seller has generation in that market, it is a relevant geographic
market for that seller'' \277\ and states that it struggles to
understand the benefit of this extended notification requirement and
the Commission's definition of a new ``relevant'' market.\278\
---------------------------------------------------------------------------

    \275\ E.ON at 10 (citing NOPR, FERC Stats. & Regs. ] 32,702 at P
96) (emphasis added by E.ON).
    \276\ Id. at 10. E.ON uses the following example: If a seller
owns or controls a generation facility in PJM and obtained market-
based rate authorization, the fact that a new affiliate may own or
control 100 MW or more of new generation in the CAISO market has no
relevance to whether the seller in PJM lacks horizontal market
power.
    \277\ Id. (citing NOPR, FERC Stats. & Regs. ] 32,702 at P 96).
    \278\ Id.
---------------------------------------------------------------------------

    220. Several commenters oppose the Commission's proposal to use
nameplate capacity to calculate the 100 MW change in status
threshold.\279\ Solomon/Arenchild argue that the proposal creates a
disconnect between the asset appendix capacity ratings and indicative
screens capacity ratings because most indicative screens are based on
seasonal (summer/winter), not nameplate, ratings, and many sellers
report summer ratings only in their asset appendix.\280\ Solomon/
Arenchild therefore propose that the Commission allow sellers to use
either nameplate or seasonal ratings and, if applicable, five-year
averages, for determining the 100 MW threshold for the notice of change
in status.\281\ Solomon/Arenchild and EEI argue that the Commission
should allow energy-limited resources, in particular, to report five-
year averages.\282\
---------------------------------------------------------------------------

    \279\ See, e.g., Solomon/Arenchild at 3; EEI at 15; EPSA at 8-9;
E.ON at 13; Idaho Power at 3-4.
    \280\ Solomon/Arenchild at 3.
    \281\ Id.
    \282\ Id.; EEI at 15.
---------------------------------------------------------------------------

    221. Similarly, E.ON states that, if an affiliate of a market-based
rate seller acquires an interest in or builds 100 MW or more of energy-
limited generation, the Commission may already have on file five years
of historical average capacity ratings or EIA-derived data for the
energy-limited generation and argues that it would be a ``mismatch'' to
apply nameplate rating to the energy-limited generation for the
purposes of triggering any notice of change in status filing
requirement.\283\ Therefore, E.ON requests that, to the extent the 100
MW threshold remains, the Commission revise its regulations in section
35.42(a)(1) to provide that a market-based rate seller submit a notice
of change in status where there are ``cumulative net increases . . . of
100 MW or more of nameplate capacity or as otherwise has been reported
to the Commission.'' \284\ Idaho Power adds that while using nameplate
ratings across all generation types may provide consistency, it does
not provide a proper basis for evaluation when comparing, for example,
variable generation (i.e., wind, solar) with thermal generation (i.e.,
natural gas).\285\
---------------------------------------------------------------------------

    \283\ E.ON at 13.
    \284\ Id. E.ON's proposed change is illustrated in italics.
    \285\ Idaho Power at 3-4.
---------------------------------------------------------------------------

    222. Other commenters argue that notices of change in status need
not be filed in certain circumstances.\286\ FirstEnergy argues that the
Commission's approval of a transaction under section 203 of the FPA
should obviate the need for a subsequent change in status report and
further Commission review under section 205 of the FPA.\287\
FirstEnergy states that it is unaware of any instance in which the
Commission authorized a merger of generation facilities under section
203 of the FPA and later found that the merged entity fails the
standard for selling electricity at market-based rates in any relevant
geographic market.\288\ FirstEnergy further claims that its
recommendation will reduce the regulatory burden on sellers without
adversely affecting the Commission's ability to protect consumers.\289\
---------------------------------------------------------------------------

    \286\ See, e.g., FirstEnergy at 10, 11; AEP at 6; E.ON at 8-9,
11.
    \287\ FirstEnergy at 10.
    \288\ Id.
    \289\ Id. at 11.
---------------------------------------------------------------------------

    223. Additionally, AEP and E.ON argue that the Commission should
eliminate altogether the notice of change in status requirement for
sellers within RTOs. AEP explains that, to the extent market power
concerns are implicated by a market-based rate seller's acquisition or
new affiliation, the extensive Commission-approved RTO market
monitoring and mitigation rules adequately prevent the exercise of
market power without the need for the seller to file an additional
report.\290\
---------------------------------------------------------------------------

    \290\ AEP at 6. E.ON makes similar arguments. See E.ON at 8-9
(emphasizing that the notice of change in status would simply repeat
what the market-based rate seller has already told the Commission,
namely, that the market-based rate seller is relying on RTO
mitigation).
---------------------------------------------------------------------------

    224. E.ON requests that the Commission clarify that a notice of
change in status filing is not necessary where an affiliate of a
market-based rate seller is granted market-based rate
authorization.\291\ E.ON also recommends that the Commission revise its
policies so that only one substantive filing is submitted to the
Commission.\292\
---------------------------------------------------------------------------

    \291\ E.ON at 11.
    \292\ Id. (arguing that an initial market-based rate application
of the new affiliate should suffice to address all other relevant,
affiliated market-based sellers).
---------------------------------------------------------------------------

    225. NextEra claims that this notice of change in status proposal
is confusing in light of another NOPR proposal to eliminate the
requirement to provide indicative screens where all of a seller's and
its affiliates' generation in the relevant market is committed under
long-term power purchase agreements.\293\ NextEra states that the
proposed revised text of section 35.42(a)(1) of the Commission's
regulations provides only a bright line test for notices of change in
status based on nameplate capacity in the relevant geographic market
and first-tier markets, thus ignoring the long-term power purchase
agreements.\294\ NextEra suggests that, if the Commission adopts this
new requirement, it should explain how section 35.42(a) of the
Commission's regulation should be interpreted when generation is
subject to a long-term power purchase agreement.\295\ EEI encourages
the Commission to find additional ways to streamline the change in
status reporting requirements. EEI offers two examples: (1) The
Commission should indicate that minor changes in organization or other
information covered by the change in status reporting requirements need
not be reported individually but can be cumulated to include with a
next change in status filing, and (2) the Commission should consider
providing additional relief from change in status reporting to
companies based on the Commission's experience with the change in
status requirements over the past decade (e.g., the Commission should
consider increasing the 100 MW thresholds).\296\
---------------------------------------------------------------------------

    \293\ NextEra at 11.
    \294\ Id.
    \295\ Id. at 12.
    \296\ EEI at 16.
---------------------------------------------------------------------------

    226. EPSA notes that sellers are required to report a change in
status when an additional 100 MW in a relevant geographic market is
attained, but states that it is unclear whether the change in status
reporting requirement is then ``reset'' and a notice of change in
status is necessary when another 100 MW of controlled generation is

obtained, or once the 100 MW threshold is attained, if all new
controlled generation in excess of 100 MW must be reported.\297\ EPSA
seeks clarification that a notice of change in status must be submitted
each time a seller attains a cumulative 100 MW of controlled
generation.\298\
---------------------------------------------------------------------------

    \297\ EPSA at 11-12.
    \298\ Id.
---------------------------------------------------------------------------

    227. FirstEnergy recommends that, in addition to the proposal to
relieve RTO/ISO sellers from the obligation to file the indicative
screens, the Commission should relieve RTO/ISO sellers from the
obligation to submit notices of change in status relating to increases
in generation capacity. Similarly, AEP recommends that the Commission
relieve RTO/ISO sellers from the obligation to submit notices of change
in status altogether. EEI encourages the Commission to consider
providing broader relief from change in status reporting to utilities
with FERC-approved market power mitigation measures to reduce the
burden associated with the market-based rate program. EEI states that
the same principles underlying the proposed exemption of sellers with
FERC-approved market power mitigation from providing the indicative
horizontal market screens in their market power updates could apply
equally to the overall change in status reporting requirements.
c. Commission Determination
    228. We adopt the NOPR proposal with certain modifications and
clarifications. In the NOPR, the Commission proposed to apply the 100
MW threshold to a seller's and/or its affiliates' generation capacity
in each relevant market and first tier market(s), and to also apply the
100 MW threshold to each new relevant market (not previously studied)
in which a seller and/or its affiliates acquire a cumulative net
increase of 100 MW. The NOPR also proposed to require that the 100 MW
threshold for change in status filings be calculated based solely on a
generator's nameplate capacity rating.
    229. We believe that the Solomon/Arenchild and NextEra comments
with respect to the calculation of the 100 MW threshold have merit
\299\ and that generation capacity in the first tier markets should not
be treated the same as capacity located in the seller's relevant
geographic market/study area. We recognize that 100 MW located outside
of the study area is only equivalent to 100 MW inside when there is a
long-term firm transmission reservation to import the 100 MW.
---------------------------------------------------------------------------

    \299\ NextEra at 11; Solomon/Arenchild at 4.
---------------------------------------------------------------------------

    230. Therefore, we will modify the proposal set forth in the NOPR.
The 100 MW threshold for reporting a change in status will apply to a
seller's and/or its affiliates' net generation capacity additions in
each individual market, but will exclude markets and balancing
authority areas that are first-tier to the seller's study area. This
means a seller need not consider its and its affiliates new generation,
including generation from long-term purchase agreements, in first-tier
areas in determining whether it has reached the 100 MW threshold.
    231. However, we confirm that, consistent with the NOPR, the 100 MW
threshold applies to each new relevant market (not previously studied)
in which a seller and/or its affiliates acquire a cumulative net
increase of 100 MW. To find otherwise would allow a loophole where an
applicant could request and be granted market-based rate authority with
a small amount of generation in one market, qualify as a Category 1
seller, and then accumulate large amounts of generation in other
markets in the same region such that the seller could become Category 2
in the region without notifying the Commission. In addition, applying
the 100 MW threshold to each new relevant market ensures that sellers
study the generation acquired in any additional market that meets or
exceeds this threshold.
    232. Further, we believe that the comments opposing the
Commission's proposal to require use of nameplate capacity to calculate
the 100 MW change in status threshold have merit.\300\ Therefore, we
will revise the NOPR proposal and permit sellers to use nameplate or
seasonal capacity ratings for the 100 MW threshold for most generation
and allow energy-limited generation to use either nameplate or a five-
year average capacity factor.\301\
---------------------------------------------------------------------------

    \300\ E.g., E.ON at 13 ; EEI at 15; Idaho Power at 3-4; Solomon/
Arenchild at 3.
    \301\ However, consistent with our finding in this Final Rule
regarding use of nameplate capacity for solar photovoltaic
facilities, for change in status threshold purposes, sellers should
use nameplate capacity for such facilities. NOPR, FERC Stats. &
Regs. ] 32,702 at P 104.
---------------------------------------------------------------------------

    233. We disagree with FirstEnergy's contention that section 203
approvals should obviate the need for subsequent change in status
filings for further Commission review under section 205. The
Commission's analyses under sections 203 and 205 consider different
criteria for approving transactions; therefore, it is not a given that
a seller that passes a section 203 analysis will pass a section 205
analysis. Furthermore, the data required for the Commission's analyses
under FPA sections 203 and 205 differ; section 203 filings are
prospective, with studies based on projected data, whereas the change
in status filings under section 205 require studies based on historical
data.
    234. Additionally, we reject AEP's, E.ON's, FirstEnergy's, AEP's,
and EEI's requests that the Commission eliminate the change in status
requirements for sellers located in RTOs/ISOs.\302\ AEP states that the
Commission-approved market monitoring and mitigation rules adequately
prevent the exercise of market power without the need for the seller to
file an additional report.\303\ As explained above, we are not prepared
at this time to adopt the NOPR proposal to relieve sellers in RTO/ISO
markets of the obligation to file indicative screens.\304\ Therefore,
we will not relieve sellers in RTO/ISO markets of their obligation to
file notices of change in status.
---------------------------------------------------------------------------

    \302\ AEP at 3; E.ON at 8-9.
    \303\ AEP at 6.
    \304\ Moreover, we note that the NOPR did not propose to
completely eliminate the requirement for RTO sellers to file
triennial updated market power analyses but instead proposed to
eliminate the need to file indicative screens with their triennials.
---------------------------------------------------------------------------

