Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 33375-33387 [2016-12427]
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Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations
individual is an eligible contract
participant if the individual has
aggregate amounts invested on a
discretionary basis of more than $10
million or more than $5 million if such
individual enters into the transaction to
manage the risk associated with an asset
owned or liability incurred, or
reasonably likely to be owned or
incurred by such individual.7
The Commission adopted Rule
15b12–1 (17 CFR 240.15b12–1) on a
time-limited basis to permit a registered
broker-dealer to engage in a retail forex
business.8 The Commission is taking no
further action, and pursuant to Rule
15b12–1(d), Rule 15b12–1 will expire
and no longer be effective on July 31,
2016. Upon expiration of the rule on
July 31, 2016, a broker-dealer registered
pursuant to Section 15(b) of the
Exchange Act, including an entity that
is registered as both a broker-dealer and
a futures commission merchant, shall be
prohibited from offering or entering into
a retail forex transaction pursuant to
Section 2(c)(2)(E) of the CEA.
By the Commission.
Dated: May 20, 2016.
Brent J. Fields,
Secretary.
33375
The Federal Energy
Regulatory Commission is denying
requests for rehearing and granting, in
part, clarification of its determinations
in Order No. 816, which amended its
regulations that govern market-based
rate authorizations for wholesale sales
of electric energy, capacity, and
ancillary services by public utilities
pursuant to the Federal Power Act.
DATES: This rule will become effective
July 25, 2016.
FOR FURTHER INFORMATION CONTACT:
Greg Basheda (Technical Information),
Office of Energy Market Regulation,
Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502–
6479.
Carol Johnson (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street NE., Washington, DC
20426, (202) 502–8521.
SUPPLEMENTARY INFORMATION:
SUMMARY:
[FR Doc. 2016–12390 Filed 5–25–16; 8:45 am]
BILLING CODE 8011–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM14–14–001; Order No. 816–
A]
Refinements to Policies and
Procedures for Market-Based Rates for
Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by
Public Utilities
Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule; Order on rehearing
and clarification.
AGENCY:
Table of Contents
Paragraph
Nos.
I. Introduction ...........................................................................................................................................................................................
II. Discussion ............................................................................................................................................................................................
A. Sellers with Fully Committed Long-Term Generation Capacity ...............................................................................................
B. Reporting of Long-Term Firm Purchases ....................................................................................................................................
C. Clarification of the Definition or Duration of Long-Term Firm Transmission Reservations ...................................................
D. Notices of Change in Status .........................................................................................................................................................
E. New Affiliation and Behind-the-Meter Generation ....................................................................................................................
F. Corporate Organizational Charts ..................................................................................................................................................
G. Part 101 Waivers ...........................................................................................................................................................................
H. Capacity Ratings ...........................................................................................................................................................................
I. Inputs to Electric Power Production .............................................................................................................................................
J. Transmission/Natural Gas Assets Sheet .......................................................................................................................................
K. Long-Term Firm Power Purchases List .......................................................................................................................................
L. Generation Assets Sheet, Rows [B] and [H] ................................................................................................................................
III. Information Collection Statement ......................................................................................................................................................
IV. Document Availability .......................................................................................................................................................................
V. Effective Date .......................................................................................................................................................................................
Order No. 816–A
(Commission) issued Order No. 816,1
which amended its regulations that
govern market-based rate authorizations
for wholesale sales of electric energy,
capacity, and ancillary services by
public utilities pursuant to the Federal
Order on Rehearing and Clarification
I. Introduction
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1. On October 16, 2015, the Federal
Energy Regulatory Commission
to transactions with major swap participants, swap
dealers, major security-based swap participants,
security-based swap dealers, and commodity pools.
See Exchange Act Release No. 66868 (Apr. 27,
2012), 77 FR 30596 (May 23, 2012).
7 7 U.S.C. 1a(18)(A)(xi).
8 See Exchange Act Release No. 69964 (Jul. 11,
2013), 77 FR 42439 (Jul. 16, 2013). By its terms,
Rule 15b12–1 expires on July 31, 2016. The
Commission previously adopted Rule 15b12–1 as
an interim final temporary rule, and extended it
once on July 11, 2012. See Exchange Act Release
Nos. 64874 (Jul. 13, 2011), 76 FR 41676 (Jul. 15,
2011) and 67405 (Jul. 11, 2012), 77 FR 41671 (Jul.
16, 2012).
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Power Act (FPA). In this order, we
address requests for rehearing and
clarification of Order No. 816.2
2. Nine requests for rehearing and
clarification were filed.3 The requests
for rehearing and clarification concern
1 Refinements to Policies and Procedures for
Market-Based Rates for Wholesale Sales of Electric
Energy, Capacity and Ancillary Services by Public
Utilities, Order No. 816, FERC Stats. & Regs. ¶
31,374 (2015) (Final Rule).
2 Order No. 816 became effective on January 28,
2016. On December 23, 2015, upon consideration of
requests for a stay of the corporate organizational
chart requirement, the Commission issued an order
granting an extension of time such that marketbased rate applicants and sellers would not be
required to comply with the corporate
organizational chart requirement prior to the
issuance of an order on the merits of the requests
for rehearing. Refinements to Policies and
Procedures for Market-Based Rates for Wholesale
Sales of Electric Energy, Capacity and Ancillary
Services by Public Utilities, 153 FERC ¶ 61,337
(2015).
3 The requests for rehearing and clarification were
filed by the following entities: EDF Renewable
Energy, Inc. and E.ON Climate & Renewables North
America LLC (IPP Developers); Edison Electric
Institute (EEI); Electric Power Supply Association
(EPSA); Invenergy Thermal Development LLC and
Invenergy Wind Development LLC (Invenergy);
National Hydropower Association (NHA); NextEra
Energy, Inc. (NextEra); Southern California Edison
Company (SoCal Edison); Southern Company
Services, Inc. (Southern); and Transmission Access
Policy Study Group (TAPS).
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the following topics: Sellers with fully
committed long-term generation
capacity; the reporting of long-term firm
purchases; the definition or duration of
long-term firm transmission
reservations; notices of change in status;
new affiliation and behind-the-meter
generation; corporate organizational
charts; and waiver of Part 101 of the
Commission’s regulations.4
3. In this order, in most respects, we
affirm the Commission’s determinations
made in Order No. 816. However,
regarding some issues, we provide
clarification.
4. Specifically, as discussed further
below, we deny rehearing regarding the
requirement to include the expiration
date of the contract when a seller claims
that its capacity is fully committed. To
the extent that the expiration date is not
known at the time a seller files for
market-based rate authority, we confirm
that a subsequent filing to report the
contract expiration date will be treated
as an informational filing rather than as
an amendment to a pending application.
5. We grant clarification regarding the
requirement for applicants within a
regional transmission organization or
independent system operator (RTO/ISO)
market to report all long-term firm
energy and capacity purchases from
generation capacity located within the
RTO/ISO market if the generation is
designated as a resource with capacity
obligations. We clarify that this
requirement does not apply if the
generation is from a qualifying facility
exempt from section 205 of the FPA. In
addition, we affirm that a market-based
rate seller must list all of its long-term
firm power purchases in its asset
appendix, Appendix B, even if it does
not have market-based rate authority in
its home balancing authority area.
6. We clarify that the Commission did
not intend to change the definition of
long-term firm transmission reservations
in Order No. 816 and clarify that longterm firm transmission reservations are
longer than 28 days.
7. Regarding the Commission’s 100
megawatt (MW) threshold for the
requirement to report new affiliations,
we affirm the determinations made in
Order No. 816 but clarify which markets
would be a seller’s relevant geographic
market for purposes of the 100 MW
threshold reporting requirement. We
also deny a rehearing request to find
that capacity in first-tier markets 5 be
4 18
CFR pt. 101 (2015).
5 We clarify that for purposes of this order, the
term ‘‘first-tier markets’’ includes all first-tier areas,
whether they are a balancing authority area or an
RTO/ISO market.
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included for determining the 100 MW
change in status threshold.
8. We affirm the Commission’s
determination in Order No. 816 that
sellers are not required to include
behind-the-meter generation in the 100
MW change in status threshold, the 500
MW Category 1 seller status threshold,
or to include such generation in the
asset appendices and indicative screens.
9. Additionally, we clarify that a
hydropower licensee that otherwise
sells power only at market-based rates
will not be subject to the full
requirements of the Uniform System of
Accounts as a consequence of filing a
cost-based reactive power tariff with the
Commission, and may satisfy the
requirements in Part 101 of the
Commission’s regulations by complying
with General Instruction 16 of the
Uniform System of Accounts.
10. We also provide clarification
regarding other aspects of the Final
Rule, including revisions to regulatory
text and instructions in the asset
appendix to ensure consistency with the
Commission’s determinations in the
Final Rule.
11. Further, as discussed below, we
grant an additional extension of time
such that market-based rate applicants
and sellers will not be required to
comply with the corporate
organizational chart requirement until
the Commission issues an order at a
later date.
II. Discussion
A. Sellers With Fully Committed LongTerm Generation Capacity
1. Final Rule
12. In Order No. 816, the Commission
clarified that sellers may explain that
their generation capacity in the relevant
geographic market (including first-tier
markets) is fully committed, in lieu of
submitting indicative screens, in order
to satisfy the Commission’s marketbased rate requirements regarding
horizontal market power in instances
where all generation owned or
controlled by a seller and its affiliates in
the relevant balancing authority areas or
markets (including first-tier markets) is
fully committed. The Commission
clarified that to qualify as fully
committed, a seller must commit the
capacity to a non-affiliated buyer so that
none of it is available to the seller or its
affiliates for one year or longer. The
Commission also adopted the proposal
that sellers claiming that all of their
relevant capacity is fully committed
must provide the following information:
the amount of generation capacity that
is fully committed, the names of the
counterparties, the length of the long-
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term contract, the expiration date of the
contract, and a representation that the
contract is for firm sales for one year or
longer.6
13. In response to NextEra’s concern
that at the time a seller files for marketbased rate authority, the expiration date
may be unknown, the Commission
stated that if a contract expiration date
is unknown at the time of the marketbased rate filing, the seller must, within
30 days of the date becoming known,
submit an informational filing, in the
docket in which the seller was granted
market-based rate authorization, to
inform the Commission of the contract
expiration date. In response to another
commenter’s remark that the expiration
date is reported separately in electric
quarterly report (EQR) filings, the
Commission noted that many contracts
reported in EQR filings do not include
expiration dates and determined that it
would require expiration date
information in order to show that
generation capacity is fully committed.7
2. Requests for Rehearing
14. NextEra requests rehearing of the
Commission’s determination concerning
sellers with fully committed long-term
generation capacity, stating that the
Commission erred in requiring a marketbased rate seller to report the expiration
date of a long-term contract to the
Commission within 30 days of the date
being known, rather than simply in an
EQR filing.8 NextEra contends that the
Commission erred by failing to set forth
an explanation of the specific after-thefact need for the contract expiration
date, as the seller is also required to
provide the length of the long-term
contract in order to demonstrate that it
has no uncommitted capacity.9 NextEra
states that if the Commission concludes
that there is an actual need for this
information given that after-the-fact
reporting means that the expiration date
can only be used in an ex post analysis,
the Commission should clarify that it
will permit sellers to provide the
information to the Commission either
through an EQR submission or on an
after-the-fact basis.10 NextEra states that
to the extent that a seller informs the
Commission of the contract expiration
date within 30 days of the date
becoming known, the Commission
should clarify that it will treat such
filings as informational filings rather
6 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 39.
7 Id. P 44.
8 NextEra Rehearing Request at 2.
9 Id. at 12.
10 Id. at 13.
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than as amendments to pending
applications.11
3. Commission Determination
15. The Commission stated in Order
No. 816 that sellers claiming that
capacity is fully committed must
provide, among other things, the length
of the long-term contract and the
expiration date of the contract. The
same information must be provided for
long-term firm sales of affiliated
generation capacity located in the
relevant balancing authority areas or
markets, including first-tier markets.
Including this information in the record
of a seller’s market-based rate filing is
necessary so that a seller’s claims of
fully committed capacity can be verified
as needed.
16. In Order No. 816, the Commission
addressed comments submitted by
NextEra regarding contract expiration
dates. In consideration of NextEra’s
contention that the expiration date may
be unknown at the time a seller files for
market-based rate authority,12 the
Commission determined that, in such
instances, the seller must follow up
with an informational filing to inform
the Commission of the contract
expiration date, within 30 days of the
date becoming known.13
17. In its request for rehearing,
NextEra questions the necessity of
requiring the expiration date given that
sellers are required to provide the length
of the contract. We continue to believe
that the expiration date is an important
piece of information for sellers to
provide. The expiration date provides
the Commission with a specific date as
to when the affected generation capacity
may become uncommitted and the
expiration date allows the Commission
to verify the information previously
provided by the seller for purposes of
the Commission’s ex ante analysis of the
seller’s potential market power. With
regard to NextEra’s argument that the
Commission erred in requiring the
market-based rate seller to report the
expiration date of a contract to the
Commission within 30 days of the date
being known, rather than in an EQR
filing, we note that, as the Commission
stated in Order No. 816, many contracts
reported in EQR filings do not include
expiration dates.14 Finally, consistent
with Order No. 816, we grant NextEra’s
request that the Commission clarify that
filings reporting contract expiration
dates in support of a seller’s claim that
at 14.
12 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 38.
13 Id. P 44.
14 Id.
capacity is fully committed will be
treated as informational filings rather
than as amendments to filings.15
B. Reporting of Long-Term Firm
Purchases
1. Final Rule
18. The Commission adopted the
proposal to report in the indicative
screens long-term firm purchases of
capacity and/or energy that have an
associated long-term firm transmission
reservation. The Commission stated that
requiring applicants under the marketbased rate program to report all of their
long-term firm purchases of energy and/
or capacity, regardless of whether the
applicant has operational control of the
generation capacity supplying the
purchased power, will improve the
accuracy of the indicative screens.16
The Commission stated that long-term
firm power purchase agreements that
are reported in the indicative screens
also should be reported in the asset
appendix, Appendix B, and created a
separate sheet in Appendix B
specifically for applicants to report all
such long-term firm purchases.17
19. The Commission stated that the
requirement that applicants only
include long-term firm power purchase
agreements in their indicative screens if
they have an associated long-term
transmission reservation will not apply
within RTO/ISO markets if that RTO/
ISO does not have long-term firm
transmission reservations or their
equivalent. Instead, applicants in such
RTO/ISO markets will be required to
report all long-term firm energy and/or
capacity purchases from generation
capacity located within the RTO/ISO
market if the generation is designated as
a network resource or as a resource with
capacity obligations.18
2. Requests for Rehearing
20. SoCal Edison and NextEra seek
clarification with regard to the reporting
of long-term firm purchases.
