[Federal Register Volume 80, Number 203 (Wednesday, October 21, 2015)]
[Notices]
[Pages 63768-63778]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-26724]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. ER10-2302-005]
Before Commissioners: Norman C. Bay, Chairman; Philip D. Moeller,
Cheryl A. LaFleur, Tony Clark, and Colette D. Honorable; Public Service
Company of New Mexico, Order Accepting Notice of Change in Status,
Rejecting, Without Prejudice, Request for Market-Based Rate
Authorization and Providing Clarification on Submitting Delivered Price
Test Analyses and Simultaneous Transmission Import Limit Studies
1. In this order, we accept the notice of change in status filed by
Public Service Company of New Mexico (PNM) to report a transaction in
which it purchased the interests in Delta Person, Limited Partnership
(Delta Person).\1\ Also in this order, we reject, without prejudice,
PNM's request for market-based rate authority in the PNM balancing
authority area and we reject, without prejudice, the simultaneous
transmission import limit (SIL) values submitted by PNM for the PNM
balancing authority area. We take this opportunity to remind applicants
seeking initial market-based rate authority or seeking to retain such
authority of the type of information and analysis that is useful and
appropriate for our consideration of a Delivered Price Test (DPT) and
what is not. We are providing this information not only to PNM but to
industry broadly with respect to several issues that arose in our
review of the DPT analysis and SIL study prepared by PNM. These issues,
as with others, are recurring across a myriad of applicants. Our goal
in providing this clarification is to promote compliance with the
Commission's regulations and policies in an effort to more timely
process requests for market-based rate authorization and reduce delay.
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\1\ The related acquisition of jurisdictional facilities was
authorized by the Commission in Delta Person, Limited Partnership,
142 FERC ] 62,155 (2013).
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I. Background
2. On August 18, 2014, as amended on December 17, 2014 and February
18, 2015,\2\ PNM filed a notice of change in status notifying the
Commission that, effective July 17, 2014, PNM purchased the interests
in Delta Person, the owner of a 132 megawatt (MW) gas-fired generating
facility located in the PNM balancing authority area. PNM states that
the acquisition does not affect PNM's horizontal market power because,
prior to the acquisition, PNM purchased the full output of the facility
under a long-term contract with Delta Person and, as such, was already
deemed to control the output of that facility.\3\
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\2\ For purposes of this order, the February 18, 2015 amendment
will be referred to as ``Response to the Data Request.''
\3\ August 18, 2014 Filing at 1.
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3. Additionally, PNM requests market-based rate authorization in
the PNM balancing authority area.\4\ PNM states that the market
characteristics in the PNM balancing authority area have changed since
PNM relinquished its market-based rate authority in 2010 and PNM is
therefore seeking to reestablish
[[Page 63769]]
its market-based rate authority in that balancing authority area.\5\
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\4\ PNM states that its tariff reflects that it relinquished its
market-based rate authority in the PNM and El Paso Electric Company
(El Paso Electric) balancing authority areas. Id. at 3 (citing
Public Service Company of New Mexico, Docket No. ER96-1551-022 (Oct.
26, 2010) (delegated letter order)). PNM states that it only seeks
to reestablish its market-based rate authority in the PNM balancing
authority area and not in the El Paso Electric balancing authority
area. Id. at 2 n.4.
\5\ Id. at 4.
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4. PNM included an updated market power analysis with its August
18, 2014 Filing. PNM states that it passes the pivotal supplier screen
and the wholesale market share screen in the summer season; however,
PNM represents that it fails the wholesale market share screen in the
winter, fall, and spring seasons. PNM notes that the failure of the
indicative screens creates a rebuttable presumption of horizontal
market power. However, PNM states it has rebutted that presumption by
demonstrating that PNM passes a DPT analysis for the PNM balancing
authority area.\6\
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\6\ On December 17, 2014, PNM submitted public versions of its
DPT files, explaining that it initially submitted numerous
electronic files related to the DPT analysis on a confidential
basis.
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5. Additionally, PNM submitted historical evidence related to a
request for proposal (RFP) issued by the City of Gallup, New Mexico,
representing that PNM was not selected as the winner and that the
results of the RFP should be considered as alternative evidence to
rebut the presumption that PNM may have market power in the PNM
balancing authority area.\7\
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\7\ Id. at 12-13.
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6. On December 19, 2014, the Director of the Division of Electric
Power Regulation--West requested additional information from PNM with
regard to the DPT analysis and SIL study (Data Request).\8\ On February
18, 2015, PNM submitted a revised DPT analysis and an additional SIL
sensitivity analysis, with revised Submittal 1 and Submittal 2 results,
in response to the request for additional information (Response to the
Data Request).
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\8\ Public Service Company of New Mexico, Docket No. ER10-2302-
005 (Dec. 19, 2014) (delegated letter order). We note that on
January 21, 2015, PNM filed a motion for an extension of time to
file its Response to the Data Request, which was granted. See Notice
of Extension of Time, Docket No. ER10-2302-005 (Jan. 27, 2015).
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II. Notice of Filings
7. Notice of PNM's August 18, 2014 filing, as amended on December
17, 2014 and on February 18, 2015, was published in the Federal
Register,\9\ with interventions and protests due on or before March 11,
2015. Navopache Electric Cooperative, Inc. (Navopache) filed a timely
motion to intervene.
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\9\ 79 FR 50,642; 79 FR 78,081 (2014); 80 FR 10,472 (2015).
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III. Discussion
A. Procedural Matters
8. Pursuant to Rule 214 of the Commission's Rules of Practice and
Procedure, 18 CFR 385.214 (2015), Navopache's timely, unopposed motion
to intervene serves to make it a party to this proceeding.
B. Substantive Matters
9. We accept PNM's notice of change in status filing. However, as
discussed below, we reject, without prejudice, PNM's request for
market-based rate authority in the PNM balancing authority area and
PNM's related SIL study. We find that PNM has failed to rebut the
presumption of horizontal market power in the PNM balancing authority
area, and therefore, has not supported its request for market-based
rate authority in the PNM balancing authority area. Also, as discussed
below, we take this opportunity to identify deficiencies in PNM's DPT
analysis and provide general clarification regarding DPT analyses and
SIL studies. We note that our efforts to provide such clarification in
this order are hampered by the fact that PNM's most recent February 18,
2015 DPT analysis and SIL submittals were all filed as non-public.\10\
Thus, we often cite to earlier public versions of filings instead of
the most recent non-public versions. However, unless otherwise noted,
the discussion is applicable to the most recent non-public version as
well.
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\10\ We encourage filers to submit as much information as
possible as public and only to claim confidential treatment for
information that is exempt from mandatory disclosure under the
Freedom of Information Act, 5 U.S.C. 552. Filers must follow the
requirements in 18 CFR 388.112 (2015) when submitting requests for
privileged treatment of filings.
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C. Market-Based Rate Authorization
10. The Commission allows power sales at market-based rates if the
seller and its affiliates do not have, or have adequately mitigated,
horizontal and vertical market power.\11\ An applicant that fails one
or more of the indicative screens is provided with several procedural
options including the right to challenge the market power presumption
by submitting a DPT analysis.\12\ As discussed in the body of this
order, PNM's DPT analysis includes inaccurate data and modeling errors
and is inconsistent with the Commission's regulations. The deficiencies
pertain to the following: (i) Data integrity; (ii) identification of
potential supply; (iii) calculation of variable costs; (iv) accounting
for power purchase agreements; (v) calculation of transmission rates;
(vi) calculation of available economic capacity (AEC); (vii) use of
historical transaction data to corroborate results; and (viii)
preparation of the SIL study.
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\11\ See 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 PP 62, 399, 408, 440,
clarified, 121 FERC ] 61,260 (2007), order on reh'g, Order No. 697-
A, FERC Stats. & Regs. ] 31,268, clarified, 124 FERC ] 61,055, order
on reh'g, Order No. 697-B, FERC Stats. & Regs. ] 31,285 (2008),
order on reh'g, Order No. 697-C, FERC Stats. & Regs. ] 31,291
(2009), order on reh'g, Order No. 697-D, FERC Stats. & Regs. ]
31,305 (2010), aff'd sub nom. Mont. Consumer Counsel v. FERC, 659
F.3d 910 (9th Cir. 2011), cert. denied, 133 S. Ct. 26 (2012).
\12\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 63.
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1. Horizontal Market Power
11. The Commission adopted two indicative screens for assessing
horizontal market power: the pivotal supplier screen and the wholesale
market share screen.\13\ The Commission has stated that passage of both
screens establishes a rebuttable presumption that the applicant does
not possess horizontal market power, while failure of either screen
creates a rebuttable presumption that the applicant has horizontal
market power.\14\
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\13\ Id. P 62.
\14\ Id. PP 33, 62-63.
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12. PNM prepared the pivotal supplier and wholesale market share
screens for the PNM balancing authority area, consistent with the
requirements of Order No. 697.\15\ We have reviewed these and find that
PNM passes the pivotal supplier screen and the wholesale market share
screen in the summer season with a market share of 18.0 percent, but
fails the wholesale market share screen in the other seasons with
market shares ranging from 24.9 to 26.8 percent.\16\ As a result of
failing the indicative screens in the fall, winter, and spring seasons,
PNM submitted alternative evidence and performed a DPT analysis to
rebut the presumption of horizontal market power in the PNM balancing
authority area.