    235. We reject EEI's request to report minor changes in
organization or other information covered by the change in status
requirements cumulatively with another change in status filing instead
of in separate change in status filings. Any change in other
information covered by the change in status requirements must be
reported within 30 days of the change. We interpret EEI's request to be
that ``minor change'' be permitted to be filed more than 30 days after
the change, i.e., at the time of the next change in status filing.
Timely notice of reportable changes in status are part of the
Commission's ex post analysis; \305\ it is not appropriate to exempt
any changes from being reported within 30 days, particularly given that
it is unclear when, if at all, those changes would ever be reported.
---------------------------------------------------------------------------

    \305\ Cal. ex rel. Harris v. FERC., 784 F.3d 1267, 1276 (9th
Cir. 2015) (``When we approved market-based ratemaking in Lockyer,
we repeatedly emphasized the importance of the `dual requirement of
an ex ante finding of the absence of market power and sufficient
post-approval reporting requirements.' '' (citing Cal. ex rel.
Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004)).
---------------------------------------------------------------------------

    236. Additionally, we reject EEI's proposal to increase the 100 MW
change in status reporting threshold.\306\ We believe that the 100 MW
threshold is reasonable, particularly given the trend towards building
smaller units. Further, changing the value of the megawatt

threshold was not proposed in the NOPR; thus, the proposal is outside
the scope of this rulemaking.
---------------------------------------------------------------------------

    \306\ EEI at 16.
---------------------------------------------------------------------------

    237. With regard to E.ON's request that the Commission clarify that
the ``any relevant market'' language is limited to the applicable
geographic region and applicable first-tier markets,\307\ we clarify
that any relevant market refers to a market in which a seller already
has generation located and acquires an additional 100 MW or a new
market that the seller had not studied previously.
---------------------------------------------------------------------------

    \307\ E.ON at 10. E.ON uses the following example: If a seller
owns or controls a generation facility in the PJM market and
obtained market-based rate authorization, the fact that a new
affiliate may own or control 100 MW or more of new generation in the
CAISO market has no relevance to whether the seller in the PJM
market lacks horizontal market power.
---------------------------------------------------------------------------

    238. Additionally, in response to E.ON's requests that the
Commission clarify if a seller needs to submit a change in status if it
acquires generation in an RTO market where it sells energy products,
and clarify whether a seller has to file a change in status when an
affiliate is granted market-based rate authority, we clarify as
follows. A seller should submit a change in status when it acquires
generation in any market, including an RTO market where it sells
electric products. Further, if a seller's affiliate is granted market-
based rate authority, and that results in 100 MW or more of new
generation capacity in a market, then the seller will have to file a
corresponding change in status. Therefore, we reject E.ON's
recommendation to revise the change in status policy so that only one
substantive filing is submitted to the Commission.\308\
---------------------------------------------------------------------------

    \308\ E.ON at 11 (arguing that an initial market-based rate
application of the new affiliate should suffice to address all other
relevant, affiliated market-based sellers).
---------------------------------------------------------------------------

    239. In response to NextEra's contention that the notice of change
in status proposal is confusing because it conflicts with the NOPR
proposal to eliminate the requirement to provide indicative screens
where all of a seller's and its affiliates' generation in the relevant
market is committed under long-term power purchase agreements, we
clarify as follows.\309\ For purposes of the change in status
requirement in section 35.42(a)(1), long-term firm purchases should be
treated as seller or affiliate-owned or controlled generation capacity
in the determination of the 100 MW threshold. Thus, a seller need not
make a change in status filing every time it enters into a new long-
term firm purchase agreement, but would need to submit a change is
status when its overall cumulative increase in generation is 100 MW.
The seller would need to revise its asset appendix to include the long-
term purchase agreement(s). In addition, we clarify that a market-based
rate seller that adds new generation capacity that is fully committed
to a non-affiliated buyer need not count that capacity toward the 100
MW threshold.
---------------------------------------------------------------------------

    \309\ NextEra at 11.
---------------------------------------------------------------------------

    240. We clarify in response to EPSA that if a seller acquires more
than 100 MW, it should report all of the newly acquired generation to
ensure that the net change in generation capacity is reported in a
timely manner. Furthermore, once a seller files a change in status for
a net increase of 100 MW or more of generation capacity, the threshold
is effectively reset such that the seller must file a change in status
each time it acquires an additional 100 MW or more of generation
capacity.
2. New Affiliation and Behind-the-Meter Generation
a. Commission Proposal
    241. Market-based rate sellers are required to make a change in
status filing when, among other requirements in section 35.42 of the
Commission's regulations, they become affiliated with entities that:
(1) Own or control generation; (2) own or control inputs to electric
power production; (3) own, operate, or control transmission facilities;
or (4) have a franchised service territory. There currently is no 100
MW threshold for reporting new affiliations (but there is a 100 MW
threshold for net increases for a seller's owned or controlled
generation facilities). In the NOPR, the Commission proposed to revise
the change in status regulations to include a 100 MW threshold for
reporting new affiliations. That is, a market-based rate seller that
has a new affiliation would not be required to file a change in status
for an affiliation with an entity with generation assets until its new
affiliations result in a cumulative net increase of 100 MW or more of
nameplate capacity in any relevant geographic market. The Commission
noted that the 100 MW threshold for reporting new generation strikes
the proper balance between the Commission's duty to ensure that market-
based rates are just and reasonable and the Commission's desire not to
impose an undue regulatory burden on market-based rate sellers.\310\
Similarly, the Commission stated that applying the 100 MW threshold to
new affiliations might ease the reporting burden on sellers without
diminishing the Commission's ability to identify possible market power.
Therefore, the Commission proposed to revise section 35.42(a)(2) of the
Commission's regulations to add a 100 MW threshold for reporting
certain new affiliations.
---------------------------------------------------------------------------

    \310\ Reporting Requirement for Changes in Status for Public
Utilities with Market-Based Rate Authority, Order No. 652, FERC
Stats. & Regs. ] 31,175, at P 68, order on reh'g, 111 FERC ] 61,413
(2005).
---------------------------------------------------------------------------

    242. The Commission also clarified that the requirement to submit a
notice of change in status to report affiliation with new generation,
transmission, or intrastate gas pipelines includes reporting that asset
in the seller's asset appendix. The Commission proposed to amend
section 35.42(c) to clarify that sellers must include all new
affiliates and any assets owned or controlled by the new affiliates in
the asset appendix.
    243. The Commission further proposed in the NOPR that ``all
assets'' include behind-the-meter generation and qualifying
facilities.\311\ However, the Commission proposed to allow sellers to
aggregate their behind-the-meter generation by balancing authority area
or market into one line on the list of generation assets. Similarly,
the Commission proposed to allow sellers to aggregate their qualifying
facilities under 20 MW by balancing authority area or market into one
line on the list of generation assets.
---------------------------------------------------------------------------

    \311\ Accordingly, the appendix must list all generation assets
owned (clearly identifying which affiliate owns which asset) or
controlled (clearly identifying which affiliate controls which
asset) by the corporate family by balancing authority area, and by
geographic region, and provide the in-service date and nameplate or
seasonal ratings by unit. As a general rule, any generation assets
included in a seller's market power study should be listed in the
asset appendix. Order No. 697, FERC Stats. & Regs. ] 31,252 at P
895.
---------------------------------------------------------------------------

    244. The Commission also proposed that sellers should include these
assets in their indicative screens, as well as in their asset appendix
and that sellers should include this generation when calculating the
100 MW change in status threshold and the 500 MW Category 1 threshold.
b. Comments
    245. Commenters generally support the Commission's proposal to
revise the change in status regulations to include a 100 MW threshold
for reporting new affiliations.\312\ Specifically, EEI supports the
Commission's proposal and adds that the Commission should consider
allowing a seller the option to file an

addendum to its appendix B asset list with the change in status filing,
instead of a complete new list, to show the specific changes in
generation.\313\ FirstEnergy also supports the Commission's proposal,
but argues that, if the new affiliation has previously been reviewed by
the Commission pursuant to its authority under section 203 of the FPA,
the Commission will derive no significant benefit by requiring the
seller to submit a notice of change in status relating to such
affiliation and recommends that the reporting requirement be further
limited.\314\
---------------------------------------------------------------------------

    \312\ See, e.g., EEI at 15-16; FirstEnergy at 11-12; SunEdison
at 9 (noting that this proposal is especially important to a company
like SunEdison that routinely acquires or becomes affiliated with
new entities that own small amounts of capacity); NRG Companies at
11-12; APPA/NRECA at 4; Golden Spread at 7.
    \313\ EEI at 16.
    \314\ FirstEnergy at 11.
---------------------------------------------------------------------------

    246. FirstEnergy supports the proposal to require generating
capacity associated with qualifying facilities and behind-the-meter
generation to be considered when determining the applicability of the
Commission's rules for filing notices of change in status and updated
market power analyses.\315\ FirstEnergy contends that, to the extent
qualifying facilities may be owned by or affiliated with entities
owning other generation resources, there is no valid reason why owners
of qualifying facilities and/or behind-the-meter generation resources
should not be subject to the same rules as those applicable to other
market participants.\316\
---------------------------------------------------------------------------

    \315\ Id. at 12.
    \316\ Id.
---------------------------------------------------------------------------

    247. Several commenters oppose the Commission's proposal to include
behind-the-meter generation as part of the 100 MW change in status
threshold.\317\ NRG Companies and NextEra argue that requiring the
inclusion of behind-the-meter generation in asset appendices and market
power analyses would impose a substantial burden on sellers.\318\ NRG
Companies and NextEra also argue that no useful purpose will be served
by the inclusion of behind-the-meter generation that is committed to
on-site consumption and not available to the grid.\319\ NRG Companies
and NextEra add that such generation may involve net metering, which
they state does not involve wholesale sales or transmission implicating
the Commission's jurisdiction.\320\
---------------------------------------------------------------------------

    \317\ See, e.g., NextEra at 12; NRG Companies at 2-3 (stating,
however, that the proposal makes sense as to qualifying facilities);
SunEdison 5-8.
    \318\ NRG Companies at 3 (stating that distributed generation
projects can be developed and installed in very short time periods
and tracking these projects with the frequency required to maintain
accurate asset appendices would be burdensome on any entity whose
affiliates are active in this area); NextEra at 12 (stating that the
burden to include behind-the-meter generation will increase
significantly, if there are numerous facilities within a corporate
family).
    \319\ NextEra at 12-13 (stating that, because of their small
size, such facilities are unlikely to affect meaningfully any
evaluation of market power in the indicative screens and adding that
there would be little or no value to the Commission in submitting a
notice of change in status in addition to the initial applications
and market power updates); NRG Companies at 2-3.
    \320\ NextEra at 13; NRG Companies at 2-3 (citing Sun Edison
LLC, 129 FERC ] 61,146, at P 18 (2009) (Sun Edison)).
---------------------------------------------------------------------------

    248. NRG Companies, NextEra, and SunEdison argue that behind-the-
meter generation does not contribute to market power and should be
excluded from the asset appendix.\321\ SunEdison argues that it is
inconsistent to require listing of assets that are not engaged in
wholesale power sales in the interstate power market and therefore
cannot and do not contribute to the seller's market share or market
power.\322\ SunEdison argues that, because the purpose of an asset
appendix is to provide data to be used in the Commission's assessment
of a seller's and its affiliates' market power in jurisdictional
wholesale markets, the Commission should find that assets that do not
participate in wholesale markets should not be included in the asset
appendix.\323\ SunEdison further contends that, since behind-the-meter
facilities are not physically capable of engaging in coordinated
interactions or arrangements with generation that sells power in
jurisdictional markets, there is no need to include them in a seller's
asset appendix.\324\ SunEdison requests that, if the Commission
determines it necessary to report behind-the-meter generation in the
asset appendix, it should exempt from this requirement facilities with
a net capacity of one MW or less.\325\
---------------------------------------------------------------------------