21. SoCal Edison seeks clarification
that the requirement to report all longterm firm energy and/or capacity
purchases from generation capacity
located within the RTO/ISO market if
the generation is designated as a
resource with capacity obligations does
not apply if the generation is a
qualifying facility exempt from section
205 of the FPA. SoCal Edison asserts
that there is no reason why an applicant
that holds a long-term contract with a
qualifying facility exempt from FPA
11 Id.
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section 205 should have to report that
in the appendix and screens, even if the
facility has capacity obligations, when
affiliate-owned exempt qualifying
facilities would be excluded from the
reporting requirement.19
22. NextEra seeks clarification related
to the necessity of reporting long-term
power purchases in the asset appendix,
Appendix B, by entities that do not have
market-based rate authorization in their
balancing authority area and as a result
are not required to submit indicative
screens.20 NextEra states that in Order
No. 816, the Commission stated that
long-term firm power purchase
agreements that are reported in the
indicative screens also should be
reported in the asset appendix. NextEra
states that based on this statement,
NextEra understands that the
Commission will not require the
inclusion of long-term power purchase
agreements if a seller does not have
market-based rate authority in its
balancing authority area, but instead
makes only cost-based sales.21 NextEra
asks the Commission to confirm that the
inclusion of such information is only
required for companies that have
market-based authority in the relevant
geographic market.22
3. Commission Determination
23. We grant SoCal Edison’s requested
clarification. Applicants purchasing
energy and/or capacity from a qualifying
facility that is exempt from section 205
of the FPA under a long-term firm
power purchase agreement do not need
to include such purchases in their
indicative screens or in their asset
appendix. In Order No. 816, the
Commission determined that qualifying
facilities that are exempt from section
205 of the FPA do not need to be
reported in the asset appendix or
indicative screens.23 Therefore, to
ensure consistency in horizontal market
power analyses filed by sellers we
clarify that this exemption applies
equally to long-term firm power
purchases agreements backed by such
resources.
24. We reject NextEra’s requested
clarification. A market-based rate seller
must list all of its generation assets in
its asset appendix even if it does not
have market-based rate authority in its
balancing authority area or, indeed,
even if its generation is fully committed
and it is not submitting any indicative
19 SoCal
Edison Rehearing Request at 2.
Rehearing Request at 2.
21 Id. at 14.
22 Id. at 15.
23 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 255.
20 NextEra
15 Id.
16 Id.
P 130.
P 139.
18 Id. P 145.
17 Id.
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screens. We see no reason to treat longterm firm power purchase agreements
differently than other generation
capacity. In Order No. 816, the
Commission determined that long-term
firm power purchase agreements with
an associated long-term firm
transmission reservation (or that are
capacity resources in RTO/ISO markets)
must be reported in a seller’s indicative
screens and asset appendix. Excluding
long-term firm power purchase
agreements as requested by NextEra
would be inconsistent with that policy.
In addition, sellers without marketbased rate authority in their own
balancing authority area typically seek
market-based rate authority elsewhere
and do so by submitting indicative
screens for their first-tier markets. A
seller’s long-term firm power purchase
agreements are a resource that would
need to be reflected in the screens for
the seller’s first-tier markets. Since these
agreements are reflected in the screens
to the extent that they provide potential
exports from a seller’s balancing
authority area to first-tier markets, they
should be included in the seller’s asset
appendix.
25. We also clarify that the generation
capacity associated with a unit-specific
long-term contract should be reported in
the ‘‘Notes’’ portion of the asset
appendix. An example of this will be
posted on the Commission’s Web site.
C. Clarification of the Definition or
Duration of Long-Term Firm
Transmission Reservations
1. Final Rule
26. In the Final Rule, the Commission
provided clarification on the
preparation of simultaneous
transmission import limit (SIL) studies.
In discussing SIL studies, the
Commission declined a request to
redefine the applicable duration of longterm firm transmission reservations,
stating that it is currently defined as 28
days or longer.24
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2. Requests for Rehearing
27. Southern states that Order No. 816
appears to erroneously refer to longterm firm transmission reservations as
comprising reservations that are 28 days
or longer. Southern maintains that this
is contrary to precedent indicating that
the expectation for entities performing
SIL studies was that only transmission
reservations with a duration longer than
28 days (i.e., a duration of 29 days and
greater) should be considered to be longterm firm reservations.
24 Id.
P 197.
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3. Commission Determination
28. We clarify that the Commission
did not intend to change the definition
of long-term firm transmission
reservations in Order No. 816. We
reaffirm prior Commission guidance
that short-term reservations are up to
one month and long-term reservations
are greater than one month.25 February
is the shortest month, which means that
long-term firm transmission reservations
must be longer than 28 days. Thus, we
clarify that long-term firm transmission
reservations are longer than 28 days.
D. Notices of Change in Status
1. Final Rule
29. In the Notice of Proposed
Rulemaking (NOPR), the Commission
proposed to revise the change in status
regulations at 18 CFR 35.42 to include
a 100 MW threshold for reporting new
affiliations. The Commission stated that
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.26 In the Final Rule,
the Commission adopted the proposed
changes to the change in status
requirements of section 35.42 of the
Commission’s regulations.27
30. In the Final Rule, the Commission
stated that 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.28 The
Commission clarified that the phrase
‘‘any relevant market’’ refers to a market
in which a seller already has generation
located and acquires an additional 100
MW or accumulates 100 MW or more in
a new market that the seller had not
studied previously.29 The Commission
also clarified that the 100 MW threshold
does not include generation capacity
that can be imported from first-tier
markets.30 The Commission agreed with
commenters that generation capacity in
first-tier markets should not be treated
the same as capacity located in the
25 Market-Based Rates for Wholesale Sales of
Electric Energy Capacity and Ancillary Services by
Public Utilities, Order No. 697–B, FERC Stats. &
Regs. ¶ 31,285 at P 25 (2008).
26 Refinements to Policies and Procedures for
Market-Based Rates for Wholesale Sales of Electric
Energy, Capacity and Ancillary Services by Public
Utilities, FERC Stats. & Regs. ¶ 32,702, at P 96
(2014) (NOPR).
27 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 251.
28 Id. P 231.
29 Id. P 237.
30 Id. P 18.
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seller’s relevant geographic market/
study area.31
2. Requests for Rehearing
31. IPP Developers request that the
Commission make the following three
clarifications: (1) If an affiliate of a seller
acquires or controls 100 MW of
generating capacity (including long-term
firm purchases), the seller must submit
a notice of change in status report if that
100 MW is located in the same relevant
market that was studied as the basis for
the seller’s grant of market-based rate
authority; (2) if an affiliate of the seller
acquires or controls 100 MW or more of
generating capacity (including long-term
firm purchases) in a market that is two
tiers away or more, the seller is not
required to submit a notice of change in
status report; and (3) if an affiliate of the
seller acquires or controls 100 MW or
more of generating capacity (including
long-term firm purchases) in a market
that is in the first-tier, the seller is not
required to submit a notice of change in
status report.32 IPP Developers state that
these three clarification requests appear
to be a proper application of the
Commission’s statements in Order No.
816. IPP Developers conclude that a
seller does not have a change in status
reporting obligation in regard to an
affiliate’s generation in first-tier and
beyond areas.33
32. However, IPP Developers state
that the following statement in
paragraph 238 of Order No. 816 makes
this reporting obligation unclear: ‘‘if a
seller’s affiliate is granted market based
rate authority, and that results in 100
MW or more of new generation in a
market, then the seller will have to file
a corresponding change in status.’’ 34
IPP Developers state that ‘‘a market’’
could be any market other than the
seller’s studied relevant market, i.e.,
affiliate generation in first-tier or
beyond markets.35 IPP Developers state
that this statement appears to say that a
seller must file a notice of change in
status report regardless of the market in
which an affiliate of the seller acquires
or controls 100 MW or more of
generating capacity.36
33. IPP Developers state that if the
Commission is not inclined to provide
the clarifications above, then IPP
Developers request rehearing.37
34. TAPS seeks rehearing of the
threshold calculation, arguing that
31 Id.
P 229.
Developers Rehearing Request at 1–3.
32 IPP
33 Id.
34 Id. at 3–4 (citing Order No. 816, FERC Stats. &
Regs. ¶ 31,374 at P 238 (emphasis added)).
35 Id. at 4.
36 Id.
37 Id. at 3.
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capacity in first-tier markets should be
included for determining changes in the
100 MW change in status threshold.38
TAPS states that in the NOPR, the
Commission proposed to clarify that the
‘‘relevant geographic market’’ for
purposes of that 100 MW trigger
included generation capacity that could
be imported from first-tier markets.39
TAPS states that the Commission then
reversed the NOPR proposal, stating that
it would ‘‘exclude markets and
balancing authority areas that are firsttier to the seller’s study area.’’ 40 TAPS
states that the Commission erred and
should grant rehearing to revise Order
No. 816 to include generation in firsttier markets for purposes of change in
status reporting, whether or not it is
supported by a long-term firm
transmission reservation.41 Specifically,
TAPS states that the Commission
should require sellers to: (1) Include
first-tier capacity when there is a longterm transmission reservation associated
with the capacity; and (2) include all
other first-tier capacity either in its
entirety or, in the alternative, on a pro
rata basis consistent with the inclusion
of such generation in market power
screens.42
35. TAPS states that the NOPR’s
proposal to include first-tier generation
capacity is both simple and adequate.43
TAPS states that the Commission could
allow sellers, with appropriate support,
to prorate generation in markets first-tier
to the study area in the same way
capacity is assigned pro rata for
indicative screen analyses (assuming
there are no firm transmission
reservations associated with the first-tier
capacity, in which case it should be
accorded its full megawatt value). TAPS
states that this approach would be
consistent with the methodology used
in the indicative screens, but would
require more analysis than reporting of
all first-tier capacity for purposes of
change in status reports.44
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3. Commission Determination
36. We grant clarification regarding
IPP Developers’ three examples of the
application of Order No. 816. The
scenarios presented by IPP Developers
are a proper application of the Final
Rule, assuming that the seller is not a
power marketer (i.e., the seller owns
generation). We also grant clarification
38 TAPS
Rehearing Request at 1.
at 4 (citing NOPR, FERC Stats. & Regs. ¶
32,702 at P 96).
40 Id. at 5 (citing Order No. 816, FERC Stats. &
Regs. ¶ 31,374 at P 230).
41 Id. at 6.
42 Id. at 5.
43 Id. at 6–7.
44 Id. at 7.
39 Id.
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regarding the Commission’s statement
in paragraph 238 of Order No. 816. In
paragraph 238 of Order No. 816, the
Commission stated that ‘‘if a seller’s
affiliate is granted market-based rate
authority, and that results in 100 MW or
more of new generation in a market,
then the seller will have to file a
corresponding change in status.’’ 45 We
clarify that the phrase ‘‘in a market’’
means any relevant geographic market
for the seller at the time of the change
in status filing. Further, we note that the
relevant geographic market for a
particular seller depends on whether the
seller is a power producer or a power
marketer, whether the seller owns
transmission or is interconnected to an
affiliated transmission system, and
whether the seller’s generation is in an
RTO/ISO. The relevant markets for a
power marketer include any market
where the power marketer’s affiliates
own generation. Thus, a power marketer
that does not own any generation itself
would need to report a change in status
for a 100 MW net increase in any market
where an affiliate owns generation and
has been granted market-based rate
authority.46 However, for a power
producer, the relevant geographic
market is where the seller’s generation
is physically located. Thus, a power
producer would not need to report a 100
MW affiliate net increase in a market
where the power producer itself does
not own any generation. Similarly, in
traditional (non-RTO/ISO) markets, the
default relevant geographic market is
‘‘first, the balancing authority area
where the seller is physically located,
and second, the markets directly
interconnected to the seller’s balancing
authority area.’’ 47 However, ‘‘[w]here a
generator is interconnecting to a nonaffiliate owned or controlled
transmission system, there is one
relevant geographic market (i.e., the
balancing authority area in which the
generator is located).’’ 48 For a seller
45 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 238 (emphasis added).
46 A power marketer with no affiliated generation
is a Category 1 seller (exempt from filing triennial
updated market power analysis) in all regions and
has no relevant geographic market. A power
marketer that acquires generation via a long-term
power purchase agreement has a relevant
geographic market where the power associated with
this agreement is delivered (sinks), not where it
originates (unless source and sink are in the same
market, which is often the case). In this scenario,
the power marketer is a Category 1 or 2 seller in
the relevant geographic market depending on the
MWs associated with the contract(s). Category 2
sellers must submit triennial update market power
analyses.
47 Market-Based Rates for Wholesale Sales of
Electric Energy Capacity and Ancillary Services by
Public Utilities, Order No. 697, FERC Stats. & Regs.
¶ 31,252 at P 232 (2007).
48 Id. P 232 n.217.
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33379
located in an RTO/ISO market, the seller
may consider the RTO/ISO as the
default relevant geographic market.49 In
each circumstance, the market-based
rate seller will have to determine
whether any 100 MW increase is in a
market that would be a relevant
geographic market for that seller.
37. We deny TAPS’s request that
capacity in first-tier markets be included
for determining the 100 MW change in
status threshold. As the Commission
stated in Order No. 816, when a seller
has a change in status in a particular
market, it does not need to include any
changes in adjoining first-tier markets in
calculating the 100 MW threshold, even
when a purchaser has long-term firm
transmission rights to import affiliated
capacity located in a first-tier market.