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\15\ Id. PP 231-232.
\16\ August 18, 2014 Filing, Exhibit No. JMC-3.
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13. As the Commission has previously explained, the DPT analysis
identifies potential suppliers based on market prices, input costs, and
transmission availability, and calculates each supplier's economic
capacity (EC) \17\ and
[[Page 63770]]
AEC \18\ for each season/load period.\19\ The results of the DPT can be
used for pivotal supplier, market share and market concentration
analyses.\20\ Under the DPT analysis, applicants must also calculate
market concentration using the Hirschman-Herfindahl Index (HHI).\21\ An
HHI of less than 2,500 in the relevant market for all seasons/load
periods, in combination with a demonstration that the applicants are
not pivotal and do not possess more than a 20 percent market share in
any of the seasons/load periods, would constitute a showing of a lack
of horizontal market power, absent compelling contrary evidence from
interveners. A detailed description of the mechanics of the DPT
analysis is provided in Order No. 697.\22\
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\17\ The EC of a supplier is defined as ``the amount of
generating capacity owned or controlled by a potential supplier with
variable costs low enough that energy from such capacity could be
economically delivered to the destination market.'' See 18 CFR
33.3(c)(4)(i)(A) (2015).
\18\ The Commission's regulations provide that AEC ``means the
amount of generating capacity meeting the definition of economic
capacity less the amount of generating capacity needed to serve the
potential supplier's native load commitments,'' 18 CFR
33.3(c)(4)(i)(B) (2015).
\19\ The seasons/load periods are as follows: super-peak, peak,
and off-peak, for winter, shoulder, and summer periods and an
additional highest super-peak for the summer.
\20\ See AEP Power Marketing, Inc., 107 FERC ] 61,018, at PP
106-108 (April 14 Order), order on reh'g, 108 FERC ] 61,026 (2004).
\21\ The HHI is the sum of the squared market shares. For
example, in a market with five equal size firms, each would have a
20 percent market share. For that market, HHI = (20)\2\ + (20)\2\ +
(20)\2\ + (20)\2\ + (20)\2\ = 400 + 400 + 400 + 400 + 400 = 2,000.
\22\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 104-117.
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14. As with the indicative screens, applicants and interveners may
present evidence, such as historical sales and transmission data, which
may be used to calculate market shares and market concentration and to
refute or support the results of the DPT analysis. In Order No. 697,
the Commission encouraged applicants to present the most complete
analysis of competitive conditions in the market as the data allow.\23\
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\23\ Id. PP 71, 111.
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15. PNM's DPT analysis for the PNM balancing authority area
indicates that PNM is not pivotal in any season/load period using
either the EC measure or the AEC measure.\24\ Using the AEC measure,
PNM reports market shares below 20 percent in all seasons/load periods
and HHIs below 2,500.\25\ However, using the EC measure, PNM reports
market shares above 20 percent in all seasons/load periods and HHIs
below 2,500.\26\
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\24\ August 18, 2014 Filing, Carey Aff. at 27, Table 4
(Delivered Price Test for the PNM BAA Destination Market Available
Economic Capacity); Id., Carey Aff. at 30, Table 5 (Delivered Price
Test for the PNM BAA Destination Market Economic Capacity). We note
that PNM also submitted sensitivity analyses that separately
analyzed what effect, if any, a 10 percent increase or decrease in
market price would have on the results of its DPT analysis. Id.,
Carey Aff. at 30.
\25\ Id., Carey Aff. at 27, Table 4.
\26\ Id., Carey Aff. at 30, Table 5.
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a. Alternative Evidence--RFP
16. PNM states that the Commission allows a seller to present
alternative evidence to rebut the results of the indicative screens.
PNM requests that the RFP results be considered as additional
alternative evidence to rebut the presumption that PNM may have market
power in the PNM balancing authority area.
17. According to PNM, on September 26, 2013, the City of Gallup
issued an RFP for long-term power supply and scheduling services for a
minimum of five years. The RFP represents that the City of Gallup
serves approximately 10,500 customers and averages approximately
215,000,000 kilowatt-hours (kWh) in annual sales provided from
wholesale energy purchases of around 220,000,000 kWh bought from PNM
and 15,000,000 kWh from Western Area Power Administration. PNM states
that, as the City of Gallup's existing supplier, it responded to the
RFP. PNM further states that the City of Gallup received bids from five
suppliers. Further, PNM represents that it was not selected as the
winner in the RFP and ranked third in the competitiveness of its bid.
PNM states that Continental Divide Electric Cooperative was selected as
the winning bidder, having submitted a bid that was significantly lower
than those submitted by either PNM or the other bidders.
18. PNM contends that the fact that there were a number of bidders
in the RFP, several of whose bids were lower than the bid submitted by
PNM, in and of itself, demonstrates that PNM lacks market power in the
PNM balancing authority area. PNM further states that this alternative
evidence is bolstered by the fact that a neighboring utility that
maintains market-based rate authority in the PNM balancing authority
area also underbid PNM, making it difficult to justify the notion that
PNM has market power. Moreover, PNM states that the RFP is significant
recent real-world evidence that corroborates the results of its DPT
analysis demonstrating that PNM lacks market power in the PNM balancing
authority area.
Commission Determination
19. Although PNM presents this RFP as alternative evidence to rebut
the results of the indicative screens, we find that this alternative
evidence does not sufficiently demonstrate that PNM lacks market power
in that balancing authority area. We do not believe that the City of
Gallup's load is a sufficient proxy for the load PNM served during the
study period.\27\ Further, the results of the RFP may simply reflect
that there are competitors to PNM that can provide a small amount of
long-term power supply and scheduling services for a minimum of five
years less expensively than PNM. However, the Commission's analysis of
horizontal market power includes other factors, such as uncommitted
capacity and system operating conditions during various levels of load
in a relevant geographic market, none of which is addressed by PNM's
alternative evidence. Thus, we are unable to conclude from the RFP
evidence that PNM lacks horizontal market power in the PNM balancing
authority area. Further, PNM does not provide historical sales or
transmission data to rebut the results of the indicative screens.\28\
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\27\ We note that the 215,000,000 kWh translates into
approximately 25 MW of load at a 100 percent load factor
(215,000,000 kWh / 1,000 = 215,000 MWh; 215,000 MWh / 8,760 hours in
a year = 24.5 MW). A load factor of 60 percent would translate into
approximately 41 MW of annual peak load. Either amount is
significantly less than the 2,142 MW of retail requirements,
wholesale load obligation plus off system sales that PNM served
during the summer peak of 2013. See id., Carey Aff. at 11. It is
also less than the 2,563 MW PNM balancing authority annual peak
load. See id., Exhibit No. JMC-3 at 1.
\28\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 75.
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b. DPT Analysis
20. In Order No. 697, the Commission provided the option for a
seller to submit a DPT analysis when that seller fails an indicative
screen.\29\
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\29\ Id. P 105.
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21. The Commission, prior to Order No. 697, provided industry
guidance concerning the DPT in the Merger Policy Statement.\30\ The
Commission provided an overview of the definition of the product market
studied by the DPT analysis, and specifically stated that a key part
``in determining the size of the geographic market is to identify those
suppliers that can compete to serve a given market or customer and how
much of a competitive presence they are in the market. Alternative
suppliers must be able to reach the market both economically and
physically. There are two parts to this analysis. One is determining
the economic capability of a supplier to reach a market. This is
accomplished by a delivered price test. The second part
[[Page 63771]]
evaluates the physical capability of a supplier to reach a
market.''\31\
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\30\ Inquiry Concerning the Commission's Merger Policy Under the
Federal Power Act: Policy Statement, Order No. 592, FERC Stats. &
Regs. ] 31,044 (1996) (Merger Policy Statement), reconsideration
denied, Order No. 592-A, 79 FERC ] 61,321 (1997).
\31\ Id. at 31,130.
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22. The first part of the product market analysis, that is, the
calculation of all potential suppliers given the prevailing market
price. The EC of a supplier is the amount of generating capacity owned
or controlled by a potential supplier with variable costs low enough
that energy from such capacity could be economically delivered to the
destination market. The EC calculation can be described as follows.\32\
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\32\ We note that these steps are not an exhaustive list to
perform a DPT analysis; however, these steps are provided as an
illustration to discuss PNM's DPT analysis.
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23. The first step in calculating a potential supplier's EC is to
calculate the variable cost of each unit.\33\ Commission regulations
state that, at a minimum, these costs include variable operation and
maintenance, including both fuel and non-fuel operation and
maintenance, and environmental compliance. To the extent these costs
are allocated among units at the same plant, allocation methods should
be fully described.\34\ Any generation capacity acquired under long-
term firm purchase contracts (i.e., contracts with a remaining
commitment of more than one year) should be added to the potential
supplier's generation capacity.\35\ In addition, the regulations
provide that ``other generating capacity may also be attributed to
another supplier based on operational control criteria as deemed
necessary, but the applicant must explain the reasons for doing so.''