    \321\ SunEdison at 4 (stating that the requirement will be
``unduly burdensome'' for a company that owns ``hundreds of small
behind-the-meter solar projects'' and whose business plan is for it
and its affiliates to develop and acquire ``thousands of additional
similar projects'' and citing Commission precedent where the
Commission held that net-metered sales do not represent
jurisdictional wholesale sales or transmission). SunEdison also
references the White House and U.S. Department of Energy initiative
to streamline the permitting, installation, and interconnection
processes and states that reducing unnecessary administrative
burdens on companies that develop solar energy projects is one way
to help achieve this goal. Id. at 4-5.
    \322\ Id. at 5.
    \323\ Id. at 7.
    \324\ Id.
    \325\ Id. at 9 (citing Revisions to Form, Procedures, and
Criteria for Certification of Qualifying Facility Status for a Small
Power Production or Cogeneration Facility, Order No. 732, 75 FR
15950 (Mar. 30, 2010), FERC Stats. & Regs. ] 31,306, at P 34 (2010)
and comparing its argument for why behind-the-meter generation
should not be included in a seller's asset appendix to the
Commission's reasoning in Order No. 732 to exempt small facilities
from the Commission's Qualifying Facility status filing
requirement).
---------------------------------------------------------------------------

    249. El Paso recognizes the increasing role of behind-the-meter
generators in wholesale power markets and does not oppose the
Commission's inclusion of behind-the-meter generation in the indicative
screens.\326\ However, El Paso cautions the Commission to recognize
that for some systems, the output of these generators will have already
been reflected in the net load reported in the FERC Form No. 714
(Annual Electric Control and Planning Area Report), thus resulting in
double-counting a utility's capacity and, consequently, overestimating
its supply.\327\ El Paso requests that the Commission further refine
its reporting directive to instruct sellers to include behind-the-meter
generation in their indicative screens to the extent such generation is
not already netted against load for purposes of their FERC Form No. 714
reporting.\328\
---------------------------------------------------------------------------

    \326\ El Paso at 4.
    \327\ Id.
    \328\ Id.
---------------------------------------------------------------------------

    250. Other commenters seek clarification of the Commission's
proposed changes to the change in status reporting requirements, as
they relate to behind-the-meter generation. Specifically, EPSA argues
that, if a seller has behind-the-meter generation that is used solely
to operate equipment for production (such as an oil or gas operation
that uses behind-the-meter generation to produce oil or gas), such
behind-the-meter generation should not be counted towards the 100 MW
threshold because that generation is never offered or sold into the
market. EPSA recommends the Commission clarify that any such behind-
the-meter generation that is wholly self-consumed would not count
towards the 100 MW threshold.\329\ SoCal Edison requests the Commission
clarify whether behind-the-meter generation includes generation not
synchronized to the grid (i.e., generation that cannot be used for
wholesale power sales), since all generation is typically behind some
meter.\330\ SoCal Edison does not believe, for example, that a back-up
generator used to power a control center in the event of a power outage
needs to be included in a seller's asset appendix and seeks
confirmation to that effect.\331\ SoCal Edison also requests that the
Commission clarify whether it will permit sellers to aggregate long-
term firm purchases from small generators (such as qualifying
facilities under 20 MW) by balancing authority area or market into one
line on the list of

generation assets.\332\ SoCal Edison argues that such aggregation
should be permitted to relieve the burden that otherwise would be
imposed.\333\
---------------------------------------------------------------------------

    \329\ EPSA at 11.
    \330\ SoCal Edison at 19 (emphasis in original).
    \331\ Id.
    \332\ Id. at 23.
    \333\ Id.
---------------------------------------------------------------------------

c. Commission Determination
    251. We adopt the NOPR proposal to establish a 100 MW threshold for
reporting new affiliations in change of status filings. A market-based
rate seller that has a new affiliation will not be required to file a
change in status for an affiliation with an entity with generation
assets until its new affiliations result in a cumulative net increase
of 100 MW of capacity in a relevant geographic market.\334\ The 100 MW
threshold for new affiliations will be determined in exactly the same
manner as the 100 MW threshold is determined for other notices of
change in status. As explained above, the 100 MW threshold will be
determined for each relevant geographic market but will not consider
generation capacity additions in first-tier markets. We believe the 100
MW threshold strikes a reasonable balance between reducing reporting
burden on sellers while keeping the Commission informed about potential
market power concerns. We clarify that the 100 MW reporting threshold
for new affiliations is not separate nor distinct from the 100 MW
thresholds for reporting power purchase agreements or owned generation
as discussed elsewhere in this Final Rule. In other words, if a seller
becomes newly affiliated with 50 MW of generation in a balancing
authority area or market and experiences an increase of 50 MW of owned
generation in that same balancing authority area or market, the 100 MW
reporting threshold would be triggered. Similarly, a seller with a
newly acquired 50 MW power purchase agreement in that same balancing
authority area of market would also trigger the reporting threshold.
---------------------------------------------------------------------------

    \334\ However, if a seller files a notice of change in status
for another reason, e.g., to report the entrance into a power
purchase agreement of more than 100 MW, the seller should note that
it has a new affiliate with market-based rate authority and include
that new affiliate and any related assets in the seller's asset
appendix.
---------------------------------------------------------------------------

    252. However, we do not adopt the NOPR proposal to count behind-
the-meter generation in the 100 MW change in status threshold and 500
MW Category 1 seller status threshold and to include such generation in
the asset appendices and indicative screens.
    253. We agree with El Paso that the output of behind-the-meter
generation should be reflected in the load data reported in the FERC
Form No. 714. That is, the load reported in FERC Form No. 714 reflects
the fact that the load is lower than it otherwise would be if a portion
of the load were not served by behind-the-meter generation.
Additionally, since behind-the-meter generation is netted out of the
load data, requiring sellers to count behind-the-meter generation as
installed capacity could result in double-counting a portion of the
seller's generation capacity. Moreover, we clarify that behind-the-
meter generation that is consumed on-site by the host load and not sold
into the wholesale market, or is not synchronized to the transmission
grid, is not relevant to the Commission's horizontal market power
analysis.
    254. Given our decision not to require sellers to include behind-
the-meter generation in their asset appendices, indicative screens, and
for purposes of calculating the 100 MW change in status threshold and
500 MW Category 1 threshold, we will not address the remaining requests
for clarifications made by NRG Companies, NextEra, SunEdison, EPSA, and
SoCal Edison.
    255. Finally, we clarify that qualifying facilities that are exempt
from FPA section 205 \335\ and facilities that are behind-the-meter
facilities do not need to be reported in the asset appendix or
indicative screens. However, many qualifying facilities do have market-
based rate authority and the capacity of these facilities should be
reported in the screens, asset appendix and in determining the 100 MW
threshold.
---------------------------------------------------------------------------

    \335\ See 18 CFR 292.601(c)(1).
---------------------------------------------------------------------------

3. Reporting of Long-Term Firm Purchases
a. Commission Proposal
    256. As discussed elsewhere in this Final Rule, the Commission
proposed to require reporting of long-term firm purchases in the
indicative screens and also proposed to include such contracts when
determining the 100 MW threshold for change in status filings.\336\
---------------------------------------------------------------------------

    \336\ NOPR, Stats. & Regs. ] 32,702 at P 100.
---------------------------------------------------------------------------

b. Comments
    257. The comments addressed in the discussion on treatment of long-
term contracts generally encompass the issues in this section. However,
SoCal Edison states that the Commission should clarify that it will
permit long-term firm purchase aggregation from small generators, such
as qualifying facilities under 20 MW. SoCal Edison requests that such
aggregation be permitted to relieve the burden that otherwise would be
imposed.\337\
---------------------------------------------------------------------------

    \337\ SoCal Edison at 23.
---------------------------------------------------------------------------

c. Commission Determination
    258. The requirement to report long-term firm purchases in the
asset appendix and indicative screens and to require that such
contracts be counted towards the 100 MW threshold is discussed
elsewhere in this Final Rule.\338\ With respect to SoCal Edison's
request regarding aggregation of long-term firm purchase agreements, we
clarify that aggregation of such agreements will be permitted in the
asset appendix if certain conditions are met. Specifically, we will
allow aggregation of long-term firm purchase agreements from small
generators only if the information in these columns in the asset
appendix is identical for all agreements: ``[E] Market/Balancing
Authority Area,'' ``[F] Geographic Region,'' ``[G] Start Date (mo/da/
yr),'' and ``[H] End Date (mo/da/yr).'' Aggregating agreements with
different start dates or end dates or agreements in different Market/
Balancing Authority Areas would defeat the usefulness of collecting
such information. We also clarify that a seller that meets these
criteria can aggregate such agreements but would need to use column
``[I] End Note'' to report different docket numbers and/or names of the
filing entities and seller(s) in the End Note list of the asset
appendix.
---------------------------------------------------------------------------

    \338\ See supra Section IV.C.1.
---------------------------------------------------------------------------

D. Asset Appendix

    259. The Commission proposed clarifications and revisions to the
required appendix that contains the lists of generation and
transmission assets.
1. Changes to the Existing Columns
a. Commission Proposal
    260. The Commission proposed to make three changes to the existing
columns in the asset appendix. The Commission proposed to change a
column heading on both assets lists from ``Balancing Authority Area''
to ``Market/Balancing Authority Area'' to reflect the correct location
for assets in organized markets as well as in balancing authority
areas. The second proposal was to change a column heading on both asset
lists from ``Geographic Region (per Appendix D)'' to ``Geographic
Region'' because there have been changes to some regions since the
Commission originally published the region map in Appendix D of Order
No. 697. Finally, the Commission proposed to change the heading for the
``Nameplate and/or Seasonal Rating'' column of the generation list to
``Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average'' to

clarify that this column requires capacity ratings in megawatts and to
reflect that each submission in the asset appendix should use either
``nameplate,'' ``seasonal,'' or ``five-year average'' ratings to
reflect the rating used throughout the filing for a particular
generation technology. The Commission indicated that these proposed
changes would ensure consistency across filings and allow the industry
and Commission staff to better utilize the information contained in the
asset lists.
    261. The Commission further proposed to clarify that the asset
lists should not contain any information other than what is required in
the respective columns. For instance, sellers frequently include
footnotes in their appendices that cause the appendices to become
unwieldy and difficult to read or understand. Sellers sometimes explain
in these footnotes that some facilities are partially owned, that some
affiliates included in their asset lists may not actually be affiliates
but are included out of an abundance of caution, or that a facility is
expected to come on-line or off-line at some future date. The
Commission discouraged any such footnotes and directed that any such
representations be made in the filing transmittal letter.
    262. Thus, the Commission proposed to modify the example of the
required appendix found in appendix B to subpart H of part 35 of the
Commission's regulations to incorporate these changes.
b. Comments
    263. Few commenters express concern about the Commission's proposed
changes to the existing columns in the asset appendix.\339\ Solomon/
Arenchild are concerned that the proposal to change the heading for
capacity ratings column from ``Nameplate and/or Seasonal Rating'' to
``Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average'' may
introduce ``another potential source of inconsistency across filings''
and therefore suggest that the Commission add another column to the
asset appendix to allow a seller to report nameplate or seasonal
ratings, as well as the five-year average rating, if the seller elects
to use five-year average ratings.\340\ EEI states that the Commission's
proposed changes to existing columns seem appropriate, but would
encourage the Commission not to change the geographic regions without
advance notice and opportunity for comment by market participants in
those regions.\341\
---------------------------------------------------------------------------

    \339\ See, e.g., Solomon/Arenchild at 7; EEI at 17.
    \340\ Solomon/Arenchild at 7 & Attachment 1 (illustrating their
proposed additional column to the asset appendix).
    \341\ EEI at 17.
---------------------------------------------------------------------------

    264. Several commenters oppose the Commission's proposal to clarify
that asset lists should not contain any information other than what is
required in the respective columns.\342\ EPSA notes that the reason
sellers include footnotes and other ``extraneous information'' is to
avoid allegations that the sellers have misled the Commission.\343\
EPSA requests that the Commission add a separate column to the asset
appendix for explanatory notes and clarifications, instead of
prohibiting the use of footnotes.\344\ NRG Companies echo EPSA's
concerns and state that sellers include explanatory notes to avoid
misleading the Commission about matters that are too complex to be
depicted fully and accurately in the prescribed fields.\345\ NRG
Companies add that providing the explanatory notes in the transmittal
letter will not be an adequate substitute for appropriate notes in the
asset appendix itself.\346\ El Paso argues that discouraging sellers
from adding footnotes to their asset appendices could cause confusion
amongst industry particularly if the Commission creates a searchable
public database from these asset appendices because sellers may
unintentionally provide misleading information.\347\ EEI notes that
this clarification seems unnecessary and could inhibit sellers from
including helpful information in the asset appendix.\348\
---------------------------------------------------------------------------