We reiterate that, with respect to the
calculation of the 100 MW threshold,
100 MW located outside of the study
area is not equivalent to 100 MW inside
the study area. In addition, requiring
sellers to consider generation capacity
in first-tier markets, and prorate
generation from the first-tier markets
into the study area, creates uncertainty
as to when a seller would trip the 100
MW threshold and effectively would
force a seller to prepare import analyses
to determine how much of their
additional first-tier capacity could be
imported into the study area. We believe
that the increased burden of preparing
such studies would outweigh the
potential benefit gained from receiving
additional information about a seller’s
affiliated generation.
E. New Affiliation and Behind-the-Meter
Generation
1. Final Rule
38. As stated above, the Commission
adopted the NOPR proposal to establish
a 100 MW threshold for reporting new
affiliations in change of status filings.
The Commission stated that a marketbased 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.50 The
49 Id. P 235 (noting that a seller may consider the
RTO/ISO as the default relevant geographic market
‘‘unless the Commission has already found the
existence of a submarket’’).
50 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 251. The Commission noted that 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. Id. P
251 n.334.
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Commission stated that the 100 MW
threshold will be determined for each
relevant geographic market but will not
consider generation capacity additions
in first-tier markets.51
39. The Commission did not adopt the
NOPR proposal to count behind-themeter generation in the 100 MW change
in status threshold and 500 MW
Category 1 seller threshold or to include
such generation in the asset appendix
and indicative screens.52
40. The Commission stated that the
output of behind-the-meter generation
should be reflected in the load data
reported in the FERC Form No. 714,
which 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. The
Commission also stated that, 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. The Commission
clarified 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.53
2. Requests for Rehearing
41. TAPS requests rehearing and/or
clarification, arguing that behind-themeter generation that is available to
make wholesale sales and that is not
reflected as a reduction in load reported
in Form No. 714 should be included in
seller reporting obligations, including
the 100 MW change in status threshold,
the indicative screens, the asset
appendix, and the 500 MW Category 1
seller status threshold.
42. Specifically, TAPS states that the
Commission should make clear that
behind-the-meter generation that is not
consumed on-site by the host load and
reflected in Form No. 714 load data
must, consistent with the Commission’s
duty to assess market power, be
included in seller reporting obligations
and indicative screens and category
seller status determinations. TAPS
contends that generation that
participates in the wholesale markets
influences a seller’s market power
regardless of whether it may be termed
behind-the-meter.54 TAPS argues that
even if it were otherwise permissible,
the exclusion for behind-the-meter
51 Id.
P 251.
P 252.
53 Id. P 253.
54 TAPS Rehearing Request at 11.
generation would be arbitrary and
capricious. TAPS states that because
Order No. 816 fails to limit the scope of
the behind-the-meter exclusion to that
included in load reported in Form No.
714 or not synchronized to the grid and
provides no definition of behind-themeter generation, sellers are left to their
own devices to determine what is meant
by behind-the-meter generation and
then to exclude those resources for
purposes of reporting under Order No.
816.55
43. TAPS states that the Commission
should clarify that its exclusion of
behind-the-meter generation was
intended to be restricted by its
clarification at paragraph 253 of the
Final Rule—that only generation that is
reflected in Form No. 714 or not
synchronized would be excludable from
generation from market-based rate
reporting and market power screens.
Alternatively, TAPS states that the
Commission should grant rehearing and:
(1) Adopt its NOPR proposal to include
behind-the-meter generation, with El
Paso’s clarification—i.e., that behindthe-meter generation that is not reflected
as a decrease in load on Form No. 714
should be included in seller reporting
obligations and all market power
screens; or (2) otherwise avoid creating
a behind-the-meter generation blind
spot of undefined proportions in its
market power monitoring and
assessment regimen.56
3. Commission Determination
44. We deny TAPS’s request for
rehearing. As the Commission stated in
the Final Rule, the output of behind-themeter generation largely should be
reflected in the load data reported in the
FERC Form No. 714, which reflects the
fact that the load is lower than it
otherwise would be if a portion of the
load were not served by behind-themeter generation. Accordingly, 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 some
sellers’ generation capacity. Further, the
Commission stated in the Final Rule
that behind-the-meter generation not
sold into the wholesale market is not
relevant to the Commission’s horizontal
market power analysis. Regarding
TAPS’s concern about behind-the-meter
generation that is available to make
wholesale sales and is not reflected in
load reported in Form No. 714, we
believe, at this time, that this category
of generation is relatively limited and
52 Id.
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56 Id.
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that the burden of sellers reporting this
behind-the-meter generation would
outweigh the benefits of such reporting.
Therefore, at this time, we will not
require sellers to report this type of
generation.
F. Corporate Organizational Charts
1. Final Rule
45. In the Final Rule, the Commission
adopted the proposal to require a seller
to include a corporate organizational
chart when filing an initial application
for market-based rate authority, an
updated market power analysis, or, in
some circumstances, a notice of change
in status reporting new affiliations.57
The Commission revised the regulatory
text in section 35.37(a)(2) and in section
35.42(c) in this regard.
2. Requests for Rehearing
46. Invenergy, SoCal Edison, NextEra,
EEI, and EPSA request rehearing and/or
clarification with respect to the
requirement to submit corporate
organizational charts. Parties argue,
among other things, that the
requirement imposes a substantial
administrative burden on filers and is at
odds with the objective of streamlining
the market-based rate filing process.
3. Commission Determination
47. As noted above, upon
consideration of requests for a stay of
the corporate organizational chart
requirement, the Commission issued an
order granting an extension of time such
that market-based rate applicants and
sellers would not be required to comply
with the corporate organizational chart
requirement prior to the issuance of an
order on the merits of the requests for
rehearing.58 Upon consideration of the
concerns raised by the parties on
rehearing regarding this requirement,
we grant an additional extension of time
such that market-based rate applicants
and sellers will not be required to
comply with the corporate
organizational chart requirement until
the Commission issues an order at a
later date addressing this requirement.
The extension will allow the
Commission more time to fully consider
the benefits and burdens associated
with the corporate organizational chart
requirement.59
57 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 21.
58 Refinements to Policies and Procedures for
Market-Based Rates for Wholesale Sales of Electric
Energy, Capacity and Ancillary Services by Public
Utilities, 153 FERC ¶ 61,337 (2015).
59 The Commission continues to consider
appropriate mechanisms for consolidating the
Commission’s data collection requirements,
including this organizational chart requirement,
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G. Part 101
a market-based rate tariff have been
previously granted waiver of Part 101.65
Waivers
1. Final Rule
48. The Commission clarified that
granting waiver of 18 CFR part 101
under market-based rate authority does
not waive the requirements under Part
I of the FPA for hydropower licensees.
In addition, the Commission clarified
that hydropower licensees that only
make sales at market-based rates may
satisfy the requirements in Part 101 of
the Commission’s regulations (Uniform
System of Accounts) by complying with
General Instruction 16 of the Uniform
System of Accounts, and confirmed that
hydropower licensees that have
Commission-approved cost-based rates
are required to comply with the full
requirements of the Uniform System of
Accounts.60
2. Requests for Rehearing
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49. NHA requests clarification that a
hydropower licensee that otherwise
sells power only at market-based rates
will not be subject to the full
requirements of the Uniform System of
Accounts as a consequence of filing a
cost-based reactive power tariff with the
Commission.61 Alternatively, NHA
requests that the Commission clarify
that it will allow licensees that
otherwise sell only at market-based rates
to request authorization, on a case-bycase basis, to continue to rely on
General Instruction 16 of the Uniform
System of Accounts at the time a
reactive power tariff is filed with the
Commission.62
50. NHA argues that the Commission
determined in Order No. 697 that ‘‘little
purpose would be served to require
compliance with accounting regulations
for entities that do not sell at cost-based
rates and do not have captive
customers.’’ 63 NHA represents that the
Commission has previously found that
reactive power tariffs do not have
captive customers and do not raise the
same concerns as other cost-based rate
tariffs.64 Additionally NHA notes that
entities with a reactive power tariff and
with the proposed rulemakings in Docket Nos.
RM15–23 and RM16–3.
60 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 22.
61 NHA Clarification Request at 3–5.
62 Id. at 5.
63 Id. at 3 (citing Order No. 697, FERC Stats. &
Regs. ¶ 31,252 at P 984).
64 Id. at 3–4 (citing Order No. 697, FERC Stats. &
Regs. ¶ 31,252 at P 483 (‘‘concerns underlying the
affiliate restrictions do not apply to sales of reactive
power because those sales are typically either made
to transmission providers so that the transmission
provider can satisfy its obligation to provide
reactive power or made by the transmission
provider under its applicable [open access
transmission tariff]’’)).
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3. Commission Determination
51. We clarify that a hydropower
licensee that otherwise sells power only
at market-based rates will not be subject
to the full requirements of the Uniform
System of Accounts as a consequence of
filing a cost-based reactive power tariff
with the Commission. Such a seller may
satisfy the requirements in Part 101 of
the Commission’s regulations by
complying with General Instruction 16
of the Uniform System of Accounts. We
find that this clarification is consistent
with previous Commission findings in
Order No. 697 and Sunbury, as noted by
NHA. We continue to find, however,
that hydropower licensees that have
Commission-approved cost-based rates
are required to comply with the full
requirements of the Uniform System of
Accounts.66 Additionally, we remind
sellers that ‘‘previously granted waivers
of the accounting requirements will
continue to be rescinded where a seller
is found to have market power (or where
the sellers accepts a presumption of
market power) and the seller proposes
cost-based rate mitigation or the
Commission imposes cost-based rate
mitigation.’’ 67
H. Capacity Ratings
52. In the Final Rule, the Commission
revised the regulations at 18 CFR 35.42
relating to the change in status reporting
requirements to 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.68 The
Commission found that solar
photovoltaic and solar thermal facilities
are energy limited and determined that,
due to their unique characteristics, solar
photovoltaic facilities, unlike other
energy-limited facilities, must use
nameplate capacity and may not use
five-year average capacity factors.69
65 Id. (citing Sunbury Generation, LLC, 108 FERC
¶ 61,160 (2004) (Sunbury); Illinois Power
Generating Co., 148 FERC ¶ 61,238 (2014) (granting
waivers of Parts 41, 101, and 141 of the
Commission’s regulations to entities with a costbased rate reactive power tariff and a market-based
rate tariff)).
66 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 22.
67 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 986.
68 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 232.
69 Id. P 15.
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2. Request for Rehearing
53. Southern notes the Commission’s
determination in the Final Rule
permitted sellers to use nameplate or
seasonal capacity ratings for the 100
MW threshold for most generation.
Southern states that the regulatory text
accompanying the Final Rule includes
the phrase ‘‘or seasonal’’ in 18 CFR
35.42(a)(2)(i) but not in 18 CFR
35.42(a)(1). Southern requests that the
Commission add the phrase ‘‘or
seasonal’’ to 18 CFR 35.42(a)(1) to align
with the discussion in the Final Rule.70
3. Commission Determination
54. We find that it is appropriate to
revise 18 CFR 35.42(a)(1) to add the
phrase ‘‘or seasonal.’’ Additionally, we
are revising both 18 CFR 35.42(a)(1) and
(a)(2)(i) to further align the regulations
with the discussion in the Final Rule.
Specifically, the revised regulations will
indicate that the 100 MW or more of
capacity should be based on nameplate
or seasonal capacity ratings and, for
energy-limited resources, with the
exception of solar photovoltaic
facilities, the capacity ratings should be
based on nameplate or five-year average
capacity factors. These revised
regulations will indicate that for solar
photovoltaic facilities, the capacity
ratings should be based on nameplate
capacity.
I. Inputs to Electric Power Production
1. Final Rule
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1. Final Rule
55. The Commission considers a
seller’s ability to erect other barriers to
entry as part of the vertical market
power analysis and, as such, the
Commission requires a seller to provide
a description of its inputs to electric
power production.71 Section 35.36(a)(4)
of the Commission’s regulations define
inputs to electric power production to
mean intrastate natural gas
transportation, intrastate natural gas
storage or distribution facilities, sites for
generation capacity development,
physical coal supply sources and
ownership of or control over who may
access transportation of coal supplies.
56. In the Final Rule, the Commission
eliminated the requirement that marketbased rate sellers file quarterly land
acquisition reports and provide
information on sites for generation
capacity development in market-based
rate applications and triennial updated
market power analyses. Specifically, the
Commission adopted the proposal to
70 Southern Rehearing Request at 7 n.15 (citing
Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P
232).
71 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 6.
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revise the regulations at 18 CFR 35.42
relating to the change in status reporting
requirements regarding sites for new
generation capacity development and
also adopted the proposal to revise the
regulations at 18 CFR 35.37 to remove
the requirement that sellers provide
information regarding sites for
generation capacity development to
demonstrate a lack of vertical market
power. However, no changes to the
definition of inputs to electric power
production were made in the Final Rule.
2. Commission Determination
57. In light the determinations made
in the Final Rule, we revise our
regulations at 18 CFR 35.36(a)(4) to
remove sites for generation capacity
development from the definition of
inputs to electric power production.
However, we clarify that the affirmative
statement regarding barriers to entry
required in 18 CFR 35.37(e)(3) continues
to cover sites for generation capacity
development.
J. Transmission/Natural Gas Assets
Sheet
1. Final Rule
58. In the NOPR, the Commission
proposed to require any seller that has
been granted waiver of the requirement
to file an open access transmission tariff
(OATT) for its transmission facilities to
report in its Transmission/Natural Gas
Assets Sheet the citation to the
Commission order granting the OATT
waiver for those transmission
facilities.72 The Commission did not
adopt the NOPR proposal in the Final
Rule, agreeing with SoCal Edison that
this requirement would not provide
useful information in light of Order No.
807.73 The Commission further 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.’’ 74
72 NOPR,
FERC Stats. & Regs. ¶ 32,702 at P 120.
No. 816, FERC Stats. & Regs. ¶ 31,374 at
P 300 (citing 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)).
74 Id. P 295 (citing Order No. 697–A, FERC Stats.
& Regs. ¶ 31,268 at P 378 (‘‘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).’’)).
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73 Order
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2. Commission Determination
59. Upon further consideration, we
modify the requirement to report in the
asset appendix transmission facilities
that have been granted an individual
OATT waiver or that qualify for a
blanket waiver under Order No. 807 and
find that sellers are no longer required
to include such facilities in their
Transmission/Natural Gas Assets Sheet.