\36\ The variable cost for contractual capacity acquired, or attributed
to another supplier, should be calculated in the same way as generation
owned or under the direct control of the supplier. Commission
regulations also require that specific information on long-term
purchase and sale data be submitted.\37\
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\33\ Revised Filing Requirements Under Part 33 of the
Commission's Regulations, Order No. 642, FERC Stats. & Regs. ]
31,111, at 31,886 n.39 (2000), order on reh'g, Order No. 642-A, 94
FERC ] 61,289 (2001).
\34\ 18 CFR 33.3(d)(2)(i) (2015).
\35\ 18 CFR 33.3(c)(4)(i)(A) (2015) (specifying that the
potential supplier's capacity is adjusted by subtracting capacity
committed under long-term firm sales contracts and adding capacity
acquired under long-term firm purchase contracts).
\36\ Id.
\37\ 18 CFR 33.3(d)(3) (2015) (``Long-term purchase and sales
data. For each sale and purchase of capacity, the applicant must
provide the following information: (i) Purchasing entity name; (ii)
Selling entity name; (iii) Duration of the contract; (iv) Remaining
contract term and any evergreen provisions; (v) Provisions regarding
renewal of the contract; (vi) Priority or degree of
interruptibility; (vii) FERC rate schedule number, if applicable;
(viii) Quantity and price of capacity and/or energy purchased or
sold under the contract; and (ix) Information on provisions of
contracts which confer operational control over generation resources
to the purchaser.'').
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24. The second step is to add to the estimate of the unit's
variable generation cost any and all applicable transmission costs that
a supplier would incur to deliver the energy into the study area.
Commission regulations state that these costs include the maximum
transmission rate in a transmission provider's tariff as well as the
estimated cost of supplying energy losses.\38\ The costs of ancillary
services incurred to deliver the competing energy into the study area
should also be included.\39\ These costs should be accumulated
beginning at the source of the generation and ending where the
generation sinks in the study area.\40\
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\38\ 18 CFR 33.3(d)(5)(i) and 33.3(d)(5)(iii)(H) (2015).
\39\ 18 CFR 33.3(c)(4) (2015) (``Perform delivered price test.
For each destination market, the applicant must calculate the amount
of relevant product a potential supplier could deliver to the
destination market from owned or controlled capacity at a price,
including applicable transmission prices, loss factors and ancillary
services costs, that is no more than five (5) percent above the pre-
transaction market clearing price in the destination market.''
(emphasis added)).
\40\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at
31,132 (``In contrast, a supplier that is three or four `wheels'
away from the same buyer may be an economic supplier if the sum of
the wheeling charges and the effect of losses is less than the
difference between the decremental cost of the buyer and the price
at which the supplier is willing to sell.'' (emphasis added)).
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25. The final step in calculating economically competitive capacity
is to determine whether the computed generation cost of a unit is price
competitive in the study area. The supplier should compare the computed
cost of a generating unit (including all aforementioned generation,
transmission, and other costs), to the computed market price plus five
(5) percent in the study area.\41\ Generation with a delivered cost
that meets all of the above conditions is referred to as the EC of that
unit.
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\41\ April 14 Order, 107 FERC ] 61,018 at Appendix F
(``[D]etermine the suppliers that could sell into the destination
market at a price less than or equal to 5% over the market price.
That is, determine which generators have costs less than or equal to
1.05 times the market price.''); id., Appendix F n.216 (``The costs
include running costs, transmission charges, [operation and
maintenance] and environmental adders.'').
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26. The AEC of the units and all suppliers must also be calculated.
AEC includes ``capacity from generating units that are not used to
serve native load (or are contractually committed).'' \42\ Accordingly,
AEC is the amount of generating capacity meeting the definition of
economic capacity less the amount of generating capacity needed to
serve the potential supplier's native load commitments, where native
load commitments are ``commitments to serve wholesale and retail power
customers on whose behalf the potential supplier, by statute,
franchise, regulatory requirement, or contract, has undertaken an
obligation to construct and operate its system to meet their reliable
electricity needs.'' \43\ Units that are contractually committed or
needed to serve native load or meet reliable electricity needs are not
available to compete in a DPT analysis.
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\42\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at
31,132.
\43\ 18 CFR 33.3(d)(4)(i) (2015).
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27. Furthermore, as stated in the Merger Policy Statement, the
presumption underlying the AEC measure is that the lowest running cost
units are used to serve native load and other firm contractual
obligations and would not be available for other sales.\44\ Such units
are not available to compete in the DPT analysis.
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\44\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at
31,132.
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28. The second part of the analysis, evaluating whether generation
with AEC can reach the study area, and the use of this information to
compute market shares and concentration statistics, is discussed below.
29. Turning to PNM's calculation, we find that the analysis as
presented is flawed and from it we are unable to conclude that PNM
rebutted the presumption of PNM's horizontal market power in the PNM
balancing authority area. The deficiencies pertain to the following:
(i) Data integrity; (ii) identification of potential supply; (iii)
calculation of variable costs; (iv) accounting for power purchase
agreements; (v) calculation of transmission rates; (vi) calculation of
AEC; (vii) use of historical transaction data to corroborate results;
and (viii) preparation of the SIL study. Each of these items is
discussed further below.
PNM's Calculation of Economic Capacity
i. Data Integrity
30. PNM submitted compact discs (CDs) that included its DPT model
and underlying work papers with links to other data sources that are
not available on its CDs. For instance, when opening some of the files
on the CDs submitted on August 18, 2014 and on February 18, 2015, there
is an error message that states ``There are links to data sources that
cannot be updated.''
31. We remind applicants that including workable links to data
sources in the spreadsheets enables the
[[Page 63772]]
Commission to verify the accuracy of the data sources and to ensure the
accuracy of the submitted DPT.
ii. Identification of Potential Supply
32. PNM appears to have included generating units that are no
longer operational when it calculated EC. EC is the amount of
generating capacity owned or controlled by a potential supplier with
variable costs low enough that energy from such capacity could be
economically delivered to the destination market. Including, for
example, the San Onofre Nuclear Generating Station (San Onofre) as
operational and reporting units 2 and 3 of this plant as having EC in
all seasons of the DPT analysis is inconsistent with the definition of
EC.\45\ Thus, the output of generating facilities, such as San Onofre,
that are not in operation during the seasons studied in a DPT analysis
cannot feasibly be delivered to the destination market and should not
be included in EC.
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\45\ We note that the Velocity Suite database indicates that the
San Onofre plant units 2 and 3 last generated electricity in January
2012, while the study period for the DPT analysis was December 2012
through November 2013. This information is sourced from the Ventyx,
Velocity Suite database in September 2015. We note that the San
Onofre plant is currently in the process of decommissioning. See
Decommissioning of San Onofre, http://www.songscommunity.com.
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33. Similarly, PNM identifies many units as having their output
committed under long-term power purchase contracts, but still considers
the units to have EC in the model. For example, PNM identifies
Whitewater Hill Wind Partners as having EC when Whitewater Hill Wind
Partners has affirmed to the Commission that the output of its facility
is fully committed to an unaffiliated third party.\46\ An entity that
does not own any uncommitted capacity or hold a long-term purchase
contract should not be considered as a potential supplier of EC in a
DPT analysis.\47\ In addition, PNM did not provide the information for
these contracts as required in 18 CFR 33.3(d)(3)(i).
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\46\ Response to the Data Request, Workpaper ``Wkp--Suppliers
Details.xlsx'' (Tab ``AEC By Suppliers--Base Prices''). See also
Whitewater Hill Wind Partners, LLC, Docket No. ER02-2309-000 at 1
(filed July 11, 2002); Whitewater Hill Wind Partners, LLC, Docket
No. ER02-2309-000 (Aug. 29, 2002) (delegated letter order accepting
filing). Note also that the comments in the spreadsheet submitted by
PNM identify Whitewater Hill Wind Partners as being under a long-
term contract. There are additional cells in PNM's spreadsheets that
identify certain generating facilities as having EC or AEC even
though the spreadsheets also show those facilities as being under
long-term contracts.
\47\ We note that here we describe Whitewater Hill Wind Partners
for illustrative purposes only, and not because it is the only
entity listed in PNM's DPT analysis that lacks EC or AEC.
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34. Commission regulations require that a potential supplier's EC
be adjusted by long-term firm contracts.\48\ Units that are committed
to unaffiliated entities under long-term firm contracts should be
attributed to the purchasing entities rather than the owners of those
facilities, and should potentially be included in EC only if the
purchasing entity has EC. Thus, the inclusion of nonoperational units
in the DPT analysis is inappropriate and the output of facilities that
are committed under long-term firm contracts should be attributed to
the purchasing entities and included as EC only if the purchasing
entity has EC. The inclusion of generation from such units distorts the
amount of EC in the DPT analysis. This raises additional concerns that
the DPT results may be inaccurate and unreliable.
---------------------------------------------------------------------------
\48\ 18 CFR 33.3(c)(4)(i)(A) (2015) (``Economic capacity means
the amount of generating capacity owned or controlled by a potential
supplier with variable costs low enough that energy from such
capacity could be economically delivered to the destination market.
Prior to applying the delivered price test, the generating capacity
meeting this definition must be adjusted by subtracting capacity
committed under long-term firm sales contracts and adding capacity
acquired under long-term firm purchase contracts (i.e., contracts
with a remaining commitment of more than one year.'').