    \342\ See, e.g., EEI at 18; El Paso at 5; EPSA at 13; NRG
Companies at 6.
    \343\ EPSA at 13.
    \344\ Id.
    \345\ NRG Companies at 6.
    \346\ Id. at 7.
    \347\ El Paso at 5 (arguing that members of the public may not
take the time to search the original transmittal letter that would
explain a seller's ownership).
    \348\ EEI at 18.
---------------------------------------------------------------------------

c. Commission Determination
    265. We adopt the proposed changes to the existing columns in the
asset appendix on both asset lists from ``Balancing Authority Area'' to
``Market/Balancing Authority Area'' to reflect the correct location for
assets in organized markets, as well as in balancing authority areas.
We also adopt the proposed column heading change from ``Geographic
Region (per Appendix D)'' to ``Geographic Region'' because there have
been changes to some regions since the Commission originally published
the region map in Appendix D of Order No. 697. We note, with regard to
EEI's comment, that removing the reference to Appendix D removes an
outdated reference to the Appendix in Order No. 697. Further, to aid in
identification of similarly named columns in the asset lists, we are
adding an alphabetic label to each column in the asset lists in the new
Asset Appendix.\349\
---------------------------------------------------------------------------

    \349\ For example, the first column in the generation asset list
is ``Filing Entity and its Energy Affiliates.'' We have labeled that
column, above the column heading, as Column ``[A].''
---------------------------------------------------------------------------

    266. We do not adopt the proposal to change the heading for the
``Nameplate and/or Seasonal Rating'' column of the generation list to
``Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average.''
Instead, in response to the Solomon/Arenchild comments, we will modify
the generation asset list to clearly distinguish between the nameplate
rating and an alternative rating of a generation facility.
Specifically, we are removing the ``Nameplate and/or Seasonal Rating''
column and replacing it with three new Columns [J], [K], and [L],
entitled ``Capacity Rating: Nameplate (MW)'', ``Capacity Rating: Used
in Filing (MW)'', and ``Capacity Rating: Methodology Used in [K]:
(N)ampelate, (S)easonal, 5-yr (U)nit, 5-yr (E)IA, (A)lternative,''
respectively.\350\ Sellers will populate Column [J] with the nameplate
capacity rating of their facilities, Column [K] with the capacity
rating attributed to that facility in the filing and any associated
market power study, and Column [L] with the appropriate letter to
indicate which rating methodology was used to derive the capacity
rating used in Column [K].\351\ Sellers will need to populate every
column for all facilities in the generation asset list, even facilities
that are not discussed in a given filing. If the instant filing does
not contain a market power study, or a particular generation asset is
not included in a market power study in that filing, sellers should
include in the generation asset list the rating that it used the last
time the asset was included in a market power study. We believe this
format addresses Solomon/Arenchild's concern about consistency of the
rating methodology across filings,

while maintaining the ability to tie asset appendix ratings to those
used in a market power analysis.
---------------------------------------------------------------------------

    \350\ As discussed in this Final Rule, sellers are allowed to
use alternative rating methodologies for different generation
technologies in their market power studies. The ``Capacity Rating:
Used in Filing (MW)'' column is where sellers should report the
actual value they used in the market power analysis. If a seller
uses nameplate ratings, the values in Column [J] ``Capacity rating
nameplate (MW)'' and Column [K] ``Capacity rating: used in filing
(MW)'' will be the same.
    \351\ For example, for a seller that has decided to use
nameplate ratings for all wind facilities in its market power
studies and owns a 100 MW (nameplate) wind facility, the seller will
place ``100'' in Column [J], ``100'' in Column [K], and ``N'' in
Column [L].
---------------------------------------------------------------------------

    267. Finally, we adopt the NOPR proposal to prohibit footnotes from
the asset appendices. However, in response to commenters' concerns
about loss of clarity and information, we adopt EPSA's suggestion and
add a separate column to the asset appendix for explanatory notes and
clarifications. We are adding a column entitled ``End Note Number
(Enter text in End Note Tab)'' as the final column in the generation
list (Column [M]), transmission list (Column [J]), and, as discussed
below, the new long-term firm power purchase agreement list (Column
[I]), and creating an additional end notes list. The end notes list
will have three columns: Column [A] ``End Note Number;'' Column [B]
``List (Generation, PPA, or Transmission);'' and Column [C]
``Explanatory Note.'' When a seller wants to provide more information
about a particular facility in an asset appendix list, the seller will
place a number in the appropriate end note column of the row listing
that facility. Furthermore, the seller will then enter that number in
Column [A] of the end notes list, specify in Column [B] which asset
list this end note refers to, and finally, enter in Column [C] the
explanatory text.
2. Reporting Power Purchase Agreements
a. Commission Proposal
    268. The Commission also proposed to require sellers to include all
of their long-term firm purchases of capacity and/or energy in their
indicative screens and asset appendices, regardless of whether the
seller has operational control over the generation capacity supplying
the purchased power. The Commission stated that this approach will help
size the market correctly and will establish consistent treatment of
long-term firm sales and long-term firm purchases.\352\ Other sections
of this Final Rule discuss the conversion of a power purchase agreement
measured in MWh into MW values that will be entered into the asset
appendix and indicative screens.
---------------------------------------------------------------------------

    \352\ NOPR, FERC Stats. & Regs. ] 32,702 at PP 16, 79.
---------------------------------------------------------------------------

b. Comments
    269. Several commenters requested clarification regarding how to
account for long-term firm purchases in the asset appendix. For
example, SoCal Edison states that it will not be possible to fill out
the asset appendix as currently proposed where a long-term firm
purchase is not tied to a physical generating asset and suggests
separating the appendix into two appendices--one for seller's/
applicant's generation and one for seller's/applicant's long-term firm
purchases.\353\ SoCal Edison states that if the Commission does not
change the asset appendix headings as requested, the Commission should
hold a technical conference to address questions raised by the change
in policy regarding the reporting of long-term firm purchases.\354\
NextEra opposes the reporting of long-term power purchase agreements in
the asset appendix but states that if the Commission decides to require
this reporting it should allow the use of EIA regional data for
facilities that do not yet have seasonal or a five-year average
capacity rating.\355\
---------------------------------------------------------------------------

    \353\ SoCal Edison at 21.
    \354\ Id. at 23.
    \355\ NextEra at 13-14.
---------------------------------------------------------------------------

c. Commission Determination
    270. We do not find the comments opposed to reporting of long-term
firm purchases in the asset appendix to be persuasive and adopt the
NOPR proposal to require sellers to report all of their long-term firm
purchases of capacity and/or energy in their indicative screens and
asset appendices. However, we agree with commenters that the format of
the generation asset list is not well suited for reporting long-term
purchases. Therefore, we are implementing SoCal Edison's recommendation
to create a separate list for a seller's long-term firm purchases.\356\
The new long-term purchases list has columns similar to the generation
list, but removes several inapplicable columns (Generation Name, Owned
By, Controlled By, and Date Control Transferred), and adds ``Start Date
(mo/da/yr)'' and ``End Date (mo/da/yr)'' columns.
---------------------------------------------------------------------------

    \356\ SoCal Edison at 21.
---------------------------------------------------------------------------

    271. NextEra requests that purchasers under a long-term firm power
purchase agreement be allowed to use EIA regional data. As discussed
above in the section on capacity ratings, we permit use of EIA regional
data but only for energy-limited facilities that lack five years of
operating data or for non-affiliated energy-limited facilities for
which the seller cannot obtain operating data.\357\ We also will
require that sellers de-rate all generators using the same technology
in a consistent manner. Thus, if a purchaser can identify which
generation units are fulfilling a long-term firm PPA, it should use the
same rating methodology for that facility in its market power study
that it is using for other generation facilities utilizing that
technology.
---------------------------------------------------------------------------

    \357\ As discussed above, the Commission will not permit de-
rating of solar photovoltaic facilities. See supra Section
IV.A.6.c.i.
---------------------------------------------------------------------------

3. Clarifications Regarding the Existing Columns
a. Commission Proposal
    272. The Commission noted that its post-Order No. 697 experience
has been that, with respect to the column in the list of generation
assets that is currently labeled ``Nameplate and/or Seasonal Rating,''
some sellers report only the portion of the capacity that they
own,\358\ whereas other sellers report the entire capacity of the
facility. Additionally, some sellers include in their generation asset
lists facilities in which they have claimed a relationship through only
passive, non-controlling interests.
---------------------------------------------------------------------------

    \358\ The Commission noted that it has not permitted market-
based rate sellers to dilute the ownership share of generation
attributed to the seller or its affiliates based on multiplying
successive shares of partial ownership in a company. See Kansas
Energy LLC, Trademark Merchant Energy, LLC, 138 FERC ] 61,107, at P
28 (2012). Instead, sellers must account for generation capacity
owned or controlled by the seller and its affiliates for purposes of
analyzing horizontal market power. See id. P 37.
---------------------------------------------------------------------------

    273. The Commission proposed the following clarifications with
respect to the asset appendix: (1) A seller must enter the entire
amount of a generator's capacity (in MWs) in the ``Capacity Rating
(MW): Nameplate, Seasonal, or Five-Year Average'' column of the
generation list even if the seller only owns part of a facility; (2) a
seller should list only one of the following as a ``use'' in the
``Asset Name and Use'' column of the transmission list: Transmission,
intrastate natural gas storage, intrastate natural gas transportation,
or intrastate natural gas distribution; and (3) entities and generation
assets in which passive ownership interests have been claimed should
not be included in the horizontal market power indicative screens or
reported in the appendix.\359\
---------------------------------------------------------------------------

    \359\ The Commission noted that sellers must demonstrate why
such ownership interests should be deemed passive. NOPR, FERC Stats.
& Regs. ] 32,702 at P 116 n.129 (citing AES Creative Resources, L.P.
et al., 129 FERC ] 61,239 (2009) (AES Creative)).
---------------------------------------------------------------------------

    274. The Commission explained that if a seller does not believe
that the entire capacity of a generation facility should be included in
its indicative screens, it may explain its position in the transmittal
letter filed with its horizontal market power screens, including
letters of concurrence where appropriate,\360\ and thus account for
only its portion of that particular generation facility in the
indicative

screens. However, the entire capacity of the facility should be
reflected in the list of generation assets in the appendix.
---------------------------------------------------------------------------

    \360\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 187.
---------------------------------------------------------------------------

    275. The Commission noted that generating units within a single
plant may be aggregated in a single row of the generation list if the
information in the other columns is the same for all units, but
separate plants cannot be aggregated into a single row. As discussed
and adopted elsewhere in this Final Rule,\361\ the Commission proposed
that qualifying facilities less than 20 MW may be aggregated by
balancing authority area or market into one line in the generation
asset list. The Commission further clarified that each asset should be
listed only once; if it is owned by more than one affiliate, all
affiliate names should be included in the ``Owned By'' column. If a
company or an affiliate is registered in the Commission's company
registration database,\362\ the Commission proposed to clarify that the
name in the asset appendix for that company must appear exactly the
same as in the registration database.
---------------------------------------------------------------------------

    \361\ See supra Section IV.C.2.c.
    \362\ The term ``company registration database'' here refers to
``FERC's Online Company Registration application'' (see http://www.ferc.gov/docs-filing/etariff/implementation-guide.pdf). However,
Commission orders have referred to this database as we have also
issued orders referring to it as ``Company Registration,'' (see
Filing Via the Internet, Revisions to Company Registration and
Establishing Technical Conference, 142 FERC ] 61,097 (2013)) or
``Company Registration system'' (see Filing Requirements for El.
Utility S.A., Order Updating Electric Quarterly Report Data
Dictionary, 146 FERC ] 61,169 (2014)).
---------------------------------------------------------------------------