We find that the burden of providing
information on such facilities outweighs
any benefit to reporting it. For this
reason, we eliminate the requirement to
report in the Transmission/Natural Gas
Assets Sheet facilities that qualify for
blanket waiver of the OATT
requirement under Order No. 807 and
those that have been granted an
individual OATT waiver.
Long-Term Firm PPAs Sheet have been
modified to reflect these changes and to
make certain other clean up edits.
K. Long-Term Firm Power Purchases List
2. Commission Determination
1. Final Rule
60. In the Final Rule, the Commission
established a new, separate list in the
asset appendix in which market-based
rate sellers are to report their Long-Term
Firm Power Purchase Agreements
(PPAs).75 The Commission agreed with
commenters that the format of the
Generation Assets Sheet was not well
suited for reporting long-term firm
purchases.
63. We revise the instructions for Row
[B] of the asset appendix to remove
references to EL and QF dockets. This
revision does not change the
Commission’s determinations in Order
No. 816. Rather, this revision aligns the
description and format information
regarding Row [B] with the
Commission’s intent that Row [B]
contain the docket number where
market-based rate authority was granted.
64. We revise the instructions to Row
[H] of the Generation Assets Sheet to
delete the second reference to
‘‘Southeast’’ and replace it with
‘‘Northwest.’’
2. Commission Determination
61. Subsequent to the issuance of
Order No. 816, Commission Staff
received numerous calls from sellers
requesting guidance with respect to
completing the Long-Term Firm PPAs
Sheet. Upon further consideration, we
recognize that certain modifications to
this sheet and its instructions are
warranted to improve its clarity. To that
end, we are making the following
changes. First, we are eliminating the
existing column B, ‘‘Docket # where
MBR authority was granted’’ as this is
duplicative of information required
elsewhere in the asset appendix. In
response to questions as to whether the
‘‘Market/Balancing Authority Area’’
column was referring to the source or
sink of the transaction, we are adding a
column and specifically requesting
sellers to identify both the source and
sink of the transaction in separate
designated columns. Finally, in
response to other questions raised by
market-based rate filers, we are adding
a column requiring sellers to indicate
whether a particular long-term firm
purchase agreement is backed by a
specific identified generation unit or by
the supplier’s generation fleet (i.e., a
‘‘system’’ contract). Instructions for the
75 Id.
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L. Generation Assets Sheet, Rows [B]
and [H]
1. Final Rule
62. The Final Rule contained
instructions for completing the asset
appendix. The description of Row [B]
indicated that, if applicable, sellers
should include the docket number
where market-based rate or qualifying
facility status was originally granted,
and that it can be an EL or QF docket
number. The description of Row [H]
listed the six market-based rate regions
but mistakenly listed the Southeast
region twice and failed to mention the
Northwest region.
III. Information Collection Statement
65. The Office of Management and
Budget (OMB) regulations implementing
the Paperwork Reduction Act of 1995 76
require that OMB approve certain
information collection requirements
imposed by an agency.77 Upon approval
of a collection(s) of information, OMB
will assign an OMB control number and
an expiration date. Respondents subject
to the filing requirements of a rule will
not be penalized for failing to respond
to these collections of information
unless the collections of information
display a valid OMB control number.
66. The revisions made in Order No.
816 to the information collection
requirements for market-based rate
sellers were approved under FERC–919
(OMB Control No. 1902–0234).78 This
order clarifies and makes minor
revisions to some aspects of the existing
information collection requirements for
the market-based rate program. The
76 44
U.S.C. 3507(d) (2012).
CFR 1320.11.
78 OMB approved the information collection in
Order No. 816 on December 22, 2015.
77 5
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Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations
changes to the information collection
include:
• Removing the need to list
transmission facilities in the
Transmission/Natural Gas Assets Sheet
that have an OATT waiver or that
qualify for the blanket OATT waiver (a
slight burden decrease)
• adding a source/sink column and a
column for generation unit/system
contract type to the Long-Term Firm
PPAs Sheet (slight burden increases)
• removing column B, ‘‘Docket #
where MBR authority was granted’’ from
the Long-Term Firm PPAs Sheet and
removing references to ‘‘EL’’ and ‘‘QF’’
in the instructions for Row [B] of the
Generation Assets Sheet (de minimis
decreases)
• removing sites for generation
capacity development from the
definition of inputs to electric power
production at 18 CFR 35.36(a)(4) (no
change to burden).
The Commission estimates that there
will be no net change to burden. This
Final Rule will be submitted to OMB for
review and approval of a ‘‘No Material/
Nonsubstantive Change.’’
Title: Market Based Rates for
Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by
Public Utilities (FERC–919).
Action: Clarification and Revision of
Currently Approved Collection of
Information.
OMB Control No.: 1902–0234.
Respondents for This Rulemaking:
Public utilities, wholesale electricity
sellers, businesses, or other for profit
and/or not for profit institutions.
67. Interested persons may obtain
information on the reporting
requirements by contacting: Federal
Energy Regulatory Commission, 888
First Street NE., Washington, DC 20426
[Attention: Ellen Brown, Office of the
Executive Director, email:
DataClearance@ferc.gov, phone: (202)
502–8663, fax: (202) 273–0873].
Comments concerning the requirements
of this rule may also be sent to the
Office of Information and Regulatory
Affairs, Office of Management and
Budget, Washington, DC 20503
[Attention: Desk Officer for the Federal
Energy Regulatory Commission]. For
security reasons, comments should be
sent by email to OMB at oira_
submission@omb.eop.gov. Comments
VerDate Sep<11>2014
17:45 May 25, 2016
Jkt 238001
submitted to OMB should refer to
FERC–919 and OMB Control Number
1902–0234.
IV. Document Availability
V. Effective Date
71. These regulations are effective
July 25, 2016.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities,
Reporting and recordkeeping
requirements.
By the Commission.
Issued: May 19, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the
Commission amends Part 35, Chapter I,
Title 18, Code of Federal Regulations, as
follows:
PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
1. The authority citation for part 35
continues to read as follows:
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Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
§ 35.36
[Amended]
2. Amend § 35.36 as follows:
a. In paragraph (a)(4), remove the
comma and add in its place a
semicolon.
■ b. In paragraph (a)(4), remove the
phrase ‘‘sites for generation capacity
development;’’.
■
68. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the Internet through
FERC’s Home Page (https://
www.ferc.gov) and in FERC’s Public
Reference Room during normal business
hours (8:30 a.m. to 5:00 p.m. Eastern
time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
69. From FERC’s Home Page on the
Internet, this information is available on
eLibrary. The full text of this document
is available on eLibrary in PDF and
Microsoft Word format for viewing,
printing, and/or downloading. To access
this document in eLibrary, type the
docket number excluding the last three
digits of this document in the docket
number field.
70. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from FERC
Online Support at 202–502–6652 (toll
free at 1–866–208–3676) or email at
ferconlinesupport@ferc.gov, or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. Email the
Public Reference Room at
public.referenceroom@ferc.gov.
■
33383
■
3. Amend § 35.42 by revising
paragraphs (a)(1) and (a)(2)(i) to read as
follows:
■
§ 35.42 Change in status reporting
requirement.
(a) * * *
(1) Ownership or control of generation
capacity or long-term firm purchases of
capacity and/or energy that results in
cumulative net increases (i.e., the
difference between increases and
decreases in affiliated generation
capacity) of 100 MW or more of capacity
based on nameplate or seasonal capacity
ratings, or, for solar photovoltaic
facilities, nameplate capacity, or, for
other energy-limited resources,
nameplate or five-year average capacity
factors, in any individual relevant
geographic market, or of inputs to
electric power production, or
ownership, operation or control of
transmission facilities; or
(2) * * *
(i) Owns or controls generation
facilities or has long-term firm
purchases of capacity and/or energy that
results in cumulative net increases (i.e.,
the difference between increases and
decreases in affiliated generation
capacity) of 100 MW or more of capacity
based on nameplate or seasonal capacity
ratings, or, for solar photovoltaic
facilities, nameplate capacity, or, for
other energy-limited resources,
nameplate or five-year average capacity
factors, in any individual relevant
geographic market;
*
*
*
*
*
4. Revise appendix B to subpart H to
read as follows:
■
Appendix B to Subpart H of Part 35—
Corporate Entities and Assets Sample
Appendix
BILLING CODE 6717–0–P
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Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations
Format
[C]
Generation Name (Plant or Unit Name)
Unit Name or if all units in a plant are reasonably similar, a plant
name. Use EIA-860 or industry standard names to the extent
Free Form Text
possible.
Name of the Entity owning the generation unit or plant. Please use
[D]
Owned By
Free Form Text
[E]
Controlled By
Free Form Text
[F]
Date Control Transferred
MM/YYYY or DD/MM/YY
the same name as in the Company Registration database if possible.
Name of the Entity that controls the output of the generation unit or
plant. Please use the same name as in the Company Registration
database if possible.
The date the unit came under the control of the Entity listed in "[E]
Controlled By." Often it is the date the generation was acquired or
built.
Free Form Text. For Markets or
Location:
heir designated submarkets (PJM-East, 5004/5005, AP South,
onnecticut, Southwest Connecticut, New York City, Long Island) or a
ERC-defined Balancing Authority Area name.
One of the six MBR regions: Northeast, Southeast, Central, SPP,
Specific Text
MM/YYYY or MM/DD/YY
[J]
Numeric. Either an integer or fixed width
The nameplate capacity rating of the unit, usually provided by the
numeric with one decimal
Capacity Rating: Nameplate (MW)
Northwest, Southwest.
The date the unit first came into service.
manufacturer, in MWs.
Numeric. Either an integer or fixed width
numeric with one decimal
I I
Capacity Rating: Used in Filing (MW)
[L]
Capacity Rating: Methodology Used in
[K]: (N)ameplate, (S)easonal, 5-yr
single capital letter (either "N", "S", "U", "E", or "A") to designate the
ating methodology of the unit's capacity used in this filing. Describe
'Alternative" Capacity Rating Method in End Notes Sheet.
(U)nit, 5-yr (E) lA, (A)Iternative
End Note Number (Enter text in End
sradovich on DSK3TPTVN1PROD with RULES
Notes Sheet)
VerDate Sep<11>2014
17:45 May 25, 2016
he capacity rating of the unit(s), in MWs, used in this filing.
he number of the explanatory note in End Notes Sheet that refers to
is entry. The numbers should be ascending integers throughout the
ppendix. If there are three notes in the Generation Assets Sheet,
Integer
en the first end note in the next asset sheet should be four (please
not start over with a new numbering sequence).
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[G]
ne of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or
submarkets please use one of the
abbreviations or names in the next
column. For balancing authority areas
Location:
Market/Balancing Authority Area
Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations
33385
Instructions for completing the Asset Appendix Sheet: Long-Term Firm Power Purchase Agreements {PPA)
Title
Format
Description
[ I
Filing Entity and its Energy Affiliates
[ I
Seller Name
Name of the Filing Entity or affiliate of the Filing Entity that is
purchasing the energy or capacity.
Free Form Text
Free Form Text
Name of the Filing Entity that is selling the capacity and/or energy.
Please use the exact name as in the Company Registration database if
possible.
Contracted amount of the PPA in MW. If the contract is for the entire
output of a specific generation unit, you may de-rate the unit using
Numeric. Either an integer or fixed width
[C]
Amount of PPA (MW)
numeric with one decimal
the same de-rating methodology that is used for generators of the
same technology elsewhere in the appendix. If this amount is derated please explain in the End Notes Sheet. Energy-only contracts
must be converted from MWh to MW. Only report contracts one year
or longer.
Free Form Text. For Markets or
submarkets please use one of the
Location:
[D]
[E]
Market/Balancing Authority Area
(Source)
abbreviations or names in the next
column. For balancing authority areas
please use the NERC-defined name
One of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or
their designated submarkets (PJM-East, 5004/5005, AP South,
Connecticut, Southwest Connecticut, New York City, Long Island) or a
NERC-defined Balancing Authority Area name. For "System" PPAs,
identify all markets and balancing authority areas from which the PPA
is sourced to the extent the source location(s) is specified in the PPA.
Free Form Text. For Markets or
submarkets please use one of the
Location:
Market/Balancing Authority Area (Sink)
One of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or
their designated submarkets (PJM-East, 5004/5005, AP South,
abbreviations or names in the next
Connecticut, Southwest Connecticut, New York City, Long Island) or a
NERC-defined Balancing Authority Area name. For all PPAs, identify
where the capacity and/or ener is delivered.
column. For balancing authority areas
please use the NERC-defined name
Specific Text
MM/DD/YY
MM/DD/YY
[I]
[J]
Enter the text "Unit" if the PPA is from a specific unit such as a wind
generator selling its output to a utility, or from multiple units at a
single plant. Please provide the name of the unit or facility supplying
"Unit" or "System"
Type of PPA (Unit or System)
End Note Number (Enter text in End
the PPA in the End Notes Sheet. Enter "System" if the PPA is sourced
from a utility's or IPP's fleet with different units providing power at
different times.
Same instruction as the Generation Assets Sheet.
Integer
Notes Sheet)
Instructions for completing the Asset Appendix Sheet: Transmission/Natural Gas Assets
Title
Format
Description
Same instruction as the Generation Assets Sheet.
Filing Entity and its Energy Affiliates
Cite to order accepting OATI or the
Commission cite to the order accepting the Filing Entity's or its Energy
Affiliate's current OATI, or the order transferring control of the
order approving the transfer of
:::trc:a:c:n:::sm=is=sc:io:cn~f=a=c:c:ilc:it:c:ie:::sc:t=oc:a:cnc:R~Tc:O~o~r:::ISc::0""-1----------------~ transmission facilities to an RTO/ISO.;;;;p;t;;;~;t\h;tyjp;~t;jiityj
Free Form Text
Controlled By
Name of the Entity that controls the transmission/natural gas assets.
Date Control Transferred
uthority Area
Market/Balancin
Same instruction as the Generation Assets Sheet.
Same instruction as the Generation Assets Sheet.