---------------------------------------------------------------------------
iii. Calculating Variable Costs
35. As mentioned above, Commission regulations state that for each
generating plant or unit owned or controlled by each potential supplier
in a DPT analysis, the applicant must also provide variable cost
components, which must include at a minimum: (A) variable operation and
maintenance, including both fuel and non-fuel operation and
maintenance; and (B) environmental compliance.\49\
---------------------------------------------------------------------------
\49\ 18 CFR 33.3(d)(2)(i) (2015). Additionally, ``[t]o the
extent costs described in paragraph (d)(2)(i) of this section are
allocated among units at the same plant, allocation methods must be
fully described.'' 18 CFR 33.3(d)(2)(ii) (2015).
---------------------------------------------------------------------------
Variable Cost: Fuel
36. In its August 18, 2014 Filing, PNM states that it constructed a
supply curve ``in the model for each entity by estimating its unit-
specific incremental dispatch costs. The incremental cost is calculated
by multiplying the fuel cost for the unit by the unit's efficiency
(heat rate) and adding any additional variable costs that may apply,
i.e., costs for variable operations and maintenance and costs for
environmental offsets.'' \50\ PNM further clarifies that ``[t]he
characteristics for all of the units included in the analysis,
including their estimated incremental costs, are included in work
papers.'' \51\ PNM states that incremental costs were derived by
multiplying unit specific heat rates (generally from the Energy
Information Administration (EIA) Form 860 or Ventyx) by fuel prices
(from FERC Form 423 for the Study Period, as reported by Ventyx) and
then adding VOM and any applicable environmental adders.
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\50\ August 18, 2014 Filing, Carey Aff. ] 34. We note that
``Ventyx'' is the same database as ``Velocity Suite'' also referred
to as ``Velocity.'' In this order we use the term ``Velocity
Suite'', except for where the term ``Ventyx'' or ``Velocity'' is
used in direct quotes from PNM's filings. We note that the acronym
``VOM'' used above in PNM's description of variable costs is
generally interpreted to mean ``Variable Operations and
Maintenance'' costs.
\51\ August 18, 2014 Filing, Carey Aff. ] 34 n.36.
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37. Fuel is a significant component of variable cost, and natural
gas- and coal-fired generation is a significant portion of the
generation analyzed by PNM.\52\ PNM takes a number of steps to compute
a fuel price for generators to determine whether they are economic in
each of the 10 season/load levels. PNM appears to use natural gas price
data from the ``ICE10x Day Ahead Gas Prices'' for the El Paso Gas
(Permian Basin) and El Paso--South Mainline locations.\53\ Further, PNM
appears to use EIA and Velocity Suite data to compute coal prices
across the Western Electricity Coordinating Council (WECC) region.
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\52\ For instance, natural gas-fired generation accounts for 28
percent of the nameplate generation capacity in the underlying PNM
dataset. See id., Workpaper ``Gas Prices Final.xlsx.''
\53\ See id., Workpaper ``Gas Prices Final.xlsx'' (Tab ``Wkp--
Gas Prices''); December 17, 2014 Filing, Workpaper ``Wkp PNM DPT
Public Inputs.xlsx'' (Tab ``Wkp--Gas Prices,'' Tab ``Wkp--Coal Spot
Prices,'' Tab ``Wkp--Detailed Coal Transactions'').
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38. For natural gas, PNM computes seasonal prices at the two
locations mentioned above by averaging all of the hourly prices for
each location in each season/load level. These two locations seem to be
the hubs that are closest to the PNM balancing authority area. However,
PNM also includes in its spreadsheets hourly gas prices for 22
locations in the WECC region.\54\ The summer average prices for the 22
locations range from $1.88 at ``Questar North Pool'' to $3.27 at
``PG&E-Citygate,'' a variation of almost 74 percent. Although PNM
submitted data for 22 locations, it only used prices from the two hubs
identified above to calculate input costs for all gas-fired generators
in the WECC region.
---------------------------------------------------------------------------
\54\ August 18, 2014 Filing, Workpaper ``Gas Prices Final.xlsx''
(Tab ``Wkp--Gas Prices'').
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39. Additionally, PNM uses only three natural gas prices in its
model, one for each of the summer, winter and shoulder seasons. To do
this, for the one-hour Summer Super Peak 1 (S_SP1)
[[Page 63773]]
season, PNM computes a price of $3.57/MMBtu at El Paso Gas (Permian
Basin) and $3.81/MMBtu at El Paso--South Mainline. In a similar way,
PNM calculates prices for the remaining seasons/load levels at each of
these locations. Next, PNM calculates the average of the El Paso Gas
(Permian Basin) and El Paso--South Mainline seasonal prices in order to
attain 10 average seasonal natural gas prices. PNM then calculates the
average over the four summer seasons/load levels as the summer natural
gas price, and uses that as the natural gas price for all four summer
seasons/load levels in its model. PNM calculates Winter and Shoulder
seasonal natural gas prices similarly.
40. Further, PNM submitted work papers that include an average coal
price for 83 plants with unique EIA identification numbers. Only seven
of these plants appear to be in the WECC region, although there are
more than seven coal-fired plants in WECC. These average prices were
calculated from monthly ``Detailed Coal Transactions From December 2012
to November 2013,'' \55\ but not every plant has an average price for
each month and some plants include more than one average price for some
months. The average prices for the seven WECC plants range from $1.42
to $2.52 per MMBtu, but do not account for any seasonality in coal
prices. In its generation dataset, PNM appears to attribute the
calculated coal price for each of the seven plants as that plant's
input cost, but then uses the average of all seven as the input price
for all other coal-fired generators in the WECC.
---------------------------------------------------------------------------
\55\ December 17, 2014 Filing, Workpaper ``Wkp PNM DPT Public
Inputs.xlsx'' (Tab ``Wkp--Detailed Coal Transactions'').
---------------------------------------------------------------------------
41. Sellers should account for some measure of regional differences
in fuel price. As described above, PNM used one natural gas price for
each of the three seasons' seasonal gas price estimate for all gas-
fired generation in the entire WECC, which are derived from the average
prices at two hubs. That is, PNM used the same natural gas fuel costs
for generators in Alberta, Northern and Southern California and New
Mexico even though PNM's own spreadsheets detail the locational
variation in natural gas prices across the WECC region. As explained
above, the fuel cost of each generating facility is one of the main
factors in determining whether the output of that facility should be
included as EC in a DPT analysis. Oversimplifying the variable cost
calculations by assuming that all gas-fired generators have the same
input cost regardless of their location may cause certain units, whose
actual gas prices are lower than these averages, to be inappropriately
considered uneconomic and may cause units whose actual gas prices are
higher than these averages to be inappropriately considered economic.
Thus, regional price variation for input fuels should be considered in
a model that includes competing supply capacity from a large geographic
footprint, and a generator's fuel cost should be estimated from a
nearby price point unless the seller explains why another methodology
is reasonable. Furthermore, we note an apparent contradiction between
the seven coal prices used in the generation data set and the single
coal price reported for WECC of $1.97 \56\ in the Fuel Prices Summary
worksheet. However, as with natural gas prices, we would expect a coal-
fired generator's fuel cost to be estimated from a nearby price point
and not an average of several price points across a region as large as
WECC.
---------------------------------------------------------------------------
\56\ Id., Workpaper ``Wkp PNM DPT Public Inputs.xlsx'' (Tab
``Wkp--Fuel Prices Summary''). PNM used a price of $1.97 for Winter,
Summer, and Shoulder season.
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42. For the reasons stated above, we cannot conclude that PNM has
rebutted the presumption of market power because of the flaws in its
analysis.
Variable Cost: Operations and Maintenance
43. As mentioned above, Commission regulations state that sellers
must calculate, at a minimum, variable cost for a unit used in the DPT
analysis. For each such generating unit, the seller must also provide
variable cost components, which include operation and maintenance
costs.\57\
---------------------------------------------------------------------------
\57\ 18 CFR 33.3(d)(2) (2015).
---------------------------------------------------------------------------
44. PNM's DPT model contains a worksheet, ``Generation Dataset,''
that contains variable cost calculations for the WECC generators that
PNM included in its model. There are 4,293 observations in this dataset
and 2,118 of these observations have a zero dollar cost for VOM.\58\ We
note that a vast majority of these observations with a zero dollar cost
for VOM are from renewable resources.
---------------------------------------------------------------------------
\58\ December 17, 2014 Filing, Workpaper ``Wkp PNM DPT Public
Inputs.xlsx'' (Tab ``Generation Dataset'').
---------------------------------------------------------------------------
45. Although the Data Request did not specifically request that PNM
provide actual values for VOM costs, we take this opportunity to
provide clarification to PNM and other DPT filers. Although VOM costs
may be a small component of hourly costs, we do not expect these costs
for most generating units to have a zero value \59\ because all
generation technologies require maintenance or have at least some
operational costs to produce electricity. PNM states that it uses
Velocity Suite data in its model. We note that Velocity Suite provides
cost estimates for various renewable generation technologies. PNM has
not explained why it assumed a zero cost for VOM when estimates for
this cost are available for most types of renewable generation from
Velocity Suite.\60\
---------------------------------------------------------------------------
\59\ We note that although EIA states that wind generation has a
relatively small VOM cost, EIA uses a zero cost for all non
dispatchable generation in its Annual Energy Outlook 2015 Reference
Case model. See EIA, Levelized Cost and Levelized Avoided Cost of
New Generation Resources in the Annual Energy Outlook 2015 (June
2015), available at http://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf.
