that
presuming a public utility transmission provider makes a sufficient
showing that it implemented intra-hour scheduling and deployed power
production forecasting for VERs, a transmission provider is further
compelled to demonstrate the basis for any difference in regulating
reserves between VER transmission customers and non-VER transmission
customers. LADWP argues that this could put the public utility
transmission providers in a defensive role of justifying the findings
and conclusions within a system impact study report, in

the event performed by the public utility transmission provider.
iii. Power Production Forecasting
    294. Some commenters state specific opposition to linking power
production forecasting to the implementation of differentiated
volumetric rates under Schedule 10.\309\ Southern argues the Commission
would exceed its statutory authority if it required implementation of
power production forecasting. Southern states courts have recognized
that the Commission ``is a `creature of statute,' having no
constitutional or common law existence or authority, but only those
authorities conferred upon it by Congress.'' \310\ Southern contends
that, because the FPA never mentions meteorological forecasting, it is
beyond the scope of the Commission's authority. Southern explains that
public utilities have long engaged in meteorological forecasting for
load forecasting and dispatch purposes; however, there never has been
an indication that such practices were within the scope of the
Commission's jurisdiction, and the advent of VER generation has not
added such forecasting to the scope of the Commission's authority.
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    \309\ E.g., Bonneville Power; Montana PSC; Natural Gas; Public
Power Council; Puget Sound Energy; NV Energy.
    \310\ Southern (citing Cal. Indep. Sys. Operator Co. v. FERC,
372 F.3d 395, 398 (D.C. Cir. 2004) (citing Atlantic City Elec. Co.
v. FERC, 295 F.3d at 8)).
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    295. While Bonneville Power acknowledges that centralized power
production forecasts will facilitate system-wide benefits, Bonneville
Power disagrees that such forecasts should be a prerequisite to the
cost recovery of balancing reserve capacity used to provide generator
regulation reserve-type services. Bonneville Power believes that such a
requirement would shift costs to other users of the transmission system
that would not be otherwise incurred but for the VER generation. Puget
believes that requiring transmission providers to implement power
production forecasting as a precondition to Schedule 10 cost recovery
inappropriately shifts the costs of integrating VERs from the VER to
the balancing authority. Southern argues that meteorological
forecasting issues are business decisions that are best left to the
transmission providers and the market. EEI states that it is not
convinced that the power production forecasting requirements are
necessary to support requiring a higher volumetric amount of Schedule
10 regulation service. According to EEI, the data necessary to
substantiate a higher volumetric charge can be derived by analyzing the
deviation between a VER's scheduled versus actual production. EEI,
therefore, claims that requiring a public utility transmission provider
to implement power production forecasting prior to establishing a
higher volumetric rate creates a barrier to cost recovery.
    296. Montana PSC notes that the Proposed Rule's data reporting
requirements to support power production forecasting would only apply
to generators that are 20 MW or larger. Montana PSC argues that
conditioning differentiation of volumetric rates on the implementation
of power production forecasting could unduly restrict application of
Schedule 10 generation regulation charges to smaller resources. Montana
PSC argues that all VERs one MW or greater should be responsible for
Schedule 10 services that they cause.
    297. Other commenters ask the Commission to mandate use of power
production forecasting by all public utility transmission providers
with significant amounts of VERs instead of relying on the public
utility transmission owner's decision to charge differentiated Schedule
10 rates.\311\ The ISO/RTO Council argues that, while transmission
providers in areas with low to moderate levels of VER interconnection
may be able to manage variability on their systems without using power
production forecasting, areas with larger levels of VERs should be
required to adopt power production forecasting tools to ensure that
conditions affecting generation output can be anticipated and managed
appropriately. SEIA suggests that each transmission provider that
provides interconnection to or has interconnections with more than 50
MW of VERs should be required to develop a power production methodology
to accommodate integration of VERs. First Wind contends that power
production forecasting should be mandatory for public utility
transmission providers with five percent of VER resources on their
system. CPUC asks that the Commission clarify that any public utility
transmission provider may require power production forecasting if VERs
are currently or anticipated to become significant.