Size (e.g., length and kV for electric,
Description of the size of the facility in the measures relevant to the
specific type of facility. For example, for electric "Size" refers to the
t.
length and diameter for pipelines, and
Free Form Text
length and kV rating of the transmission line; for gas pipeline "Size"
capacity for gas storage)
sradovich on DSK3TPTVN1PROD with RULES
[J]
VerDate Sep<11>2014
refers to the length and diameter of the pipeline; for gas storage
"Size" refers to the capacity of the facility.
End Note Number (Enter text in End
Notes Sheet)
17:45 May 25, 2016
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Same instruction as the Generation Assets Sheet.
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[I]
33386
Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations
Fc:J
Title
Format
End Note Number
[A]
Description
Should match an End Note number in the Generation Assets, Long-
Integer
Term Firm PPAs or Transmission/Natural Gas Assets Sheets.
Sheet (Generation Assets, Long-Term
[B]
The words 11 Generation 11 1 11 PPA 11 1 or
.. Transmission/Natural Gas ..
Firm PPAs or Transmission/Natural Gas
Assets)
Indicates in which asset sheet the End Note is located.
Free Form Text
[B]
[C]
[D]
[E]
[F]
[G]
[H]
[I]
[I]
[K]
ln-SeNice
Date
Capacity
Rating:
Nameplate
(MW)
Capacity
Rating: Used
Location
Filing
Entity and
Generation
Market/
Docket#
Date
where MBR
Name
Owned Controlled
Balancing
Control
its Energy authority was (Plant or
By
By
Authority
Transferred
granted
Unit Name)
Affiliates
Area
Geographic
Region
in Filing
(MW)
Asset Appendix: Long-Term Firm Power Purchase Agreements (PPA)
~
[B]
[A]
[D]
[C]
[E]
[H]
[I]
[J]
Type of
l"l
1~1
End Note
Number (Enter
Location
Filing Entity
and its Energy
Affiliates
Seller Name
Market/
Amount
Balancing
ofPPA
Authority Area
(MW)
!Source!
Market/
Balancing
Authority
Area !Sinkl
Geographic
Region
(Sink)
Start Date
(mo/da/yr)
PPA
(Unit or
Svsteml
End Date (mo/da/yr)
text in End
Notes Sheetl
Asset Appendix: Transmission/Natural Gas isets
I
I
Intrastate Pipelines and/or Gas Storage Facilities
[D]
[C]
[E]
[F]
[G]
I
[H]
Location
Cite to order
accepting OATT
or order
Filing Entity and
approving the
its Energy
transfer of
Affiliates
transmission
sradovich on DSK3TPTVN1PROD with RULES
17:45 May 25, 2016
rn
length and kV
Asset Name
and Use
Owned By
Controlled
By
Market/
Date
Control
Balancing Geographic Region
Transferred
Authority
Area
facilities to an
RTOoriSO
VerDate Sep<11>2014
[I]
Size
Size (e.g.,
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for electric,
End Note Number
length and
(Enter text in End
diameter for
Notes Sheet)
pipelines, and
capacity for gas
stora2el
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[A]
FOR FURTHER INFORMATION CONTACT:
[FR Doc. 2016–12427 Filed 5–25–16; 8:45 a.m.]
Andrew R. Davis, Chief of the Division
of Interpretations and Standards, Office
of Labor-Management Standards, U.S.
Department of Labor, 200 Constitution
Avenue NW., Room N–5609,
Washington, DC 20210, olms-public@
dol.gov, (202) 693–0123 (this is not a
toll-free number), (800) 877–8339 (TTY/
TDD).
SUPPLEMENTARY INFORMATION:
BILLING CODE 6717–01–C
DEPARTMENT OF LABOR
Office of Labor-Management
Standards
29 CFR Parts 403 and 458
The Reorganization and Delegation of
Authority for the Procedures Involving
the Election of Officers in Federal
Sector Labor Organizations; Filing
Threshold for Simplified Annual
Reports; and Instructions Regarding
the Reports for Labor Organization
Officer and Employee, Labor
Organization Annual Report,
Trusteeship, and Terminal Trusteeship
Office of Labor-Management
Standards, DOL.
ACTION: Final rule; technical corrections.
AGENCY:
The Office of LaborManagement Standards (OLMS) is
making a number of technical
corrections to its regulations and LM
form instructions. OLMS is revising the
instructions for the Form LM–30, Labor
Organization Officer and Employee
Report. OLMS is also amending a 2003
final rule on labor organization annual
reports in order to incorporate the
previously updated filing threshold for
smaller labor organizations with gross
annual receipts totaling less than
$250,000, make a technical correction to
the instructions for the Form LM–2
Labor Organization Annual Report, Item
36 (Dues and Agency Fees), as well as
to update the instructions for the Form
LM–15, Trusteeship Report, and Form
LM–16, Terminal Trusteeship Report. In
addition, OLMS is amending a 2013
technical amendment implementing
Secretary’s Order No. 02–2012, which
delegated appellate authority over
certain federal sector labor organization
officer election matters to the
Administrative Review Board.
DATES: Effective May 26, 2016.
sradovich on DSK3TPTVN1PROD with RULES
SUMMARY:
VerDate Sep<11>2014
17:45 May 25, 2016
Jkt 238001
Background
The Form LM–30 final rule that is the
subject of these corrections appeared in
the Federal Register on October 26,
2011 (76 FR 66441); the final rule
revised the Form LM–30, Labor
Organization Officer and Employee
Report, its instructions, and related
provisions in the Department’s
regulations. The rule implemented
section 202 of the Labor-Management
Reporting and Disclosure Act of 1959
(LMRDA), 29 U.S.C. 432, whose purpose
is to require officers and employees of
labor organizations to report specified
financial transactions, arrangements,
and holdings to effect public disclosure
of any possible conflicts of interest with
their duty to the labor organization and
its members. The Form LM–30 and
instructions are referenced in 29 CFR
part 404. See 29 CFR 404.3 (Form of
Annual Report).
These corrections also amend a final
rule published in the Federal Register
on October 10, 2003 (68 FR 58374),
concerning labor organization annual
reports. In that rule, the Department
increased the filing threshold for Form
LM–2 filers from $200,000 to $250,000
in gross annual receipts. See 68 FR
58383. However, the rule did not make
a corresponding amendment to the text
of 29 CFR 403.4(a)(1) (Simplified annual
reports for smaller labor organizations),
which permits smaller labor
organizations to file the simplified Form
LM–3 if they do not have gross annual
receipts that meet the filing threshold
for the Form LM–2.
Furthermore, the 2003 rule mandated
electronic filing of the Form LM–2 for
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33387
labor organizations with $250,000 or
more in gross receipts. See 68 FR 58407.
The instructions for the Form LM–2
were properly revised to reflect this
requirement, but the rule did not update
the instructions for the Form LM–15,
Trusteeship Report, or the instructions
for the Form LM–16, Terminal
Trusteeship Report, both of which still
contain references to the old paper
format of the Form LM–2. Pursuant to
Title III of the LMRDA and the
Department’s regulations at 29 CFR part
408, the instructions for the Forms LM–
15 and LM–16 detail a parent
organization’s obligation to complete
the Form LM–2 on behalf of a
subordinate organization that it has
placed in trusteeship.
Moreover, today’s corrections fix an
omission in Section III of the
instructions for the Form LM–16, by
making clear that the treasurer of the
parent union, in addition to the
president (or corresponding principal
officers), is required to sign the
subordinate union’s Form LM–2 report,
pursuant to 29 U.S.C. 461(a). The Forms
LM–16 and LM–16 and instructions are
referenced in 29 CFR part 408. See 29
CFR 408.3 (Form of Initial Report) and
29 CFR 408.7 (Terminal Trusteeship
Information Report).
Additionally, these amendments
correct a technical error in the
instructions for Form LM–2 Labor
Organization Annual Report, Item 36
(Dues and Agency Fees), by clarifying
an example concerning the reporting by
a parent body and its subordinate for
dues retained by the parent body from
dues checkoff as payment for supplies
purchased from the parent body by its
subordinate. The Form LM–2 and
instructions are referenced in 29 CFR
part 403. See 29 CFR 403.3 (Form of
Annual Financial Report—Detailed
Report).
Finally, these corrections amend a
final rule published in the Federal
Register on February 5, 2013 (78 FR
8022), concerning technical
amendments implementing Secretary’s
Order No. 02–2012 (77 FR 69378),
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Federal Register / Vol. 81, No. 102 / Thursday, May 26, 2016 / Rules and Regulations
]]>Agencies
[Federal Register Volume 81, Number 102 (Thursday, May 26, 2016)]
[Rules and Regulations]
[Pages 33375-33387]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-12427]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM14-14-001; Order No. 816-A]
Refinements to Policies and Procedures for Market-Based Rates for
Wholesale Sales of Electric Energy, Capacity and Ancillary Services by
Public Utilities
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule; Order on rehearing and clarification.
-----------------------------------------------------------------------
SUMMARY: The Federal Energy Regulatory Commission is denying requests
for rehearing and granting, in part, clarification of its
determinations in Order No. 816, which amended its regulations that
govern market-based rate authorizations for wholesale sales of electric
energy, capacity, and ancillary services by public utilities pursuant
to the Federal Power Act.
DATES: This rule will become effective July 25, 2016.
FOR FURTHER INFORMATION CONTACT:
Greg Basheda (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-6479.
Carol Johnson (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, (202) 502-8521.
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
Nos.
I. Introduction............................................. 1
II. Discussion.............................................. 12
A. Sellers with Fully Committed Long-Term Generation 12
Capacity...............................................
B. Reporting of Long-Term Firm Purchases................ 18
C. Clarification of the Definition or Duration of Long- 26
Term Firm Transmission Reservations....................
D. Notices of Change in Status.......................... 29
E. New Affiliation and Behind-the-Meter Generation...... 38
F. Corporate Organizational Charts...................... 45
G. Part 101 Waivers..................................... 48
H. Capacity Ratings..................................... 52
I. Inputs to Electric Power Production.................. 55
J. Transmission/Natural Gas Assets Sheet................ 58
K. Long-Term Firm Power Purchases List.................. 60
L. Generation Assets Sheet, Rows [B] and [H]............ 62
III. Information Collection Statement....................... 65
IV. Document Availability................................... 68
V. Effective Date........................................... 71
Order No. 816-A
Order on Rehearing and Clarification
I. Introduction
1. On October 16, 2015, the Federal Energy Regulatory Commission
(Commission) issued Order No. 816,\1\ which amended its regulations
that govern market-based rate authorizations for wholesale sales of
electric energy, capacity, and ancillary services by public utilities
pursuant to the Federal Power Act (FPA). In this order, we address
requests for rehearing and clarification of Order No. 816.\2\
---------------------------------------------------------------------------
\1\ Refinements to Policies and Procedures for Market-Based
Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary
Services by Public Utilities, Order No. 816, FERC Stats. & Regs. ]
31,374 (2015) (Final Rule).
\2\ Order No. 816 became effective on January 28, 2016. On
December 23, 2015, upon consideration of requests for a stay of the
corporate organizational chart requirement, the Commission issued an
order granting an extension of time such that market-based rate
applicants and sellers would not be required to comply with the
corporate organizational chart requirement prior to the issuance of
an order on the merits of the requests for rehearing. Refinements to
Policies and Procedures for Market-Based Rates for Wholesale Sales
of Electric Energy, Capacity and Ancillary Services by Public
Utilities, 153 FERC ] 61,337 (2015).
---------------------------------------------------------------------------
2. Nine requests for rehearing and clarification were filed.\3\ The
requests for rehearing and clarification concern
[[Page 33376]]
the following topics: Sellers with fully committed long-term generation
capacity; the reporting of long-term firm purchases; the definition or
duration of long-term firm transmission reservations; notices of change
in status; new affiliation and behind-the-meter generation; corporate
organizational charts; and waiver of Part 101 of the Commission's
regulations.\4\
---------------------------------------------------------------------------
\3\ The requests for rehearing and clarification were filed by
the following entities: EDF Renewable Energy, Inc. and E.ON Climate
& Renewables North America LLC (IPP Developers); Edison Electric
Institute (EEI); Electric Power Supply Association (EPSA); Invenergy
Thermal Development LLC and Invenergy Wind Development LLC
(Invenergy); National Hydropower Association (NHA); NextEra Energy,
Inc. (NextEra); Southern California Edison Company (SoCal Edison);
Southern Company Services, Inc. (Southern); and Transmission Access
Policy Study Group (TAPS).
\4\ 18 CFR pt. 101 (2015).
---------------------------------------------------------------------------
3. In this order, in most respects, we affirm the Commission's
determinations made in Order No. 816. However, regarding some issues,
we provide clarification.
4. Specifically, as discussed further below, we deny rehearing
regarding the requirement to include the expiration date of the
contract when a seller claims that its capacity is fully committed. To
the extent that the expiration date is not known at the time a seller
files for market-based rate authority, we confirm that a subsequent
filing to report the contract expiration date will be treated as an
informational filing rather than as an amendment to a pending
application.
5. We grant clarification regarding the requirement for applicants
within a regional transmission organization or independent system
operator (RTO/ISO) market to report all long-term firm energy and
capacity purchases from generation capacity located within the RTO/ISO
market if the generation is designated as a resource with capacity
obligations. We clarify that this requirement does not apply if the
generation is from a qualifying facility exempt from section 205 of the
FPA. In addition, we affirm that a market-based rate seller must list
all of its long-term firm power purchases in its asset appendix,
Appendix B, even if it does not have market-based rate authority in its
home balancing authority area.
6. We clarify that the Commission did not intend to change the
definition of long-term firm transmission reservations in Order No. 816
and clarify that long-term firm transmission reservations are longer
than 28 days.
7. Regarding the Commission's 100 megawatt (MW) threshold for the
requirement to report new affiliations, we affirm the determinations
made in Order No. 816 but clarify which markets would be a seller's
relevant geographic market for purposes of the 100 MW threshold
reporting requirement. We also deny a rehearing request to find that
capacity in first-tier markets \5\ be included for determining the 100
MW change in status threshold.
---------------------------------------------------------------------------
\5\ We clarify that for purposes of this order, the term
``first-tier markets'' includes all first-tier areas, whether they
are a balancing authority area or an RTO/ISO market.
---------------------------------------------------------------------------
8. We affirm the Commission's determination in Order No. 816 that
sellers are not required to include behind-the-meter generation in the
100 MW change in status threshold, the 500 MW Category 1 seller status
threshold, or to include such generation in the asset appendices and
indicative screens.