\60\ A Velocity Suite supply curve for the PNM balancing
authority area for July 31, 2013, provides a range of VOM cost
estimates for most types of renewable generation. Specifically,
Velocity Suite provides a VOM in $/MWh of $1.26 to $1.56 for the
hydro plants; $1.90 to $2.06 for photovoltaic generation; $1.25 for
energy storage devices; and $4.79 for biomass facilities. Velocity
Suite does not provide a VOM cost for wind generation. Velocity
Suite states that its estimates are based on many sources of unit or
plant data and are calculated in an internal model.
---------------------------------------------------------------------------
46. Therefore, it appears that PNM underestimates the variable cost
of a significant portion of generation in its DPT model, which
potentially overestimates the amount of EC calculated in its DPT
analysis.
iv. Accounting for Purchase Contracts
47. As mentioned above, another step in the calculation of a
supplier's EC is accounting for long-term firm purchase contracts. EC
refers to ``the amount of generating capacity owned or controlled by a
potential supplier with variable costs low enough that energy from such
capacity could be economically delivered to the destination market.''
\61\ The Commission's regulations require that ``the generating
capacity meeting this definition must be adjusted by subtracting
capacity committed under long-term firm sales contracts and adding
capacity acquired under long-term firm purchase contracts (i.e.,
contracts with a remaining commitment of more than one year).'' \62\
The regulations further provide that ``capacity associated with any
such adjustments must be attributed to the party that has authority to
decide when generating resources are available for operation'' and
notes that ``other generating capacity may also be attributed to
another supplier based on operational control criteria as deemed
[[Page 63774]]
necessary, but the applicant must explain the reasons for doing so.''
\63\
---------------------------------------------------------------------------
\61\ See 18 CFR 33.3(c)(4)(i)(A) (2015).
\62\ Id.
\63\ Id.
---------------------------------------------------------------------------
48. As noted above, Commission regulations require information on
all long-term firm purchases and sales ``for each sale and purchase of
capacity'' as part of the DPT analysis.\64\ A seller performing a DPT
analysis should account for the purchase contracts of potential
suppliers because the contracts may affect the competitive situation of
a supplier in a DPT analysis. A supplier with a contractual obligation
to sell energy or capacity may not have any AEC to be considered as
competing in the DPT analysis. Conversely, a supplier with the
contractual obligation to purchase supply may have excess energy and
become a potential supplier in the DPT analysis. The determination of
whether a supplier with purchase contracts has EC or AEC depends on a
number of factors specific to that supplier such as the supplier's
native load (if any), the amount of generation the supplier has to meet
that load, including any contracts the supplier has to buy or sell
energy or capacity, and the prevailing market price. These specific
factors should be accounted for in a DPT analysis to determine whether
a potential supplier with purchase contracts is a potential competitor.
---------------------------------------------------------------------------
\64\ See 18 CFR 33.3(d)(3). See also n.37 above.
---------------------------------------------------------------------------
49. The Data Request sought information from PNM concerning how
certain sellers could be considered competitive suppliers for purposes
of the DPT analysis when each of those seller's native load appeared to
exceed its generation capacity. Specifically, PNM was asked to explain
whether one particular supplier, Tri State Generation & Transmission
Association Inc. (TriState), could have any uncommitted capacity to
compete with PNM given that TriState's peak load is reported to be
greater than its generation capacity. The Data Request did not
specifically identify any other sellers in a similar situation to
TriState. However, the Data Request directed PNM to identify every
potential supplier for whom its study deducted native load obligations,
the amount of those obligations and the source of their native load
values.\65\ Finally, the Data Request directed PNM to adjust its model
as needed to reflect TriState and other sellers that have load greater
than their respective uncommitted capacity.\66\
---------------------------------------------------------------------------
\65\ See Data Request, Question No. 5, at 4.
\66\ See Data Request, Question No. 6, at 4.
---------------------------------------------------------------------------
50. In its Response to the Data Request, PNM stated that there are
differences between the reporting in the data sources that the
Commission used to formulate its questions and the data source(s) PNM
used in its calculation of competitive supply. PNM further added that
TriState ``has substantial purchase agreements, including ownership in
[WECC] output facilities that would not be tracked by Velocity.'' \67\
PNM did not mention any other sellers who might be in this similar
situation.
---------------------------------------------------------------------------
\67\ Response to the Data Request at 8.
---------------------------------------------------------------------------
51. We appreciate PNM's Response to the Data Request but find that
more information is necessary. While PNM provided information on
TriState's purchasing, it did not disclose the amount of power
purchased under these contracts that would enable TriState to meet its
native load requirements and have sufficient generation to be a
competitive supplier in the DPT analysis. PNM also did not meet the
reporting requirements for long-term contracts of sales and purchases
in 18 CFR 33.3(d)(3) for TriState or for any other suppliers, such as
Whitewater Hill Wind Partners, whose output is fully committed under
long-term contract to another entity. Additionally, in its Response to
the Data Request, PNM did not indicate whether there are other
potential suppliers with long-term contracts or adjust its model to
reflect any other potential suppliers with native load obligations
greater than their respective generation capacity.
52. Generation units in a supplier's portfolio whose output is
committed under long-term firm contracts should not be considered
available to compete in the study area as AEC. Including such capacity
may overstate the amount of AEC that a potential supplier can
contribute or inaccurately attribute that capacity to the wrong
potential supplier in a DPT analysis. Additionally, incorrectly
attributing capacity to sellers that have sold the output of their
facilities to unaffiliated entities under purchase power agreements
impacts the market concentration results of the DPT analysis. Lastly,
PNM did not adjust its model as requested in the Data Request or
otherwise explain that such adjustment was not required. For these
reasons, we are unable to rely on PNM's DPT analysis.
v. Transmission Rates
53. As mentioned above, Commission regulations require a DPT
analysis to account for any and all applicable transmission costs that
a supplier would incur to deliver the energy into the study area and
add these costs to the estimate of the available unit's variable
generation cost. Commission regulations state that these costs must
include the maximum transmission rate in a transmission provider's
tariff as well as the estimated cost of supplying energy losses.\68\
---------------------------------------------------------------------------
\68\ 18 CFR 33.3(d)(5) (2015).
---------------------------------------------------------------------------
54. PNM did not include all applicable transmission costs in its EC
calculation. In the December 17, 2014 Filing, PNM's DPT analysis used a
universal $2.00 transmission rate for all peak periods and a $1.00
transmission rate for all off-peak periods for all generators,
regardless of location.\69\
---------------------------------------------------------------------------
\69\ December 17, 2014 Filing, Workpaper ``Wkp PNM DPT Public
Inputs.xlsx'' (Tab ``Wkp--TTC and Tx Rates'').
---------------------------------------------------------------------------
55. In the Data Request, PNM was requested to provide the
transmission rate schedule for the PNM balancing authority area and all
of the balancing authority areas where competing suppliers are located,
and to provide cites to the relevant open access transmission
tariff(s).\70\ The Data Request asked PNM to explain if the
transmission rates used in its DPT analysis are the maximum rates for
the PNM balancing authority area and the balancing authority areas
where the DPT analysis indicates there is competitively priced
generation.\71\ Finally, the Data Request directed that, if those are
not the maximum rates, PNM should re-run the AEC calculations to
include the cost to traverse each balancing authority area using the
maximum `up to' transmission rate when PNM re-runs the DPT model.\72\
---------------------------------------------------------------------------
\70\ Data Request, Question No. 14a, at 6.
\71\ Id., Question No. 14b, at 6-7.
\72\ Id., Question No. 14c, at 7.
---------------------------------------------------------------------------
56. In Response to the Data Request, PNM stated that it assumed
transmission rates for purposes of the model because it lacks details
on specific transmission rates for some of the WECC transmission
providers. PNM stated that this assumption has a de minimis impact on
the results of the analyses. PNM also provided a spreadsheet that
identifies the 24 individual balancing authority areas in WECC, their
minimum and maximum transmission rates, information on the rate
schedules for these balancing authority areas and screen snapshots of
the appropriate Open Access Same Time Information System (OASIS) Web
sites where PNM retrieved the maximum and minimum rates.\73\
---------------------------------------------------------------------------
\73\ See Response to the Data Request, ``WECC OATT Rates.xlsx.''
---------------------------------------------------------------------------
57. We note that these maximum rates for the peak periods ranged
from $1.26 to $10.02 and averaged $4.96. Likewise, the maximum rates
for the off-peak periods ranged from $0.72 to $9.00 and averaged $3.59.
In Response to the Data Request, PNM provided a sensitivity analysis
that used the average of these
[[Page 63775]]
maximum transmission rates to update its DPT model.\74\ PNM complied
with the first part of Question 14 by identifying that the $2.00 and
$1.00 transmission rates are not the maximum rates for the peak and
off-peak periods, respectively. PNM also identified the 24 source
balancing authority areas and provided a link and screen snapshots of
the OASIS Web sites for these balancing authority areas that display
their maximum and minimum rates.