    276. With respect to the ``Date Control Transferred'' column in
both the generation and transmission asset lists, the Commission
proposed to clarify that the ``Date Control Transferred'' column should
identify the date on which a contract or other transaction that
transfers control over a facility became effective. The Commission
noted that where appropriate, sellers may enter ``N/A'' in this field
to indicate that it is not applicable to their asset(s) and explain why
in the end note list.
    277. With respect to the ``Size'' column in the list of
transmission assets, the Commission proposed to clarify that the
``Size'' refers to both the length of the transmission line (i.e., feet
or miles) and the capability of the line in voltage (kV). The
Commission noted that sellers may aggregate their transmission assets
by voltage. For instance, a seller that owns a transmission system with
several hundred transmission lines might include two rows in the
transmission asset list; one row with 200 miles of 138 kV lines listed
in the ``Size'' column and another row with 100 miles of 230 kV lines
listed in the ``Size'' column as long as all the other columns (e.g.,
owned by, controlled by, balancing authority area, geographic region,
etc.) remain the same for all assets aggregated in that row. The name
for such aggregated facilities should describe the lines that are being
aggregated, e.g., ``230 kV transmission lines.''
i. Entire Amount of Generator's Capacity in Asset Appendix
(a) Comments
    278. Several commenters express concern over the Commission's
proposal to require a seller to include the entire amount of a
generator's capacity in its asset appendix, even if the seller only
owns part of a facility.\363\ Idaho Power, EEI, and FirstEnergy argue
that this proposal may lead to double counting many generation
facilities, or would otherwise lead to confusion.\364\ FirstEnergy also
argues that the proposal will result in the amount of generation
capacity reported by a seller in its asset appendix to differ from the
amount of generation capacity reflected in its indicative screens,
which may cause confusion over the amount of generation capacity
controlled by the reporting entity.\365\ NextEra adds that the
information in the asset appendix may not match the information in the
transmittal letter, which only includes a seller's ownership interest
in the generation facility where it has demonstrated its partial
ownership (or lack of control over).\366\ Idaho Power, NextEra, and El
Paso suggest that, if the Commission adopts this requirement, it should
add a column to the asset appendix to allow a seller to declare the
percentage of the generation facility it owns or controls.\367\
---------------------------------------------------------------------------

    \363\ See, e.g., Idaho Power at 2, 4; EEI at 17; FirstEnergy at
12-13; NextEra at 14-15; El Paso at 4-5.
    \364\ Idaho Power at 2, 4 (explaining that, if a seller enters
the entire amount of the generator's capacity when it owns just a
share of the generating asset, it is unclear how the Commission
would ensure that the generation capacity is not being counted
twice); EEI at 17 (explaining that, if multiple sellers have an
interest in an asset, and each lists the asset's entire generation,
the seller may over count the facility's capacity); FirstEnergy at
12-13 (explaining that each joint owner including the entire
generating capacity of a jointly owned facility may result in
double-counting).
    \365\ FirstEnergy at 12-13.
    \366\ NextEra at 14.
    \367\ Idaho Power at 2, 4; NextEra at 15 (expressing concern
over the public having to search for the seller's transmittal letter
in which the seller declares its partial interest); El Paso at 4-5
(recommending that the Commission add a ``Percentage of Ownership/
Control'' column to the asset appendix that would allow a seller to
identify the percentage of a generation facility that the seller
owns or controls).
---------------------------------------------------------------------------

(b) Commission Determination
    279. We adopt the NOPR's proposed clarification that a seller must
enter the entire amount of a generator's capacity in the generation
asset list. In response to commenters' concerns that the NOPR proposal
could result in double counting, confusion, or other inconsistencies,
we believe we have addressed those concerns through the addition of
capacity rating and end notes columns discussed above. Specifically, as
discussed more fully above, we are adopting Solomon/Arenchild's
proposal to add a new end notes column where sellers will be able to
place explanatory notes.\368\ To the extent a seller is attributing to
itself less than a facility's full capacity rating, the seller can
explain that in the end notes column.
---------------------------------------------------------------------------

    \368\ See supra Section IV.D.1.c.
---------------------------------------------------------------------------

ii. Size Column in Transmission Asset List
(a) Comments
    280. SoCal Edison questions the continued need for mileage of
transmission assets as required in the asset appendix for entities that
own integrated transmission networks rather than number of
interconnection customer's interconnection facilities. SoCal Edison
argues that the total length in miles of a utility's integrated network
transmission assets has no meaningful relationship to the ability to
exercise vertical market power. SoCal Edison further argues that one of
the aims of the distributed generation movement is to slow transmission
growth, such that a lack of transmission system growth could merely
reflect state preference for distributed generation over long-distance
transmission. Finally, SoCal Edison argues that FERC Form No. 1
provides the Commission an annual update of the transmission mileage
for major utilities and should prove sufficient for analysis. SoCal
Edison recommends that the Commission explain the need to track mileage
of transmission lines in service and how it relates to vertical market
power, particularly in light of third parties' ability to build new
transmission additions under Order No. 1000.\369\
---------------------------------------------------------------------------

    \369\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, FERC Stats. &
Regs. ] 31,323 (2011), order on reh'g, Order No. 1000-A, 139 FERC ]
61,132, order on reh'g, Order No. 1000-B, 141 FERC ] 61,044 (2012),
aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir.
2014).
---------------------------------------------------------------------------

(b) Commission Determination
    281. We disagree with SoCal Edison that reporting the mileage of

transmission assets as required in the asset appendix for entities that
own integrated transmission networks is unnecessary for a transmission
market power analysis. While we agree that the total length in miles of
a utility's integrated network transmission assets has no direct
relationship to the ability to exercise vertical market power, the
asset appendix is not intended to provide a detailed study of a
transmission owner's system. Instead, the transmission asset list, like
the generation asset list, provides a comprehensive list of the assets
owned or controlled by a market-based rate seller and identifies the
relevant transmission assets of sellers in wholesale power markets.
Collecting this information adds transparency to the market and allows
the public the opportunity to provide comments on a seller's
transmission assets. However, as noted in the NOPR, sellers are
permitted to aggregate similar assets in a balancing authority area,
which will reduce the burden associated with preparing the asset
lists.\370\
---------------------------------------------------------------------------

    \370\ NOPR, FERC Stats. & Regs. ] 32,702 at P 118.
---------------------------------------------------------------------------

iii. Passive Ownership
(a) Comments
    282. Some commenters took issue with the Commission's proposal to
clarify that entities and generation assets in which passive ownership
interests have been claimed should not be reported in the asset
appendix.\371\ EEI states that the clarification seems appropriate, but
vague.\372\ EEI asks whether partial passive ownership by anyone is
enough to exclude the asset from the asset appendix, or whether passive
ownership as the seller's only interest in the asset is what is
required for that seller to exclude the asset from its asset
appendix.\373\
---------------------------------------------------------------------------

    \371\ See, e.g., EEI at 17; AAI at 7-9.
    \372\ EEI at 17.
    \373\ Id.
---------------------------------------------------------------------------

    283. However, AAI cautions the Commission against eliminating the
passive ownership interests reporting requirement. AAI argues that a
passive interest can still affect competitive dynamics in the market
because control is not the sole factor to determine whether an entity
exercises market power.\374\ AAI further argues that eliminating the
reporting requirement could encourage generation owners to acquire
undisclosed passive interests that enhance their incentive to engage in
generation withholding and other abusive market behavior.\375\
---------------------------------------------------------------------------

    \374\ AAI at 7-8.
    \375\ Id. at 7-9
---------------------------------------------------------------------------

(b) Commission Determination
    284. We clarify that sellers should not include in their asset
appendices entities and facilities for which they have claimed, and
demonstrated to the Commission, that the only relationship is through
passive, non-controlling interests consistent with AES Creative (i.e.,
where the seller has a strictly passive ownership interest in another
entity, or another entity has a strictly passive ownership interest in
the seller). This is consistent with current Commission practice. As
noted in the NOPR, sellers must demonstrate why such a relationship
should be deemed passive.\376\ We are not persuaded by AAI's concerns
that eliminating this reporting requirement could encourage generation
owners to acquire undisclosed passive interests. We stress that we are
not eliminating the requirement to demonstrate passivity; we are merely
articulating our existing expectations. As noted above, we will
continue to require that any seller that claims certain interests are
passive or non-controlling must meet the standards set out in AES
Creative.
---------------------------------------------------------------------------

    \376\ NOPR, FERC Stats. & Regs. ] 32,702 at P 116 n.130 (citing
AES Creative, 129 FERC ] 61,239).
---------------------------------------------------------------------------

iv. Other Issues
    285. The Commission proposed clarifications regarding: Populating
the ``Use'' column in the transmission asset list; listing each asset
once in an asset list; matching seller and affiliate names in the asset
lists with the name registered in the Commission's company registration
database where possible; and the use of the ``Date Control
Transferred'' column in the transmission asset list.
(a) Comments
    286. We did not receive any comments directly related to the
aforementioned proposals. However, Solomon/Arenchild raised a concern
related to clarifications regarding existing columns in the asset
appendix. Solomon/Arenchild note that the proposed reporting of
capacity values in generation asset list in the asset appendix may be
inconsistent with the indicative screens. Specifically, Solomon/
Arenchild state that there is a disconnect between the time period
covered in the asset appendix and the time period covered in the
indicative screens.\377\ Solomon/Arenchild also state that the
indicative screens cannot rely solely on the ratings reported in the
asset appendix because both summer and winter seasonal ratings
typically are used in the indicative screens while the current asset
appendix only allows sellers to report one rating per generation
unit.\378\ Accordingly, Solomon/Arenchild recommend that the Commission
specify that any generation sold or contracts terminated following the
relevant study period be excluded from the historical study period of
the triennial filing, and that any generation acquired or contracts
begun since the historical study period be included in the indicative
screens and asset appendix.\379\
---------------------------------------------------------------------------

    \377\ Solomon/Arenchild at 7-8.
    \378\ Id.
    \379\ Id. at Attachment 1 (noting that their recommendation
conforms the indicative screens with the asset appendix that is part
of the triennial filing, creates a ``baseline'' for any future
notice of change in status filings, and more properly aligns the
determination of when a change in status should be filed in the
context of the 100 MW net change in capacity ownership for those
entities that have sold generation or terminated contracts).
---------------------------------------------------------------------------

(b) Commission Determination
    287. We adopt the proposed clarifications regarding: Populating the
``Use'' column in the transmission asset list; listing each asset once
in an asset list; matching seller and affiliate names in the asset
lists with the name registered in the Commission's company registration
database where possible; and to the use of the ``Date Control
Transferred'' column in the transmission asset list.
    288. In regard to the ``Date Control Transferred'' column, we
further clarify that sellers should identify the date on which a
contract or other transaction that transfers control over a facility
becomes effective. Where appropriate, companies may enter ``N/A'' in
this field to indicate that it is not applicable to their asset(s) and
provide any further explanation in the new end notes column.
    289. We do not adopt Solomon/Arenchild's recommendation to modify
the data in the market power analysis to match the data required for
the asset appendix. In Order No. 697, the Commission stated ``that when
the Commission evaluates an application for market-based rate
authority, the Commission's focus is on whether the seller passes both
of the indicative screens based on unadjusted historical data.
Likewise, when a seller fails one or both of the screens and the
Commission evaluates whether that seller passes the DPT, the
Commission's focus is on whether the seller passes the DPT based on
unadjusted historical data'' \380\ We will continue to require that a
seller's market power analysis rely on unadjusted historical data. To
the extent that a seller's generation

assets have changed between the historical time period used in the
market power analysis and the current time period of the asset
appendix, the seller should explain and reconcile any differences in
its application. Sellers may also provide sensitivity runs along with
the required historical studies to show whether changed circumstances
since the end of the study period justify a different conclusion than
what the data from the study period indicates.\381\ The Commission has
addressed the data disconnect issue by noting previously that the
Commission will consider, on a case-by-case basis, clear and compelling
evidence that seeks to demonstrate that certain changes in the market
should be taken into account as part of the market power analysis in a
particular case.\382\ However, we provide the following guidance for
preparing the studies and asset appendices for filings that commonly
contain both asset appendices and market-power studies.
---------------------------------------------------------------------------

    \380\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 301.
    \381\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at PP 124-
130.
    \382\ Id. P 130.
---------------------------------------------------------------------------