9. Additionally, we clarify that a hydropower licensee that
otherwise sells power only at market-based rates will not be subject to
the full requirements of the Uniform System of Accounts as a
consequence of filing a cost-based reactive power tariff with the
Commission, and may satisfy the requirements in Part 101 of the
Commission's regulations by complying with General Instruction 16 of
the Uniform System of Accounts.
10. We also provide clarification regarding other aspects of the
Final Rule, including revisions to regulatory text and instructions in
the asset appendix to ensure consistency with the Commission's
determinations in the Final Rule.
11. Further, as discussed below, we grant an additional extension
of time such that market-based rate applicants and sellers will not be
required to comply with the corporate organizational chart requirement
until the Commission issues an order at a later date.
II. Discussion
A. Sellers With Fully Committed Long-Term Generation Capacity
1. Final Rule
12. In Order No. 816, the Commission clarified that sellers may
explain that their generation capacity in the relevant geographic
market (including first-tier markets) is fully committed, in lieu of
submitting indicative screens, in order to satisfy the Commission's
market-based rate requirements regarding horizontal market power in
instances where all generation owned or controlled by a seller and its
affiliates in the relevant balancing authority areas or markets
(including first-tier markets) is fully committed. The Commission
clarified that to qualify as fully committed, a seller must commit the
capacity to a non-affiliated buyer so that none of it is available to
the seller or its affiliates for one year or longer. The Commission
also adopted the proposal that sellers claiming that all of their
relevant capacity is fully committed must provide the following
information: the amount of generation capacity that is fully committed,
the names of the counterparties, the length of the long-term contract,
the expiration date of the contract, and a representation that the
contract is for firm sales for one year or longer.\6\
---------------------------------------------------------------------------
\6\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 39.
---------------------------------------------------------------------------
13. In response to NextEra's concern that at the time a seller
files for market-based rate authority, the expiration date may be
unknown, the Commission stated that if a contract expiration date is
unknown at the time of the market-based rate filing, the seller must,
within 30 days of the date becoming known, submit an informational
filing, in the docket in which the seller was granted market-based rate
authorization, to inform the Commission of the contract expiration
date. In response to another commenter's remark that the expiration
date is reported separately in electric quarterly report (EQR) filings,
the Commission noted that many contracts reported in EQR filings do not
include expiration dates and determined that it would require
expiration date information in order to show that generation capacity
is fully committed.\7\
---------------------------------------------------------------------------
\7\ Id. P 44.
---------------------------------------------------------------------------
2. Requests for Rehearing
14. NextEra requests rehearing of the Commission's determination
concerning sellers with fully committed long-term generation capacity,
stating that the Commission erred in requiring a market-based rate
seller to report the expiration date of a long-term contract to the
Commission within 30 days of the date being known, rather than simply
in an EQR filing.\8\ NextEra contends that the Commission erred by
failing to set forth an explanation of the specific after-the-fact need
for the contract expiration date, as the seller is also required to
provide the length of the long-term contract in order to demonstrate
that it has no uncommitted capacity.\9\ NextEra states that if the
Commission concludes that there is an actual need for this information
given that after-the-fact reporting means that the expiration date can
only be used in an ex post analysis, the Commission should clarify that
it will permit sellers to provide the information to the Commission
either through an EQR submission or on an after-the-fact basis.\10\
NextEra states that to the extent that a seller informs the Commission
of the contract expiration date within 30 days of the date becoming
known, the Commission should clarify that it will treat such filings as
informational filings rather
[[Page 33377]]
than as amendments to pending applications.\11\
---------------------------------------------------------------------------
\8\ NextEra Rehearing Request at 2.
\9\ Id. at 12.
\10\ Id. at 13.
\11\ Id. at 14.
---------------------------------------------------------------------------
3. Commission Determination
15. The Commission stated in Order No. 816 that sellers claiming
that capacity is fully committed must provide, among other things, the
length of the long-term contract and the expiration date of the
contract. The same information must be provided for long-term firm
sales of affiliated generation capacity located in the relevant
balancing authority areas or markets, including first-tier markets.
Including this information in the record of a seller's market-based
rate filing is necessary so that a seller's claims of fully committed
capacity can be verified as needed.
16. In Order No. 816, the Commission addressed comments submitted
by NextEra regarding contract expiration dates. In consideration of
NextEra's contention that the expiration date may be unknown at the
time a seller files for market-based rate authority,\12\ the Commission
determined that, in such instances, the seller must follow up with an
informational filing to inform the Commission of the contract
expiration date, within 30 days of the date becoming known.\13\
---------------------------------------------------------------------------
\12\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 38.
\13\ Id. P 44.
---------------------------------------------------------------------------
17. In its request for rehearing, NextEra questions the necessity
of requiring the expiration date given that sellers are required to
provide the length of the contract. We continue to believe that the
expiration date is an important piece of information for sellers to
provide. The expiration date provides the Commission with a specific
date as to when the affected generation capacity may become uncommitted
and the expiration date allows the Commission to verify the information
previously provided by the seller for purposes of the Commission's ex
ante analysis of the seller's potential market power. With regard to
NextEra's argument that the Commission erred in requiring the market-
based rate seller to report the expiration date of a contract to the
Commission within 30 days of the date being known, rather than in an
EQR filing, we note that, as the Commission stated in Order No. 816,
many contracts reported in EQR filings do not include expiration
dates.\14\ Finally, consistent with Order No. 816, we grant NextEra's
request that the Commission clarify that filings reporting contract
expiration dates in support of a seller's claim that capacity is fully
committed will be treated as informational filings rather than as
amendments to filings.\15\
---------------------------------------------------------------------------
\14\ Id.
\15\ Id.
---------------------------------------------------------------------------
B. Reporting of Long-Term Firm Purchases
1. Final Rule
18. The Commission adopted the proposal to report in the indicative
screens long-term firm purchases of capacity and/or energy that have an
associated long-term firm transmission reservation. The Commission
stated that requiring applicants under the market-based rate program to
report all of their long-term firm purchases of energy and/or capacity,
regardless of whether the applicant has operational control of the
generation capacity supplying the purchased power, will improve the
accuracy of the indicative screens.\16\ The Commission stated that
long-term firm power purchase agreements that are reported in the
indicative screens also should be reported in the asset appendix,
Appendix B, and created a separate sheet in Appendix B specifically for
applicants to report all such long-term firm purchases.\17\
---------------------------------------------------------------------------
\16\ Id. P 130.
\17\ Id. P 139.
---------------------------------------------------------------------------
19. The Commission stated that the requirement that applicants only
include long-term firm power purchase agreements in their indicative
screens if they have an associated long-term transmission reservation
will not apply within RTO/ISO markets if that RTO/ISO does not have
long-term firm transmission reservations or their equivalent. Instead,
applicants in such RTO/ISO markets will be required to report all long-
term firm energy and/or capacity purchases from generation capacity
located within the RTO/ISO market if the generation is designated as a
network resource or as a resource with capacity obligations.\18\
---------------------------------------------------------------------------
\18\ Id. P 145.
---------------------------------------------------------------------------
2. Requests for Rehearing
20. SoCal Edison and NextEra seek clarification with regard to the
reporting of long-term firm purchases.
21. SoCal Edison seeks clarification that the requirement to report
all long-term firm energy and/or capacity purchases from generation
capacity located within the RTO/ISO market if the generation is
designated as a resource with capacity obligations does not apply if
the generation is a qualifying facility exempt from section 205 of the
FPA. SoCal Edison asserts that there is no reason why an applicant that
holds a long-term contract with a qualifying facility exempt from FPA
section 205 should have to report that in the appendix and screens,
even if the facility has capacity obligations, when affiliate-owned
exempt qualifying facilities would be excluded from the reporting
requirement.\19\
---------------------------------------------------------------------------
\19\ SoCal Edison Rehearing Request at 2.
---------------------------------------------------------------------------
22. NextEra seeks clarification related to the necessity of
reporting long-term power purchases in the asset appendix, Appendix B,
by entities that do not have market-based rate authorization in their
balancing authority area and as a result are not required to submit
indicative screens.\20\ NextEra states that in Order No. 816, the
Commission stated that long-term firm power purchase agreements that
are reported in the indicative screens also should be reported in the
asset appendix. NextEra states that based on this statement, NextEra
understands that the Commission will not require the inclusion of long-
term power purchase agreements if a seller does not have market-based
rate authority in its balancing authority area, but instead makes only
cost-based sales.\21\ NextEra asks the Commission to confirm that the
inclusion of such information is only required for companies that have
market-based authority in the relevant geographic market.\22\
---------------------------------------------------------------------------
\20\ NextEra Rehearing Request at 2.
\21\ Id. at 14.
\22\ Id. at 15.
---------------------------------------------------------------------------
3. Commission Determination
23. We grant SoCal Edison's requested clarification. Applicants
purchasing energy and/or capacity from a qualifying facility that is
exempt from section 205 of the FPA under a long-term firm power
purchase agreement do not need to include such purchases in their
indicative screens or in their asset appendix. In Order No. 816, the
Commission determined that qualifying facilities that are exempt from
section 205 of the FPA do not need to be reported in the asset appendix
or indicative screens.\23\ Therefore, to ensure consistency in
horizontal market power analyses filed by sellers we clarify that this
exemption applies equally to long-term firm power purchases agreements
backed by such resources.
---------------------------------------------------------------------------
\23\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 255.
---------------------------------------------------------------------------
24. We reject NextEra's requested clarification. A market-based
rate seller must list all of its generation assets in its asset
appendix even if it does not have market-based rate authority in its
balancing authority area or, indeed, even if its generation is fully
committed and it is not submitting any indicative
[[Page 33378]]
screens. We see no reason to treat long-term firm power purchase
agreements differently than other generation capacity. In Order No.
816, the Commission determined that long-term firm power purchase
agreements with an associated long-term firm transmission reservation
(or that are capacity resources in RTO/ISO markets) must be reported in
a seller's indicative screens and asset appendix. Excluding long-term
firm power purchase agreements as requested by NextEra would be
inconsistent with that policy. In addition, sellers without market-
based rate authority in their own balancing authority area typically
seek market-based rate authority elsewhere and do so by submitting
indicative screens for their first-tier markets. A seller's long-term
firm power purchase agreements are a resource that would need to be
reflected in the screens for the seller's first-tier markets. Since
these agreements are reflected in the screens to the extent that they
provide potential exports from a seller's balancing authority area to
first-tier markets, they should be included in the seller's asset
appendix.
25. We also clarify that the generation capacity associated with a
unit-specific long-term contract should be reported in the ``Notes''
portion of the asset appendix. An example of this will be posted on the
Commission's Web site.
C. Clarification of the Definition or Duration of Long-Term Firm
Transmission Reservations
1. Final Rule
26. In the Final Rule, the Commission provided clarification on the
preparation of simultaneous transmission import limit (SIL) studies. In
discussing SIL studies, the Commission declined a request to redefine
the applicable duration of long-term firm transmission reservations,
stating that it is currently defined as 28 days or longer.\24\
---------------------------------------------------------------------------
\24\ Id. P 197.
---------------------------------------------------------------------------
2. Requests for Rehearing
27. Southern states that Order No. 816 appears to erroneously refer
to long-term firm transmission reservations as comprising reservations
that are 28 days or longer. Southern maintains that this is contrary to
precedent indicating that the expectation for entities performing SIL
studies was that only transmission reservations with a duration longer
than 28 days (i.e., a duration of 29 days and greater) should be
considered to be long-term firm reservations.
3. Commission Determination
28. We clarify that the Commission did not intend to change the
definition of long-term firm transmission reservations in Order No.
816. We reaffirm prior Commission guidance that short-term reservations
are up to one month and long-term reservations are greater than one
month.\25\ February is the shortest month, which means that long-term
firm transmission reservations must be longer than 28 days. Thus, we
clarify that long-term firm transmission reservations are longer than
28 days.
---------------------------------------------------------------------------
\25\ Market-Based Rates for Wholesale Sales of Electric Energy
Capacity and Ancillary Services by Public Utilities, Order No. 697-
B, FERC Stats. & Regs. ] 31,285 at P 25 (2008).
---------------------------------------------------------------------------
D. Notices of Change in Status
1. Final Rule
29. In the Notice of Proposed Rulemaking (NOPR), the Commission
proposed to revise the change in status regulations at 18 CFR 35.42 to
include a 100 MW threshold for reporting new affiliations. The
Commission stated that 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.\26\ In the Final
Rule, the Commission adopted the proposed changes to the change in
status requirements of section 35.42 of the Commission's
regulations.\27\
---------------------------------------------------------------------------
\26\ Refinements to Policies and Procedures for Market-Based
Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary
Services by Public Utilities, FERC Stats. & Regs. ] 32,702, at P 96
(2014) (NOPR).
\27\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 251.
---------------------------------------------------------------------------
30. In the Final Rule, the Commission stated that 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.\28\ The Commission clarified that the phrase ``any
relevant market'' refers to a market in which a seller already has
generation located and acquires an additional 100 MW or accumulates 100
MW or more in a new market that the seller had not studied
previously.\29\ The Commission also clarified that the 100 MW threshold
does not include generation capacity that can be imported from first-
tier markets.\30\ The Commission agreed with commenters that generation
capacity in first-tier markets should not be treated the same as
capacity located in the seller's relevant geographic market/study
area.\31\
---------------------------------------------------------------------------
\28\ Id. P 231.
\29\ Id. P 237.
\30\ Id. P 18.
\31\ Id. P 229.
---------------------------------------------------------------------------
2. Requests for Rehearing
31. IPP Developers request that the Commission make the following
three clarifications: (1) If an affiliate of a seller acquires or
controls 100 MW of generating capacity (including long-term firm
purchases), the seller must submit a notice of change in status report
if that 100 MW is located in the same relevant market that was studied
as the basis for the seller's grant of market-based rate authority; (2)
if an affiliate of the seller acquires or controls 100 MW or more of
generating capacity (including long-term firm purchases) in a market
that is two tiers away or more, the seller is not required to submit a
notice of change in status report; and (3) if an affiliate of the
seller acquires or controls 100 MW or more of generating capacity
(including long-term firm purchases) in a market that is in the first-
tier, the seller is not required to submit a notice of change in status
report.\32\ IPP Developers state that these three clarification
requests appear to be a proper application of the Commission's
statements in Order No. 816. IPP Developers conclude that a seller does
not have a change in status reporting obligation in regard to an
affiliate's generation in first-tier and beyond areas.\33\
---------------------------------------------------------------------------
\32\ IPP Developers Rehearing Request at 1-3.