---------------------------------------------------------------------------
\74\ See id.
---------------------------------------------------------------------------
58. However, we find the remaining portion of PNM's Response to the
Data Request to be unresponsive to the question asked and not in
compliance with Commission regulations. PNM did not re-run the DPT
analysis with the maximum rate for each balancing authority area as
requested in the Data Request \75\ and required by Commission
regulations.\76\ Furthermore, PNM did not calculate any additional
costs for transmission losses or ancillary services necessary to
deliver energy into the study area, as required by Commission
regulations.\77\ For capacity outside of the study area, PNM did not
consider additional transmission charges that a competing generator
would likely incur to deliver power to the destination market.
Therefore, we find that PNM's calculations underestimate the
transmission cost component for most observations in its dataset and
further compromise the results of the DPT analysis.
---------------------------------------------------------------------------
\75\ Data Request, Question No. 14c, at 7 (``If the rates used
in your model are not the maximum rate, please re-run your AEC
calculations using the maximum `up to' transmission rate to include
the cost to traverse each balancing authority when you re-run your
DPT model.'').
\76\ 18 CFR 33.3(d)(5) (2015).
\77\ 18 CFR 33.3(d)(5) (2015).
---------------------------------------------------------------------------
vi. Calculation of AEC
59. As mentioned above, alternative suppliers should be able to
reach the market both economically and physically.\78\ First, we
discuss how to determine the AEC of a supplier.
---------------------------------------------------------------------------
\78\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at
30,130.
---------------------------------------------------------------------------
60. After computing the EC of potential competing suppliers, an
applicant should compute the AEC of those suppliers. AEC is ``the
amount of generating capacity meeting the definition of EC less the
amount of generating capacity needed to serve the potential supplier's
native load commitments.'' \79\ We note that the Commission has relied
more heavily on AEC in the DPT analysis when utilities have significant
native load.\80\ Further, in Order No. 697, the Commission stated that
``in markets where utilities retain significant native load
obligations, an analysis of available economic capacity may more
accurately assess an individual seller's competitiveness, as well as
the overall competitiveness of a market, because available economic
capacity recognizes the native load obligations of the sellers.'' \81\
---------------------------------------------------------------------------
\79\ 18 CFR 33.3(c)(4)(i)(B) (2015).
\80\ Great Plains Energy, Inc., 121 FERC ] 61,069, at P 34 &
n.44 (2007), reh'g denied, 122 FERC ] 61,177 (2008); Nat'l Grid,
plc, 117 FERC ] 61,080, at PP 27-28 (2006), reh'g denied, 122 FERC ]
61,096 (2008); Westar Energy, Inc., 115 FERC ] 61,228, at P 72,
reh'g denied, 117 FERC ] 61,011, at P 39 (2006); Nev. Power Co., 113
FERC ] 61,265, at P 15 (2005).
\81\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 112.
---------------------------------------------------------------------------
61. The Data Request directed PNM to explain whether its DPT model
first allocated the lowest running cost units to a supplier's native
load and cited to the Merger Policy Statement.\82\ In Response to the
Data Request, PNM stated, in part, that ``[t]he model implicitly
allocates PNM's lowest running cost units to serve native load for PNM
and non-PNM suppliers to their native load (non-PNM load) by the
derivation of the [AEC]. The DPT model does not rank order each
supplier's generating units from lowest to highest running cost but
rather aggregates all [EC] for each supplier within the seasonal/load
periods analyzed.'' \83\
---------------------------------------------------------------------------
\82\ Data Request, Question No. 4, at 3 (``In the [AEC]
calculation, please explain whether the model first allocates PNM's
lowest running cost units to serve native load for PNM. Please
explain whether the model allocates the lowest running cost units of
non-PNM suppliers to their native load (non-PNM load).''). The Data
Request noted that ``AEC includes `capacity from generating units
that are not used to serve native load (or are contractually
committed) and whose variable costs are such that they could deliver
energy to a market at a price close to the competitive price in the
market. The presumption underlying this measure is that the lowest
running cost units are used to serve native load and other firm
contractual obligations and would not be available for other
sales.''' Data Request, Question No. 4 n.6, at 3 (citing Merger
Policy Statement, FERC Stats. & Regs. ] 31,044 at 30,132).
\83\ Response to the Data Request at 7.
---------------------------------------------------------------------------
62. In the Merger Policy Statement, the Commission stated that the
AEC measure ``includes capacity from generating units that are not used
to serve native load (or are contractually committed).'' \84\ However,
PNM stated that ``[t]he DPT model does not rank order each supplier's
generating units from lowest to highest running cost but rather
aggregates all economic capacity for each supplier within the seasonal/
load periods analyzed.'' \85\ Further, it is unclear how PNM's model
might implicitly allocate an entity's lowest running cost units to
serve its native load. Based on this response, we conclude that PNM did
not allocate the lowest cost units of itself and its competitors to
serve their respective native load. Therefore, we are unable to rely on
the reported results of potential competitive AEC suppliers and whether
they accurately reflect the costs of the competitive generation in the
market.
---------------------------------------------------------------------------
\84\ Merger Policy Statement, FERC Stats. & Regs. ] 31,044 at
30,132.
\85\ Response to the Data Request at 7 (emphasis added).
---------------------------------------------------------------------------
vii. Historical Transaction Data to Corroborate Results
63. Commission regulations state that ``[t]he applicant must
provide historical trade data and historical transmission data to
corroborate the results of the horizontal Competitive Analysis
Screen.'' \86\ Commission regulations also state that the applicant
must provide data and information used in calculating the EC and AEC
that a potential supplier could deliver to a destination market,
including transmission capability, transmission constraints and firm
transmission rights.\87\ Further, Commission direction has been to
provide a ``trade data check'' to support the results of the DPT
analysis.\88\
---------------------------------------------------------------------------
\86\ 18 CFR 33.3(c)(6) (2015).
\87\ See 18 CFR 33.3(d)(7)-(9) (2015).
\88\ See Merger Policy Statement, FERC Stats. & Regs. ] 31,044
at 30,133 (``It would be expected that there be some correlation
between the suppliers included in the market by the delivered price
test and those actually trading in the market. As a check, actual
trade data should be used to compare actual trade patterns with the
results of the delivered price test. For example, it may be
appropriate to include current trading partners in the relevant
market even if the above analysis indicates otherwise.'').
---------------------------------------------------------------------------
64. The Data Request directed PNM to identify suppliers with AEC
and document their contribution to competing supply entering the PNM
study area.\89\ In its Response to the Data Request, PNM provided a
spreadsheet that complied with the request by identifying all
generation units, their location, and the identity of the suppliers
with non-zero contribution to the AEC calculation.\90\
---------------------------------------------------------------------------
\89\ Data Request, Question No. 15, at 7 (``Please provide the
following information for each supplier with a non-zero contribution
to the available economic capacity in the study area of your model:
the full name of each supplier, the name of the unit(s) that
supplied the energy, the amount of energy supplied by each unit(s)
in megawatts and the balancing authority area location of the
unit(s) for each of the 10 load level/study periods.'' (footnote
omitted)).
\90\ Response to the Data Request at 12 & Workpaper ``Wkp--
Suppliers Details.xlsx.''
---------------------------------------------------------------------------
65. Although the Data Request did not specifically ask PNM to
provide historical transaction data to corroborate the results of its
DPT analysis, we take this opportunity to provide clarification for PNM
and others who may file a DPT
[[Page 63776]]
analysis in a section 205 proceeding in order to rebut the presumption
of market power. PNM did not submit historical transaction data or
transmission data to corroborate the results of its model as required
by 18 CFR 33.3(c)(6). For example, although PNM indicates in its
Response to the Data Request that its model includes significant
generation capacity from the California Independent System Operator
Corporation (CAISO) market as available to compete in the PNM balancing
authority area, PNM did not submit historical transaction data or
transmission data to corroborate this. PNM could have submitted eTag
data to demonstrate flows from CAISO were consistent with its DPT
model. Moreover, the Commission's review of eTag data was not able to
corroborate PNM's results. Without such information, we are concerned
that the amount of competing generation capacity imported into the PNM
study area in PNM's DPT analysis is not supported by historical trade
or transmission data and is overstated. We remind DPT filers that they
should provide historical trade and transmission data and explain
significant discrepancies between modeling results and such data.
viii. SIL Study
66. As mentioned above, alternative suppliers must be able to reach
the market both economically and physically. We provide clarification
regarding determining the physical capability of a supplier with EC and
AEC to reach the study area.\91\
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\91\ In this order, we do not discuss the ultimate DPT
calculations, combining the economic and physical analyses to create
market share and concentration indices because we do not believe
that the first two steps of the PNM DPT analysis provide a
reasonable foundation to examine this final step.
---------------------------------------------------------------------------
67. The physical ability of a supplier to reach the market or study
area requires the use of a SIL study as a basis for transmission access
for both the indicative screens and the DPT analysis.\92\ In Order No.