    290. For initial applications where the seller has acquired an
existing facility, sellers should prepare or rely on a study with
historical data that transfers the MW values of the acquired generation
from the Non-Affiliate Capacity rows to the Seller and Affiliate
Capacity rows of their indicative screens and enter the information for
the acquired facility in the generation asset list.
    291. For initial applications where the seller has newly built
generation, sellers should submit a study that increases the total
capacity value of the market/balancing authority area in which the
seller is physically located by the seller's newly built generation
capacity. To accomplish this, the seller should use a previously
approved study and add the value of their newly built generation to the
total capacity value of the market/balancing authority area. Sellers
must report this newly built generation in the generation asset list.
    292. In triennials, there are occasions when a seller's generation
fleet at the time of filing has changed since the close of the relevant
study period. In these instances, sellers should explain the changes in
the text of their filing, the end notes of the asset appendix if
applicable, and if the changes are significant, the seller should
provide a sensitivity analysis reflecting those changes.
    293. Notices of change in status generally do not require
indicative screens. However, sometimes a seller provides screens for
changes that the seller considers significant enough to merit the
submission of screens to show that it would not fail the indicative
screens with these new assets. In this case, we clarify that any
studies submitted by a seller should use the most recently available
historical data for the market, but include the seller's current
generation portfolio, imports, and load and reserve obligations (if
any).
    294. We understand Solomon/Arenchild's concern that the indicative
screens cannot solely rely on the ratings reported in the asset
appendix. Based on our experience, sellers that use seasonal ratings
for thermal generation in their indicative screens are likely to use
either summer or winter ratings in their asset appendix. However, in
some cases sellers that use seasonal ratings in their screens use
nameplate ratings in their asset appendix. Therefore, we clarify that
when sellers use seasonal ratings in their indicative screens, their
asset appendix should include the capacity rating used for each
generation unit in their pivotal supplier screen(s). Requiring sellers
to report the capacity rating used in their pivotal supplier screen
eliminates this inconsistency and allows us to maintain the simplicity
of the asset appendix. In addition, this ensures that the generation
asset list displays the seasonal rating of each generation unit at the
time of peak demand, when capacity is most needed.\383\
---------------------------------------------------------------------------

    \383\ As previously noted, if a filing does not contain a market
power study, or a particular generation asset is not included in a
market power study, sellers should include in the asset appendix the
rating that it used the last time the asset was included in a market
power study.
---------------------------------------------------------------------------

4. Changes Regarding OATT Waiver and Citations in Transmission Asset
List
a. Commission Proposal
    295. The Commission has stated that even if a seller has been
granted waiver of the requirement to file an OATT, those transmission
facilities should be reported in its asset appendix,\384\ and the
Commission stated in the NOPR that this should be reiterated and
clarified going forward. Therefore, the Commission proposed to require
any seller that has been granted waiver of the requirement to file an
OATT for its facilities \385\ to report in its transmission asset list
the citation to the Commission order granting the OATT waiver for those
facilities. The Commission proposed to modify the example of the asset
appendix found in appendix B to subpart H of part 35 of the
Commission's regulations to add a new column in the transmission asset
list for the citation to the Commission order accepting the OATT or
granting waiver of the OATT requirement. Providing the citation to the
Commission order accepting the OATT or granting waiver of the OATT
requirement in the list of transmission assets was intended to
facilitate the Commission's and market participants' verification that
sellers were granted the appropriate authorizations or waivers.
---------------------------------------------------------------------------

    \384\ ``We clarify that the transmission facilities that we
require to be included in that asset appendix are limited to those
the ownership or control of which would require an entity to have an
OATT on file with the Commission (even if the Commission has waived
the OATT requirement for a particular seller).'' Order No. 697-A,
FERC Stats. & Regs. ] 31,268 at P 378.
    \385\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 408.
---------------------------------------------------------------------------

b. Comments
    296. While APPA/NRECA support the Commission's proposal to require
a seller that has been granted waiver of the requirement to file an
OATT for its facilities to cite the Commission order granting that
waiver in its list of transmission assets in the asset appendix,\386\
other commenters oppose it. Some commenters note that the Commission's
proposal may be at odds with the Interconnection Customer
Interconnection Facility (ICIF) rulemaking in Docket No. RM14-11-000
that was pending at the Commission at the time the comments were
submitted.\387\ SoCal Edison requests that the Commission reject this
proposal because the new column will not provide useful information, in
light of the proposed ICIF rulemaking, and may cause confusion.\388\
NextEra suggests that the Commission synthesize the OATT waiver
provisions in both pending rulemakings.\389\
---------------------------------------------------------------------------

    \386\ APPA/NRECA at 5; see also Golden Spread at 7.
    \387\ SoCal Edison at 25 (explaining that the Commission is
proposing a blanket waiver of all OATT, OASIS, and Standards of
Conduct requirements to any public utility that is subject to such
requirements solely because it owns, controls, or operates
interconnection customer interconnection facilities and citing Open
Access and Priority Rights on Interconnection Customer's
Interconnection Facilities, 147 FERC ] 61,123, at P 35 (2014));
NextEra at 15; EEI at 17-18.
    \388\ SoCal Edison at 25.
    \389\ NextEra at 15.
---------------------------------------------------------------------------

    297. Other commenters argue that the proposal is unnecessary and
unclear.\390\ Specifically, FirstEnergy states that, if the citation to
the OATT or OATT waiver is in the transmittal letter, including the
citation in the asset appendix is redundant and unnecessary.\391\
FirstEnergy further states that, if a company transferred operational
control of its facilities to an

RTO, a citation to the order authorizing the transfer should
suffice.\392\ AEP argues that the proposal to provide a citation to the
OATT waiver is an extra imposition on sellers that is inconsistent with
the stated purpose of the NOPR.\393\ AEP and EEI state that OATTs are
readily publicly available and therefore do not need to be included in
the transmission asset list.\394\ AEP further argues that it is unclear
which OATT waiver citation a company like AEP would list because its
filings are frequently revised and updated.\395\
---------------------------------------------------------------------------

    \390\ See, e.g., AEP at 9; EEI at 17; and FirstEnergy at 13.
    \391\ FirstEnergy at 13.
    \392\ Id. at 14.
    \393\ AEP at 9.
    \394\ Id.; EEI at 17.
    \395\ AEP at 9; see also EEI at 17.
---------------------------------------------------------------------------

c. Commission Determination
    298. We adopt the proposal to require sellers to add a citation to
the order accepting a seller's OATT. Further, we agree with
FirstEnergy's suggestion that if a seller has transferred operational
control of its facilities to an RTO/ISO, this cite should be to the
order authorizing the transfer. Therefore, we have changed the text to
the proposed column (Column [B]) of the transmission asset list from
``Cite to Order Accepting OATT or granting OATT waiver'' to ``Cite to
order accepting OATT or order approving the transfer of transmission
facilities to an RTO or ISO.'' The change to remove ``granting OATT
waiver'' is discussed below.
    299. We do not agree with AEP's assertion that this requirement is
an extra imposition upon sellers. Further, in regard to AEP and EEI's
comments, we understand that OATT information is already publicly
available. However, sellers are already required to supply this
information as part of their demonstration that they meet the
Commission's vertical market power requirements. The new column
provides a convenient location for sellers to provide the information
and for the Commission or third-parties to find the information. We
clarify that sellers are not expected to change the citation every time
they revise or update their OATTs. Similar to Column [B] ``Docket #
where market-based rate authority was granted'' in the generation asset
list, we expect sellers to provide citation to the initial order
accepting a seller's OATT or accepting the seller's transfer of
transmission facilities to an RTO/ISO in Column [B] of the transmission
asset list. This will minimize any burden associated with including
this information in the transmission asset list.
    300. However, we do not adopt the NOPR proposal to require sellers
to add a citation to orders granting the seller waiver of the OATT
requirements. We agree with SoCal Edison that this requirement will not
provide useful information, in light of the Final Rule in the ICIF
proceeding.\396\
---------------------------------------------------------------------------

    \396\ See Open Access and Priority Rights on Interconnection
Customer's Interconnection Facilities, Order No. 807, FERC Stats. &
Regs. ] 31,367 (2015) (amending Commission regulations to waive the
OATT requirements of section 35.28, the OASIS requirements of part
37, and the Standards of Conduct requirements of part 358, under
certain conditions, for entities that own interconnection
facilities).
---------------------------------------------------------------------------

5. Electronic Format
a. Commission Proposal
    301. Currently, virtually all of the asset appendices are submitted
to the Commission using PDF format. Staff is unable to perform
calculations on PDF files, or to search, or sort the data contained in
the asset lists. Staff therefore frequently transfers the information
included in the asset lists into spreadsheets for sorting, comparison
purposes, and internal calculations, and in doing so has found numerous
submission errors from sellers. In the NOPR, the Commission stated that
if it provided a sample electronic spreadsheet and required sellers to
submit the assets lists in an electronic spreadsheet, it would reduce
filing burdens, improve accuracy, decrease the number of staff
inquiries to sellers regarding submission errors, and result in a more
efficient use of resources.
    302. Therefore, the Commission proposed to require market-based
rate sellers to submit the appendix B asset lists in an electronic
spreadsheet format that can be searched, sorted, and otherwise accessed
using electronic tools. The Commission proposed to post on the
Commission's Web site sample asset lists in formatted electronic
spreadsheets and to require sellers to submit the asset appendix in the
form and format of the sample electronic asset list spreadsheets.\397\
---------------------------------------------------------------------------

    \397\ The Commission proposed that if a seller chooses to create
its own workable electronic spreadsheet, the file it submits must
have the same format as the sample spreadsheet on the Commission Web
site. Specifically, it must have the same exact columns and
descriptive text as the sample spreadsheet. The Commission further
proposed that the file must be submitted in one of the spreadsheet
file formats accepted by the Commission for electronic filing. NOPR,
FERC Stats. & Regs. ] 32,702 at P 63 n.71. See FERC, Acceptable File
Formats (January 2012), available at http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
---------------------------------------------------------------------------

    303. An example of the electronic spreadsheet for the asset
appendix with the proposed new columns and column headings was included
as appendix B to the NOPR.
b. Comments
    304. Commenters generally support the Commission's proposal to
require sellers to submit the asset appendix in an electronic
spreadsheet format; however, several commenters request clarification
or modification of the proposal.\398\ EPSA requests clarification on
the specific fields that would be required in the electronic format,
and the methodology that should be used to submit the electronic
forms.\399\ E.ON urges the Commission to thoroughly vet the process to
ensure ease of use and submission by market participants, which may
require a public test period.\400\ EEI states that, ``if the Commission
simply intends to require market-based rate applicants and sellers to
file the information in standard electronic formats, such as Adobe,
Excel, and Word, that would be fine. Such straightforward electronic
filing will simply mirror the current FERC eFiling process, which has
eased the burden of filing documents at FERC. If, however, the
Commission has in mind that market-based rate applicants and sellers
must provide the information using rigid new formats, e.g. with pre-
defined rows and columns using XML data, EEI asks the Commission to
engage in further dialogue with the regulated community first, to
ensure that the format changes are reasonable, clear, and workable.''
\401\
---------------------------------------------------------------------------

    \398\ See, e.g., APPA/NRECA at 5 (supporting the Commission's
proposal and requesting no clarifications or modifications);
Solomon/Arenchild at 6-7; EPSA at 12; E.ON at 13, 14.
    \399\ EPSA at 12.
    \400\ E.ON at 13.
    \401\ EEI at 18.
---------------------------------------------------------------------------

c. Commission Determination
    305. We adopt the NOPR proposal to require sellers to submit the
asset appendix in an electronic spreadsheet format.
    306. EEI apparently misconstrued this proposal and we clarify here
that the electronic format requirement for the asset appendix is
specifically designed to stop the submission of asset appendices in
Word or PDF format and instead require that these be submitted in a
workable electronic file format such as Excel. We adopt the NOPR
requirements of a ``workable electronic spreadsheet,'' \402\ provide an
example on

our Web site, and provide the electronic filing requirements for such a
filing.\403\ Furthermore, we clarify that this requirement is not
dependent upon any particular technology such as Extensible Markup
Language (XML), and instead can use any one of a number of Commission
accepted spreadsheet formats.\404\ In response to EPSA, we clarify that
the entire asset appendix (including all relevant lists) should be
submitted in the electronic format. Sellers should submit the
electronic asset appendix as an attachment to their filings, following
the Commission's electronic filing requirements described above.
---------------------------------------------------------------------------