\33\ Id.
---------------------------------------------------------------------------
32. However, IPP Developers state that the following statement in
paragraph 238 of Order No. 816 makes this reporting obligation unclear:
``if a seller's affiliate is granted market based rate authority, and
that results in 100 MW or more of new generation in a market, then the
seller will have to file a corresponding change in status.'' \34\ IPP
Developers state that ``a market'' could be any market other than the
seller's studied relevant market, i.e., affiliate generation in first-
tier or beyond markets.\35\ IPP Developers state that this statement
appears to say that a seller must file a notice of change in status
report regardless of the market in which an affiliate of the seller
acquires or controls 100 MW or more of generating capacity.\36\
---------------------------------------------------------------------------
\34\ Id. at 3-4 (citing Order No. 816, FERC Stats. & Regs. ]
31,374 at P 238 (emphasis added)).
\35\ Id. at 4.
\36\ Id.
---------------------------------------------------------------------------
33. IPP Developers state that if the Commission is not inclined to
provide the clarifications above, then IPP Developers request
rehearing.\37\
---------------------------------------------------------------------------
\37\ Id. at 3.
---------------------------------------------------------------------------
34. TAPS seeks rehearing of the threshold calculation, arguing that
[[Page 33379]]
capacity in first-tier markets should be included for determining
changes in the 100 MW change in status threshold.\38\ TAPS states that
in the NOPR, the Commission proposed to clarify that the ``relevant
geographic market'' for purposes of that 100 MW trigger included
generation capacity that could be imported from first-tier markets.\39\
TAPS states that the Commission then reversed the NOPR proposal,
stating that it would ``exclude markets and balancing authority areas
that are first-tier to the seller's study area.'' \40\ TAPS states that
the Commission erred and should grant rehearing to revise Order No. 816
to include generation in first-tier markets for purposes of change in
status reporting, whether or not it is supported by a long-term firm
transmission reservation.\41\ Specifically, TAPS states that the
Commission should require sellers to: (1) Include first-tier capacity
when there is a long-term transmission reservation associated with the
capacity; and (2) include all other first-tier capacity either in its
entirety or, in the alternative, on a pro rata basis consistent with
the inclusion of such generation in market power screens.\42\
---------------------------------------------------------------------------
\38\ TAPS Rehearing Request at 1.
\39\ Id. at 4 (citing NOPR, FERC Stats. & Regs. ] 32,702 at P
96).
\40\ Id. at 5 (citing Order No. 816, FERC Stats. & Regs. ]
31,374 at P 230).
\41\ Id. at 6.
\42\ Id. at 5.
---------------------------------------------------------------------------
35. TAPS states that the NOPR's proposal to include first-tier
generation capacity is both simple and adequate.\43\ TAPS states that
the Commission could allow sellers, with appropriate support, to
prorate generation in markets first-tier to the study area in the same
way capacity is assigned pro rata for indicative screen analyses
(assuming there are no firm transmission reservations associated with
the first-tier capacity, in which case it should be accorded its full
megawatt value). TAPS states that this approach would be consistent
with the methodology used in the indicative screens, but would require
more analysis than reporting of all first-tier capacity for purposes of
change in status reports.\44\
---------------------------------------------------------------------------
\43\ Id. at 6-7.
\44\ Id. at 7.
---------------------------------------------------------------------------
3. Commission Determination
36. We grant clarification regarding IPP Developers' three examples
of the application of Order No. 816. The scenarios presented by IPP
Developers are a proper application of the Final Rule, assuming that
the seller is not a power marketer (i.e., the seller owns generation).
We also grant clarification regarding the Commission's statement in
paragraph 238 of Order No. 816. In paragraph 238 of Order No. 816, the
Commission stated that ``if a seller's affiliate is granted market-
based rate authority, and that results in 100 MW or more of new
generation in a market, then the seller will have to file a
corresponding change in status.'' \45\ We clarify that the phrase ``in
a market'' means any relevant geographic market for the seller at the
time of the change in status filing. Further, we note that the relevant
geographic market for a particular seller depends on whether the seller
is a power producer or a power marketer, whether the seller owns
transmission or is interconnected to an affiliated transmission system,
and whether the seller's generation is in an RTO/ISO. The relevant
markets for a power marketer include any market where the power
marketer's affiliates own generation. Thus, a power marketer that does
not own any generation itself would need to report a change in status
for a 100 MW net increase in any market where an affiliate owns
generation and has been granted market-based rate authority.\46\
However, for a power producer, the relevant geographic market is where
the seller's generation is physically located. Thus, a power producer
would not need to report a 100 MW affiliate net increase in a market
where the power producer itself does not own any generation. Similarly,
in traditional (non-RTO/ISO) markets, the default relevant geographic
market is ``first, the balancing authority area where the seller is
physically located, and second, the markets directly interconnected to
the seller's balancing authority area.'' \47\ However, ``[w]here a
generator is interconnecting to a non-affiliate owned or controlled
transmission system, there is one relevant geographic market (i.e., the
balancing authority area in which the generator is located).'' \48\ For
a seller located in an RTO/ISO market, the seller may consider the RTO/
ISO as the default relevant geographic market.\49\ In each
circumstance, the market-based rate seller will have to determine
whether any 100 MW increase is in a market that would be a relevant
geographic market for that seller.
---------------------------------------------------------------------------
\45\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 238
(emphasis added).
\46\ A power marketer with no affiliated generation is a
Category 1 seller (exempt from filing triennial updated market power
analysis) in all regions and has no relevant geographic market. A
power marketer that acquires generation via a long-term power
purchase agreement has a relevant geographic market where the power
associated with this agreement is delivered (sinks), not where it
originates (unless source and sink are in the same market, which is
often the case). In this scenario, the power marketer is a Category
1 or 2 seller in the relevant geographic market depending on the MWs
associated with the contract(s). Category 2 sellers must submit
triennial update market power analyses.
\47\ Market-Based Rates for Wholesale Sales of Electric Energy
Capacity and Ancillary Services by Public Utilities, Order No. 697,
FERC Stats. & Regs. ] 31,252 at P 232 (2007).
\48\ Id. P 232 n.217.
\49\ Id. P 235 (noting that a seller may consider the RTO/ISO as
the default relevant geographic market ``unless the Commission has
already found the existence of a submarket'').
---------------------------------------------------------------------------
37. We deny TAPS's request that capacity in first-tier markets be
included for determining the 100 MW change in status threshold. As the
Commission stated in Order No. 816, when a seller has a change in
status in a particular market, it does not need to include any changes
in adjoining first-tier markets in calculating the 100 MW threshold,
even when a purchaser has long-term firm transmission rights to import
affiliated capacity located in a first-tier market. We reiterate that,
with respect to the calculation of the 100 MW threshold, 100 MW located
outside of the study area is not equivalent to 100 MW inside the study
area. In addition, requiring sellers to consider generation capacity in
first-tier markets, and prorate generation from the first-tier markets
into the study area, creates uncertainty as to when a seller would trip
the 100 MW threshold and effectively would force a seller to prepare
import analyses to determine how much of their additional first-tier
capacity could be imported into the study area. We believe that the
increased burden of preparing such studies would outweigh the potential
benefit gained from receiving additional information about a seller's
affiliated generation.
E. New Affiliation and Behind-the-Meter Generation
1. Final Rule
38. As stated above, the Commission adopted the NOPR proposal to
establish a 100 MW threshold for reporting new affiliations in change
of status filings. The Commission stated that 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.\50\ The
[[Page 33380]]
Commission stated that the 100 MW threshold will be determined for each
relevant geographic market but will not consider generation capacity
additions in first-tier markets.\51\
---------------------------------------------------------------------------
\50\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 251. The
Commission noted that 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. Id. P 251 n.334.
\51\ Id. P 251.
---------------------------------------------------------------------------
39. The Commission did 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 threshold or to include such generation in the
asset appendix and indicative screens.\52\
---------------------------------------------------------------------------
\52\ Id. P 252.
---------------------------------------------------------------------------
40. The Commission stated that the output of behind-the-meter
generation should be reflected in the load data reported in the FERC
Form No. 714, which 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. The Commission also stated that, 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. The
Commission clarified 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.\53\
---------------------------------------------------------------------------
\53\ Id. P 253.
---------------------------------------------------------------------------
2. Requests for Rehearing
41. TAPS requests rehearing and/or clarification, arguing that
behind-the-meter generation that is available to make wholesale sales
and that is not reflected as a reduction in load reported in Form No.
714 should be included in seller reporting obligations, including the
100 MW change in status threshold, the indicative screens, the asset
appendix, and the 500 MW Category 1 seller status threshold.
42. Specifically, TAPS states that the Commission should make clear
that behind-the-meter generation that is not consumed on-site by the
host load and reflected in Form No. 714 load data must, consistent with
the Commission's duty to assess market power, be included in seller
reporting obligations and indicative screens and category seller status
determinations. TAPS contends that generation that participates in the
wholesale markets influences a seller's market power regardless of
whether it may be termed behind-the-meter.\54\ TAPS argues that even if
it were otherwise permissible, the exclusion for behind-the-meter
generation would be arbitrary and capricious. TAPS states that because
Order No. 816 fails to limit the scope of the behind-the-meter
exclusion to that included in load reported in Form No. 714 or not
synchronized to the grid and provides no definition of behind-the-meter
generation, sellers are left to their own devices to determine what is
meant by behind-the-meter generation and then to exclude those
resources for purposes of reporting under Order No. 816.\55\
---------------------------------------------------------------------------
\54\ TAPS Rehearing Request at 11.
\55\ Id.
---------------------------------------------------------------------------
43. TAPS states that the Commission should clarify that its
exclusion of behind-the-meter generation was intended to be restricted
by its clarification at paragraph 253 of the Final Rule--that only
generation that is reflected in Form No. 714 or not synchronized would
be excludable from generation from market-based rate reporting and
market power screens. Alternatively, TAPS states that the Commission
should grant rehearing and: (1) Adopt its NOPR proposal to include
behind-the-meter generation, with El Paso's clarification--i.e., that
behind-the-meter generation that is not reflected as a decrease in load
on Form No. 714 should be included in seller reporting obligations and
all market power screens; or (2) otherwise avoid creating a behind-the-
meter generation blind spot of undefined proportions in its market
power monitoring and assessment regimen.\56\
---------------------------------------------------------------------------
\56\ Id. at 13.
---------------------------------------------------------------------------
3. Commission Determination
44. We deny TAPS's request for rehearing. As the Commission stated
in the Final Rule, the output of behind-the-meter generation largely
should be reflected in the load data reported in the FERC Form No. 714,
which 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. Accordingly, 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 some sellers' generation capacity. Further, the Commission
stated in the Final Rule that behind-the-meter generation not sold into
the wholesale market is not relevant to the Commission's horizontal
market power analysis. Regarding TAPS's concern about behind-the-meter
generation that is available to make wholesale sales and is not
reflected in load reported in Form No. 714, we believe, at this time,
that this category of generation is relatively limited and that the
burden of sellers reporting this behind-the-meter generation would
outweigh the benefits of such reporting. Therefore, at this time, we
will not require sellers to report this type of generation.
F. Corporate Organizational Charts
1. Final Rule
45. In the Final Rule, the Commission adopted the proposal to
require a seller to include a corporate organizational chart when
filing an initial application for market-based rate authority, an
updated market power analysis, or, in some circumstances, a notice of
change in status reporting new affiliations.\57\ The Commission revised
the regulatory text in section 35.37(a)(2) and in section 35.42(c) in
this regard.
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\57\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 21.
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2. Requests for Rehearing
46. Invenergy, SoCal Edison, NextEra, EEI, and EPSA request
rehearing and/or clarification with respect to the requirement to
submit corporate organizational charts. Parties argue, among other
things, that the requirement imposes a substantial administrative
burden on filers and is at odds with the objective of streamlining the
market-based rate filing process.
3. Commission Determination
47. As noted above, upon consideration of requests for a stay of
the corporate organizational chart requirement, the Commission issued
an order granting an extension of time such that market-based rate
applicants and sellers would not be required to comply with the
corporate organizational chart requirement prior to the issuance of an
order on the merits of the requests for rehearing.\58\ Upon
consideration of the concerns raised by the parties on rehearing
regarding this requirement, we grant an additional extension of time
such that market-based rate applicants and sellers will not be required
to comply with the corporate organizational chart requirement until the
Commission issues an order at a later date addressing this requirement.
The extension will allow the Commission more time to fully consider the
benefits and burdens associated with the corporate organizational chart
requirement.\59\
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\58\ Refinements to Policies and Procedures for Market-Based
Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary
Services by Public Utilities, 153 FERC ] 61,337 (2015).
\59\ The Commission continues to consider appropriate mechanisms
for consolidating the Commission's data collection requirements,
including this organizational chart requirement, with the proposed
rulemakings in Docket Nos. RM15-23 and RM16-3.
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[[Page 33381]]
G. Part 101 Waivers
1. Final Rule
48. The Commission clarified that granting waiver of 18 CFR part
101 under market-based rate authority does not waive the requirements
under Part I of the FPA for hydropower licensees. In addition, the
Commission clarified that hydropower licensees that only make sales at
market-based rates may satisfy the requirements in Part 101 of the
Commission's regulations (Uniform System of Accounts) by complying with
General Instruction 16 of the Uniform System of Accounts, and confirmed
that hydropower licensees that have Commission-approved cost-based
rates are required to comply with the full requirements of the Uniform
System of Accounts.\60\
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\60\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 22.
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2. Requests for Rehearing
49. NHA requests clarification that a hydropower licensee that
otherwise sells power only at market-based rates will not be subject to
the full requirements of the Uniform System of Accounts as a
consequence of filing a cost-based reactive power tariff with the
Commission.\61\ Alternatively, NHA requests that the Commission clarify
that it will allow licensees that otherwise sell only at market-based
rates to request authorization, on a case-by-case basis, to continue to
rely on General Instruction 16 of the Uniform System of Accounts at the
time a reactive power tariff is filed with the Commission.\62\
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\61\ NHA Clarification Request at 3-5.