697, the Commission clarified that the SIL study as shown in Appendix E
of the April 14 Order is the only study that meets the Commission's
requirements for the DPT analysis and the indicative screens.\93\ In
the April 14 Order, the Commission set the amount of supply that can
reach the relevant market as uncommitted capacity limited by the
simultaneous transmission import capability.\94\ In Puget Sound Energy,
Inc., the Commission consolidated and clarified its direction regarding
SIL studies given in previous orders and provided required formats for
submitting SIL data.\95\ Specifically, the Commission directed filers
to submit their SIL data in the format provided in Appendix B of Puget
in order to properly summarize and document their SIL study
results.\96\
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\92\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 19.
\93\ Id. (``With regard to [SILs], the Commission adopts the
requirement that the SIL study be used as a basis for transmission
access for both the indicative screens and the DPT analysis.
Further, the Commission clarifies that the SIL study as shown in
Appendix E of the April 14 Order is the only study that meets our
requirements.'').
\94\ April 14 Order, 107 FERC ] 61,018 at Appendix E.
\95\ Puget Sound Energy, Inc., 135 FERC ] 61,254 (2011) (Puget).
\96\ Submittal 1 of Appendix B of Puget contains a summary table
of components used to calculate SIL values and provides a
spreadsheet format with numerical examples. Submittal 2 provides a
spreadsheet for identification of long-term firm transmission
reservations used to import power from seller and affiliate
generating resources in a first-tier area to serve native load in
the study area.
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68. The SIL study calculates the aggregated simultaneous transfer
capability into the balancing authority area being studied. It is
intended to provide a reasonable simulation of historical conditions
and is not a theoretical maximum import capability or best import case
scenario.\97\ A simplified view of the SIL study is that it
simultaneously increases generator output in one area, the first-tier,
and decreases generator output in another area, the study area. As the
source of generation is incrementally shifted, single contingency
conditions are tested in both areas while the relevant transmission
elements are monitored for overloads.\98\ A ``single contingency
condition'' is the unexpected failure of a single system component,
such as a generator, transmission line, circuit breaker, switch or
other electrical equipment.\99\ The Commission direction has been to
increase or ``scale up available generation in the exporting
(aggregated first tier areas) and scale down the study area resources
according to the same methods used historically in assessing available
transmission for non-affiliate resources.'' \100\
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\97\ Puget, 135 FERC ] 61,254 at Appendix B (citing Order No.
697, FERC Stats. & Regs. ] 31,252 at P 354).
\98\ See, e.g., Puget, 135 FERC ] 61,254, Appendix B, Sec. I.D
(Prior Commission Direction on Scaling).
\99\ Id. Appendix B (citing Carolina Power & Light Co., 128 FERC
] 61,039, at P 8 n.7 (2009)).
\100\ April 14 Order, 107 FERC ] 61,018 at Appendix E.
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69. The Commission recognizes that it is a complex process for a
seller to estimate transmission capability using the model of its
transmission system in a simplified manner so that elements are
accurately accounted for in SIL studies. Therefore, the Commission
previously has provided guidance so that sellers can more accurately
measure the amount of available transmission capability into the study
area. One area of concern has been the proper modeling and scaling of
jointly-owned generating plants in a SIL study, particularly when units
have long-term firm transmission reservations.\101\ The Commission has
determined that these remote plants should be dispatched at their
historical output levels and should not be scaled down as doing so
would be unrealistic and inconsistent with historical practices.\102\
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\101\ A long-term firm transmission reservation is a reservation
that is 28 days or longer. See Order No. 697, FERC Stats. & Regs. ]
31,252 at P 368 (``While we find that firm transmission reservations
less than or equal to 28 days in duration are usually unpredictable,
we believe that firm transmission reservations of a longer duration
are not related to the unpredictable nature of real time events and
are based upon planned and predictable events. Therefore, the
Commission will require sellers to account for firm and network
transmission reservations having a duration of longer than 28
days.'').
\102\ See Pinnacle West Capital Corp., 117 FERC ] 61,316, at P 6
(2006) (Pinnacle West).
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70. In Pinnacle West,\103\ the Commission identified errors and
provided guidance and clarification as to how the SIL study should be
revised to satisfy the Commission's requirements. The PNM SIL study
presents issues similar to those presented by the SIL study at issue in
Pinnacle West. With regard to the PNM SIL study, the Data Request noted
that some units within the study area have long-term firm commitments
to serve load outside of the study area. The Data Request noted that
the Commission expects that any such unit's generation that has been
committed with long-term firm transmission reservations would be
considered unavailable for scaling; however, it appears that some such
units were scaled down during the SIL study. Therefore, the Data
Request required PNM to identify all generation units within the PNM
balancing authority area that have long-term firm transmission
reservations (to serve study area load or to export power to the first-
tier), describe whether the unit's output level was either maintained
or scaled in the SIL study, and adjust the SIL study as necessary.\104\
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\103\ Id. P 3.
\104\ Data Request, Question No. 2, at 2 (citing Pinnacle West,
117 FERC ] 61,316 at P 6; April 14 Order, 107 FERC ] 61,018 at
Appendix E).
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71. In its Response to the Data Request, PNM filed revised work
papers and SIL information. PNM also submitted a table listing the
long-term firm transmission reservations for exports out of the PNM
balancing
[[Page 63777]]
authority area and the corresponding source generator within the study
area. This table indicates that these generation units are jointly-
owned by PNM and other entities, and that the non-PNM owned portions of
these units are committed with long-term firm transmission reservations
to export out of the study area (i.e., the PNM balancing authority
area). However, based on the power flow models submitted by PNM in the
original SIL study, it is evident that PNM scaled down these jointly-
owned generation units, including portions belonging to other
owners.\105\ In addition, PNM provided Submittal 1 and Submittal 2
tables which reported the results of two sensitivities that PNM
conducted in response to the scaling guidance in the Data Request.
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\105\ August 18, 2014 Filing, Stahlhut Aff. Exhibit JWS-3.
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72. PNM's first sensitivity study ``does not scale resources with
potential commitments outside of the PNM [balancing authority area].''
\106\ The second sensitivity ``scales half of the resources with
potential commitments outside of the PNM [balancing authority area].''
\107\ However, for both sensitivities, PNM stated that ``the associated
export reservations are recognized as long-term firm commitments to be
consistent and reflect the equal but opposite effect to import
reservations and compensate for prematurely limiting the imports below
the physical limit of the transmission system or load within the study
area. The export reservations are reflected in the SIL sensitivity
analyses by inclusion in Table 2 [of Submittal 2].'' \108\
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\106\ Response to the Data Request at 3. We interpret PNM's
language ``resources with potential commitments'' to mean the long-
term firm transmission reservations capacity or export reservations
of the units within the PNM balancing authority area that have long-
term firm transmission reservations to serve load in the first tier.
\107\ Id. at 4.
\108\ Id. at 3-4.
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73. The practice of capturing long-term firm export reservations in
Submittal 2 is inconsistent with the instructions and purpose of
Submittal 2, which is to identify and sum the long-term firm
transmission reservations from affiliated remote generating resources
in the first-tier to serve native load in the study area.\109\ Export
reservations are long-term firm transmission reservations from the
study area to the first-tier to serve first-tier load; because the
exports are commitments from capacity that belongs to the first-tier,
these export reservations should not be captured in Submittal 2. As
such, the Commission cannot utilize these sensitivities as support for
PNM's SIL study. Furthermore, while the scaling method used in the
first sensitivity is consistent with guidance given in the Data
Request, the ownership and commitments of the generation units was not
apparent in the original August 18, 2014 Filing or the December 17,
2014 Filing. Thus, we believe that further clarification is warranted
on the modeling and treatment of jointly-owned units in SIL studies.
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\109\ Puget, 135 FERC ] 61,254, at Appendix B, Sec. II.B.
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74. In Puget, the Commission stated that ``[i]n the case of
jointly-owned power plants, the plant's capacity should be allocated
among the generator owners' balancing authority areas according to its
ownership percentages.'' \110\ Additionally, the Commission has stated
that a seasonal benchmark case model should simulate historical
seasonal conditions that were present during the modeled season. The
Commission has stated that ``[a]ny generating units owned by the study
area utility that are located in the first-tier area, including the
study area utility's portion of jointly-owned units[,] should be
modeled . . . in the first-tier area.'' \111\ In addition, ``any long-
term reservations from these facilities used to serve study area native
load shall be included in the study area net area interchange.'' \112\
While this statement references jointly-owned generating units located
in the first-tier area, we believe that it is reasonable to treat
jointly-owned generating units located within the study area committed
to serving first-tier load similarly. As portions of these units belong
to unaffiliated entities located in the first-tier area, they should
not be scaled down; doing so would misrepresent the incremental
transfer capability of the study area by reducing generation that
actually has commitments to first-tier load.\113\ This has the effect
of allowing more first-tier generation into the study area than is
actually available to be displaced in the study area.
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\110\ Id. P 18.
\111\ Id., Appendix B, II.D at 4.3.7.
\112\ Id.
\113\ See id., Appendix B, Sec. II.D (Submittal 4: Seasonal
Benchmark Case) (4.3.7 and 4.3.8 discuss how jointly-owned units
should be modeled according to historical dispatch).