    \402\ `` `Workable electronic spreadsheet' refers to a machine
readable file with intact, working formulas as opposed to a scanned
document such as an Adobe PDF file.'' NOPR, FERC Stats. & Regs. ]
32,702 at P 63 n.70. Additionally:
    If a seller chooses to create its own workable electronic
spreadsheet, the file it submits must have the same format as the
sample spreadsheet on the Commission Web site. Specifically, it must
have one worksheet for each of the indicative screens and each
screen must have the same exact rows, columns, and descriptive text
as the sample worksheets. Cells requiring negative values must be
pre-programmed to only allow negative values. Likewise, cells with
calculated values must contain a working formula that calculates the
value for that cell. Finally, the file must be submitted in one of
the spreadsheet file formats accepted by the Commission for
electronic filing. See FERC, Acceptable File Formats (Jan. 2012),
available at http://www.ferc.gov/docs-filing/elibrary/accept-fileformats.asp. NOPR, FERC Stats. & Regs. ] 32,702 at P 63 n.71.
    \403\ Id. P 123 n.135.
    \404\ Id. P 65 n.73; see also supra Section IV.A.4.c.
---------------------------------------------------------------------------

    307. Finally, we replace the example appendix found in appendix B
to subpart H of part 35 of the Commission's regulations with the
appendix B in this Final Rule.
6. Database
a. Commission Proposal
    308. The Commission sought comment regarding whether in the future
it would be beneficial to develop a comprehensive searchable public
database of the information contained in the asset appendix, which
would eventually replace the pre-formatted spreadsheet. The Commission
noted that such an approach would allow market-based rate sellers to
update their asset appendices when circumstances change. The Commission
sought comments regarding whether such a database would be useful, how
the database might be created, standardized and maintained, and the
frequency with which it should be updated. The Commission further
sought input on the usefulness of including unique identifiers for the
affiliate companies and generation assets in such a database, e.g., the
company registration database and the EIA Power Plant Code and
Generator ID, respectively, where those identifiers exist. The
Commission also sought comment on the difficulty of reporting and the
usefulness of including in such a database the percentage each
affiliate owns of each of its assets.
b. Comments
    309. While APPA/NRECA, Golden Spread, and E.ON support the
Commission's proposal to develop a comprehensive, searchable public
database of the information contained in the asset appendix,\405\
several other commenters expressed concern.\406\ SoCal Edison and EEI
argue that including contract data in the database would raise concerns
about confidentiality.\407\ EEI states that the database would need to
be designed in close coordination with the regulated community to
ensure a useful result, minimize the regulatory burden, and address
confidentiality and critical energy infrastructure information (CEII)
concerns.\408\ Idaho Power states that, in some cases, proprietary
information of a generator's capacity would be masked in a public
database, impacting the usefulness of the database.\409\
---------------------------------------------------------------------------

    \405\ APPA/NRECA at 5; Golden Spread at 7; E.ON at 14 (stating
that a database would be particularly useful if the Commission
ultimately adopts its proposal to redefine relevant markets for
generation-only balancing authority areas, and it would provide
market participants and market-based rate sellers with access to
megawatt generation data needed for horizontal market power
analyses).
    \406\ See, e.g., SoCal Edison at 26; EEI at 18; Idaho Power at
2-3.
    \407\ SoCal Edison at 26; EEI at 18 (adding that including
contract data in the database would create additional information
collection burdens and would also raise concerns about the
disclosure of Critical Energy Infrastructure Information (CEII)).
    \408\ EEI at 18.
    \409\ Idaho Power at 2-3.
---------------------------------------------------------------------------

    310. Other commenters raise issues related to maintaining the
database's integrity.\410\ SoCal Edison, EEI, and AEP state that the
database could omit qualifying facilities' generation and non-
jurisdictional entities' generation.\411\ SoCal Edison also argues that
it would be difficult to assemble information from the asset appendix
about long-term firm purchases into a meaningful database.\412\
Solomon/Arenchild support the database, in theory, but state that the
database would require continual, time-consuming, and cumbersome
maintenance to maintain its integrity.\413\ They further state that for
such a database to provide meaningful information, one would need to be
able to readily identify duplicates, overlaps etc., or the utility of
the database will be undermined. NextEra echoes Solomon/Arenchild's
concern and state that the burdens associated with maintaining such a
database would outweigh the benefits.\414\ EPSA expresses concern over
whether the industry or the Commission will be responsible for updating
the database and how the accuracy of the information will be
ensured.\415\
---------------------------------------------------------------------------

    \410\ See, e.g., SoCal Edison at 26; EEI at 18; AEP at 10;
Solomon/Arenchild at 6-7; NextEra at 15; EPSA at 14.
    \411\ SoCal Edison at 26 (adding also that the data may not be
particularly useful due to joint ownership issues); EEI at 18; AEP
at 10.
    \412\ SoCal Ed. at 26.
    \413\ Solomon/Arenchild at 6-7.
    \414\ NextEra at 15.
    \415\ EPSA at 14.
---------------------------------------------------------------------------

    311. EPSA also seeks clarification on whether the database would
eventually replace the asset appendix, or if both a database and an
asset appendix would be required.\416\ EPSA states that, if both a
database and an asset appendix will be required of all market-based
rate sellers, then such requirements would run counter to the
Commission's stated intentions to streamline the information required
and reduce the regulatory burden on market-based rate sellers. EPSA
suggests that, if sellers will be required to use the database for
documentation of assets, the seller should be responsible for updating
and maintaining its data on the database.\417\
---------------------------------------------------------------------------

    \416\ Id.
    \417\ Id.
---------------------------------------------------------------------------

    312. AEP does not see the need for the Commission to host a
comprehensive searchable public database, stating that the information
is available through other means and creating the database would impose
another reporting obligation on sellers.\418\
---------------------------------------------------------------------------

    \418\ AEP at 9.
---------------------------------------------------------------------------

c. Commission Determination
    313. We will not direct the creation of a comprehensive public
database as part of this rulemaking. In the NOPR, we sought industry
comment on the usefulness of a potential database and for input on how
the database might be created and maintained. While some commenters
raise valid concerns about the structure, confidentiality, burden and
maintenance of the database, others recognize the potential utility of
a well-designed and properly administered database.\419\ Similarly, we
continue to recognize the potential value of the database and may
consider the creation of a database in the future.
---------------------------------------------------------------------------

    \419\ APPA/NRECA at 5; Golden Spread at 7; E.ON at 14; Solomon/
Arenchild at 6-7.
---------------------------------------------------------------------------

E. Category 1 and Category 2 Sellers

1. Commission Proposal
    314. In Order No. 697, the Commission created a category of market-
based rate sellers, Category 1 sellers, that are exempt from the
requirement to periodically submit

updated market power analyses in accordance with the regional reporting
schedule. Category 1 sellers include wholesale power marketers and
wholesale power producers that own or control 500 MW or less of
generation in aggregate per region; that do not own, operate or control
transmission facilities other than limited equipment necessary to
connect individual generating facilities to the transmission grid (or
have been granted waiver of the requirements of Order No. 888); that
are not affiliated with anyone that owns, operates, or controls
transmission facilities in the same region as the seller's generation
assets; that are not affiliated with a franchised public utility in the
same region as the seller's generation assets; and that do not raise
other vertical market power concerns.\420\
---------------------------------------------------------------------------

    \420\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 853-863;
see also 18 CFR 35.36(a)(2).
---------------------------------------------------------------------------

    315. In the NOPR, the Commission proposed to clarify the
distinction in determining the seller category status of power
marketers and power producers. For purposes of determining seller
category status for each region, a power marketer should include all
affiliated generation capacity in that region. Power producers only
need to include affiliated generation that is located in the same
region as the power producer's generation assets. The Commission
explained that the reason behind this distinction is that a power
marketer with no generation assets in the ground is assumed to have no
home market; it is thus assumed to be equally likely to make sales in
any region. In contrast, although a power producer has authorization to
make sales in other regions, it is assumed that the majority of its
sales will be in the region(s) in which it owns generation assets.
    316. Thus, the Commission proposed to clarify that a power marketer
with no generation assets may qualify as a Category 1 seller in any
region where: (1) Its affiliates own or control, in aggregate, 500 MW
or less of generation capacity; (2) it is not affiliated with anyone
that owns, operates or controls transmission facilities; (3) it is not
affiliated with a franchised public utility; and (4) it does not raise
other vertical market power issues. The Commission noted that the above
is consistent with the Commission's treatment of power marketers since
the issuance of Order No. 697.
    317. The Commission also proposed to clarify that a power producer
may qualify as a Category 1 seller in any region in which the power
producer itself owns generation and the power producer and its
affiliates own or control, in aggregate, 500 MW of generation capacity
or less, as long as the power producer is not affiliated with anyone
that owns, operates or controls transmission facilities in that region,
is not affiliated with a franchised public utility in that region, and
does not raise other vertical market power issues. In addition, unlike
power marketers, a power producer may qualify as a Category 1 seller in
a region where the power producer itself does not own or control any
generation or transmission assets but where it has affiliates that are
Category 2 sellers.\421\
---------------------------------------------------------------------------

    \421\ The Commission noted that a mitigated seller cannot use an
affiliated power producer in another region as a conduit to sell in
a mitigated balancing authority area because all affiliates of a
mitigated seller are prohibited from selling at market-based rates
in any balancing authority area or market where the seller is
mitigated. Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 335.
---------------------------------------------------------------------------

    318. Therefore, the Commission proposed to revise the regulation at
18 CFR 35.36(a)(2) and clarify that in order to qualify for Category 1
status, a seller must meet all of the requirements. Failure to satisfy
any of these requirements results in a Category 2 designation.
2. Comments
    319. EEI recommends that the Commission modify its proposed
clarifications regarding Category 1 and Category 2 sellers. EEI
encourages the Commission to allow power marketers to demonstrate that
their sales from particular capacity are confined to particular regions
and thus should be counted accordingly in determining their category
status.\422\ EEI adds that the Commission should modify the definition
of a Category 1 seller from ``no more than 500 MW generation ownership
and/or control'' to ``no more than 500 MW of uncommitted resources
owned and/or controlled.'' \423\ EEI contends that some companies have
always had negative uncommitted resources because they are net buyers,
and so should not be required to make updated market power analysis
filings or change in status filings.\424\
---------------------------------------------------------------------------

    \422\ EEI at 19.
    \423\ Id.
    \424\ Id.
---------------------------------------------------------------------------

3. Commission Determination
    320. We adopt the proposed clarifications regarding Category 1 and
Category 2 sellers and the corresponding regulatory changes to 18 CFR
35.36(a)(2) as proposed in the NOPR.
    321. In response to EEI's comment to allow power marketers to
demonstrate that sales from particular capacity are confined to a
particular region, the Commission has found that category seller status
is based on the region in which generation capacity is owned or
controlled by the seller and its affiliates in aggregate rather than
where sales are made in an effort to keep the definition and
demonstration of a seller's category status simple and
straightforward.\425\ Since sales change frequently, we believe basing
the category seller status definition on sales could create an
additional burden on sellers to demonstrate that their and their
affiliates' sales are confined to a particular region. However, we note
that to the extent that any seller wishes to limit its market-based
rate authority to a particular region or set of regions in its tariff,
it is free to do so. If a seller does not have market-based rate
authority in a particular region, it will not have an obligation to
file regular updated market-power analyses for that region.
---------------------------------------------------------------------------

    \425\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 864-868.
---------------------------------------------------------------------------

    322. EEI also proposed that the category seller status designation
be based on whether a seller owns or controls uncommitted resources in
a region. We reject this proposal as beyond the scope of what was
proposed in the NOPR. Moreover, the test for category seller status was
intended to be a bright line test that would be easy to
administer.\426\ The Commission has previously found that ``aggregate
capacity in a given region best meets our goal of ensuring that we do
not create regulatory barriers to small sellers seeking to compete in
the market while maintaining an ample degree of monitoring and
oversight that such sellers do not obtain market power.'' \427\ We do
not believe that a seller with over 500 MW of capacity is the type of
seller that the Commission intended to exclude from periodic updated
market power analyses, regardless of whether the seller's capacity
happens to be committed at a particular point in time.
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    \426\ Id. P 864.
    \427\ Id. P 865; Order No. 697-A, FERC Stats. & Regs. ] 31,268
at P 360.
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F. Corporate Families