\62\ Id. at 5.
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50. NHA argues that the Commission determined in Order No. 697 that
``little purpose would be served to require compliance with accounting
regulations for entities that do not sell at cost-based rates and do
not have captive customers.'' \63\ NHA represents that the Commission
has previously found that reactive power tariffs do not have captive
customers and do not raise the same concerns as other cost-based rate
tariffs.\64\ Additionally NHA notes that entities with a reactive power
tariff and a market-based rate tariff have been previously granted
waiver of Part 101.\65\
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\63\ Id. at 3 (citing Order No. 697, FERC Stats. & Regs. ]
31,252 at P 984).
\64\ Id. at 3-4 (citing Order No. 697, FERC Stats. & Regs. ]
31,252 at P 483 (``concerns underlying the affiliate restrictions do
not apply to sales of reactive power because those sales are
typically either made to transmission providers so that the
transmission provider can satisfy its obligation to provide reactive
power or made by the transmission provider under its applicable
[open access transmission tariff]'')).
\65\ Id. (citing Sunbury Generation, LLC, 108 FERC ] 61,160
(2004) (Sunbury); Illinois Power Generating Co., 148 FERC ] 61,238
(2014) (granting waivers of Parts 41, 101, and 141 of the
Commission's regulations to entities with a cost-based rate reactive
power tariff and a market-based rate tariff)).
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3. Commission Determination
51. We clarify that a hydropower licensee that otherwise sells
power only at market-based rates will not be subject to the full
requirements of the Uniform System of Accounts as a consequence of
filing a cost-based reactive power tariff with the Commission. Such a
seller may satisfy the requirements in Part 101 of the Commission's
regulations by complying with General Instruction 16 of the Uniform
System of Accounts. We find that this clarification is consistent with
previous Commission findings in Order No. 697 and Sunbury, as noted by
NHA. We continue to find, however, that hydropower licensees that have
Commission-approved cost-based rates are required to comply with the
full requirements of the Uniform System of Accounts.\66\ Additionally,
we remind sellers that ``previously granted waivers of the accounting
requirements will continue to be rescinded where a seller is found to
have market power (or where the sellers accepts a presumption of market
power) and the seller proposes cost-based rate mitigation or the
Commission imposes cost-based rate mitigation.'' \67\
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\66\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 22.
\67\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 986.
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H. Capacity Ratings
1. Final Rule
52. In the Final Rule, the Commission revised the regulations at 18
CFR 35.42 relating to the change in status reporting requirements to
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.\68\ The Commission found that solar photovoltaic and solar
thermal facilities are energy limited and determined that, due to their
unique characteristics, solar photovoltaic facilities, unlike other
energy-limited facilities, must use nameplate capacity and may not use
five-year average capacity factors.\69\
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\68\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 232.
\69\ Id. P 15.
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2. Request for Rehearing
53. Southern notes the Commission's determination in the Final Rule
permitted sellers to use nameplate or seasonal capacity ratings for the
100 MW threshold for most generation. Southern states that the
regulatory text accompanying the Final Rule includes the phrase ``or
seasonal'' in 18 CFR 35.42(a)(2)(i) but not in 18 CFR 35.42(a)(1).
Southern requests that the Commission add the phrase ``or seasonal'' to
18 CFR 35.42(a)(1) to align with the discussion in the Final Rule.\70\
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\70\ Southern Rehearing Request at 7 n.15 (citing Order No. 816,
FERC Stats. & Regs. ] 31,374 at P 232).
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3. Commission Determination
54. We find that it is appropriate to revise 18 CFR 35.42(a)(1) to
add the phrase ``or seasonal.'' Additionally, we are revising both 18
CFR 35.42(a)(1) and (a)(2)(i) to further align the regulations with the
discussion in the Final Rule. Specifically, the revised regulations
will indicate that the 100 MW or more of capacity should be based on
nameplate or seasonal capacity ratings and, for energy-limited
resources, with the exception of solar photovoltaic facilities, the
capacity ratings should be based on nameplate or five-year average
capacity factors. These revised regulations will indicate that for
solar photovoltaic facilities, the capacity ratings should be based on
nameplate capacity.
I. Inputs to Electric Power Production
1. Final Rule
55. The Commission considers a seller's ability to erect other
barriers to entry as part of the vertical market power analysis and, as
such, the Commission requires a seller to provide a description of its
inputs to electric power production.\71\ Section 35.36(a)(4) of the
Commission's regulations define inputs to electric power production to
mean intrastate natural gas transportation, intrastate natural gas
storage or distribution facilities, sites for generation capacity
development, physical coal supply sources and ownership of or control
over who may access transportation of coal supplies.
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\71\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 6.
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56. In the Final Rule, the Commission eliminated the requirement
that market-based rate sellers file quarterly land acquisition reports
and provide information on sites for generation capacity development in
market-based rate applications and triennial updated market power
analyses. Specifically, the Commission adopted the proposal to
[[Page 33382]]
revise the regulations at 18 CFR 35.42 relating to the change in status
reporting requirements regarding sites for new generation capacity
development and also adopted the proposal to revise the regulations at
18 CFR 35.37 to remove the requirement that sellers provide information
regarding sites for generation capacity development to demonstrate a
lack of vertical market power. However, no changes to the definition of
inputs to electric power production were made in the Final Rule.
2. Commission Determination
57. In light the determinations made in the Final Rule, we revise
our regulations at 18 CFR 35.36(a)(4) to remove sites for generation
capacity development from the definition of inputs to electric power
production. However, we clarify that the affirmative statement
regarding barriers to entry required in 18 CFR 35.37(e)(3) continues to
cover sites for generation capacity development.
J. Transmission/Natural Gas Assets Sheet
1. Final Rule
58. In the NOPR, the Commission proposed to require any seller that
has been granted waiver of the requirement to file an open access
transmission tariff (OATT) for its transmission facilities to report in
its Transmission/Natural Gas Assets Sheet the citation to the
Commission order granting the OATT waiver for those transmission
facilities.\72\ The Commission did not adopt the NOPR proposal in the
Final Rule, agreeing with SoCal Edison that this requirement would not
provide useful information in light of Order No. 807.\73\ The
Commission further 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.'' \74\
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\72\ NOPR, FERC Stats. & Regs. ] 32,702 at P 120.
\73\ Order No. 816, FERC Stats. & Regs. ] 31,374 at P 300
(citing 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)).
\74\ Id. P 295 (citing Order No. 697-A, FERC Stats. & Regs. ]
31,268 at P 378 (``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).'')).
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2. Commission Determination
59. Upon further consideration, we modify the requirement to report
in the asset appendix transmission facilities that have been granted an
individual OATT waiver or that qualify for a blanket waiver under Order
No. 807 and find that sellers are no longer required to include such
facilities in their Transmission/Natural Gas Assets Sheet. We find that
the burden of providing information on such facilities outweighs any
benefit to reporting it. For this reason, we eliminate the requirement
to report in the Transmission/Natural Gas Assets Sheet facilities that
qualify for blanket waiver of the OATT requirement under Order No. 807
and those that have been granted an individual OATT waiver.
K. Long-Term Firm Power Purchases List
1. Final Rule
60. In the Final Rule, the Commission established a new, separate
list in the asset appendix in which market-based rate sellers are to
report their Long-Term Firm Power Purchase Agreements (PPAs).\75\ The
Commission agreed with commenters that the format of the Generation
Assets Sheet was not well suited for reporting long-term firm
purchases.
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\75\ Id. P 270.
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2. Commission Determination
61. Subsequent to the issuance of Order No. 816, Commission Staff
received numerous calls from sellers requesting guidance with respect
to completing the Long-Term Firm PPAs Sheet. Upon further
consideration, we recognize that certain modifications to this sheet
and its instructions are warranted to improve its clarity. To that end,
we are making the following changes. First, we are eliminating the
existing column B, ``Docket # where MBR authority was granted'' as this
is duplicative of information required elsewhere in the asset appendix.
In response to questions as to whether the ``Market/Balancing Authority
Area'' column was referring to the source or sink of the transaction,
we are adding a column and specifically requesting sellers to identify
both the source and sink of the transaction in separate designated
columns. Finally, in response to other questions raised by market-based
rate filers, we are adding a column requiring sellers to indicate
whether a particular long-term firm purchase agreement is backed by a
specific identified generation unit or by the supplier's generation
fleet (i.e., a ``system'' contract). Instructions for the Long-Term
Firm PPAs Sheet have been modified to reflect these changes and to make
certain other clean up edits.
L. Generation Assets Sheet, Rows [B] and [H]
1. Final Rule
62. The Final Rule contained instructions for completing the asset
appendix. The description of Row [B] indicated that, if applicable,
sellers should include the docket number where market-based rate or
qualifying facility status was originally granted, and that it can be
an EL or QF docket number. The description of Row [H] listed the six
market-based rate regions but mistakenly listed the Southeast region
twice and failed to mention the Northwest region.
2. Commission Determination
63. We revise the instructions for Row [B] of the asset appendix to
remove references to EL and QF dockets. This revision does not change
the Commission's determinations in Order No. 816. Rather, this revision
aligns the description and format information regarding Row [B] with
the Commission's intent that Row [B] contain the docket number where
market-based rate authority was granted.
64. We revise the instructions to Row [H] of the Generation Assets
Sheet to delete the second reference to ``Southeast'' and replace it
with ``Northwest.''
III. Information Collection Statement
65. The Office of Management and Budget (OMB) regulations
implementing the Paperwork Reduction Act of 1995 \76\ require that OMB
approve certain information collection requirements imposed by an
agency.\77\ Upon approval of a collection(s) of information, OMB will
assign an OMB control number and an expiration date. Respondents
subject to the filing requirements of a rule will not be penalized for
failing to respond to these collections of information unless the
collections of information display a valid OMB control number.
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\76\ 44 U.S.C. 3507(d) (2012).
\77\ 5 CFR 1320.11.
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66. The revisions made in Order No. 816 to the information
collection requirements for market-based rate sellers were approved
under FERC-919 (OMB Control No. 1902-0234).\78\ This order clarifies
and makes minor revisions to some aspects of the existing information
collection requirements for the market-based rate program. The
[[Page 33383]]
changes to the information collection include:
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\78\ OMB approved the information collection in Order No. 816 on
December 22, 2015.
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Removing the need to list transmission facilities in the
Transmission/Natural Gas Assets Sheet that have an OATT waiver or that
qualify for the blanket OATT waiver (a slight burden decrease)
adding a source/sink column and a column for generation
unit/system contract type to the Long-Term Firm PPAs Sheet (slight
burden increases)
removing column B, ``Docket # where MBR authority was
granted'' from the Long-Term Firm PPAs Sheet and removing references to
``EL'' and ``QF'' in the instructions for Row [B] of the Generation
Assets Sheet (de minimis decreases)
removing sites for generation capacity development from
the definition of inputs to electric power production at 18 CFR
35.36(a)(4) (no change to burden).
The Commission estimates that there will be no net change to burden.
This Final Rule will be submitted to OMB for review and approval of a
``No Material/Nonsubstantive Change.''
Title: Market Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities (FERC-919).
Action: Clarification and Revision of Currently Approved Collection
of Information.
OMB Control No.: 1902-0234.
Respondents for This Rulemaking: Public utilities, wholesale
electricity sellers, businesses, or other for profit and/or not for
profit institutions.
67. Interested persons may obtain information on the reporting
requirements by contacting: Federal Energy Regulatory Commission, 888
First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office
of the Executive Director, email: DataClearance@ferc.gov, phone: (202)
502-8663, fax: (202) 273-0873]. Comments concerning the requirements of
this rule may also be sent to the Office of Information and Regulatory
Affairs, Office of Management and Budget, Washington, DC 20503
[Attention: Desk Officer for the Federal Energy Regulatory Commission].
For security reasons, comments should be sent by email to OMB at
oira_submission@omb.eop.gov. Comments submitted to OMB should refer to
FERC-919 and OMB Control Number 1902-0234.
IV. Document Availability
68. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (https://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5:00
p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC
20426.
69. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
70. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or email at
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
public.referenceroom@ferc.gov.
V. Effective Date
71. These regulations are effective July 25, 2016.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By the Commission.
Issued: May 19, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the Commission amends Part 35,
Chapter I, Title 18, Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES AND TARIFFS
0
1. The authority citation for part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
Sec. 35.36 [Amended]
0
2. Amend Sec. 35.36 as follows:
0
a. In paragraph (a)(4), remove the comma and add in its place a
semicolon.
0
b. In paragraph (a)(4), remove the phrase ``sites for generation
capacity development;''.
0
3. Amend Sec. 35.42 by revising paragraphs (a)(1) and (a)(2)(i) to
read as follows:
Sec. 35.42 Change in status reporting requirement.
(a) * * *
(1) Ownership or control of generation capacity or long-term firm
purchases of capacity and/or energy that results in cumulative net
increases (i.e., the difference between increases and decreases in
affiliated generation capacity) of 100 MW or more of capacity based on
nameplate or seasonal capacity ratings, or, for solar photovoltaic
facilities, nameplate capacity, or, for other energy-limited resources,
nameplate or five-year average capacity factors, in any individual
relevant geographic market, or of inputs to electric power production,
or ownership, operation or control of transmission facilities; or
(2) * * *
(i) Owns or controls generation facilities or has long-term firm
purchases of capacity and/or energy that results in cumulative net
increases (i.e., the difference between increases and decreases in
affiliated generation capacity) of 100 MW or more of capacity based on
nameplate or seasonal capacity ratings, or, for solar photovoltaic
facilities, nameplate capacity, or, for other energy-limited resources,
nameplate or five-year average capacity factors, in any individual
relevant geographic market;
* * * * *
0
4. Revise appendix B to subpart H to read as follows:
Appendix B to Subpart H of Part 35--Corporate Entities and Assets
Sample Appendix
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[FR Doc. 2016-12427 Filed 5-25-16; 8:45 a.m.]
BILLING CODE 6717-01-C