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75. Thus, we clarify that, for purposes of generation scaling for
the SIL, the appropriate method of modeling a generation unit in the
study area that is jointly-owned between the seller and one or more
unaffiliated sellers in the first-tier area is to represent the unit as
multiple units in the model based on ownership percentage such that the
multiple units fully represent the generation commitments and impacts
on the transmission system. One unit will represent the seller's
generation capacity in the study area, and one or more additional units
will represent the capacity owned by unaffiliated entities within the
first-tier area.\114\ The seller's unit will remain modeled within the
study area balancing authority area while the portion of the unit(s)
belonging to unaffiliated first-tier sellers will be given the
appropriate first-tier balancing authority area number in the model.
Importantly, we note that this method retains the same physical
location of the unit within the transmission network as modeled;
however, the portion of the unit(s) belonging to the unaffiliated
first-tier sellers would not be considered a study area generator for
purposes of calculating net area interchange. We also note that with
this method, the seller's generation capacity can appropriately be
scaled down, and the portion of the unit(s) belonging to the
unaffiliated first-tier sellers now modeled in the first-tier area can
appropriately be scaled up to serve study area load if it is not
committed under long-term firm transmission reservations. Additionally,
any generating resources in the first-tier with long-term firm
transmission reservations to serve study area load should be reported
as a long-term firm transmission reservation in Submittal 2.\115\
Furthermore, entities are required to ``[p]rovide a listing of first-
tier area generating units and portions of jointly-owned first-tier
area generating units to be scaled-up in the first-tier area, including
any first-tier area generation or portions of jointly-owned first-tier
area generating units physically located within the study area,
according to the same methods used historically in assessing available
transmission for non-affiliate resources.'' \116\ Entities should
identify their jointly-owned units, report the ownership breakdown, and
indicate what scaling, if any, was utilized for each portion of the
generator.
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\114\ In Puget, the Commission approved NorthWestern's use of
this general method to represent the jointly-owned Colstrip plant.
The model represented separate generators for each owner, each with
one owner's portion of Colstrip's total capacity. Id. P 18.
\115\ Id., Appendix B, II.B, Instruction 3.
\116\ Id., Appendix B, II.G (Submittal 7: The Sub-System File)
(7.2.1).
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76. Finally, we clarify that entities should complete the
``Description of Remote Resources'' column as necessary
[[Page 63778]]
in each row of Submittal 2.\117\ We expect that, at a minimum, entities
will indicate the balancing authority area from which these remote
resources are sourced.
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\117\ Id., Appendix B, II.B (Submittal 2: Identification of
Long-Term Firm Transmission Reservations used to Import Power for
Generating Resources in the First-Tier Area to Serve Native Load in
the Study Area) (Instruction 2).
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Conclusion
77. As described above, we are unable to validate the results of
PNM's SIL model, its calculations of EC and AEC, and its DPT analysis.
Thus, we find that PNM has not adequately rebutted the presumption of
horizontal market power caused by its failure of the indicative screens
in the PNM balancing authority area. Therefore, we reject, without
prejudice, PNM's request for market-based rate authorization in the PNM
balancing authority area. We encourage other market-based rate
applicants to make use of the guidance and clarification offered
herein.
D. Notice of Change in Status
78. PNM states that its purchase of Delta Person does not affect
PNM's horizontal market power because PNM was already deemed to control
the output of the Delta Person facility under a long-term contract with
Delta Person.\118\ In its most recent updated market power analysis for
the Southwest region, PNM studied Delta Person's generation in the
first-tier balancing authority areas in which PNM has market-based rate
authority.\119\
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\118\ August 18, 2014 Filing at 1.
\119\ Public Service Company of New Mexico, Docket No. ER10-
2302-004 (Aug. 22, 2014) (delegated letter order). PNM has market-
based rate authority in seven first-tier balancing authority areas
to the PNM balancing authority area. These balancing authority areas
are Southwestern Public Service Company, Western Area Power
Administration-Colorado Missouri, Western Area Power
Administration--Lower Colorado, Public Service Company of Colorado,
Arizona Public Service Company, Salt River Project, and Tucson
Electric Power Company.
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79. Based on PNM's representations, we find that PNM satisfies the
Commission's requirements for market-based rates regarding horizontal
market power in all balancing authority areas in which PNM currently
has market-based rate authority, i.e., outside of the PNM and El Paso
Electric balancing authority areas.
80. PNM represents that of it and its affiliates, only PNM owns or
controls transmission facilities subject to Commission jurisdiction.
PNM states that open access to these transmission facilities is
provided pursuant to the terms of PNM's Open Access Transmission Tariff
on file with the Commission.\120\ Further, PNM represents that neither
it nor any affiliate owns or controls intrastate natural gas
transportation, storage, or distribution facilities. PNM represents
that it owns several sites that may be used for generation capacity
development including sites in which PNM has existing facilities. PNM
states that it currently has plans to develop new generation at or near
the San Juan Generating Station in the PNM balancing authority area.
Additionally, PNM states that it holds one undeveloped site near
Albuquerque, New Mexico.
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\120\ Public Service Company of New Mexico, FERC FPA Electric
Tariff, PNM Open Access Transmission Tariff.
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81. PNM states that it purchases coal under various long-term
agreements but does not currently own any coal mines or mineral rights.
PNM represents that these coal purchase contracts are used exclusively
to supply coal to power plants owned and operated by PNM.
82. Finally, PNM states that it has not erected barriers to entry
into the relevant market, the PNM balancing authority area, and will
not erect barriers to entry into the relevant market.
83. Based on PNM's representations, we find that PNM satisfies the
Commission's requirements for market-based rates regarding vertical
market power.
84. Based on PNM's satisfaction of the Commission's requirements
for market-based authorization regarding horizontal and vertical market
power in the markets where it has market-based rate authority, we
accept PNM's notice of change in status.
E. Reporting Requirements
85. An entity with market-based rate authorization must file an
Electric Quarterly Report (EQR) with the Commission, consistent with
Order Nos. 2001 \121\ and 768,\122\ to fulfill its responsibility under
section 205(c) \123\ of the Federal Power Act to have rates on file in
a convenient form and place.\124\ PNM must file EQRs electronically
with the Commission consistent with the procedures set forth in Order
No. 770.\125\ Failure to timely and accurately file an EQR is a
violation of the Commission's regulations for which PNM may be subject
to refund, civil penalties, and/or revocation of market-based rate
authority.\126\
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\121\ Revised Public Utility Filing Requirements, Order No.
2001, FERC Stats. & Regs. ] 31,127, reh'g denied, Order No. 2001-A,
100 FERC ] 61,074, reh'g denied, Order No. 2001-B, 100 FERC ]
61,342, order directing filing, Order No. 2001-C, 101 FERC ] 61,314
(2002), order directing filing, Order No. 2001-D, 102 FERC ] 61,334,
order refining filing requirements, Order No. 2001-E, 105 FERC ]
61,352 (2003), order on clarification, Order No. 2001-F, 106 FERC ]
61,060 (2004), order revising filing requirements, Order No. 2001-G,
120 FERC ] 61,270, order on reh'g and clarification, Order No. 2001-
H, 121 FERC ] 61,289 (2007), order revising filing requirements,
Order No. 2001-I, FERC Stats. & Regs. ] 31,282 (2008).
\122\ Electricity Mkt. Transparency Provisions of Section 220 of
the Fed. Power Act, Order No. 768, FERC Stats. & Regs. ] 31,336
(2012), order on reh'g, Order No. 768-A, 143 FERC ] 61,054 (2013).
\123\ 16 U.S.C. 824d(c) (2012).
\124\ See Revisions to Electric Quarterly Report Filing Process,
Order No. 770, FERC Stats. & Regs. ] 31,338, at P 3 (2012) (citing
Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 31).
\125\ Order No. 770, FERC Stats. & Regs. ] 31,338.
\126\ The exact filing dates for these reports are prescribed in
18 CFR 35.10b (2015). Forfeiture of market-based rate authority may
require a new application for market-based rate authority if the
applicant wishes to resume making sales at market-based rates.
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86. PNM must timely report to the Commission any change in status
that would reflect a departure from the characteristics the Commission
relied upon in granting market-based rate authority.\127\
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\127\ Reporting Requirement for Changes in Status for Public
Utilities with Market-Based Rate Authority, Order No. 652, FERC
Stats. & Regs. ] 31,175, order on reh'g, 111 FERC ] 61,413 (2005);
18 CFR 35.42 (2015).
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87. Additionally, PNM must file an updated market power analysis
for all regions in which it is designated as a Category 2 seller in
compliance with the regional reporting schedule adopted in Order No.
697.\128\ The Commission also reserves the right to require such an
analysis at any intervening time.
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\128\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 848-850.
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The Commission orders:
(A) PNM's notice of change in status is hereby accepted for filing,
as discussed in the body of this order.
(B) PNM's request for market-based authority in the PNM balancing
authority area is hereby rejected, without prejudice, as discussed in
the body of this order.
(C) PNM's SIL study is hereby rejected, without prejudice, as
discussed in the body of this order.
(D) The Secretary is hereby directed to publish a copy of this
order in the Federal Register.
By the Commission.
Issued: October 15, 2015.
Kimberly D. Bose,
Secretary.
[FR Doc. 2015-26724 Filed 10-20-15; 8:45 am]
BILLING CODE 6717-01-P