1. Corporate Organizational Charts
a. Commission Proposal
    323. In the NOPR, the Commission proposed to require sellers to
provide an organizational chart, in addition to the existing
requirement \428\ to provide written descriptions of their affiliates
and corporate structure or upstream

ownership, for initial applications for market-based rate authority,
updated market power analyses and notices of change in status reporting
new affiliations.
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    \428\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 181,
n.258 (also requiring sellers seeking market-based rate authority to
describe the business activities of their owners, stating whether
they are in any way involved in the energy industry).
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    324. The Commission noted that it has seen increasingly complex
organizational structures as private equity funds and other financial
institutions take ownership positions in generation and utilities.\429\
The Commission stated that requiring the filing of an organizational
chart would make reviewing market-based rate filings more efficient,
increase transparency, and synchronize information about corporate
structure that the Commission receives from sellers with market-based
rate authority with similar information that the Commission receives
under section 203 of the FPA.\430\ The Commission proposed to require
that sellers provide an organizational chart similar to that which the
Commission requires from section 203 applicants. Specifically, the
Commission noted that section 33.2(c)(3) of its regulations \431\
provides that section 203 applicants must include: A description of the
applicant, including, among other things, organizational charts
depicting the applicant's current and proposed post-transaction
corporate structures (including any pending authorized but not
implemented changes) indicating all parent companies, energy
subsidiaries and energy affiliates unless the applicant represents that
the proposed transaction does not affect the corporate structure of any
party to the transaction. The Commission proposed that market-based
rate sellers be required to provide, in addition to the already
required written descriptions of their affiliates and corporate
structure or upstream ownership, an organizational chart depicting the
market-based rate seller's current corporate structures (including any
pending authorized but not implemented changes) indicating all upstream
owners, energy subsidiaries and energy affiliates. The Commission
believed that the increased burden on market-based rate sellers would
be minimal as most sellers have this organizational chart available.
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    \429\ We note that the Commission recently issued a NOPR seeking
comment on a proposal to require each RTO and ISO to electronically
deliver to the Commission data from market participants that lists
market participants' ``connected entities,'' including entities that
have certain ownership, employment, debt or contractual
relationships to the market participant, and describes the nature of
such relationships. See Collection of Connected Entity Data from
Regional Transmission Organizations and Independent System
Operators, Docket No. RM15-23-000, 80 FR 58382 (Sept. 29, 2015), 152
FERC ] 61,219 (2015).
    \430\ 16 U.S.C. 824b.
    \431\ See 18 CFR 33.2(c)(3).
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    325. Thus, the Commission proposed to revise the text in section
35.37(a)(2) of the Commission's regulations to add this requirement for
purposes of initial applications and updated market power analyses. The
Commission also proposed that such organizational chart be required for
any notice of change in status involving a change in the ownership
structure that was in place the last time the seller made a market-
based rate filing with the Commission. Therefore, the Commission
proposed to revise the text in section 35.42(c) accordingly.
b. Comments
    326. Many commenters oppose the Commission's proposal to require
sellers to provide an organizational chart, in addition to written
descriptions of their affiliates and corporate structure or upstream
ownership, for initial applications for market-based rate authority,
updated market power analyses, and notices of change in status
reporting new affiliations.\432\ However, APPA/NRECA and Golden Spread
support the proposal.\433\
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    \432\ See, e.g., EPSA at 15-17; E.ON at 14-16; NextEra at 16;
EEI at 19; FirstEnergy at 14-16; NRG Companies at 3-6; AEP at 9.
    \433\ APPA/NRECA at 5; Golden Spread at 7.
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    327. Several commenters submit that this proposal would impose a
burden on sellers disproportionate to any benefit received, requiring
significant investigation into numerous affiliate relationships.\434\
EPSA notes that, even if a market-based rate entity already has an
organizational chart, often those charts are not developed and used for
the purpose of showing control, but rather to demonstrate how finances
flow throughout the various companies.\435\ Consequently, EPSA argues
that the charts would require significant revisions to comply with the
Commission's proposal.\436\
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    \434\ See, e.g., EPSA at 15-17 (noting that not all market-based
rate sellers have these organization charts readily available and
that many sellers have hundreds of affiliates); E.ON at 14-15;
NextEra at 16; EEI at 19; NRG Companies at 3-4; AEP at 9.
    \435\ EPSA at 16.
    \436\ Id.
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    328. EPSA proposes that, if the Commission implements the proposal,
the Commission should limit the entities depicted in the organizational
chart to include only public utilities subject to the Commission's
jurisdiction rather than all affiliates within a seller's corporate
structure.\437\ Other commenters state that the Commission does not
need an organizational chart to evaluate market power concerns and that
an organizational chart does not provide meaningfully different or
material information to the Commission than is currently required.\438\
Specifically, FirstEnergy argues that, because the evaluation of a
market-based rate application treats the seller and its affiliates as a
single entity, the complex internal relationships among affiliated
entities that might be illustrated in an updated organizational chart
are not relevant to the Commission's evaluation of whether an entity
should enjoy market-base rate authority.\439\
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    \437\ Id. at 15-16.
    \438\ See, e.g., E.ON at 15-16; NextEra at 16; EEI at 19;
FirstEnergy at 14-16; NRG Companies at 5.
    \439\ FirstEnergy at 15.
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    329. If the Commission adopts this proposal, some commenters
suggest that the Commission provide further guidance regarding which
affiliated entities should be included in the organizational
chart.\440\ E.ON requests that the Commission clarify the meaning of
``energy affiliate'' and ``energy subsidiary'' and suggests that the
meaning be limited to affiliates and subsidiaries that (1) own or
control electric generation or inputs to electric power production in
the relevant market or balancing authority area; (2) own, operate, or
control electric transmission facilities in the relevant market or
balancing authority area; or (3) have a franchised service territory in
the relevant market or balancing authority area.\441\ EPSA requests
clarification of how the Commission would treat sellers that are part
of joint ventures, whether they would be exempt from the organizational
chart or require particular treatment in the organizational chart.\442\
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    \440\ E.ON at 15; EPSA at 16.
    \441\ E.ON at 15.
    \442\ EPSA at 16.
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    330. Some commenters assert that if the Commission adopts this
proposal, the Commission should allow exemptions for specific
filers.\443\ AEP notes that Order No. 717 eliminated a similar previous
requirement for transmission providers to post an organizational chart
of all affiliates, finding such a requirement to be an ``undue burden
on transmission providers.'' \444\ AEP also suggests that only filings
that impact the organizational structure should require an
organizational chart.\445\ EEI similarly proposes that an
organizational chart should not be required if ``that applicant

demonstrates that the proposed transaction does not affect the
corporate structure of any party to the transaction.'' \446\
FirstEnergy suggests that there should be no need for a seller to
submit an organizational chart (1) if the seller and its affiliates
operate within an RTO with Commission-approved market monitoring and
mitigation procedures and rely on such procedures to address horizontal
market power concerns or (2) if a seller has become affiliated with a
new entity that owns generation or transmission assets and where the
transaction has been approved by the Commission pursuant to its
authority under section 203 of the FPA.\447\
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    \443\ See, e.g., AEP at 19; EEI at 19; FirstEnergy at 15-16.
    \444\ AEP at 9 (citing Standards of Conduct for Transmission
Providers, Order No. 717, FERC Stats. & Regs. ] 31,280, at P 243
(2008)).
    \445\ Id.
    \446\ EEI at 19.
    \447\ FirstEnergy at 15-16 (arguing that the requirement should
be limited to circumstances in which the information may be useful
to its review of an application for market-based rate authority).
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    331. If the Commission adopts the organizational chart proposal,
some commenters suggest that the Commission allow flexibility for
meeting this proposal.\448\ The NRG Companies suggest that the
Commission allow sellers to submit simplified organizational charts
that omit intermediate holding companies, energy subsidiaries and
affiliates not relevant to the analysis in the applicable filings.
\449\ AEP proposes that market-based rate sellers be allowed to provide
a link to an organizational chart on their Web sites or other
accessible location.\450\
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    \448\ NRG Companies at 5; AEP at 10.
    \449\ NRG Companies at 5.
    \450\ AEP at 10.
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c. Commission Determination
    332. We adopt the corporate organizational chart requirement with
modifications and clarifications, as discussed below. We disagree with
commenters' concerns that filing such charts will impose an undue
burden on sellers. The Commission already requires sellers to file
organizational charts for filings under FPA section 203, and, as EPSA
notes, some companies already have organizational charts for other
purposes. Furthermore, as acknowledged by some commenters, the
information that the Commission would require in organizational charts
does not materially differ from what is currently provided in narrative
form in market-based rate filings. Thus, presenting this same
information in a graphic format should not be unduly burdensome.
Similarly, presenting organizational charts in market-based rate
filings, rather than through links to a corporate Web site as proposed
by AEP, should not be unduly burdensome.
    333. However, in response to commenters' concerns, we provide
further guidance regarding the extent to which upstream owners and
affiliates need to be included in the corporate organizational charts.
First, we find that the terms ``energy subsidiaries'' and ``energy
affiliates,'' as used in the FPA section 203 context and as originally
proposed in the NOPR, are not meaningful in the market-based rate
context. Instead, we clarify that instead of ``indicating all upstream
owners, energy subsidiaries, and energy affiliates'' in the
organizational chart, as proposed in the NOPR, filers should indicate
all affiliates, as defined under section 35.36(a)(9) of the
Commission's market-based rate regulations. Second, to minimize burdens
on filers and to simplify the charts, we clarify that if an entity is
owned by multiple individual investors, such investors may be grouped
in the organizational chart as long as they are identified elsewhere in
the filing.
    334. We caution applicants to examine all upstream ownership
information to ensure that all affiliates are captured in the chart.
Applicants should not assume that upstream owners are not affiliates of
the applicant without looking further up the ownership chain. For
example, suppose the applicant (Company A) has four upstream owners
(Companies B, C, D, and E) each of which owns 8 percent of the voting
shares of A. If Company F owns 100 percent of the voting interests in
Companies B, C, D, and E, under the Commission's affiliate definition,
Company F indirectly owns 32 percent of Company A and should be listed
in the chart as an affiliate of Company A. Furthermore, since Companies
A, B, C, D, and E are all under the common control of Company F,
Companies B, C, D, and E also are affiliated with Company A under the
Commission's definition and should be depicted as such in the
organizational chart, even though they own less than 10 percent of the
voting interests in Company A. Further, as the Commission clarified in
Tonopah Solar Energy, LLC, applicants are not permitted to use a
derivative share method to calculate ownership interests in downstream
partially-owned entities for purposes of identifying affiliates.\451\
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    \451\ Tonopah Solar Energy, LLC, 151 FERC ] 61,203, at PP 11-12
(2015).
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    335. Consistent with our clarifications above, we will revise the
regulatory text in Sec.  35.37(a)(2) to clarify that the organizational
chart must include affiliates, without any further reference to
``upstream owners,'' ``energy subsidiaries,'' or ``energy affiliates.''
We will also revise the regulatory text in section 35.42(c) of the
Commission's regulations to require the submission of an organizational
chart that depicts the seller's prior and new affiliations unless the
change in status does not affect the seller's affiliations.
2. Single Corporate Tariff
a. Commission Proposal
    336. In the NOPR, the Commission noted that when a corporate family
has more than one affiliated seller, it may use a joint tariff. The
Commission committed to clarify on its Web site how a corporate family
that chooses to submit a joint master corporate tariff should identify
its designated filer and what each of the other filers should submit
into their respective eTariff databases. This information can be found
on the Commission's Web site at http://www.ferc.gov/industries/electric/gen-info/mbr/tariff/joint.asp.
b. Comments
    337. EEI appreciates the Commission's recognition that allowing
joint filings for corporate families provides economy of effort to
companies.\452\ EEI encourages the Commission to continue working with
companies to enable companies to file joint tariffs within their
corporate families.\453\
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    \452\ EEI at 20.
    \453\ Id.
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c. Commission Determination
    338. There is no opposition to the Commission's NOPR clarification.
We reiterate that when a corporate family has more than one affiliated
seller, it may use a joint master tariff. Filing instructions for
entities wishing to use a joint tariff are available on the
Commission's Web site, as stated above.

G. Part 101 and 141 Waivers

1. Commission Proposal
    339. In the NOPR, the Commission noted that it has granted certain
entities with market-based rate authority, such as power marketers and
independent power producers, waiver of the Commission Uniform System of